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G E O S C I E N C E A U S T R A L I AProceedings of the 2009Australian GeothermalEnergy ConferenceBudd, A.R. and Gurgenci, H.Record2009/35GeoCat #69699APPLYING GEOSCIENCE TO AUSTRALIA’S MOST IMPORTANT CHALLENGES

Proceedings of the 2009 AustralianGeothermal Energy ConferenceGEOSCIENCE AUSTRALIARecord 2009/35Edited byAnthony Budd 1 and Hal Gurgenci 212Geoscience Australia, GPO Box 378, Canberra, ACT 2601Queensland Geothermal Energy Centre, The University of Queensland, St Lucia 4072

Department of Resources, Energy and TourismMinister for Resources and Energy: The Hon. Martin Ferguson, AM MPSecretary: Mr John PierceGeoscience AustraliaChief Executive Officer: Dr Neil Williams PSM© Commonwealth of Australia, 2009This work is copyright. Apart from any fair dealings for the purpose of study, research,criticism, or review, as permitted under the Copyright Act 1968, no part may be reproducedby any process without written permission. Copyright is the responsibility of the ChiefExecutive Officer, Geoscience Australia. Requests and enquiries should be directed to theChief Executive Officer, Geoscience Australia, GPO Box 378 Canberra ACT 2601.Geoscience Australia has tried to make the information in this product as accurate aspossible. However, it does not guarantee that the information is totally accurate or complete.Therefore, you should not solely rely on this information when making a commercialdecision.ISSN 1448-2177ISBN 978-1-921672-28-6GeoCat # 69699Recommended bibliographic reference: Budd, A.R. and Gurgenci, H. (editors), 2009.Proceedings of the 2009 Australian Geothermal Energy Conference, Geoscience Australia,Record 2009/35.Recommended bibliographic citation: Chen, D. B. and Wong, G. 2009. Aims of a BasicEGS Model for the Cooper Basin, Australia, in: Budd and Gurgenci (editors), Proceedings ofthe 2009 Australian Geothermal Energy Conference, Geoscience Australia, Record 2009/35.Cover illustration: 3D image of gravity inversion modelling in the are between Mt Isa andthe Georgetown Inlier, Queensland, viewed obliquely from the south. The red bodies encloseregions of low density interpreted as granites located at depth beneath Millungera Basinsediments, the base of which is shown as the yellow surface. The interpreted granites areshown projected above an image of the Bouguer Gravity field, from which the inversionmodel was generated. Courtesy of Alison Kirkby, Geoscience Australia.

The Convenors would like to thank the following sponsors for their kind support:Platinum SponsorsGold SponsorsSilver SponsorsBronze SponsorsWednesday Happy Hour Conference Dinner Thursday Happy Hour

IntroductionThis volume is a compilation of Extended Abstracts presented at the 2009 AustralianGeothermal Energy Conference, 11-13 November 2009, Hilton Hotel, Brisbane, organised bythe Australian Geothermal Energy Association and the Australian Geothermal Energy Group.This Conference is the second dedicated conference organised by the geothermal energycommunity in Australia. The first conference in August 2008 was made possible by seedfunding from the Australian Government under the Sir Mark Oliphant International Frontiersof Science and Technology Conference funding scheme. This conference is made possible bythe sponsoring companies acknowledged earlier and paying delegates.This Conference is being held at a time of continuing rapid growth in all sectors of thegeothermal community, but also following a time of restricted financing availability due tothe Global Financial Crisis. The number of companies engaged in exploration stands at 48,the number of leases held or applied for is 386, and the value of the work program for thesecompanies exceeds $1.5 billion between 2002-2013. The Australian Geothermal EnergyAssociation serves as the peak industry representative body. The Australian Code forReporting Exploration Results, Geothermal Resources and Geothermal Reserves has been ineffect for over a year, and the second edition will be launched at this conference. TheUniversities of Queensland, West Australia, Adelaide and Newcastle have active establishedgeothermal research programs. The Australian Government has continued its strong supportof the sector through the international Partnership for Geothermal Technology, GeothermalIndustry Development Framework and Technology Roadmap, the Geothermal DrillingProgram, and the Onshore Energy Security Program.This volume of Extended Abstracts is organised under five headings:• Exploration• Underground Science and Technology• Power Conversion Technologies• Legislation, Policy and Infrastructure• Direct and Low-temperature UseAs editors of these proceedings, we first would like to thank the Technical Committee whohave been very generous with their time to review the submissions and to work with theauthors of the accepted submissions to improve the quality of the Abstracts and thepresentations.We also thank the Conference Chair Tony Hill and the rest of the Organising Committee whowere brave enough to take on the job organising this second event on behalf of the AustralianGeothermal Energy Association and the Australian Geothermal Energy Group. Jem Hansenand Impact Environment Conferences have done an excellent job in assisting theorganisation.We also thank again the sponsoring companies for their generous support.We thank Geoscience Australia for publishing the proceedings.Finally, we thank all delegates without whose participation none of this is worthwhile.Anthony BuddHal Gurgencii

Conference Organising CommitteeTony Hill (Chair), Primary Industries and Resources South AustraliaDr Andrew Barnicoat, Geoscience AustraliaDr Graeme Beardsmore, Hot Dry Rocks Pty LtdRod Bresnehan, Clean Energy AustraliasiaDr Anthony Budd, Geoscience AustraliaPeter Green, Geological Survey of QueenslandProfessor Hal Gurgenci, Queensland Geothermal Energy Centre of ExcellenceSusan Jeanes, Australian Geothermal Energy AssociationJohn King, Petratherm LtdAlan Knights, Green Rock Energy LtdKumar Thambar, Queensland Office of Clean EnergyProgram Technical PanelDr Anthony Budd (Chair), Geoscience AustraliaDr Bridget Ayling, Geoscience AustraliaDelton Chen, Geodynamics LtdGareth Cooper, Hot Dry Rocks Pty LtdNeal Evans, Geoscience AustraliaDes Fitzgerald, Intrepid GeophysicsEd Gerner, Geoscience AustraliaHelen Gibson, GeoIntrepidProfessor Hal Gurgenci, Queensland Geothermal Energy Centre of ExcellenceAlison Kirkby, Geoscience AustraliaAlan Knights, Green Rock Pty LtdChris Matthews, Torrens Energy LimitedTony Meixner, Geoscience AustraliaProfessor Behdad Moghtaderi, The University of NewcastleProfessor Klaus Regenauer-Lieb, The University of Western AustraliaPeter Reid, Petratherm LtdMichel Rosener, Geodynamics LtdDr Catherine Stafford, Granite Power LtdDr Adrian Williams, Geodynamics LtdDr Doone Wyborn, Geodynamics LtdConference OrganisersJem Hansen & Dawn HallinanImpact Environmental ConferencesPh: 02 6583 8118 Fax: 02 6583 8065ausgeothermal@impactenviro.com.auwww.ausgeothermal.comii

Contents Australian Geothermal Energy Conference 2009Meixner, T.J., Johnston, S., Kirkby, A.L., Gibson, H.J., Seikel, R., Stüwe, K., FitzGerald, D., Horspool, N.,Lane, R. and Budd, A.R.Establishing Hot Rock Exploration Models: From Synthetic Thermal Modelling to the CooperBasin 3D Geological Map ...........................................................................................................89Mortimer, L.Hydro-Mechanical Selection Criteria of Engineered Geothermal Systems ................................95Musson, A., Harrison, B., Gordon, K., Wright, S. and Sandiford, M.Thermal thinking: optimal targeting for Australian geothermal explorers ..................................101Taylor, D.H. and Harrison, B.C.Overview of Geothermal Resources and Exploration Activity in Victoria ..................................104Van Zyl, J.A.B., Uysal, I.T. and Gasparon, M.Mineralogy and Petrology of the Cooper Basin Basement Granites .........................................107Wellmann, J.F., Horowitz, F.G. and Regenauer-Lieb, K.Concept of an Integrated Workflow for Geothermal Exploration in Hot Sedimentary Aquifers .111Underground Science and TechnologyAtrens, A.D., Gurgenci, H. and Rudolph, V.Exergetic performance and power conversion of a CO 2 thermosiphon.....................................117Battye, D.L. and Ashman, P.J.Radiation associated with Hot Rock geothermal power ............................................................120Bhuana, D.S., Ashman, P.J. and Nathan, G.J.Silica deposition in Enhanced Geothermal Systems.................................................................124Chen, D.B. and Wong, G.Aims of a Basic EGS Model for the Cooper Basin, Australia ....................................................128Espinoza-Ojeda, O.M., Santoyo, E. and Andaverde, J.Analysis of error sources for estimating geothermal stabilised formation temperatures usinganalytical and rigorous methods................................................................................................134Kaieda, H., Ueda, A., Kubota, K., Wakahama, H., Mito, S., Sugiyama, K., Ozawa, A., Kuroda, Y., Kaji,Y., Suzuki, H. and Sato, H.Field experiments for studying CO 2 mineral trap at high temperature at Ogachi, Japan ..........140Kuncoro, G.B., Ngothai, Y., O’Neill, B., Pring, A., Brugger, J.A Preliminary Study on Fluid-Rock Interactions of the Hot Fractured Rock GeothermalSystem in Cooper Basin, South Australia .................................................................................144Lawless, J.V., Clotworthy, A.W. and Ussher, G.The End Point of Geothermal Developments: Modelling Depletion of Geothermal Resources 150Leary, P. and Malin, P.EGS & "The Law of Averages"..................................................................................................153Long, A., Goldstein, B.A., Hill, T. and Malavazos, M.Summary of AGEG Technical Interest Groups Research Projects ...........................................158Lukas, A., Steinbrecher, T. and Uhde, J.Geothermal Applications: Development of new state of the art drilling rigs for geothermaluse.............................................................................................................................................164iv

Contents Australian Geothermal Energy Conference 2009Remoroza, A.I., Doroodchi, E., and Moghtaderi, B.Power Generation Potential of SC-CO 2 Thermosiphon for Engineered Geothermal Systems .169Shen, B.Modelling Reservoir Behaviour during Stimulation Tests at Habanero #1 ...............................175Thiel, S., Peacock, J., Heinson, G. and McAllister, L.Magnetotelluric Monitoring Of Geothermal Fluid Flow ..............................................................180Wyborn, D.Completion of Habanero Closed-loop Circulation Test .............................................................183Xing, H., Zhang, J., Liu, Y. and Mulhaus, H.Enhanced Geothermal Reservoir Simulation ............................................................................187Xu, C. and Dowd, P.A.Fracture Simulation for Deep Crystalline Rock .........................................................................191Yanagisawa, N., Rose, P. and Wyborn, D.Habanero Tracer Tests in the Cooper Basin, Australia: Key Results for EGS Development ...197Zhang, X., Jeffrey, R. and Wu, B.Two Basic Problems for Hot Dry Rock Reservoir Stimulation and Production..........................201Power ConversionBrimblecombe, J.S. and Vos, T.J.The Feasibility of a Nocturnal Radiative Heat Dissipation System for Remote GeothermalApplications...............................................................................................................................206Bryson, M., St Hill, S., Joshi, V. and Dixon, C.Low Temperature Difference Electricity Generation Using ORC ..............................................210Collins, R.Seasonal Storage of Air Cooled Water for Arid Zone Geothermal Power Plants......................216Dally, B., Nathan, G., Watson, S., Heath, A. and Howard, C.Feasibility Assessment of Underground Cooling for Geothermal Power Cycles ......................219Guan, Z. and Gurgenci, H.Dry Cooling Technology in Chinese Thermal Power Plants .....................................................224Gurgenci, H.How to Increase Geothermal Power Conversion Efficiencies ...................................................229Moghtaderi, B. and Doroodchi, E.An Overview of GRANEX Technology for Geothermal Power Generation and Waste HeatRecovery ...................................................................................................................................234Morgan, C. and Byers, S.PureCycle® Product Development and Applications Update....................................................239Murray, C.Natural Draft Dry Cooling Tower ...............................................................................................241Odabaee, M., Hooman, K. and Gurgenci, H.Comparing the Tube Fin Heat Exchangers to Metal Foam Heat Exchangers for GeothermalApplications...............................................................................................................................244v

Contents Australian Geothermal Energy Conference 2009Quinlivan, P.Assessment of Current Costs of Geothermal Power Generation in New Zealand (2007Basis) ........................................................................................................................................248Zhu, J. and Wang, K.Analysis of Reinjection Tests in a Bedrock Geothermal Reservoir, Tianjin, China ...................255Direct/Low-temperature UseGutiérrez, H. and Espíndola, S.Low and Moderate Enthalpy Geothermal Resources to Desalinate Sea Water and ElectricityProduction .................................................................................................................................259Payne, D.J.B., Hampson, G., Kiraly, D. and Davis, E.Direct GeoExchange Cooling for the Australian Square Kilometre Array Pathfinder ................265Swift, M. and Muhlhaus, J.Geothermal extraction from porous rocks - revisited ................................................................270Legislation/Policy/infrastructureBattye, D.L. and Ashman, P.J.Radiation associated with Hot Rock geothermal power ............................................................275Butler, T.R., Tissai-Krishna, S. and Morton, A.B.Bringing large scale geothermal electricity to the National Grid................................................279Dickinson, R.R., Battye, D.L., Linton, V., Ashman, P.J. Nathan, G.Alternative Energy Carriers for Remote Geothermal Sources ..................................................286Froome, C.W.What Contribution Can Geothermal Energy Make to Australia’s Renewable Energy Target ...290Knights, A.Levelised Unit Cost – A Calculation and Reporting methodology .............................................295Newson, J. and Brotheridge, J.Skills Issues and Training in the Geothermal Industry: A New Zealand perspective ................297Nguyen, M.H. and Saha, T.K.Power loss evaluations for long distance transmission lines.....................................................307Regenauer-Lieb, K. et al.The Western Australian Geothermal Centre of Excellence ......................................................313Ward, M., Beardsmore, G.R., Budd, A.R., Goldstein, B.A., Holgate, F.L., Jeffress, G., Larking, A.,Lawless, J.V., Reid, P.W. and Williams, A.The development, launch and implementation of the Australian Geothermal Reporting Codeand current developments.........................................................................................................317vi

Australian Geothermal Energy Conference 2009The Portable Electronic Divided Bar (PEDB): a Tool for MeasuringThermal Conductivity of Rock SamplesAnson M. AntriasianHot Dry Rocks Pty. Ltd.Level 4, 141 Osborne Street, South Yarra, Victoria, 3141anson.antriasian@hotdryrocks.comThe thermal conductivity of a geological formationis an essential physical property to be determinedwhen attempting to understand and model heatflow. The Portable Electronic Divided Bar (PEDB)is an effective tool in measuring thermalconductivity, and is currently playing an importantrole in the development of heat flow modelling ofAustralian geothermal resources.The PEDB is an electronic apparatus thatproduces a temperature gradient across aspecially prepared rock sample; and with itsprecision heat flow monitoring system, it allowsthermal conductivity of a rock sample to bedetermined via the application of Fourier’s Law. Asimple spreadsheet allows direct temperaturemeasurements—utilizing thermocouples—to berecorded and interpreted to provide an absolutethermal conductivity value within ±3.5%.Measurements are rapid, taking from 5 to 15minutes per sample.In addition to uniaxial thermal conductivitymeasurements, biaxial and triaxial measurementscan be made with the PEDB, allowing for studiesof thermal conductivity anisotropy. Cylindrical coreas well as irregularly shaped rock samples can bemeasured.The Divided Bar was first described as a steadystatetool used to measure the thermalconductivity of materials by Benfield in 1939(Beardsmore and Cull, 2001). The PortableElectronic Divided Bar (PEDB) is a developmentof Benfield’s divided bar operating principal,utilizing advancements in technology to create ahigh accuracy (±3.5%), light-weight (less than 5kg), small size (260 mm x 310 mm x 450 mm) andlow power consumption (less than 200W), lownoise production device.In the field it is valuable for measuring the thermalconductivity of rock samples immediately afterrecovery from drilling, maintaining as closely aspossible the rock’s in-situ porosity and moisturecontent.For use in laboratory settings, the space that isrequired is the corner of an office desk, a singleAC power outlet, and a PC and logging device.Keywords: PEDB, portable electronic divided bar,thermal conductivity, heat flow, anisotropyThermal Conductivity and Heat FlowObserving Fourier’s Law:Q = (1)Q, , and are heat flow (W/m 2 ), thermalconductivity (W/mK), and thermal gradient (K/m),respectively.The heat flow of a site can be derived by utilisinga combination of: 1) thermal conductivitymeasurements to define ; and 2) down-holetemperature logging to define . Determining heatflow requires consideration of the geologicformations from which the thermal conductivitysamples came, and so rock samples that are tobe tested for thermal conductivity must becarefully chosen to ensure they are appropriatelyrepresentative of those geologic formations, withattention paid to characteristics such as lithologyand porosity.If thermal conductivity measurements fromseveral geological formations are taken, it ispossible to develop a down-hole profile of thermalconductivity.Calculation of Thermal ConductivityThermal conductivity of a rock sample, asmeasured by a PEDB, is determined by:d =(2)R = thermal conductivityd = thickness of the sample in mmR = (A (ΔT- c))/(a (diameter + b))A = surface area of sample in mm 2a, b, c, are calibration constants determinedduring the calibration process.ΔT is defined by:T2 T3 T =(3)T T T T 123T 1 , T 2 , T 3 , T 4 = temperatures of PEDB plates asshown on Figure 1.The thermal conductivity of each rock sample iscalculated using the measurements of the threevalues d, A, and ΔT, where ΔT is the ratio of thetemperature drop across the sample relative tothe sum of temperature drops across thepolycarbonate layers within each plate-pair—aunit-less quantity.411

Australian Geothermal Energy Conference 2009The measurements of d and A are made utilisingprecision callipers; the measurement of ΔT ismade utilising the PEDB, a PC, and a digitallogging device.Figure 1: Diagram showing principal components of theplates of the PEDB. Each brass plate is fitted with aseparate thermocouple; ΔT is the ratio of the temperature ofthe plates of the PEDB: ΔT = (T2-T3)/((T1 -T2)+(T3-T4)). Theheat source is above the top pair of brass plates, and thecold source is below the bottom pair; the consequence isthat heat flows across the rock sample.The PEDBPower supplyThe PEDB has a ‘universal’ power supply,capable of being powered by mains sources thatare within 100-250 VAC, 45-70 Hz. Portability ofthe PEDB can be achieved by using a sine-wavegenerator, a sine-wave inverter rated for 200 Wfrom a power source such as an automobile, orfrom a DC source.Plates of the PEDBTwo pairs of highly thermally conductive plates—brass in the case of the PEDB—are used, eachwith a layer of polycarbonate in between,comprising a brass-polycarbonate-brassassembly that resembles a sandwich, as shown inFigure 2. Each of these assemblies has athickness of approximately 7mm and a diameterof 65 mm. One of the assemblies is situated ontop of the rock sample—thermally connected to aheat source—and the other assembly is below thesample—thermally connected to a cold source.Such an orientation prevents: 1) convection fromoccurring between the plates and; 2) resultantintroduced uncertainties.Within each of the four brass plates is embeddeda thermocouple with its welded joint located in thecentre of the brass plate. Thus the temperaturesof each brass plate can independently bemeasured and used to determine .Figure 2: The plates of the PEDB. An HQ sized rock sampleis in place and ready for thermal conductivity measurement.Each pair of plates is brass, with a polycarbonate layer inbetween. Above the upper plate is a heat source, and belowthe lower plate is the cold source--a thermal gradient acrossthe sample is created; the ratio of the temperature dropsacross each of the polycarbonate layers and the sample isSample preparationThe PEDB measures the thermal conductivity ofconsolidated drill core. Samples measured forthermal conductivity can be any size up to adiameter of to 65 mm (approximate size of HQcore is 60mm). The samples should be cut so thatthe two faces of the sample produced areapproximately parallel, although preciseparallelism is not essential, owing to a swivelheadwhich allows for measurement of samplesthat are not perfectly parallel (Figure 3); samplepreparation is consequently easier than withsystems that do not allow for sub-parallel samplefaces.Figure 3: The swivel head (indicated by arrow) of the PEDBallows for thermal conductivity measurements of samples tobe made without necessitating perfect parallelism betweensample faces. Additionally, the black insulation shown iseffective in minimizing thermal loss from the sample.It is however essential that the faces of the rocksample are flat. This can be accomplished byusing a flat grinding wheel and lap-wheelcombination, which has been HDRPL’s preferred22

Australian Geothermal Energy Conference 2009method for processing thermal conductivitysamples thus far. The system of samplepreparation should be standardized. Generally,polishing to a fine grade up to 600-grit isrecommended.If the samples being measured for thermalconductivity were saturated with water in situ, allefforts should be made to preserve the inter-porewater within the core sample. If this is notpracticable, then the sample should be resaturatedbefore measurement via vacuumsaturation. In such cases the samples aresubjected to a vacuum for a standardized timebefore being submerged in water and returned toatmospheric pressure for a standardized time,whereafter they can be measured for thermalconductivity.Importance of sample preparation qualityIt has been observed that samples prepared withsub-flat faces or surface irregularities can returnsignificantly lower measured thermal conductivityvalues. Examples of surface irregularities thathave resulted in significant decrease in apparentthermal conductivity are:Convex sample faces resulting from worngrinding and polishing wheels.Grooved sample faces left over from therock-sawing process; chips that havefractured from the sample during cutting.Pitted surfaces resulting from preparationof weakly consolidated rocks susceptibleto “plucking” of grains.Sub horizontal fractures and/or joints.As zones of low thermal conductivity and highwater/air content that are created either within thesample itself or along the sample/plate contact,these irregularities effectively impede the heatflow across the sample. Careful efforts—implemented during sample selection,preparation, and measurement—are essential forproducing representative thermal conductivityresults. The overwhelming majority of coresamples that have been encountered by theauthor during conductivity measurement haveprovided useful samples for reliable thermalconductivity measurements, when carefullyprepared.Relevance of size and shape of samplestested in the PEDBIrregularly shaped rock samples can bemeasured. The accuracy of thermal conductivitymeasurements is independent of sample shapeso long as thermal loss around the perimeter ofthe sample is minimized. Generally, the thermalloss that may exist for a sample would increaseas its surface area increases, but this tendency iseffectively controlled with the use of thermalinsulation around the PEDB plates and rocksample (Figure ) which prevents environmental aircirculation from interfering with thermalconductivity measurements.Figure and Figure 5 show examples ofmeasurements that were made on differentlyshaped rock samples. In both cases, sampleswere ground flat, polished, and were of a variablesiltstone lithology. Variation in thermalconductivity was 5% or less from the mean in bothcases, consistent with normal inter-samplevariation.The dimensions of a rock sample that must bemeasured when calculating thermal conductivityare thickness and heat flux cross-section.Thickness is measured with precision calipers.Heat flux cross-section can found by measuringthe surface area of the rock sample’s face, eitherby calculating from core diameter, or by tracingthe sample and measuring the surface area of thetracing digitally (via scanner and digital graphicssoftware) or on to graph paper. Experiments haveshown that variations in results of measurementsmade via the tracing method and via thecalculation from diameter method are within 0.7%variation from the mean.Figure 4: Although varying significantly in size and shape,these samples—which were taken from the same rockspecimen—provide consistent results. Their conductivitiesare 2.04, 1.90, and 1.98 W/mK respectively, representing arange of 3.5% from the mean conductivity of 1.97 W/mK.33

Australian Geothermal Energy Conference 2009Figure 5: Although varying significantly in size and shape,these samples—taken from the same specimen—provideconsistent results. Their conductivities are 2.25, 2.11, and2.30 W/mK respectively, representing a range of 5% from themean conductivity of 2.22 W/mK.Mean Sample Temperature of the PEDBThe PEDB operates best when the mean sampletemperature is near the environmental airtemperature. To facilitate field operations, thePEDB is capable of operating at a range of meantemperatures, from approximately 10–35°C, andhas an indication system showing when the meantemperature approximates the environmentaltemperature.Thermal conductivity for rocks is dependent upontemperature, generally becoming less conductivewith increasing temperature, at a rate ofapproximately 0.16% per degree Celcius(Vosteen and Schellschmidt, 2003). This must bekept in mind when determining the thermalconductivity of geological formations, where thein-situ temperature is greater than that at whichthe laboratory tests were made.Equilibration ProcessOnce the sample is placed between the plates ofthe PEDB and slight pressure is applied to thesample via the hand-operated clamp, atemperature gradient is imposed across thesample and thermal equilibrium typically occurswithin 5–15 minutes. The time required isdependent upon sample thickness and surfacearea, and upon the thermal characteristics of therock sample—most importantly, thermaldiffusivity. A sample will equilibrate relativelyquickly if it is thin, and has a high surface areaand thermal diffusivity. Alternatively, a sample willtake longer to equilibrate if it is very thick, and hasa low surface area and thermal diffusivity. Figure6 and Figure 7 represent 1000 seconds ofrecorded data from the same thermal conductivitymeasurement.Figure 6: Example of data collected during thermalconductivity measurement; the horizontal axis is time,measured in seconds, and the vertical axis is temperaturemeasured in °C. Each plot represents the temperature of aplate of the PEDB, T1–T4, where the hot plate (T1) in this caseis approximately 35°C, the cold plate (T4) is approximately17°C, and the intermediate plates (T2 and T3), after having arock sample placed in between them, gradually increase intemperature until thermal equilibrium is reached.Figure 7: Example of data collected during thermalconductivity measurement; the horizontal axis is time,measured in seconds, and the vertical axis is ΔT. In thisexample, the sample measured for thermal conductivity isfully equilibrated after approximately 600s, to a ΔT value of1.44.Calibration of the PEDBThe PEDB is calibrated using a set of standardsof known thermal conductivity. These standardsare of differing thicknesses and surface areas,enabling the PEDB to be used for measuringdiversely shaped samples, and samples with arange of thicknesses and surface areas.During calibration, standards are placed in thePEDB individually and measurements are madeof the four plate temperatures T 1 –T 4 and thederived ΔT value once the standard has reachedthermal equilibrium.Measurement of thermal conductivityanisotropyAnisotropy is the characteristic of a material tobehave differently in one direction with respect toanother. Rocks can be thermally anisotropic, andin so being can exhibit different thermalconductivity in different directions.Typically, thermal conductivity measurements aremade along the long axis of a core specimen.During such testing, it is the expectation of theheat flow modeller that the core specimen was44

Australian Geothermal Energy Conference 2009taken from a bore that was drilled nearly vertically,and therefore was sufficiently parallel to Earth’sheat flow that the need for understanding howheat travels laterally across the core specimen isnegated.Testing for thermal conductivity anisotropy of arock sample involves biaxial or triaxialmeasurements. The preparation of cube-shapedsamples allows thermal conductivity to bemeasured along each axis of the same sample;thus, one sample can provide the minimum datarequired for the creation of an ellipsoidal thermalmodel. Alternatively, three orthogonally orientedsamples can be prepared from a commonspecimen, collectively providing data for thecreation of an ellipsoidal thermal model.For foliated meta-sedimentary specimens, thetendency has been observed (Figure 8) forthermal conductivity to be greater parallel to thefoliation, compared to perpendicular to thefoliation. In this paper, 1 is nominated as the axisof greatest thermal conductivity, while 2 isnominated the axis of least thermal conductivity,and it is assumed that there is an ellipticalgradation between 1 and 2 .Figure 8: Summary of thermal conductivity data from sixmeta-sedimentary rock specimens; the six differently shapedsymbols indicating the different specimens studied. Eachspecimen was measured for thermal conductivity at severalangles with respect to the specimen’s foliation. The verticalaxis is thermal conductivity (W/mK); the horizontal axis is theangle between the foliation of the rock sample, and thedirection of heat flow across the rock sample while within thePEDB, measured in degrees (°), where 0° indicates heatflow parallel to the planes of foliation, and 90° indicates heatflow perpendicular to the planes of foliation. A relationship isshown to exist between the magnitude of thermalconductivity and the direction of heat flow with respect to thespecimen’s foliation.Results of anisotropy testingThe results of two extreme cases of rock thermalconductivity anisotropy are shown in Figure 8 anddiscussed below.A foliated meta-sediment, Specimen A had amean conductivity of 4.26 W/mK parallel tofoliation, and a mean conductivity of 1.44 W/mKperpendicular to foliation. That is a variation of50% from the mean conductivity of 2.85 W/mK.The anisotropy factor for Specimen A expressedas 1 / 2 , is 2.96.Another foliated meta-sediment, Specimen B, hada mean conductivity of 5.37 W/mK parallel tofoliation, and a mean conductivity of 2.65 W/mKperpendicular to foliation. That is a variation of34% from the mean conductivity of 4.01 W/mK.The anisotropy factor for Specimen B expressedas 1 / 2 , is 2.03.In both cases, 1 was parallel to the rockspecimen’s foliation, while 2 was perpendicular tothe rock specimen’s foliation. In addition, 1 andthe foliation were within 5° of parallel to the borein both cases. Since the bores that these samplesoriginated from were vertical, the thermalconductivities that would be most relevant to theheat-flow modeller—for the location within thegeological formation from which the specimenscame—would be those that were parallel toEarth’s heat flow, and in these cases parallel to 1 . The conductivity values most relevant for heatflow modelling of geological formationsrepresented by specimens A and B, would be4.26 W/mK and 5.37 W/mK respectively.Calculation of variability in thermalconductivityBut what if the bores, foliation, and the direction of 1 discussed immediately above were NOTparallel to Earth’s heat flow, and happened to bedipping at 45° instead, as it might in a steeplydippingmineral exploration bore? In such a case,Earth’s heat flow is now no longer parallel with thebore, but is 45° to it; and consequently, thethermal conductivity vector of the rock specimenmost relevant to the heat flow modeller is thatwhich is parallel to the direction of Earth’s heatflow. Using an elliptical thermal conductivityblending model, where 1 and 2 are the vectorsrepresenting the greatest and lowest thermalconductivities respectively, the resultant thermalconductivity vector for 45° can be determined.The elliptical model is derived beginning with theequation for an ellipse:2 2x y1=(4)2 2a bx = cos θy = sin θa = 1b = 2 = resultant thermal conductivity when heat flowis at angle θ 1 = vector of greatest thermal conductivity55

Australian Geothermal Energy Conference 2009 2 = vector of least thermal conductivity = angle in (°) between the direction of Earth’sheat flow and 1Substituting variable into Equation (4) gives:2 2 2 2 cos sin 1= (5)1Solving for in Equation (5) gives:1 =22cos sin 122By applying the 1 and 2 data from the results ofanisotropy testing into Equation (6), the equivalentuniaxial thermal conductivity of the rock samplesA and B can be determined:Sample A:(6) 1 = 4.26 W/mK and 2 = 1.44 W/mKThe resultant when 1 is dipping at 45°is: 1.93 W/mKSample B: 1 = 5.37 W/mK and 2 = 2.65 W/mKThe resultant when 1 is dipping at 45°is: 3.36 W/mKSignificance of variability in thermalconductivityThe resultant of sample A and B at 45° is 1.93and 3.36 W/mK respectively. These values aresignificantly different than either of their respective 1 or 2 values.Sample ASample B55% variation from 1 (4.26 W/mK)34% variation from 2 (1.44W/mK)37% variation from 1 (5.37 W/mK)27% variation from 2 (2.65 W/mK)When entered into a heat flow model, thisvariation in measured thermal conductivity mayresult in significant variation of calculated heatflow.While bores drilled purposefully for geothermalenergy exploration may as a rule be vertical,bores such as those used for minerals explorationmay be significantly non-vertical owing to theefforts of the exploration program to maximize thelikelihood of hitting a target lode. Thus, careshould be taken when utilizing core from nonverticalbores for geothermal data, ensuring thatthermal conductivity anisotropy is accounted forwhen developing heat flow models.Limitations of the PEDBThe PEDB is not calibrated for measuringconductivities of samples larger than 65 mm indiameter. Larger core or hand specimens canhowever be accommodated by cutting them to asuitable size.The PEDB provides thermal conductivitymeasurements at mean temperatures from 15–35°C. Considerations of the geological formation’sin-situ temperature should be made, since thermalconductivity in rocks is a property that generallydecreases with increasing temperature.ConclusionsThe PEDB is effective in measuring thermalconductivity of rock specimens:Rapidly and on a production scaleIn remote locations and in the laboratoryUsing variable power suppliesThat have a non-standardized size andshape Triaxially for thermal conductivityanisotropy studiesReferencesIn parallel (two PEDB’s can be operatedsimultaneously)Vosteen, H.D. and Schellschmidt, R., 2003.Influence of temperature on thermal conductivity,thermal capacity and thermal diffusivity fordifferent types of rock. Physics and Chemistry ofthe Earth, 28, 499–509.Beardsmore, G.R. and Cull, J.P., 2001. CrustalHeat Flow, A Guide to Measurement andModelling, 108 pp.66

Modelling in Geothermal ExplorationGraeme R Beardsmore*Hot Dry Rocks Pty LtdLevel 4, 141 Osborne Street, South Yarra VIC 3141Australian Geothermal Energy Conference 2009In geothermal studies we often have to drawconclusions and make decisions using uncertainor incomplete data sets. In such circumstances,we are compelled to rely on ‘modelling’. Modellingtakes many forms and is used for many purposes,from temperature prediction to cash flowprediction.Equations typically modelled in geothermalstudies include the heat flow equation, phasechange equations, fluid dynamics equations,Rayleigh number equations, project valuationequations or hydro-geo-mechanical equations.Models of geothermal systems are oftenconstrained by geophysical measurements,observations of structural trends, geochemicalsignatures, flow rate observations, or temperaturemeasurements.Thermal modelling sheds light on probabletemperatures at depth prior to expensive drilling.Reservoir modelling, likewise, helps predict theperformance of future geothermal productionwells, with increasing confidence as reservoirproperties are constrained. Economic modelling,however uncertain, is essential to make informedinvestment and project development decisions.Keywords: Modelling, Inversion, Stored Heat,Numerical Simulation, Economic ModellingIntroductionIn geothermal studies we often have to drawconclusions and make decisions about complexsystems using uncertain or incomplete data sets.In such circumstances, we are compelled to relyon ‘modelling’ to make sense of the data. Butmodelling, itself, often presents us with anassortment of possible methods. This paperbriefly covers some of the common instanceswhere modelling is required in geothermal; thetype of data required; the range, strengths, andweaknesses of the different available modellingmethods; and what stages in the developmentprocess each might be appropriate.The authoritive online dictionary ‘wiktionary.com’defines a ‘model’ as “(1) A person who serves asa subject for artwork or fashion, usually in themedium of photography but also for painting ordrawing. (2) A miniature representation of aphysical object. (3) A simplified representation(usually mathematical) used to explain theworkings of a real world system or event.”Some individuals in the industry may fit definition(1), but the processes we use to make sense ofdisparate geothermal data fall into definition (3).The purpose of models is to assist predictionsabout variables that are beyond the current reachof measurements. Models might be used to helppredict the location of undiscovered heat sources,the temperature and reservoir conditions at undrilleddepths, or the income from a geothermaldevelopment at some time in the future.“Real world systems” that can be modelled ingeothermal studies include:Geological structuresUnderground temperatures (°C)Response of fracture networks to stressWell productivity (MWt)Generation capacity (MWe) Cash flow for a projectAll modelling should be based on observations ormeasured data. Models based on ‘estimated’ or‘assumed’ values do not add value to a projectbecause the outputs of any model are only asreliable as the inputs. If the inputs are poorlyconstrained, so are the outputs.Models must also conform to the laws of physics,such as conservation of mass and energy. Arobust model is a mathematical representation ofa system that honours all relevant governingequations, and is consistent with all observed ormeasured data. We say that these known data‘constrain’ the model.Models can be developed around many differentgoverning equations and be constrained by manydifferent types of data. Relevant governingequations in geothermal studies may include theheat flow equation, phase change equations, fluiddynamics equations, Rayleigh number equations,project valuation equations or hydro-geomechanicalequations. Models of geothermalsystems are often constrained by geophysicalmeasurements, observations of structural trends,geochemical signatures, flow rate observations, ortemperature measurements.Modelling terms that are commonly used, butrarely explained, include:1D, 2D, 3D, 4D, 2.5D etcForward modelling versus inversionStored heat versus numerical simulationHydro-geo-mechanical modellingEconomic modelling17

Australian Geothermal Energy Conference 2009The following sections explain each of theseterms and how they relate to “real world systems”.1D, 2D, 3D, 4D, 2.5D etcThe “D” in these terms means “dimension”—usually spatial dimension. The first threedimensions are the three orthogonal dimensionsof space (or ‘length’, ‘width’ and ‘depth’). Thefourth dimension is (usually) time. 1D modelling issufficient for processes that happen in a straightline. If a process intrinsically encompasses anarea or a vertical section, then a minimum of 2Dmodelling is required. Processes involvingvolumes of rock or space require 3D models,while 3D processes that change through timehave to be represented by 4D models.‘2.5D’ modelling refers to when a systemeffectively only varies in two dimensions, but isassumed to extend infinitely and unchanged intothe third dimension. Thus, for example, a threedimensional block can be entirely represented bya two dimensional cross-section.1D modellingAn example of 1D modelling is predicting thetemperature (T z ) at a particular depth (z) when weknow surface heat flow (Q) and assume verticalconductive heat transfer in the crust (Figure 1).divided by thermal conductivity) between thesurface and depth, z. All the energy transferoccurs vertically so the system can berepresented in a single dimension.1D models have the advantage that they are easyto comprehend, are computationally relativelysimple, do not require much computer memory orprocessing power, and deliver rapid results. Theyare appropriate for rapid regional reconnaissance,or in situations where data may only be availablefor a single location. Their disadvantages includethe fact that very few natural processes are trulyone-dimensional, so certain simplifications areinherent in the models.2D ModellingSome problems are too complex, or inherentlyareal or spatial in scope, to reduce to 1D. Anexample might be modelling the thermal effect ofconvection in a permeable layer. This requires atleast a 2D space to represent the vertical andhorizontal movement of water and heat (Figure 2).Figure 2. 2D model of temperature (°C) distribution wherecool water enters the bottom left of the model and exits at thetop left. The axes represent the physical dimensions, and theresult (temperature) is represented by cell colour. This couldnot be modelled in 1D. After Wang et al. (2009).Figure 1. 1D conductive heat flow model of temperatureincrease with depth. Only one dimension (‘depth’) ismodelled, with results (‘temperature’) plotted on the x-axis.Constraining temperature data shown in green.The governing equation for this is:T z = T 0 + Q.R Eq 1where T 0 is the surface temperature and R is thecumulative thermal resistance (physical thicknessHigher Dimensional ModellingThe real world is inherently four-dimensional.Everything exists in three-dimensional space andtime. The higher the dimension of modelling,therefore, the closer a model can approximate‘reality’. However, higher dimensional modellingcomes with significant challenges.It is usual to break each dimension of a model intosub-sections and to treat each subsection as adiscrete unit. In a 1D model, this may result inseveral tens or hundreds of discrete units makingup the total length of the model. In 2D, eachdimension might be divided into several tens orhundreds of units, resulting in hundreds to tens ofthousands of individual ‘cells’. For instance, theexample in Figure 2 shows the model areadivided into 20 units in each dimension, resulting28

Australian Geothermal Energy Conference 2009in 400 discrete cells. The number of cells ismultiplied further with 3D or 4D modelling, to thepoint where models (e.g. Figure 3) regularlyrequire millions of cells to adequately define themodel space.Figure 3. 3D representation of a geological layer. Threeorthogonal axes are displayed, with a particular variable(‘rock type’) represented by colour. There are over onemillion individual cells in this model.Storing and manipulating information aboutmillions of cells in a computational processrequires significant computing power and/or time.It is not unusual for a typical desktop computer totake several days, or even weeks, to solve asingle 3D model. In addition, the number ofboundary conditions and variables required tofully define a 3D model is typically higher thanlower dimensional problems.Boundary ConditionsSpatial-type models of any dimension needboundary conditions to constrain a solution.Boundary conditions provide a starting point forthe mathematical solution of the particulargoverning equation under investigation.Forward Modelling / InversionThe terms ‘forward modelling’ and ‘inversion’ referto fundamentally different ways of interpretingmeasured data. In ‘forward modelling’, anoperator builds a geological model and assignsproperties and boundary conditions that representa ‘best guess’ about the true nature of the piece ofcrust under investigation. The model is thensolved and the results are compared againstknown measurements of certain parameters. Ifthe results do not closely match the observations,the model is manually altered and the processrepeated until a good match is achieved.‘Inversion’ starts with the known measurements.The operator effectively tells the model what isknown, and the inversion process then derives theappropriate boundary conditions or particularvalues for variables to match the known data.3D conductive temperature modelling can beused to illustrate these two approaches.Conductive heat flow modelling typically relies ona geological model to represent the structure andlithological variation with the piece of crust underinvestigation. The different geological units of themodel are assigned properties including (as aminimum) thermal conductivity. Surfacetemperature is almost always used as one of thethermal boundary conditions, and there is anassumption of zero heat flow through the sides ofthe model. A second thermal boundary conditionis always required at either the top or base of themodel to fully constrain the solution to theconductive heat flow equation. The nature of thesecond boundary condition and how a solution isderived effectively distinguishes forward modellingfrom inversion modelling.Forward modelling of 3D conductive heat flow hasbeen practiced since the advent of digitalcomputers (e.g. Sams and Thomas-Betts, 1988;Gibson et al., 2008). Its strength lies in its relativesimplicity and ability to quickly reach a solution fortemperature distribution that satisfies a smallnumber of surface heat flow observations. It isappropriate in situations where very little is knownabout surface heat flow, or for conceptualmodelling to explore the effect of differentparameters on subsurface temperaturedistribution.Forward modelling inherently requires theoperator to assume a thermal boundary condition(typically ‘constant temperature’ or ‘constant heatflow’) at the base of the model. However, there isno geological reason to expect either heat flow ortemperature to be constant across any particulardepth surface. In fact, the whole premise ofgeothermal exploration is that heat flow andtemperature are not laterally constant at depth!Inversion modelling comes into its own when thenumber of surface observations increases beyondtwo or three. In this situation, it is unlikely that asimple basal condition will yield a solution thatclosely satisfies all the available data. But aninversion process inherently starts with thesurface data and derives the temperaturedistribution that best accounts for theobservations. This process results in conditions atthe base of the model that are rarely constanttemperature or constant heat flow (Figure 4).Stored Heat / Numerical SimulationTable 2 of the ‘Geothermal Lexicon’ (AGEG,2008) includes ‘stored heat’ and ‘numericalsimulation’ as options for estimating GeothermalResources and Geothermal Reserves. TheLexicon goes on to describe the two differentmethodologies in some detail. The methods aremutually independent and represent two verydifferent ways of assessing the potential of ageothermal play.39

Australian Geothermal Energy Conference 2009Figure 4. Inversion modelling of conductive heat flow. Thecolours represent modelled temperature at 5,000 m depthbeneath an area approximately 50 km x 40 km. The modelwas constrained by heat flow measurements at the sixlocations shown. Both heat flow and temperature varysignificantly across the model. After Torrens Energy (2008).A ‘stored heat’ evaluation is a technique forestimating the total heat energy contained within atarget volume of rock. The method requires theestimation of the volume, density, specific heatcapacity and temperature of the target reservoirformations. These parameters are sufficient toestimate the absolute amount of thermal energy inthe rock. The proportion of that energy that mightultimately be extracted depends on the lowesteconomically extractable temperature (‘cut-offtemperature’), the application to which the energywill be applied, and the efficiency with which theenergy can be extracted.The ‘stored heat’ approach quantifies theresource base—that is, it addresses the question,“How much thermal energy is in this geothermalplay?” It does not address any aspect ofextracting the energy, except for a considerationof the ultimate end use of the energy. It also doesnot address possible recharge of the thermalenergy during extraction. ‘Stored heat’ is a usefulconcept at the early stages of resource estimationand play evaluation, but is of limited use fordetailed project planning.‘Numerical simulation’ lets us investigate some ofthe practical issues surrounding the extraction ofthermal energy. Unlike ‘stored heat’ assessments,‘numerical simulation’ incorporates a timeelement. At the early stages of field development,it allows us to model the flow of fluid (liquid and/orgas) and heat for different extraction strategies,and investigate how they impact on the life of theresource in terms of achievable power output,reservoir temperature and pressure (Figure 5).Later in the life of the project, the models can berefined using actual production data like thermaldraw down to develop a predictive understandingof the response of the reservoir to production.Figure 5. Predicted temperature distribution in an EGSreservoir after 20 years of production using a hexagonal (top)and square (bottom) well pattern. Results from numericalsimulation. After Vörös et al. (2007).Numerical simulation is the best way toinvestigate parameters such as power outputthrough time, the effects of reinjection on reservoirtemperature and pressure, improvements inproductivity achievable through permeabilityenhancement, the impact of pumping on reservoirproductivity and lifetime, and similar issues.Numerical simulation, therefore, has a role to playat all stages of a project’s life.Hydro-geo-mechanical modellingCoupled hydro-geo-mechanical modelling is thefrontier of EGS numerical investigations. Thegrowth of an EGS reservoir during hydraulicstimulation and the geo-mechanical behaviour ofa reservoir during production are incrediblycomplex processes that currently defy realisticnumerical modelling. To get an idea of thecomplex systems at interplay during an EGSproject, consider the following:When water is injected into a fractured rock, manyprocesses take place. The pressured waterincreases the pore pressure in the fractures andeffectively jacks the fracture open. Eventually, thefriction on critically orientated fracture is reducedto the point where the two sides of the fracturecan slip against each other in response to thetectonic stress field. This slippage alters the local410

Australian Geothermal Energy Conference 2009stress field in the matrix in the vicinity of thefracture and the pressure within the pores. At thesame time, the thermal shock of the cool injectedwater on the hot fractured rocks causes thermalshrinking of the rock matrix, which in turn alsoaffects the local stress field. As the high-pressurewater near the borehole works its way into therock fabric, the volume of rock affected by thehydraulic stimulation increases, and the localstress field, pore pressures and temperaturescontinuously adjust and readjust to the hydraulicand thermal changes. As the injected fluidaccumulates in the fractured rock, even the bulkvolume of the rock increase.The exact reaction of the rock and fracture systemto the injected water depends on the density andorientation of all the fractures; the strength of therock; the thermal expansion coefficient, specificheat capacity, density and thermal conductivity ofthe rock; the pressure and temperature of theinjected fluid; the initial magnitude and orientationof the local stress field; the stiffness of thefractures; all of which are difficult to quantify.Developing code to explicitly model theoverwhelmingly complex system of interactingforces and flows is effectively impossible. It isphysically impossible to provide the computingpower and memory to store and process all theessential variables and governing equations onthe many different required scales. The problemmust be tackled in individual pieces, or by using a‘lumped variable’ approach.One example is ‘UDEC 1 ’ (Universal DistinctElement Code). UDEC models a rock mass as aseries of impermeable blocks separated bydiscontinuities (joints). The joints form boundariesbetween the blocks, and impose their ownboundary conditions. UDEC models the physicaldisplacement of the blocks in response to a stressfield. Solutions satisfy the laws of conservation ofmomentum and energy. UDEC simulations canprovide the following useful outcomes: Identification of the orientation of fracturesmost likely to shear during stimulation.An estimate of the pre-stimulation hydraulicconductivity and anisotropy of the fracturedrock (e.g. Figure 6).An indication of potential reservoir growth andfluid flooding directions.An estimate of stress magnitudes at the targetdepth and the injection pressures required forhydraulic stimulation.Results provide the basis for more complexmodels to simulate the lifetime performanceof an EGS project.1 UDEC is a Trademark of Itasca InternationalFigure 6. UDEC model results of the horizontal planarhydraulic conductivity (K) ellipse for a fracture network at aspecific depth (stress) level.Economic ModellingEconomic modelling aims to simplify the multitudeof factors that affect the ultimate profitability of aproject into a few basic assumptions. Unlike themodelling discussed earlier in this document,economic modelling is primarily about estimatingcash flow through time, with little reference tospatial or volumetric details.Many parameters can be estimated througheconomic modelling. Parameters such as the‘Levelised Cost of Power’, ‘Net Present Value’and ‘Expected Monetary Value’ allow the relativevalues of different geothermal plays, or differentstrategies for developing the same play, to beassessed. The sensitivity of project value tovariables such as discount rates, electricity price,operating costs, drilling costs, distance from thegrid, and so forth, can be explored througheconomic models. Likewise, the impact of policymeasures such as Renewable EnergyCertificates, Geothermal Drilling Program grants,and so forth, can also be explored.Economic modelling is a powerful tool forinforming investment decisions and for projectplanning, but the critical input variables oftenrelate to future economic conditions and are verydifficult to constrain. Regardless, economicmodelling should be used from very early in aproject’s life in order to identify the key drivers forthe economic success of each individual project.In some cases that may be low developmentcosts, while in others it may be high power saleprice.ConclusionsModelling in all its forms and guises is a vital andvaluable tool in making sense of the often scarceand uncertain data inherent in geothermal studies.Thermal modelling sheds light on probable511

Australian Geothermal Energy Conference 2009temperatures at depth prior to expensive drilling.Reservoir modelling, likewise, helps predict theperformance of future geothermal productionwells, with increasing confidence as reservoirproperties are constrained. Economic modelling,however uncertain, is essential to make informedinvestment and project development decisions.At each stage of development, the sophisticationof the modelling should refect the amount andreliability of the available data. Simple 1D modelsmay be appropriate when little information isavailable, while more complex, multi-dimensionalmodels are better for extracting the maximumvalue from larger, more reliable data sets.ReferencesAGEG (Australian Geothermal Energy Group)(2008). Geothermal lexicon for resources andreserves definition and reporting—Edition 1.AGEG Geothermal Code Committee, August2008. 105pp.Gibson, H., Stuwe, K., Seikel, R., FitzGerald, D.,Calcagno, P., Argast, D., McInerney, P. andBudd, A. (2008). Forward prediction of spatialtemperature variation from 3D geology models. In:Blevin, J.E., Bradshaw, B.E. and Uruski, C. (Eds),Eastern Australasian Basins Symposium III,Petroleum Exploration Society of Australia,Special Publication, 425-430.Sams, M.S. and Thomas-Betts, A. (1988). 3Dnumerical modelling of the conductive heat flow ofSW England. Geophysical Journal, 92, 323-334.Torrens Energy (2008). 780,000 PJ inferredresource, Parachilna Project, South Australia.Statement to the Australian Securities Exchange,20 August 2008. 4pp.Vörös, R., Weidler, R., de Graaf, L. and Wyborn,D. (2007). Thermal modelling of long termcirculation of multi-well development at theCooper Basin hot fractured rock (HFR) projectand current proposed scale-up program.Proceedings: Thirty-Second Workshop onGeothermal Reservoir Engineering, StanfordUniversity, Stanford, California, January 22–24.SGP-TR-183.Wang, Z., McClure, M.W. and Horne, R.N. (2009).A single-well EGS configuration using a thermosiphon.Proceedings: Thirty-Fourth Workshop onGeothermal Reservoir Engineering, StanfordUniversity, Stanford, California, February 9–11.SGP-TR-187.612

Australian Geothermal Energy Conference 2009A Geothermal Play Systems approach for explorationA.R. Budd, A.C. Barnicoat, B. F. Ayling, E.J. Gerner, A. J. Meixner, A. M. Kirkby.Geoscience Australia, GPO Box 378, Canberra 2601, ACT, AustraliaHot Rock exploration and development hasprogressed rapidly in Australia in the last decade.A wealth of pre-competitive geological dataacquired by government surveys and mineral andpetroleum explorers is available in Australia, butheat flow data specific to geothermal explorationis sparse. A methodology is presented that setsout the key parameters required in Hot Rockexploration. Mappable practical proxiescorresponding to these parameters can utiliseexisting geological datasets. Australia has anenviable amount of geological data that is publiclyavailable, and this can be used to show that manyparts of the continent are attractive Hot Rockexploration areas.Keywords: Hot Rock, exploration, Australia,geothermal play systemsIntroductionMineral Systems Analysis or Petroleum PlaySystems are well established in their respectiveindustries. Exploration methods for conventionalgeothermal systems are likewise well established.To date, most EGS or Hot Rock projects (inAustralia at least) have used compilations ofbottom-hole temperatures to identify prospectivegeothermal systems. These data are mostlyrestricted to petroleum exploration areas. As aresult, with few exceptions only areas of historicalpetroleum potential in Australia have beenidentified as having geothermal potential, whetherHot Rock or hydrothermal. The other obvious datatype for temperature prediction (heat flow) ispoorly constrained in Australia with only ~150publicly-available measurements.Hot Rock systems are not restricted to thegeological settings favorable for oil and gasaccumulation and preservation. Therefore, it is tobe expected that there are areas of Australia withuntested Hot Rock geothermal potential.Geoscience Australia is deriving a GeothermalPlays System approach, modeled on the‘Exploration Science’ methodology of MineralSystems Analysis (Barnicoat 2008), to formulate aframework for Hot Rock exploration. Thisapproach links the key physical and/or chaemicalparameters of the geological system underconsideration, with mappable ‘practical proxies’ todefine exploration criteria. It is a scalableapproach that works for terrain selection, areaselection and drill target selection.To derive the key components necessary to forman accumulation of heat in a Hot Rock geothermalplay, a systematic approach is desirable. Fromthese key components, the geological,geophysical and geochemical data necessary forexploration should be identifiable. Importantly,‘practical proxies’ should be able to be developed,which utilize existing datasets to make informedassumptions regarding missing data. This wouldenable Hot Rock exploration in Australia toprogress.MethodHot Rock systems comprise a heat source, aninsulating layer, and sufficient permeability –either natural or enhanced - to enable sufficientflow of fluid through the heat reservoir.Temperature and flow rate are the two essentialparameters describing the potential output of ageothermal system.The steady-state equation for temperature (1)shows that the important determinants oftemperature are: thermal conductivity , depthintegratedheat generation A, mantle or basal heatflow Q m and the crustal thickness underconsideration Z.TAz Qmdz (1)In most areas of Australia, this temperatureequation cannot be solved by input of directmeasurements. Estimates must be used based oninference from other datasets that may have beenacquired for other purposes, and as such arepractical, proxy measurements. Further, some ofthese proxies translate readily to mappablefeatures that have concerned petroleum andmineral exploration geologists for many years.Increasingly in Australia, 3D geological maps arebeing made at various scales that already containmany of the mapped proxy data necessary for HotRock exploration, and these may be practicallyutilized for predicting the thermal structure of theupper crust.Thermal conductivityThe thermal conductivity of rocks varies accordingto composition, grainsize, porosity andtemperature. Basic geological mapping andlogging of drill core or chips will record lithology,and this information can be used to estimategrainsize, porosity and composition. Porosity maybe determined from density measurements andwell data. In a simplistic first-pass assessment,the effect of temperature may be ignored as itsinfluence is smaller than effects from composition,grainsize, or porosity. In more advanced problemsolvingmodels, it may be solved-for iteratively.113

Australian Geothermal Energy Conference 2009Heat GenerationHeat generation is a property that is dependent oncomposition. Uranium, thorium and potassium arethe main radiogenic elements that contribute toheat generation. The density of a rock is also animportant variable. The heat generation of a rockis given by the equation of Rybach (1988):A = 10 -5 ρ(9.52U + 2.56Th + 3.48K) (2)where ρ = density in kg m -3 and U, Th and K arethe concentration of uranium and thorium in partsper million and potassium in weight percent.Geochemical analyses of whole-rock samplesplus determination of density will fully solve theequation. In Australia, geochemical data is oftenanalyzed for a sample although density isgenerally not. In such case, density must beestimated based on lithology, the determination ofwhich will be aided by geochemistry. In detail, theheat production of a rock also depends on its age.In Australia, where recent active volcanism islacking, high-heat-producing granites aregenerally the only rocks capable of creating asufficient additional heat flow in the upper crust tocause significantly elevated temperaturenecessary for viable Hot Rock geothermalsystems, although low conductivity cover mayallow temperatures in radiogenic lithologies toreach economic values. High-heat productiongranites often occur as deeply (>3 km) buriedplutons and are not directly sampled. Graniteplutons, suites and supersuites share a geneticlineage that potentially enables some constraintsto be placed on unsampled plutons.Mappable practical proxies for heat production(from granites) can therefore be utilized frommapping geochemistry, geochronology andgeophysics (gravity, magnetic, radiometrics,seismic surveys) by: (1) mapping trends ofgranites from outcrop to beneath insulatingmaterials using geophysical interpretations; (2)using the chemistry (either measured or inferredfrom radiometrics) of outcropping granites tocalculate heat production; and (3) estimating thedepth and area (and therefore volume) of buriedgranites using constraints supplied by seismicsurveys and interpretation of gravity and magneticpotential field data (see Meixner et al. thisvolume).In Australia, the general nature of granites ingeological provinces is quite well known andcontinues to be refined. For example, it is knownthat late Archean granites in the Yilgarn Cratonare high-heat producing (Cassidy et al. 2002), asare the more felsic members of numeroussupersuites of the Paleozoic of eastern Australia(eg Chappell et al. 2000). Proterozoic granites inAustralia generally have high U, Th and Kcompared to granites of older and youngerperiods, and many Proterozoic supersuites arehigh heat producing (Budd et al. 2001, McLaren etal. 2003).At a national scale, the newly releasedRadiometric Map of Australia(http://www.ga.gov.au/minerals/research/national/radiometric/index.jsp) shows the surfacedistribution of K, U and Th for over 80 per cent ofthe continent (Figure 1). This new radiometricmap has been produced by leveling more than450 individual surveys collected over the past 40years and compiling them into a single seamlessimage. This dataset readily shows areas of highU, Th and K, some of which may correlate to highheat-producinggranites. Heat production mayalso be estimated from gamma logs or fromseismic velocity.Figure 1: A clip-out of the Radiometric Map of Australia, FirstEdition (Minty et al. 2008). The ternary radiometric imageshows the concentrations of the radioelements potassium(K), uranium (U) and thorium (Th) at the Earth’s surface asmeasured using the airborne gamma-ray spectrometricmethod. The image is a false color composite using thecolors red, blue and green to represent K, U and Threspectively.These various mappable proxies for heatproduction are supported by extensive publiclyavailabledatasets, and are readily incorporatedinto both 2D GIS and 3D maps.Mantle/Basal heat flow and section depthIn comparison to some other parts of the world,the broad thermal structure of the Australian crustis understood in great detail only in small areas.Sass and Lachenbruch (1979) and Cull (1982,1991) examined information on heat flow inAustralia, but with less than 150 heat flowmeasurements across the entire continent, thedata available are insufficient to be definitive.From this work, it was recognized that severalareas of Proterozoic crust have anomalously highheat flow (and include abundant high-heatproducinggranites). Several studies have214

Australian Geothermal Energy Conference 2009examined the occurrence of this high heat flow,heat production and implications for tectonicevolution, including (but not limited to): McLarenet al. (2006) in the Mount Painter Province, SouthAustralia; Neumann et al. (2000) in the area of theSouth Australian Heat Flow Anomaly; andSandiford et al (2001) in central Australia. Evenwith these studies, considerable further work isrequired to be done throughout Australia to betterunderstand the application of heat flow provinceunderstanding as outlined by Roy et al. (1968).Information on crustal structure is central tounderstanding the overall thermal structure of thecrust and for deriving mantle heat flow. Seismicreflection surveys directly map crustal structure,and provide information on the potential range oflithologies and hence heat generation and thermalconductivity. Seismic velocities derived from thedata also have implications for thermal structureincluding temperature and heat generation.Seismic velocity is a proxy for density, which mayassist in the mapping of granite volumes andtherefore potential heat production. Australia hasa good database of seismic reflection surveys,and surveys are being continually acquired.Other parametersOnce the temperature of a potential geothermalHot Rock reservoir is constrained, the nextconcern is whether a fluid can pass through thereservoir at the necessary velocity and volume(flow rate) to extract the required energy from thereservoir and transport it to the surface. Darcy’slaw describes the flow of a fluid through a porousmedium: A( Pb Pa)q L(3)where q is the total discharge (units of volume pertime, e.g., m³/s) and is equal to the product of thepermeability (κ units of area, e.g. m²) of themedium, the cross-sectional area (A) to flow, andthe pressure drop (P b − P a ), all divided by thedynamic viscosity μ (in SI units e.g. kg/(m·s) orPa·s), and the length L the pressure drop is takingplace over.Of most interest during a resource evaluationphase is the permeability of the target reservoir orformation. Other than direct measurement,mappable practical proxies for this includepredicted lithology and seismic velocity.As Hot Rock developments usually includereservoir engineering to enhance reservoirpermeability, mapping the stress regime at thatcrustal level is of interest. This is mapped eitherdirectly through borehole measurement, mediumtolong-term passive seismic monitoring using anAustralia-wide seismic monitoring network, shorttermpassive seismic monitoring using temporaryarray deployments, or indirectly through surfaceneotectonic kinematic indicators. The AustralianStress Map (Hillis and Reynolds, 2000) showingthe crustal stress regime is available athttp://www.asprg.adelaide.edu.au/asm/ (Figure 2)and has provided useful information forgeothermal explorers in the early stages of theirdevelopments.Figure 2: Stress trajectories calculated from the AustralianStress Map (Hillis and Reynolds, 2000). The stresstrajectories indicate the orientation of the maximumhorizontal stress at each point along the trajectory, but theydo not imply information about magnitudes.ConclusionIn Hot Rock exploration in Australia, it is possibleto link the fundamental geothermal parameters tothe exploration process by means of thegeological expression of the fundamentalprocesses and the application of a scaledependentmapping of these into explorationdecision making.The most important step in the process istranslating the understanding of the process andthe key parameters controlling the process intofactors that can be determined spatially. Hot Rockgeothermal exploration in Australia is in its infancyand with some exceptions has been based on thedatabase of bottom-hole temperatures frompetroleum drilling. By incorporating national-scaledatasets into a Geographical Information System,a relatively rapid assessment of Hot Rockgeothermal plays can be done at a regional scale.This will inform both exploration programs (andtherefore lower risk) and pre-competitive dataacquisition programs.A companion paper (Meixner et al. this volume,Establishing Hot Rock Exploration Models - FromSynthetic Thermal Modeling to the Cooper Basin3D Geological Map) describes the use of thermalmodeling of 3D geological datasets as a moredetailed way of assessing geothermalprospectivity at a regional scale. Australia hasextensive publicly-available geological datasets,and with the understanding of how to practicallyapply these to geothermal exploration incombination with the tools to perform 3D thermalmodeling, the assessment of Hot Rock315

Australian Geothermal Energy Conference 2009geothermal play assessments will highlightAustralia as an attractive candidate forgeothermal investment.ReferencesBarnicoat A.C. 2008. The mineral systemsapproach of the pmd*CRC. Geoscience AustraliaRecord 2008/09, 1-6.Budd, A.R., Wyborn, L.A.I. & Bastrakova, I.V.2001. The metallogenic potential of AustralianProterozoic granites. Geoscience AustraliaRecord 2001/12, pp 154 + 2 CD-ROMs.Cassidy, K.F., Champion, D.C., McNaughton,N.J., Fletcher, I.R., Whitaker, A.J., Bastrakova,I.V. and Budd, A.R. 2002. Characterisation andmetallogenic significance of Archaean granitoidsof the Yilgarn Craton. AMIRA ProjectP482/Meriwa Project M281. Minerals and EnergyResearch Institute of Western Australia Report222.Chappell, B.W., White, A.J.R., Williams, I.S.,Wyborn, D. & Wyborn, L.A.I. 2000. Lachlan FoldBelt granites revisited: high- and low-temperaturegranites and their implications. Australian Journalof Earth Sciences, 47/1, 123-138.Cull, J.P. 1982. An appraisal of Australian heatflow data. Bureau of Mineral Resources Journal ofAustralian Geology and Geophysics, 7, 11-21.Cull, J.P. 1991. Heat flow and regionalgeophysics in Australia. In: Cermáck, V. andRybach, L. (eds.) Terrestrial Heat Flow and theLithosphere Structure, Springer-Verlag, Berlin,486-500.Hillis, R.R. and Reynolds, S.D. 2000. TheAustralian Stress Map. Journal of the GeologicalSociety (London), 157, 915-921McLaren, S., Sandiford, M., Hand, M., Neumann,N., Wyborn, L. and Bastrakova, I. 2003. The hotsouthern continent: heat flow and heat productionin Australian Proterozoic terranes. In: Hillis, R.R.and Muller, D. (eds.) Evolution and Dynamics ofthe Australian Plate. Geological Society ofAustralia Special Publication 22, 151-161.McLaren, S., Sandiford, M., Powell, R., Neumann,N. and Woodhead, J. 2006. Paleozoic intraplatecrustal anatexis in the Mount Painter Province,South Australia: timing, thermal budgets and therole of crustal heat production. Journal ofPetrology, 47/12, 2281-2302.Minty, B.R.S., Franklin, R., Milligan, P.R.,Richardson, L.M. and Wilford, J. 2008.Radiometric Map of Australia (First Edition), scale1:15 000 000, Geoscience Australia, Canberra.Neumann, N., Sandiford, M. and Foden, J. 2000.Regional geochemistry and continental heat flow:implications for the origin of the South Australiaheat flow anomaly. Earth and Planetary ScienceLetters, 183, 107-120.Roy, R.F., Blackwell, D.D. and Birch, F. 1968.Heat generation of plutonic rocks and continentalheat flow provinces. Earth and Planetary ScienceLetters, 5, 1-12.Rybach, L. 1988 Determination of heat productionrate, in: Haenel, R., Rybach, L. and Stegena, L.(eds.) Handbook of Terrestrial Heat-Flow DensityDetermination, Kluwer Academic Publishers, 125-142.Sandiford, M., Hand, M. and McLaren, S. 2001.Tectonic feedback, intraplate Orogeny and thegeochemical structure of the crust: a centralAustralian perspective. In: Miller, J.A.,Holdsworth, R.E., Buick, I. and Hand, M. (eds.)Continental Reactivation and Reworking.Geological Society, London, Special Publication184, 195-218.Sass, J.H. and Lachenbruch, A.H. 1979. Thethermal regime of the Australian continental crust.In: McElhinny, M.W. (ed.) The Earth – its Origin,Stucture and Evolution. Academic Press, NewYork, 301-352.416

Australian Geothermal Energy Conference 2009What target to drill? Geothermal Pre-Drill Play Evaluation (PDPE):Understanding the nexus between project risk and valueGareth T. Cooper * , Graeme R. Beardsmore and Luke MortimerHot Dry Rocks Pty Ltd, PO Box 251, South Yarra, VIC, 3141.* Corresponding author: Gareth.Cooper@hotdryrocks.comGeothermal exploration and development inAustralia is rapidly evolving and many companieswill soon be at a critical juncture of deciding whichtargets to drill and likely well locations. Althoughthe global petroleum sector has evolved adetailed system of prospect evaluation andrisking, the same level of discipline has not yetbeen formalised in the geothermal sector, whereplay evaluation decisions are largely focused oncost, rather than value and risk.Geothermal systems in Australia can becharacterised by four aspects of geological risk(P g ) - heat flow, thermal resistance, reservoir andwater. These risks can be condensed, on furthermodelling, to temperature risk (P t ) and flow raterisk (P w ). When combined with perceived drilling,engineering and other risks (P e ), these factorsform the basis of a simple risk-based evaluationsystem that can be applied to geothermal playsanywhere in the world.Combining cash flow considerations allows for theestimation of Net Present Value (NPV) for eachplay. The product of risk and NPV (the ExpectedMonetary Value, EMV) provides a more robustand considered assessment of the relative ‘riskedvalue’of a geothermal play.Keywords: Drilling, Levelised Cost, Risk, NPV,EMVIntroductionMany geothermal energy explorers in Australiaare rapidly approaching a phase of the explorationcycle where an informed decision needs to bemade regarding the siting of either a deep ‘proofof-concept’development well, or a moderatedepthexploratory well. In most cases multipleplays will be available within a single tenement orgroup of tenements and explorers must make acritical decision between them, which may havewide-reaching impact.The prevailing decision making process within thegeothermal sector is to make relative empiricalassessments of sites based on known geology(but usually biased by perceptions of temperaturealone) and then to further constrain site-selectionbased on cost, usually expressed in theimmediate term as drilling cost, and in the longtermas the project Levelised Cost of Electricity(LCOE). This cost-based approach has somesignificant flaws, which may be misleading at thebest.The use of a cost-based approach (such asLCOE) alone for site evaluation encompassesneither project risk nor revenue and can thereforelead to erroneous perceptions of relative value -and misguided decisions on drill site location.In contrast the petroleum sector has evolved amature and formalised system of projectevaluation, which encompasses the inherentgeological and commercial risks of a prospect.The assessed value of the prospect (eg. Magoonand Dow, 1994; Otis and Schneidermann, 1997)is usually quantified as the Net Present Value(NPV). The combination of risk and value is theExpected Monetary Value (EMV) of the project,and this risked-value approach more accuratelydefines the relative worth of projects.This study describes a risk-based approach toassessing the value of a geothermal project in theAustralian context, synonymous with theapproach used by the petroleum sector. Thestudy demonstrates how project NPV can becombined with risk via a simple decision tree, toascertain the EMV of a geothermal project.The dilemmaA geothermal explorer (hypothetical) has a seriesof potential ‘plays’ across GEL7000 and mustmake a decision to drill one play in the next 6months. Each target has slightly differentcharacteristics, pros and cons. Two targets (A andB) are schematically shown in Figure 1.Figure 1: Schematic section showing two hypotheticalgeothermal plays. Play A is a HSA play targeting 160°C at 3km depth and Play B is an EGS play targeting 185°C at 3.5km depth.Target A is a HSA play with a target sandstoneaquifer at 3 km depth. The modelled conductiveheat flow in the vicinity of A is 85 mW/m 2 , giving areservoir target temperature of 160°C. Target B isan EGS play with a target granite reservoir at 3.5km depth. The modelled conductive heat flow inthe vicinity of B is 110 mW/m 2 , giving a reservoirtarget temperature of 185°C. Both plays are about117

Australian Geothermal Energy Conference 2009the same distance from the national electricity gridand have similar market potential. The explorationcompany would like to establish a 10 MWe binarypower plant, and although initially attracted toTarget B due its high surface heat flow andpotentially high reservoir temperature, it is nowuncertain about the relative value of Target Bcompared to the shallower Target A.Which target offers the best value?Geothermal systems risk and theexploration and development cycleAustralia is unique amongst the world ofgeothermal exploration and development in that itis mainly driven by capital investment via publicshare issues. Costs and timing are, therefore,strongly influenced by the capital-raising cycle.Most Australian geothermal exploration activitiescan be summarized in a five-year cycle (Figure 2),although longer periods may be expected formore complex projects.7. GenerationphaseYear 56. Production& injectiondrill phaseYear 45. Fracture &/orreservoirmodelling phaseAustralianGeothermalExploration Cycle1. Study &establishmentphaseYear 1Year 2Year 33. Shallowdrill phase4. Mod-deep drill phase2. IPO phaseFigure 2: The Australian Geothermal Exploration Cycleshowing the progress of activities typical in a five-yearexploration cycle leading to the establishment of a small‘proof-of-concept’ plant by the end of year 5 (idealised).By the time most companies reach the moderatedepthdrilling phase (Phase 4) in about year 3 ofthe cycle, they need to have some form ofanalysis of the value of their plays by which theycan make a decision about drilling location, targettype and target depth. Anecdotal evidencesuggests that, to-date, much of this decisionprocess is empirical, ad-hoc, or (at best) lacksdocumented systematics.Whilst petroleum and geothermal systems have anumber of differences, there is no reason why thegeothermal sector cannot benefit from a riskbasedapproach as used in the petroleum sector.In the case of the petroleum system, totalgeological risk (P g ) is defined by:P g = P ch x P s x P r x P cl (Eq 1)The four aspects of petroleum system risk areshown in Table 1., along with suggestedequivalent risk categories for geothermal.Table-1 Comparison of geological risk categoriesPetroleum System Geothermal SystemCharge (Pch) Heat flow (mW/m 2 )Seal (Ps)Thermal resistance (m 2 K/W)Reservoir (Pr)ReservoirClosure (Pcl)WaterBy assigning a probability value (P) to each of therisk categories in Equation 1, petroleumcompanies derive a relative, but neverthelessuseful, risk ranking for their prospects.Conductive geothermal systems in Australia canbe assessed against four discrete aspects ofgeological risk (Cooper and Beardsmore, 2008).In the early phases of the exploration cycle,companies should undertake a comprehensiveGeothermal Systems Assessment (GSA) toidentify the key risks in their plays and the relativedegree of these risks.The key geological risks can be summarised asfollows:Heat flow: Probability that heat flowmeasurements or assumptions reliablycharacterise the play under investigation.Estimated from geographic coverage and‘uncertainty’ of heat flow estimates.Thermal resistance: Probability that thermalresistance and heat transfer mechanism beneaththe level of well intersects are as assumed (purelyconductive, convective component, advectivecomponent).Reservoir: Probability that reservoir propertiesand volumetric extent are as assumed. Estimatedfrom geographic coverage, data type andreservoir type.Water: Probability that water supply or chemistrymay adversely impact on the project.The above risk variables are defined bymeasurable factors with intrinsic distributions. Forexample, in petroleum exploration reservoir risk(P r ) incorporates the distributions of porosity,permeability, area and net:gross thickness data.These factors are typically combined in Monte-Carlo simulations to define the overall probabilitydistribution of reservoir risk. This process providesa disciplined and uniform approach to helpmitigate exploration/drilling risks (Capen, 1992;Rose, 1992).Some aspects of risk in the geothermal systemshare varying degrees of co-dependence. Forexample, heat flow and thermal resistance riskshare a common link via rock thermal conductivitymeasurements. It is perhaps more useful tocombine geological variables of the geothermalsystem into just two simple risk categories which218

Australian Geothermal Energy Conference 2009are first derived from the four factors in Table 1.These two risk categories are:P t – target temperature risk, and,P w – flow rate riskPre-Drill Play Evaluation (PDPE) – asimple geothermal risk toolThe concepts outlined in the following paragraphsdefine a process that may be termed ageothermal Pre-Drill Play Evaluation (PDPE).Different geothermal plays will have differentExpected Monetary Value (EMV). In simple terms,the net EMV is a proxy for ‘risked value’ and canbe used to rank a series of geothermal plays todetermine the lowest-risk, highest-value drillinglocation. The work path for a PDPE isschematically shown in Figure 3.A Geothermal Systems Assessment (GSA)should be the first significant activity for anexploration company with new ground, so that thefour key geological risks (P g ) can be defined andquantified (Cooper and Beardsmore, 2008).These four risks can be subsequently refined intotemperature risk (P t ) and flow risk (P w ), which arequantitatively estimated through heat flow andhydro-geomechanical modelling, respectively.In a conductive geothermal setting, theprobabilistic distribution of reservoir temperaturesis a function of the standard deviation of surfaceheat flow and the uncertainties of rock thermalconductivities. A 3D earth model with estimatedsurface heat flow of 90±10 mW/m 2 may have anormally distributed probability curve with a meanheat flow of 90 mW/m 2 and standard deviation ()10 mW/m2. Thus the ‘P90’ value (ie ‘true’ heatflow is 90% likely to exceed this value) is 2 lessthan the mean, or 70 mW/m 2 , while ‘P10’ wouldbe 110 mW/m 2 . In some cases, the analyst maybelieve that heat flow risk is not normallydistributed, and may define P90 and P10according to a different distribution, perhapsbased on a log-probability plot of regional heatflow data.The risk that heat flow is not purely conductive isaddressed through hydraulic reservoir modelling,by assessing the thermal stability of conductivemodels when populated with permeability data. Athreshold, or ‘critical’, permeability is identified forkey layers, beyond which spontaneous convectionmight occur. The analyst is then in a position toquantify the risk that the critical permeability maybe exceeded. This is the risk that temperaturemay be overestimated.Likewise, the outcomes of hydraulic reservoirmodelling, using tools such as TOUGH2 andFEFLOW finite element code, determines thelikely distribution of well flow rates for a givendistribution of porosity, permeability, pressure,fluid viscosity, well and pump design variables.Combined, the temperature and flow rateprobability distributions allow a direct assessmentof probable well power output for differentgeothermal plays, well patterns, designparameters, or other variables. The outcome is aprobability based picture of well output.Geological risk is directly apparent from themedian value and the shape and width of theprobability distribution curve. The well productivity(typically time-variable) feeds directly intoeconomic models for the expected revenuestream, which are combined with cost estimatesto derive the Net Present Value (NPV) of a play.The NPV, however, does not address nongeologicalrisks. The most significant nongeologicalrisk in a geothermal program isengineering risk (P e ). This is largely the explorer’sFigure 3: A simple flow chart for a geothermal Pre-Drill Play Evaluation (PDPE). Quantifiable geological risks are incorporatedwith the NPV. The product of all risks and NPV results in the net EMV, which can be used to decide target priority.319

Australian Geothermal Energy Conference 2009perception of the chance (probability) ofexperiencing trouble-free drilling. This may beinfluenced by play type (EGS or HSA), drillingdepth, lithology, temperature, logging capabilitiesetc. The product of geological risk (P g ) profile andthe engineering risk (P e ) largely defines thegeothermal exploration and development risk.Other risks (eg perceived sovereign risk) can alsobe addressed at this stage. The product of NPVand risks is the net EMV of a play.Incorporating project value into thedecision making processThe Levelised Cost of Electricity (LCOE) is astandard measure of the cost of energy over aproject life and is used to compare the relativecosts of various forms of energy (eg. coal, solar,wind, geothermal). It is defined as the sum of alldiscounted project costs over a stated lifetimedivided by the sum of discounted net electricitygeneration. It has been used in the geothermalsector as a project evaluation tool, but LCOEalone does not incorporate information about therelative risks involved in a project.ExampleIn the hypothetical example discussed earlier(Figure 1), the exploration company has assessedthe LCOE for plays A and B.Play A has a shallower target reservoir and lowerdrilling costs than Play B. However, the lowerreservoir temperature in Play A means that netwell output is expected to be about 0.7 MWe lessper well, compared to Play B. Consequently bothprojects have a similar LCOE of about $115/MWhover a 20 year project life, discounted at 10%(Table 2).Table-2 Comparison of parameters for hypothetical plays Aand BParameter Play A Play BPlay type HSA EGSReservoir temp. (P50) 160°C 185°CModelled flow (P50) 100 l/s 90 l/sExpected net MWe/well 4.6 5.3LCOE ($MWh) $115 $115NPV ($ million) 20 years $20 $30Geological Risk (Pg) 0.53 0.44Engineering Risk (Pe) 0.80 0.50Net EMV ($ million) $8.4 $6.6The LCOE, however, only tells the company the‘break even’ price for the electricity produced. Itdoes not reveal the relative value of the two plays.After modelling expected flow rates, thermal drawdown and pressure draw down over 20 yearsusing TOUGH2 and FEFLOW, the companyfound that the higher expected net MWeproduction for Play B resulted in a NPV of $30million, compared to $20 million for Play A.Consequently, based on NPV alone, Play Bappears to offer better lifetime value (Table 2).In assessing the relative geological andengineering risks (including reservoir engineering)of each play, however, the opinion of theexploration company is that Play B (EGS) has amuch lower probability of success compared tothe more conventional Play A.The net EMV for the ‘success case’ for each playis the product of NPV, P g and P e , so Play A has amore attractive net EMV than Play B. Althoughboth plays have similar costs (LCOE) and Play Bhas an attractive NPV, the perceived risks for PlayB are much higher, such that the ‘risked-value’ ispoorer. Consequently, in this instance, thecompany decides that Play A provides betterlong-term value.DiscussionA Pre-Drill Play Evaluation (PDPE) incorporatesall available information about a geothermal play,its geological and engineering risks, its probablecosts and revenue stream. Geological uncertaintyis minimised through an early and thoroughGeothermal Systems Assessment (GSA). TheGSA process identifies the geological variables(heat flow, thermal resistance, reservoir andwater) with the greatest uncertainty (risk), whichallows targeted exploration to reduce those risks.Other, non-geological, risks are, to a large extent,subjective and may be perceived at differentlevels by different people. Parameters such as‘drilling risk’, ‘sovereign risk’ etc should bequantified through a process of discussion andcareful consideration to incorporate a range ofviews.There will very likely be widely different opinionsabout drilling risk for EGS, convection risk inpermeable sediments, sovereign risk indeveloping nations, and other. It may be thatprobability distributions are derived for each ofthese risks, rather than simple ‘median’ values.EMV may then, also, be derived as a distributionwith P10, P50 and P90 values. This is a validalternative to the process outlined above.If undertaken in a methodical and inclusivemanner, a PDPE will naturally reach a consensusview for the exploration (or investment) companyabout the relative ‘risked-value’ of potentially verydisparate geothermal plays.ConclusionsThe methodical application of a risk-basedassessment system, similar to that used by thepetroleum sector, will assist geothermalexploration and investment companies toappraise the relative value of different geothermal420

Australian Geothermal Energy Conference 2009plays. When risks are combined with cash flowprojections, the net EMV for each play can beranked to produce an inventory of drilling orinvestment options. This approach is distinctlydifferent from a cost-based approach.The use of a ‘risked-value’ approach togeothermal exploration and investment decisionmakingprovides internal company discipline fordrilling decisions and some surety for investorswho are familiar with existing and similar systemsin the petroleum sector.ReferencesCapen, E., 1992. Dealing with explorationuncertainties. In: Steinmetz, R., (Ed), TheBusiness of Petroleum Exploration, Treatise ofPetroleum Geology, Handbook of PetroleumGeology, American Association of PetroleumGeologists, Tulsa, Oklahoma, 29-62.Cooper, G.T. and Beardsmore, G.R.: Geothermalsystems assessment: understanding risks ingeothermal exploration in Australia. Proceedingsof PESA Eastern Australasian Basins SymposiumIII, Sydney 14–17 September, (2008), 411–420.Magoon, L.B. and Dow, W.G., 1994. ThePetroleum System. In: Magoon, L.B. and Dow,W.G. (Eds), The Petroleum System – from sourcetop trap, American Association of PetroleumGeologists, Memoir 60, 3-24.Otis, R.M. and Schneidermann, N., 1997. AProcess for evaluating exploration prospects.American Association of Petroleum Geologists,Bulletin 81, 1087-1108.Rose, P.R., 1992. Chance of success and its usein petroleum exploration. In: Steinmetz, R., (Ed),The Business of Petroleum Exploration, Treatiseof Petroleum Geology, Handbook of PetroleumGeology, American Association of PetroleumGeologists, Tulsa, Oklahoma, 71-86.521

Australian Geothermal Energy Conference 2009The 3D Basement and Thermal Structure of the Gunnedah BasinCara R. Danis * and Craig O’NeillGemoc Macquarie University, Sydney, NSW, Australia* Corresponding author: cdanis@els.mq.edu.auWith the development of geothermal resources byin the Cooper Basin, South Australia, interest insedimentary basins for potential resources hasintensified. In Eastern Australia sedimentarybasins not only host large deposits of coal, theyare closer to large population centres withestablished infrastructure. The 3D architectureand geothermal potential of such sedimentarybasins has so far not been assessed in greatdetail, however the assessment of temperature at5km and heat flow in these Basin systems byBudd (2007) indicates some potential in theSydney-Gunnedah-Bowen Basin System. Thispaper focuses on the Gunnedah Basin and aimsto better constrain the 3D structure and thermalevolution of the Basin and presents a 3D depth tobasement model, derived from regional gravitymodelling, density measurements, borehole andseismic information, and basement temperaturesfrom thermal modelling.Keywords: Gunnedah Basin, 3D depth tobasement, thermal modelling.Geological BackgroundThe Gunnedah Basin, part of the Sydney-Gunnedah-Bowen Basin (SGBB), began as anextensional rift basin in the Late Carboniferous toEarly Permian towards the end of the Hunter-Bowen Super Cycle (Glen, 2005). The extensionaltectonic regime initiated half-graben likestructures and produced large quantities of riftvolcanics (Tadroz, 1993) which overly thebasement rocks of the Lachlan Fold Belt. Basinfill, including coal bearing deposits, localised inrapidly subsiding troughs separated by highlandsand ridges consisting of silicic and mafic volcanicswith the northerly orientated Boggabri Ridgeeffectively acting as a principle sediment sourceand dviding the Gunnedah Basin into two subbasins, Maules Creek and Mullaley. At the end ofthe Hunter-Bowen Super Cycle in the LatePermian, the SGBB developed into a forelandbasin followed by a period of convergence, upliftand erosion. Final filling of the Gunnedah Basin(235 to 230Ma) was dominated by detritus shedfrom the New England Orogen (Glen, 2005).Vitrinite reflectance data suggest the removal ofup to 2km of Triassic and Permian sedimentsbetween 227Ma and 235Ma. Compressionalmovement of the Hunter-Mooki Fault resulted inthe development of a number of high reliefanticline (Glen, 2005). During the Jurassic-Cretaceous the epicontinental Surat Basindeveloped over the northern and western parts ofthe Gunnedah Basin.The geology, stratigraphy and structural historyare well documented by Tadroz (1993) and drillingin the basin has reached top of basal rift volcanicsin many areas and defines the stratigraphythickness over an extensive area. This providesgood geological controls for gravity modelling ofthe Gunnedah Basin, with the only main variablethe top of the Lachlan Fold Belt.MethodologyGravity modelling of the Gunnedah Basin usedeight profiles derived from the Gravity AnomalyGrid of the Australian Region 2008 (Fig. 1),available for download from Geoscience Australia.These profiles were modelled using the interactivepotential-field modelling package ModelVision Prov8.0 supplied by Pitney Bowes ®. Model profileswere constructed similarly to Guo et al., (2007) fordensity values, body extent and total model depth.The upper 5km of the models are constrained byover 60 boreholes for key stratigraphic layerssuch as the base of Jurassic, top of rift volcanicsand were available top of the Lachlan Fold Belt.Increasing density with depth is accounted forwith a change in density for sediments >300mdeep, as determined by the measure boreholedensities of Guo et al. 2007 and densitymeasurement of 185 core samples drilled fromhand samples of representative key geologicalunits using:D = [(A x )/(A - B)] +CLwhere D is density (g/cm 3 ), A is dry weight (g), Bis wet weight (g), is liquid density and C is theLair buoyancy constant of 0.0012. All depths tostratigraphy derived from the gravity modellingwere converted to metres Australian HeightDatum (mAHD) and gridded in Surfer v8.0supplied by Golden Software ® producingsurfaces for the 3D model at a 0.05 degreeinterval.Thermal models for the basin were developedusing an existing, extensively benchmarkedresearch finite element code Ellipsis (Moresi etal., 2003). Distinct layers from the gravity modelswere imported as different materials into the code,which solved the time-dependent energy equationwith constant temperature top and bottomboundary conditions. The thermal properties foreach material layer is outlined in Table 1, and areaggregates of measurements on each unit/rocktype. The main free parameter in these modelswas the bottom temperature condition at 5km,122

Australian Geothermal Energy Conference 2009which was estimated from the Nationaltemperature at 5km map (eg. Budd et al. 2007) tobe ~180 o C, and fine tuned to match existingtemperature data for the Gunnedah Basin.Table 1. Thermal PropertiesRockTypeDensity(kg/m 3 )Conductivity(W/m-K)HeatProduction(µW/m 3 )Basement 2700 3 2Mafics 2900 3 0.5Sediments 2500 2 1.25Coal Measures 1500 0.3 1.25From the gravity modelling a 2.5-3km deepchannel runs through the central part of thebasement of the Gunnedah Basin. The overlyingbasal rift volcanics fill the basement channel andin some areas reach a thickness of up to 3kmthick. The Rocky Glen Ridge forms a cleanstructural high to control the western extent of therift volcanics whilst the Hunter-Mooki Faulttruncates them at depth in the east. To the northFigure 1: Gravity anomaly map for the Gunnedah Basin(outlined in black) with NE relief using a 0.01 degree gridspacing in Surfer ®. Gravity profile locations shown by redlines, extension of profiles black dashed lines and boreholesgrey circles. Grid data available for download fromGeoscience Australia.Gravity ModellingThe geometry of the Gunnedah Basin duringmodelling was initially based on the work of Guoet al. (2007), however borehole and seismicconstraints required a review of this. The finalmodel geometry derived for the profiles correlateswell with the recently published work of Krassayet al. (2009). Presented in Figure 2 are the sixeast-west profiles. The densities of the keystructural units are Jurassic 2.31t/m 3 , TertiaryVolcanics 2.88t/m 3 , Gunnedah Sediments 300m 2.54t/m 3 , Granite 2.59t/m 3 ,Lachlan Fold Belt 2.60t/m 3 and 2.70t/m 3 and basalrift volcanics 2.95t/m 3 .Figure 2: 2.5D E-W Gravity model profiles through theGunnedah Basin. Model depth shown is 5km, profilesstacked to view NE.and south the basal volcanics appear continuousinto the Bowen and Sydney Basins.3D Depth to Basement ModelThe basement of the Gunnedah Basin is definedhere as the metamorphic rocks of the LachlanFold Belt, which includes metasediments, granitesand volcanics. Using borehole information, andthe gravity model profiles a 3D basementstructure of the Gunnedah Basin is interpolated inFigure 3. In addition to interpolating the top of theLachlan Fold belt the Permian Coal Measuresinterval is also interpolated from boreholeinformation. As the coal measures act as athermal blanket in basin geometry it is necessaryto determine their extent and thickness for thethermal modelling of temperature at depth.223

Australian Geothermal Energy Conference 2009Figure 3: 3D basement structure of the Gunnedah Basin,showing the top of the Lachlan Fold Belt, Top of Volcanics,top and base of Permian coal interval, base of Jurassic andsurface elevation from 90m SRTM satellite data.Thermal ModellingThermal models were constructed for six lines(Gravity Lines 1-6), using the thermal propertieslisted in Table 1, which are derived from publishedvalues for each lithology or composite lithology,and the boundary conditions listed in themethodology. The heat production in thebasement is taken from representative Lachlanfold belt granites immediately adjacent to theGunnedah Basin (OZCHEM database). The initialthermal profile is linear between the top andbottom temperatures, and is allowed to evolve inresponse to the conductivity and heat productionstructure of the crustal units until equilibrium isreached. We use the finite element code Ellipsis(Moresi et al., 2003) to solve the non-steady stateheat equation with internal heat sources in twodimensions.The model’s boundary conditions were refinedusing limited available temperature data from theGunnedah Basin. The two data points within theGunnedah region from the only availablecontinent-scale compilation (Cull, 1982) suggestheat flows in the range 50-80mW/m 2 areappropriate for the Gunnedah Basin - within therange of our models (~70 +/- 10 mW/m 2 ). Manypublicly available down-hole temperaturemeasurements were made in non-equilibriumconditions shortly after drilling, and so are oflimited value in constraining the steady-statethermal structure of the crust. Our recentmeasurements in the southern Gunnedah areasuggest temperatures of around 60 o C at 1km, or ageothermal gradient of around 0.048 o C/m.Figure 4a illustrates the temperature field andmaterial configurations of two of the thermalmodels, from Lines 2 and 6. Surface heat flux isshown at top of Figure 4a. The critical differencebetween the two Lines is the thickness of the coalsequences in Line 6. These economic coalmeasures, whilst interbedded with thesedimentary sequence, have, on bulk, asignificantly lower thermal conductivity than thesurrounding basins sediments. This results in ablanketing effect and a thermal refraction of heatflow around the insulating coal measures. As aresult, despite the highest basement temperaturesoccurring beneath the thick coal and maficvolcanic units, the highest surface heat flow andnear surface temperatures are exhibited aroundthe periphery of the coal. This demonstrates thedanger of extrapolating near-surface heat flowmeasurements to depth without considering 2 and3-D thermal effects.We have also stacked and gridded the 2D crosssectionsto obtain a 2.5D model of the basementtemperatures across the entire Gunnedah basin,shown in Figure 4b. The temperatures at the topof the basement were obtained for each individualprofile, this data was then gridded, and drapedacross our model for the basement architecture.The highest basement temperatures occur in thedeeper portions of the basin, particularly underthe thickest coal and mafic units. The basementtemperatures range from ~105-165 o C, with thehighest temperatures occurring at the northernand southernmost extents of the basin. Highertemperatures again extend deeper within thecrystalline basement.The model presented here considers thermalconduction only, it does not take into accountadvective effects, or the effects of varying surfacetemperature conditions. It does include variablenear surface topography, though the effects ofthis are negligible here given the relief and extentof the Gunnedah Basin. The most critical part ofthis modelling is establishing a lowermost thermalboundary condition for the model. This boundarycondition can, potentially, take the form of atemperature or heat flux constraint. In either casethe uncertainty and variability of this parameter324

Australian Geothermal Energy Conference 2009are very large. Here we have combined availabledeep borehole temperature constraints and heatflux measurements, including some of our ownmeasurements, to converge on a lower boundarycondition (ie. T-180 o C at 5km) which is mostconsistent with the regional thermal constraints.This value, and perhaps the model, may berefined as improved steady-state deep boreholetemperature measurements of this region becomeavailable.BFigure 4: a) 2D cross sections of the modelled temperature fieldof Lines 2 and 6. Different colours represent different materials,which from top to bottom are basin sediments, interbedded coalmeasures, mafic volcanics, and Lachlan fold belt basement.Colour gradients represent temperatures. Surface heat flux isalso plotted.b) Temperatures at the top of the Lachlan Fold Belt basement,interpolated from 2D profiles, draped over the basementarchitecture. Basement contour interval is 200m AHD.ASummary and DiscussionThe 3D structure of the Gunnedah Basin ischaracteristic of a typical rift basin. This providesa deep central channel in the basin where up to3km of sediments and volcanics haveaccumulated over basement with temperatures of105-165°C.Our modelling demonstrates the importance of2/3D effects - particularly the distribution of lowconductivity sediment cover - in determiningbasement temperatures. Temperatures may beelevated beneath blanketing sediments, but thismay not be evident in shallow boreholetemperature measurements. Instead heat may berefracted around such insulators, giving heat fluxanomalies at the edge of thick low-conductivitysediment cover. This highlights a potentialcomplication in extrapolating shallower boreholetemperatures to depth as per the Austherm07database. While a good starting point for regionaltemperatures at depth, it is essential to comparemodelled temperature results, using accuratebasin geometries, with regional borehole data toascertain the validity of the model’s boundaryconditions, and the reproducibility of thesubsurface temperature field.The potential for geothermal resources in theGunnedah Basin based on this initial work isstrongest in the northern and southern most partsof the basin where the coal/sediment blanketprovides thermal insulation. In these areastemperatures deeper within crystalline basementare expected to be hotter.ReferencesBudd, A.R., 2007, Australian radiogenic graniteand sedimentary basin geothermal hot rockpotential map (preliminary edition), 1:5 000 000scale. Geoscience Australia, Canberra.Cull, J.P., 1982, An appraisal of Australian heatflow data. BMR Journal of Australian Geology &Geophysics v.7, p. 11-21.Glen, R.A., 2005, The Tasmanides of easternAustralia in Vaughan, A.P.M., Leat, P.T., andPankhurst, R.J., ed., Terrane Processes at theMargins of Gondwana: Geological Society,London, Special Publications 246, p. 23-96.Guo, B., Lackie, M.A., and Flood, R.H., 2007,Upper crustal structure of the Tamworth Belt, NewSouth Wales: constraints from new gravity data.Australian Journal of Earth Sciences v.54, p.1073-1087.Krassay, A.A., Korsch, R.J., and Drummond, B.J.,2009, Meandarra Gravity Ridge: symmetryelements of the gravity anomaly and itsrelationship to the Bowen-Gunnedah-Sydneybasin System. Australian Journal of EarthSciences v.56, p. 355-379.425

Australian Geothermal Energy Conference 2009Moresi, L., Dufour, F., Muhlhaus, H.-B., 2003, ALangrangian integration point finite elementmethod for large deformation modeling ofviscoelastic geomaterials. J. Comput. Phys.v.184, p. 476–497.Tadroz, N.Z., 1993, The Gunnedah Basin, NewSouth Wales: Geological Survey of New SouthWales, Memoir Geology 12, 649.526

Australian Geothermal Energy Conference 2009Understanding Risks and Uncertainties in Geothermal Modelling:Constraining Thermal Conductivity ModelsDavey J. E., Preston J. C. & Keetley J. T.3D-GEO, level 5, 114 Flinders Street, Melbourne, Victoria 3000, (03) 96398028Prediction of the rate at which temperatureincreases with depth in a sediment pile is animportant tool in the evaluation of manygeothermal prospects. Such prediction istypically carried out by geothermal modellingbased on assumptions that can be made withregard to the interplay of heat-flow andlithological conductivity, from which estimates ofgeothermal gradient, and therefore absolutetemperature, can be derived. Approaches tosuch modelling work may differ widely, with acorrespondingly wide range of outcomes,bringing into question the reliability ofgeothermal modelling as a predictive tool.This paper focuses on addressing some of theuncertainties and risks associated with thermalmodelling.Keywords: Geothermal modelling, conductivity,heat-flow.Thermal ModellingThe thermal conductivity of a rock directlydetermines the efficiency (or otherwise) withwhich heat is propagated through it. Thisconductivity is lithology-dependent, and variesfrom layer to layer in a sediment pile accordingto the nature of the various lithologies presentand their degree of compaction. The geothermalgradient within any single lithological unit resultsfrom the interplay of heat-flow with the thermalconductivity of that unit, broadly expressed thus:Q/K = GwhereQ = heatflow (mW/m 2 )k = conductivity (cals/cm/sec)G = geothermal gradient ( o C/km)The temperature-depth profile at a given locationin a sedimentary basin can therefore be thoughtof as the vertical summing of the geothermalgradients established within the individual layerswithin the sediment pile. Such a profile is, as weshall see, rarely linear.Two primary methods are used for modellinggeothermal systems based on the aboverelationship between heat-flow, conductivity andtemperature:In the absence of existing well data, shallow(200-500m) wells are drilled, down-holetemperatures recorded, and conductivitiesmeasured in the laboratory from down-holesamples. The depths from which thetemperatures and samples were taken, andthe temperatures and conductivitiesappropriate to those depths, provide valuesfor k and G in the equation described above,permitting a calculation of a notional value ofheat-flow (Q) that can then be applied to thebase of the sediment pile over the localarea. The geothermal gradient that isobtained in the shallow section is typicallyextrapolated, or projected, to depth in thesubsurface in order to provide estimates ofdrilling depths that would be required toreach commercially viable temperatures(typically 150 o C). This is referred to hereinas the "projected approach"; and Where down-hole temperature andlithostratigraphic data are available fromadjacent wells, such data can be input to acommercially available burial-historymodelling software package, of the kindroutinely used in petroleum exploration forthe prediction of the degree and timing ofsource rock maturation, reservoirtemperatures, and other mitigatinggeothermal properties. Such packagestypically contain default thermalconductivities for end-member lithologiesthat can be mathematically averaged toreflect lithological mixtures as necessary,and thus do not rely on the laboratorymeasurement of conductivities on down-holesamples. Since such packages also takeinto account burial-compaction effects (inparticular, increase in conductivity withincreasing compaction), permitting thecalculation of a temperature-depth profilefrom which predictions of depths to keyisotherms can be made. This is referred toherein as the "calculated approach".While both methods can be adapted to specificcases, both contain considerable uncertaintiesthat can affect the predicted temperatures.Projected versus Calculated ModelsThermal conductivity varies with rock type andproperties (such as porosity), the latter beinghighly dependent on depth of burial, chiefly as aresult of compaction. Assumptions concerningthermal conductivity measurements aretherefore very important in thermal modelling,especially since stratigraphy, and thereforeburial history (depth through time), show greatlateral variation. Therefore, thermal modelling isnecessarily location-specific, and generates atemperature-depth profile unique to the local127

Australian Geothermal Energy Conference 2009geology. However, the assumptions madeabout conductivity are very different according tothe two approaches outlined above.The projected approach uses input values ofconductivity (k) measured directly on samplesfrom shallow wells (200-500m), combined withmeasured temperatures and values of heat-flow(Q), to generate a geothermal gradient (G) in theshallow section that is then linearly extrapolatedto depth (2000-5000m).By contrast, the calculated approach takes, asits starting point, a stratigraphic sequence todepths of 2000-4000m, typically intersected bypetroleum exploration wells or interpreted fromseismic data tied to such wells. Thesesequences are entered into commerciallyavailable modelling software packages thatutilise default (published), lithology-specific inputconductivities that are made to vary withprogressive burial and resulting compaction. Avalue of heat-flow is then calculated in such away that, when it is applied to the lithologicalcolumn, the resulting depth-temperature profilematches the down-hole temperatures (Hornercorrectedfor circulation effects) measured in thewell at the time of drilling. This results in apredictive depth-temperature profile that is moreaccurately calibrated to the known temperatureconditions at depth. The heat-flow calculated atthe well location, by virtue of its constraint bymeasured temperature data, can then be usedin offset locations more reliably than if it werederived from shallow, relatively uncompactedsamples. Such modelling techniques are routinein the petroleum exploration industry.A comparison of the outcomes typical of thesetwo approaches was made on wells from thePerth Basin, Bass Basin and the Vulcan Subbasin.In the well from the Perth Basin (Figure 1), twodown-hole temperatures (Horner-corrected fordrilling circulation effects) were availabletogether with a comprehensive stratigraphy.These data were input to Genesis TM , acommercially available interactive thermalmodelling package used by 3D-GEO Pty Ltd.Heat-flow input to the base of the sediment pilewas varied until a temperature-depth profile (inblue) was obtained that was commensuratewith, and therefore calibrated to, the measureddown-hole temperatures.The two most important features of the predictedtemperature-depth curve are (a) its non-uniformslope as it responds to changes in lithologicalconductivity from one formation to the next, and(b) the general steepening of the slope(decrease in geothermal gradient) with depth asit responds to increasing lithological conductivitywith increasing compaction (porosity-reduction).The predicted depth-temperature profile (in blue)is compared in Figure 1 to that which mightresult from the "projected" approach (red dottedline), which may have been required had thewell, and the data available from it, not existed.According to this approach, a temperature-depthprofile derived at shallow levels is extrapolatedlinearly downwards. As Figure 1 shows, in theshallower part of the sequence (above 2500m),both curves approximately coincide, and matchthe shallower down-hole temperature. However,as you go deeper in the profile, the temperaturedepthprofile projected linearly from the shallowsection deviates significantly from the calculated(blue) curve. At the bottom of the hole, the blue(calculated) curve intersects the measureddown-hole temperature (approx 142 o C), whilethe projected curve indicates a temperature of160 o C, some 18 o C higher than that measured.Another result is that the depth to an economictarget of 150 o C varies by 540 m between thetwo models. Figure 1. Comparison between theprojected and calculated approach from thePerth Basin.The projected approach therefore has the veryobvious effect of being too optimistic in itsestimate of the drilling depths required to reachcommercially desirable temperatures. Acomparison of the two modelling approaches inthe Durroon Sub-Basin in southern Australia andthe Vulcan Sub-Basin in the Timor Sea show asimilar relationship (Figure 2). The calculatedcurve fits well with measured temperature,whereas the projected linear profile deviatessignificantly. Here, two linear temperatureprofiles are compared to the calculated trend,one based on 300 mssf (in red), the other from500 mssf (in purple). Both profiles deviatesignificantly from the calculated curve at depth,with up to 1.2 km difference between where thepredicted gradients intersect the target 150 o C.(Note that two corrected BHTs were availablefrom the well, the calculated curve beingcalibrated to the more reliable one based onother calibration data. The higher of the twotemperatures, which is considered to be overcorrected,coincidentally fits with the profileprojected from 500m).An example from the Vulcan Sub-Basin inoffshore NW Australia shows a similarcomparison with the 300-500 mssfextrapolations (Figure 3), with a similar outcome(significant overestimation of temperature by the"projected" approach).The calculated approach is only possible wheredeep well data are available, and, like allmodelling exercises, is prone to numeroussources of error in terms of its inputassumptions. However, it does at least takeaccount of the non-uniform nature oftemperature-depth profiles with depth. While, in228

Australian Geothermal Energy Conference 2009Figure 1. Comparison between the projected and calculated approach from the Perth Basin.defence of the projected approach, it might besaid that it is useful in areas in which no deepdrillingdata are available, it is clear from thecomparisons shown in Figures 1, 2 and 3 that itis almost inevitably prone to under-estimation ofthe drilling depths required to reachtemperatures of commercial significance.Otherwise put, if the wells shown in thesefigures had not existed, and the projectedapproach was applied to the problem ofpredicting depths to 150 o C, the results wouldhave been grossly misleading.329

Australian Geothermal Energy Conference 2009Figure 2. Comparison between the projected and calculated approach from the Durroon Sub-basin. Modelled approximately tobasement. Red temperature plot corresponds to Horner corrected temperature. Green temperature plot corresponds to anarbitrary 25% correction applied by the previous modelling attempts.ConclusionsFor the reasons outlined above, the calculatedapproach accounts for variations in conductivitywith both lithostratigraphy and depth (andtherefore compaction), and uses measureddown-hole temperatures to constrain andcalibrate the magnitude of heat-flow beingconducted through the sediment pile. Theresulting depth-temperature profile is thereforenecessarily more consistent with geothermalgradients observed basin-wide. By contrast, the"projected" approach may predict, depth fordepth, significantly higher temperaturescompared with the "calculated" approach, mainlybecause the conductivities acquired at shallowlevels are anomalously low, and are assumed tobe continuous with depth (unaffected bylithological variation or burial-compaction). The430

Australian Geothermal Energy Conference 2009Figure 3. Comparison between the projected and calculated approach from the Vulcan Sub-Basin. Profile modelled toapproximate basement.temperatures predicted at depth by linearextrapolation may therefore significantly higherthan those predicted by the "calculated" method,and as such are in danger of predicting theeconomic target (eg. 140 or 150o C) atoptimistically shallow levels, and ofoverestimating geothermal potential.While both methods have considerable risks anduncertainties associated with them, and whilemeasuring the conductivity in the projected531

Australian Geothermal Energy Conference 2009approach may seem more precise, it is likely tobe less accurate than the temperature estimatesobtained from the "calculated" approach.However, the "projected" technique may be bestsuited for areas where calibration data arelimited.ReferencesF. Ascencio, F. Samaniego and J. Rivera,Application of a spherical–radial heat transfermodel to calculate geothermal gradients frommeasurements in deep boreholes, Geothermics35 (2006), pp. 70–78Yuan Y. Zhu W., Mi L, Zhang G., Hu S. and HeL. 2008. "Uniform geothermal gradient” andheat flow in the Qiongdongnan and Pearl RiverMouth Basins of the South China Sea. Marine &Petroleum Geology, 26 (7) 1152-1162.632

Australian Geothermal Energy Conference 2009The Penola Project – Australia’s First Hot Sedimentary AquiferDevelopmentLambertus de Graaf*, Ron Palmer, Ian ReidPanax Geothermal Ltd, PO Box 2142, Milton, QLD 4064*Corresponding author: bdegraaf@panaxgeothermal.com.auPanax Geothermal Ltd (“Panax”) holds thegeothermal rights covering four Hot SedimentaryAquifers (HSA) within troughs or sub-basins in theOtway Basin in southeast South Australia,covering an area of more than 3,000 km 2 . TheLimestone Coast Geothermal Project is designedto demonstrate that conventional geothermalresources within Australia's hot sedimentarybasins can be used to generate large amounts ofcompetitively priced, zero-emission, base-loadpower. Due to an existing comprehensivedatabase acquired by the petroleum industry, theinitial development of its Limestone CoastGeothermal Project is focused on the PenolaTrough (GEL223).The first well, Salamander-1, is the first in a seriesof wells in the development of a 50 MWegeothermal power plant, which could become thefirst grid connected geothermal power plant inAustralia.A Pre-Feasibility study has also been completedto assess the total cost per MWh of powerproduced after taking into account all plant andpump requirements. This study found thatelectricity can be sustainably generated at a totalcost (capital and operating) of AUD$63 per MWh.The Penola Trough has been subjected tointensive oil and gas exploration, including 27deep petroleum wells with wireline logging andconventional core measurements of reservoirporosity and permeability. In addition, there are271 km 2 of 3D seismic and a significant amount of2D seismic data. These data are available as partof the Open File data base and studies haveshown that the over 1,000m thick CretaceousPretty Hill Formation (sandstones) of the PenolaTrough has the capacity to deliver geothermalwaters of >140˚C at high volumes, sufficient forthe operation of a commercial, mediumtemperature geothermal power plant. Thegenerating potential is large, as is evidenced by arecent independent Geothermal Resourceassessment, which has estimated a “MeasuredGeothermal Resource” of 11,000 PJ for thePenola Trough.IntroductionPanax Geothermal Ltd (“Panax”) holds eightGeothermal Exploration Licences (GELs), overfour Hot Sedimentary Aquifers (HSA) withintroughs or sub-basins in the Otway Basin insoutheast South Australia, covering an area ofmore than 3,000 km 2 (see figure 2). TheLimestone Coast Geothermal Project is designedto demonstrate that conventional geothermalresources contained within Australia'ssedimentary basins have the capacity to generatelarge amounts of competitively priced, zeroemission,base-load power. The initialdevelopment of its Limestone Coast GeothermalProject is focused on the Penola Trough(GEL223, see figure 2), as this trough has acomprehensive exploration database acquired bythe petroleum industry.The Penola Project is located in GeothermalExploration Licence (GEL) 223, approximately 40km north of Mount Gambier in South Australia.The Penola Trough is a sub-basin or trough in theon-shore Otway Basin area of south-easternSouth Australia. It is one of several sedimentarytroughs and represents an area of thick sedimentand relatively recent volcanic activity as indicatedby the presence of extinct volcanoes such asthose associated with the Mount Gambier region40km to the south. It is an area of anomalouslyhigh heat flow (see figure 3).The Penola Trough (GEL 223) has been selectedfor the first deep well because this trough has anextensive data-base of the target productive wells,reservoir, based on more than 20 deep petroleummany of which have intersected the targetreservoir, as well as extensive seismic data,including 271 km 2 of 3D seismic.The Geothermal ReservoirThe target reservoir is the Cretaceous Pretty HillFormation, a member of the Crayfish Group (seefigure 1). The good reservoir quality of the PrettyHill Formation sandstones has been known frompetroleum activities for some time. Gas was firstdiscovered in the trough in 1987 in Katnook-1.These gas discoveries are mainly restricted to thetop 25m of the formation, trapped beneath LairaFormation shale. This is relevant and significantbecause the Laira Formation shale has a lowthermal conductivity and is assumed to be athermally insulating unit, overlying the Pretty HillFormation target reservoir.As part of the drilling of the petroleum wells, asignificant amount of wireline logging, coresampling and resulting petrophysical evaluationwere undertaken in the Pretty Hill Formation. Theporosity of the target Pretty Hill Formation sectionwas determined by Panax based on wireline logscalibrated to porosity samples from conventionalcores and sidewall cores.133

Australian Geothermal Energy Conference 2009Figure 1: Schematic cross-section of the Penola Trough (from north to south, see inset). Correlated, wireline logs from severalwells are also shown. The target reservoir formation, the Pretty Hill Formation, attains maximum thickness in the KatnookGraben (near the Katnook 2 well). After Boult et al. (2002).We have estimated a total transmissivity(permeability thickness product) of 10-50Darcy.metres (D.m) depending on well andthickness of Pretty Hill Formation penetrated.The availability of well data, combined with theavailable 3D seismic data gives the PenolaGeothermal Project a significant degree ofcredibility and reduced technical uncertainty inregards to the existence of suitable geothermalreservoirs.Figure 2: Outline of Sub-basins or troughs of the LimestoneCoast Geothermal Project.Geothermal Resource Estimation andTemperature DeterminationHot Dry Rocks Pty Ltd (HDRPL) undertook ageothermal resource assessment acrossgeothermal tenements owned by Panax, adheringto the Australian Code for Reporting ofExploration Results, Geothermal Resources andGeothermal Reserves, 2008 edition (the Code)(Beardsmore, 2009). The geothermal resourcesummary in table 1 shows the relatively largeoverall potential of the Limestone CoastGeothermal Project.The Penola Trough stands out as being the onlytrough with indicated and measured resources,courtesy of reservoir information derived fromprevious petroleum wells and 3D and 2D seismicdata. The outline of the measured resource in thePenola Trough is shown in figure 4.Within most of the Penola Trough, consistent withobservations in well Katnook 2, modelling predictsthat the temperature is relatively constant around160°C at 4,000m.Location and InfrastructureGEL 223 is located within 50km of Mt Gambier,close to the township of Penola (figure 5). GEL223 is transected by a transmission network of275kV and 132kV power grid lines. Indicationsare there is sufficient capacity at two localsubstations to facilitate a low cost option (AUD$1-$2 million) for connecting the Demonstration Plantof the Penola Project234

Australian Geothermal Energy Conference 2009Table 1: Estimated Geothermal Resource within the Pretty Hill Formation and deeper reservoir units for the Penola GeothermalPlay. Resource estimates rounded to two significant figures (Beardsmore, 2009; for full reports please refer to the Panaxwebsite: www.panaxgeothermal.com.au)from the Pretty Hill Formation reservoir to providean assessment of the economic viability of thisproject. The total cost per MWh is considered tobe the cost per MWh of power generated aftertaking into account all plant and pumprequirements.The Penola Project power generation is based onthe production of 175kg/sec of brine (=166.4kgallons/hr (US)), at a temperature of 145˚C(293˚F) from each production well, and aninjection temperature of 70˚C (158˚F). This BaseCase using a standard binary organic rankinecycle binary geothermal power plant, has anestimated Gross output of 6.7 MWe and Netoutput of 5.9 MWe and a net/net output of 4.5MWe.The development is divided up in three stages:Figure 3: Schematic diagram of the LimestoneCoast Geothermal Project.Seismic InterpretationSeismic interpretation of the 3D seismic datasetshas allowed a confident delineation of the top ofthe Pretty Hill Formation and the base of the rift.The seismic data was also processed to providemore information on the reservoir quality thanfrom the well data alone. An ‘acoustic impedance’inversion of the 3D seismic was undertaken tobetter identify the prospective reservoir section.Pre-Feasibility StudyPanax compiled a Pre-Feasibility Study of thePenola Project to determine the total costs perMWh of power generated from brine produceda Demonstration Plant based on oneproduction wellthe Phase 1 Plant based on a total of threeproduction wells; and the Phase 2 Plant based on a total of tenproduction wells.A summary of the output and total cost per MWhfor the three stages and a summary of the totalcapital and operating costs per MWh is listed intables 2 and 3 below:Output MW $ MWhGross 67.0 42Net Plant 59.0 48Net Plant/NetPumps45.0 63Table 2: Penola Project Summary of Base Case OutputGross, Net Plant and Net Plant/Net Pumps, Total Costs perMWhThe cost per MWh produced after plant and pumppower demands (i.e. net plant, net pumps) isestimated at AUD$63 per MWh. The cost ofconnecting the Penola Project power generationto the grid (based on independent expert advice)adds approximately AUD$2 to the total cost per335

Australian Geothermal Energy Conference 2009MWh generated, a direct reflection of theexcellent infrastructure location of this project.Capital & Operating Costs per MWh(Phase 2 Plant, AUD$’s)Capital Costs $51Operating Costs $12Total Costs $63Grid Connection $2Total $65Table 3: Penola Project Capital and Operating Costs perMWh Phase 2 Plant (67 MW).Figure 4: Surface outline of the MeasuredGeothermal Resources of the Penola Project.ConclusionIt can be concluded that the Penola Projectrepresents a commercially attractive geothermaldevelopment proposition targeting a hotsedimentary aquifer which is well known fromprevious petroleum exploration. A pre-feasibilitystudy indicates that a competitive total cost perMWh of AUD$63 can be achieved. Further, theplans for drilling the first well in the project,Salamander 1, are well advanced. Overall, thePenola Project has the scope to be of nationalsignificance in the quest to reduce carbonemissions through providing competitively priced,zero emission, base-load power, and to be thefirst grid connected geothermal electricitygenerator in Australia.ReferencesBeardsmore, G.R., 2009: Limestone CoastProject: Penola Geothermal Play, Statement ofGeothermal Resources, Internal report.Beardsmore, G.R, 2009: Limestone CoastProject: Tantanoola Geothermal Play, Statementof Geothermal Resources, internal report.Beardsmore, G.R, 2009: Limestone CoastProject: Rendelsham Geothermal Play, Statementof Geothermal Resources, internal report.Beardsmore, G.R, 2009: Limestone CoastProject: Rivoli - St Clair Geothermal Play,Statement of Geothermal Resources, internalreport.Boult, P.J., White, M.R., Pollock, R., Morton,J.G.G., Alexander, E.M., and Hill, A.J., 2002,Lithostratigraphy and environments of deposition,in J., B.P., and Hibburt, J.E., eds., The petroleumgeology of South Australia, Volume Vol 1: OtwayBasin, Primary Industries and Resources SouthAustralia (PIRSA).Figure 5: Penola Project – Location &Infrastructure.436

Australian Geothermal Energy Conference 2009Water Requirements in Deep Geothermal SystemsJim P. DriscollHot Dry Rocks Pty Ltd, Level 4, 141 Osborne Street, South Yarra, VIC, 3141.jim.driscoll@hotdryrocks.comThe working fluid in a geothermal system is themedium through which heat is extracted from thesub-surface realm and brought to surface.Access to a working fluid is one of four criticalrisk areas that need to be addressed whenundertaking Geothermal Systems Assessments.Surface water and groundwater are regarded asthe most viable supplies of working fluid,although there is scope for the use of water cogeneratedfrom hydrocarbon operations. Theuse of CO2 as a working fluid has also beensuggested, and research into this field continues.Water is a valuable commodity, and it isessential that water access issues be addressedin the early stages of planning a geothermalproject. Rainfall in Australia is unevenlydistributed, both seasonally and geographically.An outline of the full life cycle waterrequirements of a deep geothermal energyproject is presented. Distinctions are madebetween Engineered Geothermal Systems andHot Sedimentary Aquifers.Keywords: Water, Working Fluid, GeothermalSystems Assessment, HSA, EGS, Reservoir,Canning BasinIntroductionAccess to a working fluid should be addressedduring the initial exploration stage of ageothermal project rather than just beingconsidered during the developmental andproduction phase. This is due to public concernsabout water security, and also to water-usebeing subject to increasingly stringent regulatoryframeworks.Working fluid risk was identified by Cooper andBeardsmore (2008) as being one of four criticalrisk areas that need to be addressed whenundertaking a Geothermal Systems Assessmentof an area.Cordon and Driscoll (2008) quantified thevolumes, rates and quality of water required atsuccessive stages of exploration, developmentand production of geothermal resources in aSouth Australian context, and these data aretransferrable to geothermal projects elsewhere inAustralia.Exploration and development programs tend tofollow similar paths, with each stage having itsown water requirements. During the initial stagesof a geothermal exploration program, it is usuallynecessary to drill a series of shallow heat flowholes to delineate the most prospective parts ofan area. Once the company has achieved a levelof confidence in defining their potentialgeothermal resource, deep geothermal resourcedrilling is planned and marks the beginning ofthe development stage as it is currently acceptedthat the first deep exploration well is convertedinto either an injection well or production well.ClimateAustralia’s rainfall is highly variable, bothseasonally and geographically, as demonstratedin data derived from the Bureau of Meteorology(Figures 1 and 2). Figure 1 details the 30 yearaverage rainfall in Australia whilst Figure 2shows the variability of rainfall in Australia overthe previous 36 months.Consequently, surface water volumes andgroundwater recharge is extremely variable on ayear-by-year basis. The Federal Governmentcompleted an assessment of Australia’s waterresources, including water availability, allocationand use, management and development, andwater quality. These data were published in2000 as part of the Australian Natural ResourcesAtlas (www.anra.gov.au/water).Surface WaterThe Australian Natural Resources Atlas (2000)divided surface water resources into 12 drainagedivisions, 246 river basins and 325 surface watermanagement areas.It can be seen from Figure 1 that much ofAustralia is classed as arid (annual rainfall

Australian Geothermal Conference 2009Figure 1. Average annual rainfall in Australia based on 30-year average 1960-1990 (sourced from www.bom.gov.au).Figure 2 Rainfall deciles for 36 month period 1st May 2006 to 30th April 2009 (sourced from www.bom.gov.au).238

Australian Geothermal Energy Conference 2009The Australian Natural Resources Atlas (2000)concluded that 26% of Australia’s surface watermanagement areas (SWMAs) were at a highlevel of development and approaching or beyondsustainable extraction limits (Table 1).Development statusLow development (100% ofnominated sustainable flow regime)Number (%) ofSWMAs195 (60%)46 (14%)50 (15%)34 (11%)Table 1. The level of development of Australia’s 325SWMAs. The surface water sustainable flow regime isdefined as the volume and pattern of water diversions froma river that includes social, economic and environmentalneeds. Sourced from the Australian Natural ResourcesAtlas, 2000.It is also worthy to note that 55% of Australia’swater is supplied by SWMAs that are consideredoverdeveloped.GroundwaterThe availability of groundwater is generallycontrolled by two important parameters: the typeof strata that hosts the aquifer (i.e. whether it is asedimentary or fractured rock aquifer system)and the degree of connectivity of the voids(whether they be fractures within the rock, orpore throats in sedimentary grains). Sedimentaryaquifers typically yield at higher rates and store agreater volume of water compared to fracturedrock aquifers.A further controlling factor in groundwateravailability is the rate of recharge to the aquifersystem versus the rate of extraction. Regions ofhigh rainfall typically have significant volumes ofgroundwater available in shallow aquifersystems (assuming an aquifer is present). Indrier climatic regions, aquifers tend to be locatedat deeper levels below the Earth’s surface, andare often associated with large volumes of waterstill resident from the geologic past. Present dayreplenishment rates in these arid to semi-aridareas are typically low.The Australian Natural Resources Atlas (2000)divided groundwater resources into 69groundwater provinces and 538 groundwatermanagement units (GMUs).Development statusLow development (100% of nominatedsustainable yield)Number (%) ofGMUs274 (53%)81 (16%)104 (20%)57 (11%)Table 2. The level of development of Australia’s 516 GMUs(note: 22 GMUs were not assessed). The groundwatersustainable yield is defined as the volume of waterextracted over a specific timeframe that should not beexceeded to protect the higher social, environmental andeconomic uses associated with the aquifer. Sourced fromthe Australian Natural Resources Atlas, 2000.Great Artesian Basin (GAB)The Great Artesian Basin (GAB) covers an areaof over 1,711,000 km2 (Figure 3), and hasestimated water storage of 8.7 million GL,although only a very small proportion of thiswater is recoverable from bores.Figure 3. Map of the GAB highlighting intake areas,direction of flow and concentration of springs (sourcehttp://www.nrw.qld.gov.au).The GAB consists of alternating layers of waterbearing (permeable) sandstone aquifers andnon-water bearing (impermeable) siltstones andmudstones. This sequence varies from less than100 m thick on the outer extremities of the GABto over 3,000 m in the deeper parts. Watertemperatures vary from 30°C in the shallowerareas to over 100°C in the deeper areas,controlled primarily by depth of burial.Throughout most of the GAB, groundwatergenerally flows to the south-west, although moreto the north-west and north in the northernsection. The rate at which it flows through thesandstones varies between 1—5 m/yr. Recharge339

Australian Geothermal Conference 2009by infiltration of rainfall into outcroppingsandstone aquifers occurs mainly along theeastern margins of the GAB, and specificallyalong the western slopes of the Great DividingRange. Natural discharge occurs mainly frommound springs in the south-western area. Thesesprings are natural outlets through which thegroundwater flows to the surface.Some of the oldest waters are found in thesouth-western area of the GAB. These haveinferred ages of up to 2 million years (datingback to the base of the Pleistocene). Thesedimentary rocks that make up the GAB weredeposited during the Jurassic and CretaceousPeriods (195–65 million years ago).Coproduced FluidsIn some areas of oil and gas development, hightemperatures are coupled with high volumes ofwater produced as a by-product of hydrocarbonproduction. This is of particular significance tothe Cooper Basin where geothermal licences fora number of companies overlap with existinghydrocarbon operations. Each oil and gas fieldhas a large evaporation pond to house water coproducedfrom the extraction of hydrocarbons,so water sources are spread throughout thebasin area. The size of the ponds variesdepending on fluid rates to surface. Furtherassessment of water sources co-produced byhydrocarbon operations could prove beneficial togeothermal energy projects in these areas.In the United States, water is produced frommassive water-flood recovery fields and frommost mature hydrocarbon areas; the disposal ofthis co produced water is an expensive problem(Tester et al., 2006). Curtice and Dalrymple(2004) estimated that co-produced water in theUnited States amounts to at least 40 billionbarrels per year, primarily concentrated inCalifornia and states bordering the Gulf ofMexico.The key factors required for successfulgeothermal electrical power generation includesufficiently high fluid rates from a well or group ofwells in relatively close proximity to each other,at temperatures in excess of 100°C.Carbon Dioxide as a Working FluidWhilst most geothermal operators considerwater to be the optimal working fluid, there isongoing research into other fluids such as supercriticalCO2 (Brown, 2000; Pruess, 2006). WhilstCO2 has many benefits including being a nonpolarfluid, low viscosity at temperatures andpressures within the reservoir, and a largebuoyancy effect; there are several drawbackssuch as a lower heat capacity and large frictionallosses (due to gas-phase flows in the productionwell-bore) which leads to lower thermodynamicperformance within the system (Atrens et al.,2009).Working Fluid RiskRegulatory processes will always be an inherentrisk in the Australian context given the increasingvalue being applied to water resources.However, the main technical risks are thevolumes of water required to initially charge anEngineered Geothermal System (EGS), and thequantities of water needed to sustain anyongoing circulation losses during developmentand production.Until recently, it was thought water chemistryissues would not adversely impact geothermalprojects in Australia so long as operatorscontrolled the quality of water introduced to thesystem. However—as the April 2009 incident atGeodynamics’ Habanero Projectdemonstrated—corrosion may be an issuewhere natural fluids are produced. Whilstunfortunate, the identification of this risk doesallow for companies to incorporate mitigatingstrategies in designing their wells and associatedinfrastructure.Water RequirementsEngineered Geothermal Systems (EGS)The water requirements for EGS projects aredetermined by the volume required to initiallycharge the system, and volumes required tosustain the system once water losses areaccounted for.Cordon and Driscoll (2008) surmised that thedevelopment stage would require 280,000 m3 ofwater based on the assumption that an EGSmodule consists of one injector (1st well) andtwo producers (2nd and 3rd well) of 8.5” openholediameter. Wells are typically drilled to adepth of 3,000–5,000 m and modelling studiessuggest a separation between wells of 600 mwould be optimal to create sufficient volume heatexchangers that operate for a period ofapproximately 20 years.Thirty one separate stages were identified byCordon and Driscoll (2008) in the developmentphase of the project, each with varying waterrequirements.Once the exploration well has been drilled, aseries of small-scale injection tests are used toassess the undisturbed hydraulic properties inthe open section of the well. These tests mayinclude slug tests (to study the response of thewell-aquifer system to an impulse in flow),production tests (which yield information on thepressure and temperature conditions deep in thewell where a future heat exchanger is planned)and low-rate injection tests (determine the440

Australian Geothermal Conference 2009hydraulic properties of the un-stimulated openholesection of the well).The next phase of development is to stimulate orcreate a reservoir in the well via initiation ofshearing within joints at a predetermined depth.The stimulation involves injecting water in stepswith increasing flow rates; and a post-stimulationtest is undertaken to evaluate the enhancementof permeability in the reservoirOnce the stimulation and the post-stimulationtest of the well is completed, an assessment ismade to see if the extent and quality of thereservoir is suitable for progressing to the nextstage, the targeting and design of a 2nd well tointersect the reservoir. During the drilling of the2nd well, wellhead pressure on the 1st well ismonitored for any pressure response from thedrilling activities in the 2nd well. Once the 2ndwell is completed, similar tests to that carried outin the 1st well are required to determine theextent of the hydraulic link between the wells.A small-scale circulation test between the twowells using tracers is carried out to evaluate thereservoir properties. Should hydraulic dataindicate impedance within the reservoir, thenremedial treatments can be implemented toimprove reservoir connectivity between thewells.A decision to drill the third well is made once thestimulation and post-stimulation tests in thesecond well indicate the extent and quality of thereservoir. Again, a series of tests are conductedbetween all three wells to confirm that circulationis established and that reservoir characteristicsare acceptable to the business plan.Finally, circulation tests with increasing flowrates are undertaken to move the project fromthe development stage to the production stage.As there are very few operational EGS’s in theworld, hydrothermal projects are generally usedas analogies to provide an estimate of waterusage for the production phase of geothermalenergy projects. In a typical, successfulhydrothermal reservoir, wells can produce 5 MWor more of net electric power through acombination of high temperatures and high flow.For instance, a well in a shallow hydrothermalreservoir producing water at 150°C needs to flowat about 125 kg/s (~125 l/s) to generate 4.7 MW(Tester et al., 2006) of net electric power to thegrid.Hot Sedimentary Aquifers (HSA)HSA systems differ from EGS projects in thatthere are substantial volumes of water inherentlywithin a naturally occurring reservoir. Primaryporosity and permeability are seen to decreasewith increasing depth due to the effects ofcompaction (Figure 4). There is thus a trade offbetween temperature and the flow rate potentialof the reservoir at depth. In instances where thetarget isotherm lies at depths where compactionprocesses have destroyed a significantproportion of the primary porosity andpermeability, hydraulic stimulation procedures,similar to those described in the previoussection, would be engaged to enhance reservoirproperties.Figure 4. Depth versus porosity plot for all onshorepetroleum wells in QueenslandIn order to commercially exploit a HSAgeothermal resource, detailed knowledge of theaquifer and water-flow characteristics needs tobe ascertained. Flow characteristics areespecially important in order to ensurereinjection does not cool the system and exhaustthe resource too quickly. Two criteria need to befulfilled: high yielding aquifers and hot waterwithin the aquifer.HSA systems utilise water at temperaturestypically between 100°C and 150°C. Water atthis temperature will not flash spontaneously intosteam at sufficient pressures to turn electricitygenerator turbines; thus binary cycle electricitygeneration is utilised. The heat contained withinthe water is transferred to another medium witha lower boiling-point, termed the ‘working’ or‘binary’ fluid. The high-pressure vapour of thebinary fluid can then be used to turn a turbine.Driscoll et al. (2009) noted in their CanningBasin geothermal assessment several highyieldingaquifers, most notably the Grant Groupsandstones which extend throughout much ofthe basin and are several kilometres thick inplaces. Two GMUs, the Desert and the WallalGMU, cover the vast majority of the CanningBasin, and both have very low to minordevelopment of the Grant Aquifer with highsustainable yields (218 and 296 Gl/yrrespectively). Assuming the geothermal systemrequires flow rates of 100 l/s, the water isreinjected back into the same aquifer, and thereis 2% water loss, then water requirements wouldbe ~64 Ml/yr for production. The Grant Aquifer541

Australian Geothermal Conference 2009can therefore be regarded as having excellentdevelopment potential.SummaryChanges in rainfall distribution and intensityhave been well documented in Australia.Geothermal operators will need to offer creativesolutions to acquire and secure their watersupplies over the lifetime of the project.Access to groundwater is limited and regulated,so advanced planning is required by companies.ReferencesAtrens, A., Gurgenci, H. and Rudolph, V., 2009.Exergy Analysis of a CO2 Thermosiphon. In:Proceedings of the Thirty-Fourth Workshop onGeothermal Reservoir Engineering, StanfordUniversity, SGP-TR-187.Australian Natural Resources Atlas, 2000(www.anra.gov.au/water).Brown, D., 2000. A Hot Dry Rock geothermalenergy concept utilizing supercritical CO2instead of water. In: Proceedings of the Twenty-Fifth Workshop on Geothermal ReservoirEngineering, Stanford University, 233–238.Cooper, G.T and Beardsmore G. R., 2008.Geothermal systems assessments:understanding risk in geothermal exploration inAustralia. In: Blevin, J.E., Bradshaw, B.E. andUruski, C. (Eds), Eastern Australasian BasinsSymposium III, Petroleum Exploration Society ofAustralia, Special Publication, 411–420.Cordon, E. and Driscoll, J.P., 2008. Full Life-Cycle Water Requirements for Deep GeothermalEnergy Developments in South Australia.Department of Primary Industries and Resources(South Australia) and the Australian School ofPetroleum, 50 pp.Curtice, R.J. and Dalrymple, E.D., 2004. Just thecost of doing business. World Oil 77–78.Driscoll, J.P., Mortimer, L., Waining, B., Cordon,E. and Beardsmore, G.R., 2009. GeothermalEnergy Potential in Selected Areas of WesternAustralia (Canning Basin). 87 pp.http://www.dmp.wa.gov.au/801.aspxPruess, K., 2006. Enhanced geothermal systems(EGS) using CO2 as working fluid—A novelapproach for generating renewable energy withsimultaneous sequestration of carbon.Geothermics, 35, 351–367.Tester, J. et al., 2006. The Future of GeothermalEnergy – Impact of Enhanced GeothermalSystems (EGS) on the United States in the 21stCentury, MIT Press, pp. 2-29; 5-3.642

Australian Geothermal Energy Conference 2009Approaches for identifying geothermal energy resources in coastalQueenslandMelanie Fitzell*, Stephanie Hamilton, Jim Beeston, Len Cranfield, Kate Nelson, Chris Xavier and Peter Green.Queensland Mines and Energy, 80 Meiers Road, Indooroopilly QLD 4068*Corresponding author: melanie.fitzell@deedi.qld.gov.auThe Coastal Geothermal Energy Initiative is aQueensland Government Program designed toinvestigate sources of hot rocks close to existingtransmission lines along the east coast ofQueensland where modelled crustaltemperatures at 5km are generally

Australian Geothermal Energy Conference 2009Initially, target areas were identified from anunderstanding of the geology and tectonichistory of eastern Queensland. These areaswere considered to have the potential to haveelevated temperatures at a shallow depth. Nospecific geothermal-energy model has beenapplied to their selection.Detailed assessment of the target areas is beingundertaken using the available geological andgeophysical data. Geophysical modelling isbeing undertaken over target areas wheregeophysical datasets are suitable, to betterdefine the geothermal target.Heat production values referred to in this paperhave been calculated from whole-rockgeochemistry data of granitoids across the state.A heat-production equation (Rybach, 1988) hasbeen used to determine locations of valuesgreater than five microwatts per cubic metre(µW/m 3 ).This paper presents five examples (Figure 1) ofthe types of geological targets to be tested andthe approaches used in their assessment.These targets include an extrapolated buriedgranitoid, inferred granitoids from geophysicalanomalies, and three sedimentary basins thatcontain low thermal conductivity lithologies suchas coal or oil shale.Inglewood areaGeological OutlineIn the Inglewood area, Jurassic-Cretaceousrocks of the Clarence-Moreton and Surat Basinsunconformably overlie Carboniferous Texasbeds basement. These rocks are unconformablyoverlain by Tertiary-Quaternary flow remnants ofthe Main Range - Lamington Basalt Province.Mesozoic units that outcrop/subcrop over thearea include the Marburg Subgroup (Lower-Middle Jurassic), the Walloon Subgroup (MiddleJurassic) and the Kumbarilla beds (MiddleJurassic-Early Cretaceous).The Texas beds form part of the TexasSubprovince, within the central part of the NewEngland Orogen. The turbidite-dominated Texasbeds are intruded by Permian-Triassic mainly I-type plutons assigned to the New EnglandBatholith.Regional GeophysicsThe regional magnetic data highlight thestructural grain of the western limb of the TexasMegafold. The most obvious surface featuresare strongly magnetic and magnetically alteredrocks in the Texas beds, and moderate tostrongly magnetic basalt lavas. These unitscontrast with the weakly magnetic Clarence-Moreton and Surat Basin successions.Unexposed, moderate to strongly magneticgranitoid intrusions vary in shape and size. Themost prominent of these is located west ofInglewood and forms the basis of thisinvestigation. The Stanthorpe Granite farthereast also has a moderate to strong positive totalmagnetic intensity (TMI) response, and is highheatproducing. A number of unexposed, nonmagneticgranitoid intrusions have also beeninterpreted in the Inglewood area (Purdy et al.,2005).Target RationaleThe premise to be tested is that Carboniferousaccretionary wedge rocks and Mesozoic fluviolacustrinerocks are insulating a high-heatproducing intrusion.The target is a north-south trending, elliptical,magnetic anomaly west of Inglewood (Figure 2).This anomaly (~90km 2 ) has a strong positiveTMI response. Preliminary modellingdemonstrates that the magnetic anomaly maybe explained by a diapiric-shaped plutonintruding basement, with the most magneticmaterial occurring more than 500m below thesurface. Donchak et al. (2007) suggested aPermian-Triassic age range for this magneticunit.A water supply bore drilled on the anomalybottomed in Marburg Subgroup at 227m. Nobottom-hole temperature was taken. If the unitis high-heat producing and there is sufficientinsulation, it could be a viable geothermal target.Figure 2: Total magnetic intensity image – colour drape ofthe Inglewood area.244

Australian Geothermal Energy Conference 2009Figure 3: A. Structural elements map of the Stanthorpe area. B. Regional Bouguer gravity image (National Gravity Database).Regional gravity trend removed. Red crosses denote heat-production values greater than 5 µW/m 3 . Note irregular gravitystation spacing.Stanthorpe areaGeological OutlineAnother target area of the CGEI is theStanthorpe area, in the Texas region of southeastQueensland. The Texas beds(Carboniferous) form the most extensive unit inthis region (Figure 3A). The unit is dominatedby volcaniclastic turbidites, altered maficvolcanics, and limestone. Granitic rocks(Permian-Triassic) intrude the Texas beds.Intrusions are mainly I-type plutons assigned tothe New England Batholith. The mostwidespread bodies of granite crop out in theStanthorpe area, where they are mapped as theRuby Creek Granite (Early Triassic), theBallandean Granite (Late Permian-EarlyTriassic) and variants of the Stanthorpe Granite(Early Triassic). The Ruby Creek Granite andStanthorpe Granite are leucogranites; theBallandean Granite is dominantly monzogranite.Regional GeophysicsThe highly evolved Stanthorpe and Ruby CreekGranites of the Stanthorpe complex show mainlywhite tones on a ternary radiometric image,indicating enrichment in all three radioactiveelements. The Stanthorpe Granite has threehigh-heat production values (max. 6.15 µW/m 3 ),and the Ruby Creek Granite one high-heatproduction value (6.31 µW/m 3 ) (Figure 3).As part of a preliminary geophysicalassessment, local-area stretching techniqueshave been applied to regional Bouguer gravitydata from the National Gravity Database. Theeffects of regional trend have been removed.Figure 3B shows an enhanced stretch ofanomalies in the Stanthorpe area.Target RationaleThe target for investigation is an area whereStanthorpe complex granites extend underinsulating cover. The Texas beds may havefacilitated the development of a steep thermalgradient relative to surrounding areas.Although gravity station spacing is sparse, asecond gravity low to the west is likely to begranite. The Ruby Creek Granite crops out overpart of the anomaly. Tin/polymetallic deposits inthis area are hosted within hornfelsed Texasbeds, capping very shallow-level and possiblyextensive plutons of the Ruby Creek Granite(Donchak et al., 2007).The continuation of high-heat producing granitesunder cover favours the Stanthorpe area as ageothermal energy source. Geophysicalmodelling will be used to infer the dip of granitecontacts and to better define the geothermaltarget.Tarong BasinGeological OutlineSouth-east Queensland contains a number ofisolated, coal-bearing, intermontane basins thatformed during the extensional phase of the LateTriassic (e.g. Callide, Tarong and IpswichBasins). These basins are underlain by a rangeof older rocks of variable derivation, which inmost cases can only be determined withuncertainty by extrapolation from outcrops onthe margins of the basins.The Tarong Basin, an arguably 1.86 kilometredeep accumulation of conglomerate, pebblysandstone, sandstone, shale and coal is ofinterest owing to the presence of the radiogenic345

Australian Geothermal Energy Conference 2009granites within the Boondooma IgneousComplex (Late Permian to Early Triassic) to thewest and north-west of the basin.This basin contains coals of moderate rank witha maximum vitrinite reflectance (R o , max) of0.68%, which suggests that they were subject tohigher temperatures in the past.Regional GeophysicsThe regional gravity coverage broadly outlinesthe extent of the basin as a north-north-westtrending graben (Figure 4). The BoondoomaIgneous Complex crops out along the westernmargin of the basin and is also coincident with awell defined gravity anomaly to the north-west.Sediments of the basin have been locallyderived from granitic rocks of the BoondoomaIgneous Complex, and basal conglomeratescontain granitic boulders and cobbles.Consequently, these sediments have a highradiometric signature on a ternary RGB image.Although it is unknown what underlies theTarong Basin, the gravity response does not ruleout the presence of granitic basement under thecoal-measures sequence. Geochemicalanalyses suggest heat production fromradiogenic granites of the Boondooma IgneousComplex can be considered to be moderate.Figure 4: Regional Bouguer gravity image over TarongBasin and Boondooma Igneous Complex (National GravityDatabase). Regional gravity trend removed.Target RationaleThe Tarong Basin has been selected as apotential geothermal target owing to thethickness of the sedimentary succession and thepresence of coal to act as an effective insulator.Based on the available geological andgeophysical data, the Boondooma IgneousComplex is present to the west and north-westand is interpreted to underlie the western part ofthe basin. The combination of BoondoomaIgneous Complex at depth and the sedimentarycover provided by the infill of the Tarong Basinsuggests that this is a valid geothermal target.Hillsborough BasinGeological OutlineA number of narrow, linear, fault-boundedTertiary grabens occur along the Queenslandcoast. These structures developed during anactive phase of extension associated with theopening of the Tasman and Coral Seas,beginning in the Late Cretaceous (Day et al.,1983).The Hillsborough Basin is defined by a northwestsouth-east asymmetrical graben, extendingfrom Proserpine area offshore to CapeHillsborough. The basin is also interpreted toextend north from Proserpine to EdgecumbeBay.Basin infill (Paleocene-Middle Oligocene)consists of minor conglomerate, sandstone,siltstone, oil shale with volcanics andvolcaniclastics in the basal sequence. Acidvolcanics and sediments crop out at CapeHillsborough (Cape Hillsborough beds) and maybe correlate to the lower part of the basinsequence (Gray, 1973).Campwyn Volcanics? (Late Devonian-EarlyCarboniferous) were intersected in anexploration well in the southern onshore part ofthe basin and are interpreted to form basement.North of Proserpine basement can only beinferred from rocks exposed adjacent to thebasin margin. Carmila beds (Permian) crop outalong the north-western margin and Edgecumbebeds (Carboniferous) and silicic volcanic rocksof the Whitsunday Volcanic Province(Cretaceous) are exposed along the northeasternmargin.Oil shales and lignites are present within thesedimentary sequences of the HillsboroughBasin and include the McFarlane Oil Shaledeposit.Regional GeophysicsA seismic refraction and reflection survey overthe southern onshore part of the HillsboroughBasin resulted in definition of an asymmetricalsyncline with a maximum stratal thickness of2100m (Gray, 1973). The basin deepens to thenorth-east and is bound by the Proserpine Fault.The south-eastern flank slopes more gently andbasin infill onlap basement. The deepest part ofthis structure (south of Proserpine) is coincidentwith a well defined gravity low anomaly (Figure5).A second, weaker gravity low occurs to the northof Proserpine. An early oil shale exploration drillhole (PDD01) intersected approximately 509mof Tertiary rocks, indicating the basin continues446

Australian Geothermal Energy Conference 2009to the north-west. Interpretation of the gravitycoverage suggests a ridge separates the subbasins.Figure 5: Regional Bouguer gravity image (with gravitystations) over the north-western (onshore) HillsboroughBasin (National Gravity Database). Regional gravity trendremoved. Note lack of gravity stations in the east.Target RationaleThe Hillsborough Basin has been selected as apotential geothermal target owing to thethickness of the sedimentary succession,particularly in the southern onshore part of thebasin, and inferred high-heat-flow conditionsinduced by an extensional history. The presenceof siltstone and oil-shale sequences may be aneffective insulator.The extensional history of the basin suggeststhere may be a significant amount of heatremaining within the lithosphere. Cooling mayhave been slowed by the presence of a thicksedimentary sequence. The target philosophywill be to determine the effectiveness of siltstoneand oil-shale sequences as insulators.Geophysical modelling may be used to advancethis geological assessment and to better definethe geothermal target.Styx BasinGeological OutlineThe Styx Basin is a small Early Cretaceoussag(?) basin, straddling the central Queenslandcoast near St Lawrence.The Styx Coal Measures are predominantlyfluvial, with occasional marine incursions, andcomprise fine-grained sandstone, mudstone,conglomerate and coal-bearing units (Malone,1970). The Styx Coal Measures unconformablyoverlie a folded sequence of Permian BackCreek Group and Boomer Formation of theBowen Basin. Sediments and volcanic rocks ofthe Carmila beds (Early Permian) underlieBowen Basin strata. Styx Basin sediments onlapPermian strata to the west, and are faultedagainst the Back Creek Group to the east.Adjacent to the fault, Cretaceous strata havebeen folded and faulted.The nature of the basement rocks beneath theBowen Basin in this area can only be inferredfrom exposed rocks outside the basin. TheConnors Arch (Late Devonian-LateCarboniferous) is exposed to the west andconsists predominantly of silicic volcanic rocksof the Connors Volcanic Group, which havebeen intruded by Late Carboniferous granites. Itis plausible to infer Connors Arch rocks mayform basement to Permian strata underlying theStyx Basin.The Connors Arch is separated from the basalstrata of the Bowen Basin by the Carmila beds.The Carmila beds and Bowen Basin strata havebeen deformed as part of the GogangoOverfolded Zone.Numerous coal seams occur within the StyxCoal Measures, but they are generally variablein thickness and lateral extent (Svenson &Taylor, 1975). Coals are considered high volatilebituminous coals with vitrinite reflectance (R o ,max) between 0.8-0.95%, indicating a history ofhigher temperature.Regional GeophysicsThe regional gravity data reflect the location ofthe Styx Basin and underlying Permian strata ofthe Bowen Basin as a gravity-low anomaly. Thebasin deepens to the north and is reflected by adecrease in gravity values.The Back Creek Group is characterised by a‘hot’ radiometric signature (moderate to high inall three channels), appearing as whitish on acomposite RGB radiometric image (Figure 6)(Withnall et al., 2009). Carboniferous graniticintrusions of the Connors Arch also exhibit aradiogenic (enriched in all three radioactiveelements) signature on the ternary radiometricimage (Figure 6). Geochemical analyses ofradiogenic granitic rocks in the southern part ofthe Connors Arch suggest heat production canbe considered to be moderate. Some felsicvolcanic units within the Connors VolcanicGroup also show a high radiometric signature.Target RationaleThe target for investigation in the Styx Basinincludes insulating sedimentary strata overlyingradiogenic units of the Permian Back CreekGroup and inferred radiogenic granites of theConnors Arch.The Styx Basin is unlikely to have been deeplyburied considering the relative stability ofeastern Queensland since the Early Cretaceous.Therefore, the high rank of the coals is unlikely547

Australian Geothermal Energy Conference 2009to have been achieved through deep burial. Anelevated heat flow seems a more likelyexplanation to produce a higher rank at ashallow depth. The elevated heat flow suggestscontribution from several sources, including theBack Creek Group and, potentially, graniticintrusions of the Connors Arch. If the PermianBowen Basin and Cretaceous Styx Basinsedimentary rocks provide effective insulation,then the radiogenic granites of the Connors Archcould be a prime geothermal target.Figure 6: Ternary radiometric image over the onshore partof the Styx Basin and surrounding area. Units of the BackCreek Group are shown by a black outline. Maroon outlinedenotes Late Carboniferous granitic intrusions of theConnors Arch which have whole-rock geochemical data.SummaryThe Coastal Geothermal Energy Initiative willinvestigate sources of hot rocks close to existingpower transmission lines along the coastal areaof Queensland. The major aim of the initiativewill be to increase knowledge of the crustaltemperatures in selected areas along the coast.It is the first government program in Australiadesigned to directly target gaps in temperatureand heat-flow data coverage in Queensland.The work program will identify potentialgeothermal targets where high temperature andheat flow may be present. The initiative will testthese targets by obtaining temperature andthermal conductivity data within these areas viaa cored-drilling program.No specific geothermal-energy model has beenapplied to the selection of areas. Five examplesof the types of targets that are currently beingassessed, through the integration of differentgeological and geophysical data, are addressed.Future work will include geophysical modellingof these targets and expanding the assessmentprocess to include other geological settingslikely to contain potential geothermal targets.ReferencesChopra, P. and Holgate, F., 2005, A GISAnalysis of Temperature in the Australian Crust,Proceedings World Geothermal Congress 2005,Antalya, Turkey, 24-29 April 2005.Day, R.W., Whitaker, C.G., Murray, C.G.,Wilson, I.H., and Grimes, K.G., 1983,Queensland Geology, Geological Survey ofQueensland, Publication 383.Donchak, P.J.T., Bultitude, R.J., Purdy, D.J.,and Denaro, T.J., 2007, Geology andmineralisation of the Texas region, southeasternQueensland: Queensland Geology, 11.Gray, A.R., 1976, Hillsborough Basin,Queensland, in Leslie, R.B., Evans, H.J., andKnight, C.L., eds., Economic geology ofAustralia and Papua New Guinea. AustralasianInstitute of Mining and Metallurgy, MonographSeries No. 6. Vol. 3 Petroleum, p.460-464.Malone, E.J., 1970, St Lawrence, Qld, 1:250 000geological series. Bureau of Mineral Resources,Australia, Explanatory Notes SF55-12.Purdy, D.J., Donchak, P.J.T., and Pascoe, G.S.,compilers, 2005, Inglewood, Sheet 9141,Queensland: 1:100 000 Geological Series,Natural Resources and Mines, Queensland,Brisbane.Rybach, L., 1988, Determination of HeatProduction Rate, in Haenel, R., Rybach, L., andStegena, L., eds., Handbook of Terrestrial Heat-Flow Density Determination, p.125-142.Svenson, D., and Taylor, D.A., 1975, Styx Basin,Queensland, in Traves, D.M., and King, D., eds.,Economic geology of Australia and Papua NewGuinea. Australasian Institute of Mining andMetallurgy, Monograph Series No. 6. Vol. 2.Coal, p.324-327.Withnall, I.W., Hutton, L.J., Bultitude, R.J., vonGnielinski, F.E., and Reinks, I.P., 2009, Geologyof the Auburn Arch, southern Connors Arch andadjacent parts of the Bowen Basin and YarrolProvince, central Queensland, QueenslandGeology, 12.648

Australian Geothermal Energy Conference 2009Remote sensing of heat: A Review of potentially useful methods andinstruments in the quest for innovative exploration approachesDesmond FitzGerald.Intrepid Geophysics, Unit 2, 1 Male Street, Brighton, Victoria, 3186, Australia.* Corresponding author: des@intrepid-geophysics.comDirect sensing of surface radiant heat, and buriedtemperature anomalies by remote methodsdeserves more attention because of the potentialuses these methods can offer the geothermalexploration industry. Many instruments andmethods exist, but their data have been largelyignored to date.This paper provides a review of available, and yetto be tested methods, and their relative merits. Insumming-up, focus is aimed at methods tomeasure surface radiant heat. There are ongoingchallenges with data interpretation, newmathematical methods and softwaredevelopment.Finally, a calibration range is advocated in one ormore of Australia’s more prospective regions forthe purpose of testing and consolidating betteruse of geophysical methods, and developingdiagnostic tools kits for exploration.Keywords: Surface radiant heat, heat flowanomalies, Aster, airborne survey, SQUID, 3Dmodelling, Curie.IntroductionThere is only token use of remote sensingtechnology in Australia for heat resourceexploration. This seems strange given that fieldmapping, sampling and drilling are orders ofmagnitude more expensive. It is also true that thequantitative values from remote sensing are notbelieved by some workers, to reflect reality.In estimating a thermal resource for a project via3D modelling, one is required to input surfacetemperature, heat flow constraints, and rockproperty constraints (i.e., thermal conductivitiesand heat production rates). For all of these inputs,direct measurements need to be obtained toenable thermal modelling and interpolation ofresults but all of these inputs are typically undersampledin the project area. The danger here isthat local variation in geology and heat flow isgenerally not being accounted for. Therefore othermethods to complete the picture of required inputsare required. This paper suggests complementaryinputs can be achieved though acquisition of awell-calibrated and high resolution remotelysensed surface radiant heat map.To reiterate the merits of this proposal:1. Measuring any independent variable thatreflects a property of the sub-surface geologywill always make a contribution to the 3Dgeology earth model. So along with gravity,magnetics and radiometrics, why not measuresurface radiant heat, as a potential means ofunderstanding relative surface heat flow?2. The rock properties required for a heatresource calculation are typically undersampled even though the variability isgenerally very high. Proxy measurements ofsurface heat flow, from remotely sensedsurface radiant heat, may help elucidatepopulations of rocks with similar properties.A common counter argument to the proposed useof surface radiant heat maps is that what happensat surface has little to do with what might behappening at a depth of say 3 kilometres, where,for e.g., there could be sedimentary layers“blanketing” the resource. Figure 1 illustrates thispoint. Different thermal gradients will exist in rockunits of different thermal conductivity. This is theessence of the "hot dry rock" geothermal energyresource.Figure 1. Cartoon illustrating how the geothermal gradientchanges with depth if a low conductivity layer (k1) overlies ahigh thermal conductivity layer (k2). This is a special case ofwhat is more generally known as heat refraction.Like any other geothermal energy resource, thisrequires elevated rock temperatures to occur atanomalously shallow depths. For instance, this isachieved if a highly radioactive granite (withmedium to high thermal conductivity) is thermallyinsulated from above by sedimentary cover of lowthermal conductivity.149

Australian Geothermal Energy Conference 2009The current thrust in Australia is to find high valueEGS resources that could provide significant baseload electricity economically. Finding lowertemperature heat and hot water resources fordirect use (e.g., Cottesloe swimming pool, inW.A.) also has significance for the Australianeconomy long-term.Both of these geological scenarios will havedistinct surface signatures in terms of heat flow,holding clues to the thermal regime existingbelow, eg., a negative or a positive surface heatflow anomaly. Surface pattern recognition will bepart of the improved innovative explorationmethodology. In summary, remote sensing ofsurface radiant heat has an important part to playin the exploration of both geothermal energyscenarios.Earth’s Heat LossIn this section we review some principles ofEarth’s heat flow balance.Earth's heat loss at present is about: 74% from plate activity, 9% from hot spots, and 17% from radiogenic heat lost fromcontinental crust.Typical heat flows at the Earths surface arebetween 0.001 W m -2 and 0.1 W m -2 . The meanheat flow of all continents qc and that of theoceans qo , are:qc = 0.065 W m -2qo = 0.101 W m -2(Stein, 1995, Stüwe, 2007).This energy is directly emitted at the surface,together with heat being absorbed and re-emittedfrom external sources (see Figure 2). The directsensing of this surface radiation (Figure 2), or“surface radiant heat” (the adopted terminologyfor this paper) is problematic, because thecontribution of Earth heat loss is very smallrelative to all other factors. This is analogous tomeasuring gravity anomalies in an aeroplane, forwhich there are now several viable systems.Figure 2 shows a cartoon of the inputs andoutputs of the surface heat balance and givesapproximate quantities during normal daylighthours. This model comes from NOAA and is asummary of the annual energy budget for theatmosphere.Figure 2. Global heat flows in Watts m -2 during daylighthours. Critically, night-time or pre-drawn readings of surfaceradiation contain a far-reduced component of reflected solarradiation.Periodic Surface TemperatureFluctuationsTemperatures at the surface of Earth vary both intime and in space: daily and annual temperaturefluctuations cause temporal variations andadiabatic gradients cause variations with surfaceelevation. While both may not be important inAustralian geothermal energy problems, they areconsidered briefly here because they areimportant to account for when interpretingremotely sensed surface radiant heat (along withother surface effects such as moisture).The relevance of temporal fluctuations may bestudied by assuming that the diurnal or annualtemperature variation at the surface is simplydescribed by a cosine function:T = ΔT cos(ft) at the surfacewhere f is the frequency (i.e. 1 per day or 1 per year).For these boundary conditions, there is ananalytical solution of the heat flow equation givenby:where T0 is the starting temperature at t = 0, f is thefrequency (e.g. 1 per year) and ∆T is the annual temperatureamplitude (e.g. 20 °C between summer maximum and meanannual temperature).Annual fluctuations only influence temperatures atdepths down to about 5 metres. Thus, annual anddaily temperature fluctuation have to beaccounted for in any remote sensing work andremoved before 3D modeling is performed.250

Australian Geothermal Energy Conference 2009A review of existing, potentially usefulmethods and instrumentsSatellite sensing of surface radiant heatThere are many contexts where either satellite,airborne or surface measurements clearly indicateunambiguous temperature anomalies in the subsurfacegeology. Scenes gathered at night-timeusing thermal imagery are often quite goodindicators of large scale sub-surface temperatureanomalies.ASTER, Landsat and NOAA satellite systems areused extensively by remote sensing specialists tohelp map geology. A considerable part of themeasured signal is from the thermal infra-red(TIR) spectrum. For example, in Figure 3 below, astrongly negative thermal anomaly is imaged onsurface in the Middle East. Here sub-surfacehydrocarbons (poor thermal insulators) arecreating a localised low heat flow anomaly thatcan be imaged on surface. Therefore, fromsurface imagery alone the ability to image thermalconductivity contrasts and gain clues about thepossibility of strong heat refraction in occurring atdepth, demonstrated here.by field observations and drillhole data (Stamoulis2006).This work has been followed up in 2007 by Houet. al. and now includes a publication of a statewide paleo-channel map. Temperature mapsavailable as higher end ASTER products requireminimal processing and can be integrated withexisting data.Figure 4a (after Stamoulis 2006). Aster NTIR system imagefrom the Beverly project in the North Flinders Ranges. Darkareas indicate cooler temperatures. In areas of highelevation, colour contrasts are likely to indicate lithologyvariation. A-B refers to the profile in Fig 4b.ABBeverley 4 Mile prospectBeverley uranium mineFigure 3. Night-time thermal imagery shows a strongnegative (cold) thermal anomaly in the core of an anticline inthe Middle East. In this case, sub-surface hydrocarbons witha low thermal conductivity are causing this surfaceexpression.Extensive use of ASTER NTIR or night-timethermal infra-red data from the northern FlindersRanges (Beverly Mine Project area), has beenused by Stamoulis 2006. This is a first attempt tominimize the effects of daytime temperatures onemissivity. In this example, paleo-channels havebeen located due to their lower sedimenttemperature, which is thought to be due to theirhigher moisture content (related to higherpermeability and porosity in fluvial sediments).Figures 4a & 4b demonstrate the identification oftemperature contrasts from the ASTER preenhancedtemperature map. Surface expressionsof palaeo-channels are not always evident fromelevation, but their presence has been supportedFigure 4b (after Stamoulis 2006). Sediment temperaturecontrasts are apparent despite no correlation with elevation,and these indicate the location of paleo-channels which areconfirmed by drillhole data.Several groups have developed technology foradjusting the Aster signal to correct for “BlackBody” radiation in order to predict surfacetemperatures and/or heat flow associated with theoutcropping geology. The RASTUS system byNeil Pendock is one example.Black body effects must be removed from eachAster spectrum before the TIR imagery can bemeaningfully interpreted. This is achieved byfitting and removing a blackbody curve from eachof the TIR spectrums.351

Australian Geothermal Energy Conference 2009Afterwards, two outputs are available: atemperature image and a blackbody correcteddata set. An example of this processing from Indiais shown below in Figure 5.Further research can provide importantinformation such as understanding temperaturevariations and properties of outcropping units.Applying such new knowledge will further improveinterpretations where ASTER NTIR data is usedand exploration targets will be better defined.ASTER data is very cheap to acquire compared toalmost any other datasets.Figure 5 shows an example of a surface temperature mapderived from pre-dawn Aster data using the RASTUSsystem. It shows over 16 degrees centigrade variation on thesurface (temperature scale in ºC).Air Airborne sensing of magnetism for Curie TdepthsThe continental scale estimate of the temperatureat 5 km depth mapped for Australia is due foranother upgrade. This time the aim should be toextrapolate from the isolated deep wellobservations as before, but to also add in ablended contribution from the estimate of thedepth to the Curie temperature (approximately560 degrees).This estimate can be made using the aeromagneticobservations and seeking the bottom orgreatest depth to magnetic basement. While thisis very dependent upon the quality of theobserved magnetic data, we are fortunate inAustralia, to have arguably the best observedregional magnetic datasets. If any country can getit right, Australia should be first. There is scope fornew algorithms to emerge for this task.Airborne sensing of past and present highheat alteration effectsAnother approach is to look at surfaceexpressions of mineralogy that indicate wherehigh heat alteration conditions have existed in thepast. The mineralogy can be directly sensed usingthe reflectance of light and analysing wavelengths(hyper spectral). Regional mapping canbe used to differentiate granites through micachemistry and mafic mineral content. (e.g., PilbaraGeology Mapping, WA.)Structure Control Of Alteration?Above map of structural features derived frominterpretation of 1:25,000 aerial photographs. Blue boxshows location of scanner image.Right Mineral index image pyrophyllite/ dickite/ sericitesuperimposed on the structural map.Figure 6. These images show methods adopted in the North Kimberley to analyse whether locations of mineral systems arecontrolled by structural features, or by alteration zones. Images courtesy of HyVista Corporation.452

Australian Geothermal Energy Conference 2009The HYVISTA system has been used in the NorthKimberley region of Australia for the detection ofhydrothermal alteration associated with deepseatedhigh temperature granites. The question,“When did this alteration occur?” is not resolvedby this sytem.Airborne sensing of radiometricsThe daughter products of natural radioactivedecay in and around granitic rocks, includesradon gas. This is routinely observable duringgamma ray airborne surveying, in Australia wherethere is granitic outcrop, on days of no rain andlittle wind.This is thought of as noise and routinelydiscarded. The entire raw radiometrics surveyingrecord for Australia contains quite a bit of thisinformation. No systematic use of this record hasbeen contemplated to date, with the possibleexception of Geoscience Australia’s OESPGeothermal Programme.Ground sampling of radiometricsAnother daughter product from deep-seatedradioactive decay is helium. This is not easilydetected from an airborne system, butinstruments do exist for ground surveying. Thisclass of instrument is a chemical sniffer ratherthan an instrument based upon spectroscopy.Hot Dry Rocks market such an instrument.Alternatively the direct detection of radon gas asan exploration tool is being used routinely inNamibia using the RADONTEX © system.Exploration Tools for the FutureInnovations in remote sensing instrumentsThe pursuit of remotely-sensed data to helpconstrain deep sub-surface temperaturepredictions prior to drilling is not new, and is notrestricted to the geothermal industry. Forexample, Shell are investigating various methodsto help devise world temperature-depth maps inrelation to sedimentary basins hostinghydrocarbons. Multidisciplinary approaches willeventually led to technology advances, benefitinga range of industries.Many types of instruments are available. With theadvent of SQUID (Super Conducting InterferenceDevice) devices, the sensitivity and response timeare now such that viable observation systems fordirect measurement of surface radiant heat areevolving, and these are significantly more useful.The classical direct heat measurementinstruments are: Thermometer – temperatures and gradients Bolometer–surface radiant heat. This is theterm coined by Langley of CIA fame for suchan instrument which he invented in 1886.Importantly, in the presence of significant watervapour, a bolometer is opaque to radiant heatthrough much of the thermal infrared band, asillustrated in figure 7 below.Therefore, the greater the column of air, the morethe heat signal would be attenuated, so satellitemeasurements are the least ideal. Low flyingaircraft based systems are a good compromise forsurveying.A downward looking “telescope” that is in fact abolometer, will yield more sensitive and precisemeasurements. At least 5 of the frequency peaksin Figure 7 should be chosen for measurement.The German group IPHT from Jena manufacturesuch an instrument that would be very suitable.This instrument has never been deployed upon anaircraft, but rather on satellites. It is expected aprototype may emerge in 2010.What To Measure?There are many sceptics to the notion of remotesensing of surface radiant heat and temperature.They claim that surface temperatures, in a spatialsense, do not vary very much when averagedover several days.Remote sensing work using thermal infra redbands from satellite systems such as Asterindicate that there are significant spatialanomalies in surface radiant heat andtemperature associated with locally outcroppinggeology (Figure 5).These two positions (above) are not irreconcilable– we look to physics to explain how bothobservations can co-exist.Figure 7. Shows the electro-magnetic spectrum and highlights in the thermal bands, those frequencies that cannotbe measured due to water.553

Australian Geothermal Energy Conference 2009For those familiar with gliding, thermals form over“Black Bodies” and strong updrafts can exist overareas of high heat emittance even though surfacetemperatures may not vary greatly.Known obstacles to the remote sensing ofsurface radiant heatAmong the obvious issues to overcome are:effect of evapo-transpirationAlbedo effectBlack body correctionsground water and its influence in masking clarification of transient vs. steady statemeasurementswhat quantity is being measured and howdoes it compare with other measurementsusing different physical principalsThere are already many examples of publishedtechniques for dealing with these issues. Forexample, the US Geological Survey via KenWatson (1992) has investigated removal of theAlbedo using innovative Fast Fourier Transformfiltering techniques.There are many examples in observationalgeophysics where the anomaly to be measured isless than 10 -5 of the gross amplitude. Heatanomalies are just another challenge of thisnature.Overcoming these and other challenges including:data interpretation and software development areall required to ensure proposed future methodsdeliver useful outcomes for EGS explorers inAustralia.A Proposal For An AustralianCalibration RangeMy proposal to the AGEG community is to set upcalibration ranges in at least two settingsrepresentative of Australian conditions.Examples of other calibration ranges are availablefrom the work of our overseas counterparts(Figure 7), but we require our own range to testspecific geological and geophysical issues arisinghere on the Australian continent, where we areleading the world in EGS exploration.In conventional geothermal systems, there isusually an easily discernable expression of nearsurface heat. Figure 8 shows a calibration or testrange set up in Nevada by the US GeologicalSurvey (Kratt, et. al. 2008). Here Aster satellitedata, pattern drilling of short length test holes,some deeper drilling and locations of known “hot”geological structures such as geysers are shown.Figure 8. Shows the general layout for what can bedescribed as a calibration range in Nevada, USA.Two calibration ranges are proposed for Australia:Range 1Northern Flinders Ranges (South Australia) wherethere are known high-heat producing granites,due to radiogenic contribution. The aim is toconduct a detailed field mapping exercise toacquire surface heat and temperaturemeasurements and rock properties on say a200m grid basis for a 5km x 5km area. The studyarea should cover both exposed and coveredgranites. The weather conditions, time of day,cloud cover and soil moisture are also factors tobe recorded.Range 2Onshore PortCampbell (south-western Victoria)where there are suspected oil seeps associatedwith faulting. There are also many deeper oilexploration wells in this area.An initiative to get the ball rolling could be fundedby government sources. All datasets go in to thepublic domain and any party that wants to try outtheir technique in the test range can have accessto all the past data.AcknowledgementsEd Biegert from Shell, Houston (SIEP), MikeHussey from HYVISTA, Neil Pendock and VickyStamoulis. Chris Matthews is thanked for hisreview comments.654

Australian Geothermal Energy Conference 2009ReferencesChristopher K., Coolbaugh M., Sladek C., ZehnerR., Penfield R., and Delwiche B., 2008, A NewGold Pan for the West: Discovering BlindGeothermal Systems with Shallow TemperatureSurveys, GRC Transactions, Vol. 32.Hou B., Fabris A., Keeling J. and Fairclough M.2007, Cainozoic palaeochannel-hosted uraniumand current exploration methods, South AustraliaMESA Journal 46 Department of PrimaryIndustries and Resources South Australia,Adelaide.tKeihl and Trenberth, 1997, Earth's annual globalmean energy budget. Bull. Amer. Met. Soc., 78,197-208.Stamoulis V., 2006. ASTER night-time thermalinfrared data: interpreting subsurface featuresfrom high resolution data. South Australia MESAJournal 43 Department of Primary Industries andResources South Australia, Adelaide.Stein, C. 1995, Heat Flow of the Earth. GlobalEarth Physics, A Handbook of PhysicalConstants. AGU Reference Shelf 1.Stüwe, K 2007, Geodynamics of the Lithosphere:An Introduction. 2 nd Edition. Springer.Watson, K., 1992, A 2D FFT program for imageprocessing with examples: U.S. GeologicalSurvey Open-File Report 92-265, 74 p.755

Australian Geothermal Energy Conference 2009Practical aspects of 3D temperature and heat flow modeling forexploration of EGS energy playsHelen J. Gibson 1* , Kurt Stüwe 2 , Ray Seikel 1 and Desmond FitzGerald 1 .1 Intrepid Geophysics, Unit 2, 1 Male Street, Brighton, Victoria, 3186, Australia.2 Karl-Franzens-University,Universitätsplatz2 A-8010 Graz, Austria.* Corresponding author: helen@intrepid-geophysics.comRealistic temperature and heat flow modellingrelies on the ability to make calculations directlyfrom well-constrained 3D geology models (Gibsonet. al. 2008, Meixner and Holgate, 2008). Correcttreatment of topography is another key concernfor modelling heat flow patterns that replicatethose measured in the real world (Stüwe andHintermüller, 2000; Braun, 2003).Commencing with a synthetic 3D geology model,featuring high topographic relief and variablescenarios of thermal conductivity contrasts, wepresent results from thermal modelling employingan explicit finite difference method to solve fortemperature in the steady state. Our solverscheme populates a Cartesian voxelised grid withresulting in-situ temperatures, heat flow valuesand temperature gradients.Our synthetic model is a test-bed for the Köflachdistrict of Eastern Austria for which a 3DGeoModeller 1 geology model is currently underconstruction. The Köflach model will demonstraterealistic 3D temperature and heat flow modeling,verified against measured insitu temperatures andheat flow data, whilst always obeying topographiceffects. The existence of thermally insulatinglignite beds at Köflach lends itself as a possibleanalogue for Enhanced Geothermal System(EGS) plays which also typically require theexistence of shallow insulating horizons to set-upa scenario of anomalously high heat occurrence,at accessibly shallow depths. This work also hasimplications for geothermal energy exploration inEastern Australian’s coal-bearing basins.Keywords: Enhanced Geothermal Systems, 3DGeoModeller 1 , geothermal module, topography,Köflach, thermal insulator.IntroductionThis extended abstract presents: 1) a review ofheat flow modeling in GeoModeller including thesimplifications, assumptions and boundaryconditions employed; 2) explanations andderivations of the temperatures and other outputswritten to 3D voxets; 3) presentations of resultsfrom a synthetic geology model featuring hightopographic relief and variable thermalconductivity contrasts; and 4) an introduction tothe geology of Köflach, Eastern Austria and adescription of the aims and objections of this casestudy which is now underway.Heat Modelling in 3D GeoModellerAn accessible method for rapid calculation of thespatial variation of temperature, heat flow andgeothermal gradients - directly from a complex 3Dgeology model – is now available within 3DGeoModeller This software (developed by BRGMand Intrepid Geophysics) is well renowned for itsability to model sophisticated geology inassociation with detailed digital elevation models(DEMs), and now also recently provides ageothermal module.The solved equation in GeoModeller combinesterms that account for conduction, heat productionand advection (Stüwe, 2007). See Table 1.Furthermore, the equation solves for the steadystate 3D temperature field under consideration ofspatially variable thermal conductivity.Implementation of the heat transport equations inGeoModeller is covered in previous work byGibson et. al. (2008).Mode of heattransferProcessAccounted forin 3DGeoModellerConduction Diffusion YesHeat Production Radioactive decay YesMechanical work No(friction)Chemical reaction NoAdvection Fluids Yes, simple 1ErosionNoDeformation NoMagmaNo1 Currently only one dimensional scenarios involvingadvection of heat by fluids can be solved in GeoModellerbut development is on-going.Table 1: Of the main processes of heat transfer (centre)three of these (diffusion, radioactive decay, and advection byfluids) are accounted for in GeoModeller because togetherthey contribute the majority of measurable heat in settingsdevoid of significant present-day tectonism, seismicity,metamorphism or volcanism.The solver currently adopts an explicit finitedifference approximation scheme that has theadvantage of being able to utilize a readilypreparedCartesian voxelised grid from thesmooth 3D geology model. (Note that modelvoxelisationis also need for geophysicalinversion, but is a simplification of GeoModeller’snormal operational mode that uses a potential156

Australian Geothermal Energy Conference 2009field method to calculate smooth 3D geologyboundaries from contact and orientation data.)For 3D temperature, finite differenceapproximation is solved with a Gauss-Seideliteration scheme continuing until one of thefollowing occurs: Either the sum of the residualerrors is smaller than the user-defined maximumvalue (maximum change in temperature in anyone cell, from one iteration to the next), or a userdefinednumber of iterations has been performed(where one iteration is defined to have occurredwhen the solver has acted in every voxel).Topography and Boundary ConditionsIn solving for temperature GeoModeller honors allthermal boundary conditions, and any knowntemperatures (fixed) that are internal to the project(e.g. temperature well-logs).As illustrated in Figure 1 (after Stüwe andHintermüller, 2000) and demonstrated by ourresults below, topography is a key concern foraccurate 3D temperature prediction (also Braun,2003). Treatment of topography during thermalmodeling can approach (but not equal) the detailof the original DEM by ensuring fine resolution inthe discretization scheme.Currently, a constant surface temperature isapplied at the topography boundary, but soon agrid-input of variable heat flow on surface (or aconstant value) will also be an option for users.This will be a useful improvement, becausemeasured heat flow values can then define theupper boundary rather than an assumed surfaceor paleo-surface temperature. Working exclusivelywith heat flows in this way can negate the concernfor a dis-equilibrium state so one can concentrateon “heat in the system now”, regardless of itsthermal equilibration status.Figure 1: Schematic illustration of the influence of surfacetopography on isotherms showing that temperaturedistribution is highly influenced by topography in the shallowsubsurface,and less influenced at depth (after Stüwe K. andHintermüller M., 2000).On the four vertical sides of the geology model,Neumann type boundary conditions apply. That is,we apply zero heat flow boundary conditionsreflecting the assumption that all lithologies aremirrored beyond the model boundary.Either constant heat flow, or constant temperatureis applicable to the bottom boundary of the model.We suggest this treatment is satisfactory in mostscenarios, but if there is evidence for variability,then a more meaningful treatment may be toexpand the vertical extent of the model, into depthzones where isotherms are predicted to flatten-out(as is the conventional approach taken amongstmany modelers), rather than implement a spatiallyvariable boundary condition.3D Temperatures and Other OutputsThe solver in GeoModeller populates a Cartesianvoxelised grid (.vo format) with estimated in-situtemperatures, heat flow values, and temperaturegradients. Output values are valid for the centerpointof the given cell/voxel. Derivations of outputsare given in Table 2, below.3D temperature and other outputs in GeoModellerTemperature (°C) Solved for every cell/voxelcentre by Finite DifferenceapproximationVertical Heat Flow (Wm -2 ) Flow of heat measured inenergy per time per unit area.Solved for each cell/voxet centrewith respect to the centre of thecell immediately above.Vertical(°Ckm -1 ) Change of temperatureTemperature over a distance. Solved for eachGradientcell/voxel centre with respect tothe centre of the cell immediatelyTotal HorizontalTemperatureGradientabove.(°Ckm -1 ) Change of temperatureover a distance of one cell to 4neighbours in the horizontalplane. Equal to the square rootof the sum of the squares of thehorizontal temperature gradientsin the x and y directions. (Anexpression of gradient strengthwith no expression of directionwithin the horizontal plane.)Table 2: Definitions and derivations of solved values fortemperature, heat flow and geothermal gradients asimplemented in GeoModeller.Test-bed Temperature ModelingSynthetic geology model + forward run set-upFigure 2 shows our synthetic geology model builtin GeoModeller. The model features topographicrelief of up to 7,500m and comprises two geologicunits with a simple conformable relationship.257

Australian Geothermal Energy Conference 2009Figure 2: Synthetic solid geology model showing projectextents and the maximum topographic relief. The intersectionof the DEM with the project bounds are shown in yellow. Themodel comprises two geology units with a conformablerelationship.Discretization of the smooth geology model inFigure 2 followed a scheme by which 100 cellswhere created in the x, y, and z directions, andhence (dividing these by the model dimensions inFigure 2) the cell sizes were 100m, square. Totalnumber of voxels was therefore 1,000,000.The mean thermal rock properties listed in Table3 for each geology unit were applied to thediscretized model. A constant heat production ratewas used, but thermal conductivities of the twounits were varied in the execution of threeseparate forward runs.at 20,000 and maximum residual tolerance wasset at 0.0001ºC. Heat capacities were assumedconstant at 1000 J kg °C.Three thermal modeling runs of the syntheticmodel were executed. The set-up parameters forall runs were identical except for the thermalconductivities (TC) of the two geology units (seeTable 3). Run 1 explored a moderate degree ofTC contrast between the capping unit and theunderlying geology, Run 2 explored the effects ofno TC contrast, and Run 3 explored a strong TCcontrast (Table 3).Results of test-bed modelling3D temperatures predicted in Run 1, are shown inFigure 3. Clearly, the strong topographic relief ofthe geology model has had a dominating effect ontemperature distribution. The temperature rangeof the 3D voxet for Run 1 is 20.0 to 76.2°C (Table4). This range is little different for Run 2 (the caseof no TC contrast), but ~16°C wider than thetemperature range for Run 3 (strong TC contrast).Temperature results are further displayed in 2D inFigure 4 where again the strong impact oftopography on temperature distribution is evidentin all runs. Note the asymmetry of the heatdistribution (in all runs) whereby temperatures areraised shallower in the section below the moregently sloping shoulder of the mountain (right-sideof figures), but pushed down in proximity to thehighly sloped shoulder (left-side of figures).Geology unitRun #Cap unitPhysical properties:ThermalconductivityW m -1 K -1Heat productionrateWm -3Run 1 1.5 3.0 x 10-6Run 2 3 3.0 x 10-6Run 3 1 3.0 x 10-6Base unitRun 1 3 3.0 x 10-6Run 2 3 3.0 x 10-6Run 3 5 3.0 x 10-6Table 3: Thermal rock properties of the geology units in thesynthetic model, for 3 forward runs estimating temperature,heat flow and gradients.Set boundary conditions for all 3 runs were: 20ºCfor the topography surface, and 0.03 Wm -2 for thebottom of the model. Maximum iterations were setFigure 3: Run 1, 3D temperature voxet (1 million nodes)imported to the synthetic geology model space inGeoModeller. Visual-cut off of the mesh was set to 20.5ºC toallow the topography wire-frame to be viewed (All airspace isotherwise 20ºC, obeying the surface boundary condition.)Additionally, increased heating of the section at,and below, the capping unit is noted in Runs 1and 3, as expected, due to the low TCs assigned358

Australian Geothermal Energy Conference 2009to this unit (hence a thermally insulating layer) incombination with higher TCs in the units below.Results of vertical heat flow for the 3 runs aregiven in Table 4 and Figure 4. By range they are:0-0.389, 0-0.382 and 0-0.388 Wm -2 respectively.Compared with world-wide surface heat flows(generally between 0.030 and 0.120 Wm -2 ) theranges include extremely high values, but wecaution that the distributions are skewed to thelower values in all runs (mostly

Australian Geothermal Energy Conference 2009Vertical temperature gradient results for the 3runs are given in Table 4 and Figure 4 (3 rd row).By range they are: 0-128.3, 0-127.4 and 0-77.7°Ckm -1 respectively. Similarly, large modelledranges have resulted, but again most values areskewed to a lower range (

Australian Geothermal Energy Conference 2009For further information visit:http://www.geomodeller.com/ReferencesBraun, J., 2003, Pecube: A new finite elementcode to solve the 3D heat transport equationincluding the effects of a time-varying, finiteamplitude surface topography, Computers andGeosciences, v. 29, p. 787-794.Gibson, H., Stüwe, K., Seikel, R., FitzGerald, D.,Calcagno, P., Guillen, A., and McInerney, P.,2008, Forward prediction temperature distributiondirect from 3D geology models, Proceedings,Australian Geothermal Energy Conference,Melbourne 2008.Meixner, T., and Holgate, F., 2008, The CooperBasin 3D Geological Model: A test-bed for thermalmodelling, Proceedings, Intrepid GeophysicsGeothermal Modelling Workshop, Adelaide 5-6November 2008.Stüwe, K., 2007, Geodynamics of theLithosphere. An Introduction. 2nd edition.Springer Verlag, 493p.Stüwe, K., and Hintermüller, M., 2000,Topography and isotherms revisited: Theinfluence of laterally migrating drainage divides.Earth and Planetary Science Letters, v. 184, p.,287-303.661

Australian Geothermal Energy Conference 2009Exploring Eastern Tasmania: A Novel Geothermal ProvinceFiona L. Holgate*, Hilary K.H. Goh, Graeme Wheller and Roger J.G. LewisKUTh Energy Limited, 35 Smith Street, North Hobart, 7000*Corresponding author: Fiona.Holgate@kuthenergy.comOver the past two years KUTh Energy Limited hasundertaken geothermal exploration across itstenements in eastern Tasmania. The initial phaseof this program is now nearing completion andhas yielded a variety of results. Although notpreviously recognised as geothermallyprospective, a program of systematic heat flowmapping has now revealed the presence of asignificant surface heat flow anomaly in thecentral Midlands area. Values of high (>90mWm -2 ) heat flow are found to be spatially associatedwith the sub-cropping extension of high-heatproducinggranite bodies. A series of sedimentaryunits, extensively intruded by dolerite sills, lieabove the granite and combine to provide theinsulation necessary for a classic EnhancedGeothermal System (EGS) target. Bisecting thenorthern portion of the heat flow anomaly is theTamar Conductivity Zone (TCZ), a region of highcrustal electrical conductivity that has beenmapped in detail by recent magneto-telluricsurvey work. This feature, which may indicate thepresence of large-scale fracture permeability inthe crust, remains open directly along strike fromthe region of highest recorded heat flow.Keywords: Tasmania, heat flow, magneto-telluricExploration Methods & ResultsTo effectively explore Eastern Tasmania for itsgeothermal potential a variety of techniques wererequired that were capable of discerning keyelements of the EGS target beneath extensiveJurassic dolerite cover. Critical amongst thesewere the magnitude and distribution of heat flow,the depth of insulator (depth to top granite), thequality (thermal properties) of the insulator andthe location and nature of the TCZ. The size ofthe area under investigation further necessitatedthat any technique used should be economicallyapplicable at a regional scale. To meet theseneeds, an exploration program was devised thatcomprised shallow drilling for surface heat flowdetermination, gravity interpretation, rock propertydetermination and magneto-telluric (MT) dataacquisition.Surface Heat Flow DeterminationA program of pattern drilling of shallow boreholeswas designed to investigate surface heat flowacross the tenement area. Holes were drilled ona 20km grid spacing at 36 locations. In all casesthe holes were percussion drilled to 100m withdiamond core cut to total depth at ~250m. Heatflow estimation was performed by Hot Dry RocksPty Ltd and was based upon application of 1Dthermal modelling. Data used in the modellingwas collected by Hot Dry Rocks and comprisedprecision down hole temperature logs and thermalconductivity values determined from core samplesusing a divided bar apparatus.At the time of writing, surface heat flow data wereavailable for 31 holes with five holes stilloutstanding (Figure 1). Heat flows determined todate are of high quality and reliability withanalytical uncertainties typically 4100km 2 ) of anomalously high heat flow(>90mWm -2 ) in the central portion of the tenementarea.Figure 1: Contoured surface heat flow field for EasternTasmania based upon new data acquired during KUThEnergy’s recent exploration program. The 90mWm -2contour, shown in red, encloses an area of over 4100km 2inside the tenement area (outlined in bold red).Gravity InterpretationEstimation of the depth to top granitoid wasundertaken by Dr. David Leaman using source162

Australian Geothermal Energy Conference 2009modelling of gravity data and following the methodof Leaman and Richardson (2003). An infillsurvey of ~500 gravity stations was undertaken toimprove the regional gravity coverage across thetenement area. These data were used to createan updated version of the Tasmanian mantlesource model MANTLE03. This model was inturn used to determine the residual Bouguergravity anomaly from which the depth and shapeof top granitoid was interpreted (Figure 2).sediments. Predictably, the turbidite sequencesof the Mathinna Supergroup display variablethermal conductivities, depending upon rock typeand grainsize. Of particular interest in these units,however, was the observation of a strong thermalanisotropy associated with the development offold axial cleavage (Figure 3). This effect, whichwas observed most strongly in fine-grainedmudstone and shale, serves to significantlyreduce the insulating advantage of the finegrainedlithologies wherever heat flow is directedalong the cleavage plane.Table 1: Thermal conductivity values (W/mK) determinedfrom core for Eastern Tasmanian rocks. Values in italics aretaken from Goh (2008). All values are from wet samples.Figure 2: Contoured surface showing estimated depth to topgranitoid. Image combines new data derived from KUThEnergy’s gravity data acquisition with the existing contours ofLeaman and Richardson (2003).Rock Property DeterminationRock units predicted to overlie the granites insignificant thicknesses are Jurassic Dolerite,Tasmania Basin sediments (ParmeenerSupergroup) and the Ordovician-DevonicanMathinna Supergroup. Thermal conductivityvalues determined from these rocks by dividedbar analysis from KUTh drill core are summarizedin Table 1 together with data from an independentstudy of this region (H. Goh, 2008). These resultsconfirm the relatively good insulating properties ofboth the Dolerite and the Tasmania BasinFigure 3: Thermal conductivity versus foliation angle (0° =vertical foliation) for the Mathinna Supergroup. Resultsindicate a strong thermal anisotropy that is most distinct inthe finer grained lithologies.Magneto-Telluric SurveyAn MT survey, comprising 96 stations located at1km intervals along two E-W lines, wasundertaken to better constrain the nature andlocation of the TCZ anomaly (Figure 4). Fulltensor time series data were collected byMoombarriga Geosciences for ~12 hours at eachsite to ensure resolution of apparent resistivityand phase data in the range 300-0.01Hz.263

Australian Geothermal Energy Conference 2009Figure 4: MT survey location and 2D modeled profile results for two lines across Eastern Tasmania. Models are inversions ofTM and TE shifted data. Resistivity range 5ohm.m (red) to 6000ohm.m (purple), maximum depth below surface is 14km, linedistance northern line = 44km, southern line = 50km.2D modelling of data generated by this surveywas performed by Dr Adele Manzella of theConsiglio Nazionale delle Ricerche-Istituto diGeoscienze e Georisorse (CNR-IGG) in Italy.Data were found to be of high quality withrelatively few incidences of major signal noise. Aspart of the modelling Dr Manzella applied asystematic process of data validation to identify,correct or remove poor or biased data. Amanually derived ‘static shift’ correction wasapplied to compensate for distortion effectsproduced in the electromagnetic field by nearsurfacefeatures.The 2D models produced by Dr Manzella for thissurvey are presented in Figure 4. In both casesthese models have been refined by the use of apriori constraints regarding the location ofresistive bodies determined in 1D inversionmodels. No assumptions were made regardingthe location, size or intensity of electricallyconductive anomalies or of the nature ordistribution of the existing geology. Comparisonsof TE, TM and joint TE-TM inversion models forthe two lines indicated a good agreement for thenorthern line whilst the southern line displayedsignificant differences indicating these data areinfluenced by 3D effects.The models derived from the MT data indicate thepresence of large electrically conductive bodieswithin the crust in the vicinity of both survey lines.In the northern profile, a strong east-dippingconductive body is observed at a depth of 2.5kmand is interpreted to have a thickness of no lessthan 2km. This body, together with a weakerwest-dipping conductor, confirms the presence ofthe ‘Tamar Conductivity Zone’ (TCZ) in thisregion.An east-dipping electrically-conductive anomaly isalso identified at the western end of the southernMT profile at a depth of 3.5 - 4km. This body liesdirectly along strike from the east-dipping featureidentified in the northern profile and is interpretedto be an extension of the TCZ along the TamarLineament (Figure 5).An electrically insulating anomaly is seen locatedto the east of the interpreted east-dipping TCZanomaly in both the northern and southern364

Australian Geothermal Energy Conference 2009profiles. At present the identity of the geologicalfeature causing this anomaly remains speculative.Figure 5: Data compilation of KUTh Energy Ltd’s newgeothermal exploration results in Eastern Tasmania.DiscussionCollation of new and existing data for EasternTasmania indicates the presence of a significantthermal anomaly in the centre of this region(Figure 5). A large area of elevated heat flow(~4100km 2 >90mWm -2 ) is seen to spatiallycoincide with the predicted extension of knowngranite bodies 3-4km under cover. Flat-lyingMesozoic cover sequences of the TasmaniaBasin and intrusive Jurassic Dolerite sills provideup to 1km of good insulating cover at surface.Beneath these lie the deformed flysch of thePalaeozoic Mathinna Supergroup, the insulatingqualities of which have been shown to dependupon the orientation of its structural grain.Evidence from field mapping in the north-eastindicates that the Mathinna comprises an olderrecumbently folded unit in the West which isjuxtaposed against younger upright foldedsequences in the East (Powell et al., 1993).Recent data suggests that the contact betweenthese units is faulted implying that the older stratamay occur at depth in the east (Reed, 2001; D.Seymour pers. comm.). This in turn suggests thatthe Mathinna section at depth will contain amixture of upright and horizontal foliations and itsbulk properties are therefore likely to be those of amoderate to good thermal insulator. Combined,these data confirm the potential of this area as aHot Rock or EGS development target. Furthergeothermal modelling work to estimate a thermalresource and predict temperature distribution withdepth in this area is now underway.MT survey work has confirmed the existence ofthe Tamar Conductivity Zone in the north andincreased its known extent into the south where itremains open along strike from an area of veryhigh heat flow (>100mWm -2 ). Whilst the nature ofthis feature is not uniquely defined, its geometryand location suggest that it is a crustal scalestructure, most likely a fault or fracture system. Itis plausible that this system may be permeable,containing electrically conductive fluid and/orhydrothermal alteration minerals. The possibilityof a southern extension of this feature, and of itsrelationship to the area of very high heat flow,remains open. Further MT survey work iscurrently in progress to address these issues bybetter defining the 3D conductivity structure of thesouthern region.SummaryA program of systematic geothermal explorationundertaken across Eastern Tasmania hasidentified a significant new geothermal province.A broad area of anomalously high heat flow(>90mWm -2 ) is found to spatially coincides withhigh-heat-producing granite at depth beneathinsulating cover. Hot Rock or EGS prospectivityin this area may be further enhanced by thepotential for in situ fracture permeabilityassociated with the Tamar Conductivity Zone.This feature, which has been detected by an MTgeophysical survey, remains open along strikefrom an area of very high heat flow (>100mWm -2 ).These targets will be further delineated byexploratory work as part of KUTh Energy’songoing Tasmanian work program.ReferencesGoh, H.K.H., 2008, Properties of north-eastern Tasmanianrocks for geothermal exploration, University of Tasmania,Honours Thesis, unpublished.Leaman, D.E. and Richardson, R.G., 2003, A geophysicalmodel of the major Tasmanian granitoids, TasmanianGeological Survey Record, 2003/11.Powell, C. McA., Baillie, P.W., Conaghan, P.J. and Turner,N.J., 1993, The mid-Paleozoic turbiditic Mathinna Group,northeast Tasmania, Australian Journal of Earth Sciences,40, 169-196.Reed, A.R., 2001, Pre-Tabberabberan deformation inEastern Tasmania: a southern extension of the BenambranOrogeny, Australian Journal of Earth Sciences, 48, 785-796.465

Australian Geothermal Energy Conference 2009Assessment of Otway Basin Hot Sedimentary Aquifer systems forgeothermal and water usesCedric Jorand*, Andrew Krassay, Lisa Hall, Stephen Hostetler, and Tom LoutitFrOG Tech Pty Ltd, 17F, Level 1, 2 King Street, Deakin ACT 2600The Otway Basin, spanning the southern parts ofVictoria and South Australia (Figure 1), is thelocation of a new regional geological andgeothermal study by FrOG Tech Pty Ltd. Inpartnership with P.I.R.S.A., Geosciences Victoriaand Geoscience Australia, the study integratespotential field and seismic data, information fromboth hydrocarbon exploration and water wells andthermal data to understand the nature of onshoreand offshore Otway Basin Hot and WarmSedimentary Aquifers and their inter-connections.The initial targeted formations within the faultcontrolled depocentres are Upper Jurassic toLower Cretaceous synrift and postrift, nonmarine,interbedded sandstones, shales and coals of theOtway Supergroup aquifers.Figure 1: Location of the Otway Sedimentary Basin and across-section from the onshore to offshore Otway Basin.Previous WorkTo date, there are no geothermal studies at theregional scale of the entire basin. The currentAustralian-scale temperature map (Austherm08, 5kilometres depth) is the result of interpolatingdispersed onshore well temperature data and assuch it is not appropriate for regional analysis ofonshore and offshore sedimentary basins. In bothstates, small scale geothermal studies have beenconducted by government geological surveys andconsultants (e.g. Jenkin, 1962; Thompson, 1978,1979; Nahm & Reid, 1979; Akbarzadeh &Thompson, 1984; King et al., 1987; theSustainable Energy Authority of Victoria (SEAV),2005, Driscoll 2006.), but have not been linkedinto a regional framework.The projectThis ongoing project will integrate Otway Basingeofabric (hydro-thermal and tectono-stratigraphicproperties) studies with a detailed geothermalresource calculation.This study intends to create for the first time, anattributed geological framework for the entireOtway Basin encompassing interpretation ofterranes, basement composition/lithology, tectonicevent-response, definition and description of deepand shallow potential aquifer/aquitard pairscontained in the economically exploitablegeothermal window to the megasequence level.This abstract summarised the main results of thePhase I of this project that focused on thecharacterisation of the deep Otway BasinCretaceous aquifers and the underlyingbasement.Otway basin basement topographyThe SEEBASE TM basement surface in the Otwaybasin has been refined since OZ-SEEBASE TMwas released in 2004, based on the most recentavailable geophysical surveys. The newSEEBASE of the Otway Basin is a model ofbasement topography and provides a new view ofthe Otway Basin geometry and a context whichcan be used to better understand the basindepocenters structural development together withthe sedimentary facies distribution. It wasconstructed by combining a structuralinterpretation with depth information derived frompotential field datasets, seismic data, FrOGTech’s seismic interpretation, wells, and publishedcross-sections. The present SEEBASE (Figure2) is a regional model at ~1:2,500,000 scale. Thesediment and basement thickness have beenderived from the depth-to-basement interpretationand will be used for the next step, heat flowmodeling.166

Australian Geothermal Energy Conference 2009Figure 2: 3D perspective view from the East of the OtwayBasin SEEBASE TM (basement topography).Seismic InterpretationSeismic profile analysis has permittedidentification of the structural signature for 3 mainextensional phases contemporary with depositionof the 3 key supersequences (Crayfish,Eumeralla, Sherbrook). The magnitude and typeof structural control has been described for eachphase. Analysis of timing, displacement, patternsand intersection relations of interpreted seismicfaults allows definition of 3 different main sets offaults.Thanks to seismic-well ties, the different aquifershave been characterized by their specific seismicand sedimentary facies, gamma ray log signatureand seismic horizon geometry and amplitude.This characterization allows the study of thevertical distribution of the potential reservoirs inthe Penola, Digby, Mocamboro, Ardonachie,Worong, Koroit troughs and in the TyendarraEmbayment. Porosity and permeability qualifiersbased on well-tie have been attributed along thestratigraphic chart.Isopachs of the supersequences have beenconstructed using the structure time surfaces fortop basement, top Crayfish Group (Figure 3), topPretty Hill sandstone, top Eumeralla and topSherbrook at basin scale.Aquifer characteristicsSix sandstone-rich reservoirs or potential deepaquifers have been identified:1. The basal Late Jurassic to earliest Cretaceousnonmarine sandstones of the Crayfish Group,sometimes informally described as the“McEachern Sandstone”.2. The thick, well developed fluvial channel andbar sandstones of the “Sawpit Sandstone”.3. The Pretty Hill Sandstone is the thickest andmost extensively developed Crayfish Groupsandstone-dominant unit.Figure 3: 3D time structure map of the top of the Crayfish Gp.4. The fine-grained sandstones within the LairaFormation, known as “intra-Laira sandstone”.5. The laterally discontinuous, lenticular channelsandstones of the Katnook Sandstone.6. The regionally extensive, thin, sheet-likeWindermere Sandstone.The best regional aquifer is the Pretty HillFormation. It is the thickest (up to 870m) andmost extensively developed, but its porosity isstrongly facies-dependent (channels = high,floodplain = low). Although thinner, the Sawpitsandstone shows similar characteristics andpotential. Alternatively, the Katnook andMacEachern sandstones are more localized, butshow higher porosity and permeability values withlocal thicknesses > 200m.Compilation of deep water bores salinity datashows that low salinity water is present within thedeep aquifers of the Otway Gp.In parallel, first-pass maps of shallower aquifers inthe Wangerrip, Nirranda and Heytesbury groupshave also been produced from regionalbores/wells databases.TemperaturesTemperature data from more than 270 wells havebeen compiled, assessed or re-assessed toattribute confidence values and generate apreliminary linear temperature gradient map at thescale of the Otway basin that will help to targetthe aquifers that will be the focus of Phase II. Thevalues stored in this temperature database willalso serve as a reference for Phase II heat flowmodelling. Preliminary linear gradient map showsthat the higher gradient values are found in thePenola, Tahara, Morenda and Elingamite troughs.As the number of reliable temperature values inwells diminishes quickly with depth, maps ofprojected temperature at the top of the deepaquifer surfaces have to be considered with care.Nonetheless temperature at the top of theCrayfish Gp, the shallowest of the targeted deep267

Australian Geothermal Energy Conference 2009aquifers gives values that are locally higher than100°C along the Victorian coastline.ConclusionThese preliminary results are encouragingconcerning the geothermal exploitation of thedeep aquifers in the Otway Basin that seems tobe economically viable for a large range of directusepurposes throughout the basin and potentiallylocally also for power generation.But, the Phase I of this project has also shown thelimitation of the direct linear gradient temperatureapproach for the deep aquifers. In phase II, adefinition/revision of rock hydraulic properties ofeach selected aquifer-aquitard pair and predictionof radiogenic heat flow derived from the basementcomposition and thickness from SEEBASETM toMoho will be performed. These inferred heat flowvalues together with available estimates of heatflow and corrected temperature at depth will beused to reassess temperature gradients usingthermal conductivities derived from mixedlithologycalculations. Heat in place maps,including the errors maps, will be then derived inorder to better define the geothermal plays andtheir associated risks. In addition to the definitionof the geofabric and geothermal resources, theproject will aim to produce a comprehensiveconceptual groundwater model of the OtwayBasin. The model will detail groundwaterrecharge, discharge and the links between theshallow, onshore groundwater resources used forconsumptive purposes (e.g. agriculture,environmental services and town water supplies)and the deep groundwater resources available forgeothermal, petroleum and carbon capture andstorage.ReferencesAkbarzadeh, A. and Thompson, B. R., 1984. Anoverview of the potential and applications ofgeothermal energy in Victoria, and proposedfuture actions. Victorian Solar Energy Council andDepartment of Minerals and Energy(Unpubl.).Melbourne, Australia.Driscoll, J. A preliminary regional assessment ofVictoria, Australia. AESC2006, Melbourne,Australia.Jenkin, J. J. 1962. Underground water in EastGippsland. Underground water investigationreport 6. Department of Mines, Victoria, 16 pp.King, R.L., Ford, A.J., Stanley, D.R., Kenley, P.R., and Cecil, M. K., 1987. Geothermal Resourcesof Victoria. Department of Industry Technologyand Resources and Victorian Solar EnergyCouncil. Melbourne, Australia. 134pp.Sustainable Energy Authority Victoria, 2005. Thegeothermal resources of Victoria. pp. 99.Thompson, B. R., 1978. On the thermal waters ofthe Gippsland Basin and the problems associatedwith the study of high temperature aquifers. In:Hydrology of great sedimentary basins;Proceedings of the Budapest Conference, 1976.Annales Instituti Geologici Publici Hungarici.Thompson, B. R., 1979. Geothermal gradientmaps of the Gippsland Basin and the occurrenceof high temperature aquifers. Geological Surveyof Victoria Unpublished Report 1979/140.368

Australian Geothermal Energy Conference 2009Multiuse-use ‘triple play’ hot sedimentary aquifer (HSA) potential ofVictoria, AustraliaRobert King, Mark Miller,Greenearth Energy Ltd, PO Box 24, Collins Street West, Melbourne 8007Greenearth Energy Ltd holds geothermalexploration permits to the east and west ofMelbourne, Victoria Australia. These permits arelocated on the Otway and Gippsland basins thatstraddle the southern part of the State. The basinfills range up to 6 km thick and form an insulatingblanket over Palaeozoic basement rocks.Geothermal gradients are somewhat elevated,with heat flows up to 100 mW/m 2 in places, andprojected temperatures of 150 o C at around 3kilometres (km) depth.Sandy units at the base of the basin sequencesoffer potential for Hot Sedimentary Aquifers (HSA)while longer term Engineered GeothermalSystems (EGS) prospectivity exists in Palaeozoicgranites beneath the insulating sedimentarycover. The HSA’s are a triple play with potentialfor electricity generation, direct heat applicationsand potential CO 2 sequestration sites.A geothermal resource has been estimated for thearea south of Geelong, encompassing both HSAand EGS geothermal plays. A proposal has beenmodelled for a 10.7 MW and 48 MW geothermaldevelopment accessing part of the HWAgeothermal resource.IntroductionGreenearth Energy Ltd (Greenearth) is a smalllisted Australian Geothermal explorer. It hasgeothermal exploration permits near MelbourneAustralia (Figure 1) that underlie the industrial hubof southeastern Australia. These areas have asignificant greenhouse gas footprint. To the eastof Melbourne, in Gippsland, the permits includethe Latrobe Valley area, the State of Victoria’spower generation hub with over 6000 MW ofbrown coal fired electricity generation. To the westof Melbourne a permit covers the Geelong region,the most carbon constrained community inAustralia. Major industry includes an aluminiumsmelter, cement works and a brown coal firedpower station.Greenearth has established inferred resources inboth its Geelong and Gippsland permits. To thesouthwest of Geelong an inferred resource of260,000 PJ is calculated (Beardsmore, 2008),encompassing both a hot sedimentary aquiferresource (HSA) and a deeper engineeredgeothermal system (EGS), while in the Gippslandarea a small inferred geothermal resource of39,000 PJ is estimated (Beardesmore, 2009).Figure 1: Greenearth Energy Ltd permits.The Australian Government has set a target that20 % of all energy generation by 2020 will be fromrenewable sources (Department of ClimateChange, 2008). This could mean thatapproximately 45,000 gigawatt-hours fromrenewable energy sources will be required by2020.The thick sedimentary basins running east andwest of Melbourne, the higher than normal heatflows in the basin margin areas and the potentialfor thick sandy sequences in the temperaturedepth widow of 3-4 km make the Greenearthpermits prospective for geothermal developmentof hot sedimentary aquifers.Geological and geothermal descriptionA Mesozoic rift basin established along the southeasternmargin of Australia during Gondwanaseparation. To the west of Melbourne is theOtway Basin, stretching 500 km, while theGippsland Basin is located to the southeast ofMelbourne.Both basins have undergone significant petroleumexploration with the offshore part of the GippslandBasin being a major hydrocarbon province.While the detailed stratigraphic nomenclaturevaries between the two basins, the overallsedimentary history is similar. Sedimentationcommenced in the early Cretaceous with fluvialsediments (Pretty Hill/Rintouls Creek) depositedonto the rifting basement. This is overlain by thicknon-marine volcanogenic sandstones andsiltstones. These sediments are in turnunconformable overlain by a series of marinesediments spanning the late Cretaceous to midTertiary (Duddy, 2003; Holdgate and Gallagher,2003).The geothermal potential is associated with theinitial sedimentary basin fill which offerpermeability potential. Faulting is extensive in thebasins with major faults bounding half grabens,originally normal and then subsequently169

Australian Geothermal Energy Conference 2009reactivated as reverse faults. Faulting in oradjacent to any sandy basal units, in particularfracture zones, should provide access to broaderreservoir areas (Figure. 2).Latrobe Valley and GippslandIn the Gippsland area the base of the sedimentarybasin is in the range 3000-4000 m or deeper. Thebasal units (Rintouls Creek Sandstone and TyersConglomerate) have known porosity and offer ageothermal target where they are most deeplyburied.3500m. An estimated temperature of 150 0 C wasachieved at a projected depth of 2900m +/- 400m(Fig. 4) (Walsh, 2009b, Greenearth Energy Ltd,2009).Any porous sandy sediment at that depth in theLatrobe Valley area provides an exploration targetfor hot wet sedimentary aquifer style geothermalresources. In the Latrobe Valley brown coalgeneration hub opportunities exist for bothelectricity generation as well as direct heatapplication for drying brown coal or pre-heatingboiler feed water.Figure 2: Schematic geological model for Hot Wet Aquifer,Otway and Gippsland basins.Heat flow investigations show that there is a trendof elevated heat flow through the Latrobe Valleyarea. Measurements on 10 wells returnedestimates up to 101 +/- 26 mW/m 2 (Figure. 3)(Walsh, 2009a). One of the most significanttemperature projections is that at the Loy Yang-2well, drilled in 2005 to 1443 m and re-entered in2008 for precision temperature logging to 713m.From the original well composite log, measuredand fair estimates of conductivity were applied todifferent layers. The resulting thermal conductivityprofile yielded a heat flow of 90 mW/m 2 .Based on this information a heat flow model wasused to predict the temperature beneath the well.Well log data from the adjacent Loy Yang-1 wellwas able to give the stratigraphy to a depth of1735 m. and a scenario was modelled down toFigure 4: Modelled temperature of Loy Yang-2 WellThese same units also offer potential targets forinvestigation as CO 2 sequestration reservoirs.The brown coal electricity generation in theLatrobe Valley area produces around 60 mtpa ofCO 2. The sandy units, located at depths of 2.5 kmor deeper beneath the power generation area,warrant further investigation of their ability to actas onshore CO 2 storage sites.Geelong areaIn the Geelong area the basal parts of theinsulating sedimentary cover (Crayfish Group/Pretty Hill Sandstone) reaches depths of 4000-5000 m (St John, 2007). Just to the west of thepermit boundary the Pretty Hill Sandstone is615m thick.This area has potential for both Hot SedimentaryAquifers(HSA) geothermal plays in the shallowersand-prone beds of the early Cretaceous CrayfishGroup as well as Engineered GeothermalSystems (EGS) geothermal plays in thePalaeozoic basement.Figure 3: Summary of heat flow investigations. The LatrobeValley area shows heat flows well above the global average.Figure 5: Seismic line OGF 92-402 showing distribution ofpossible sand prone units. Yellow – top E1, blue – top F,brown – base F, light blue – top Casterton A.270

Australian Geothermal Energy Conference 2009Seismic mapping has identified the distribution oftwo possible sand-prone units in the earlyCretaceous CrayFish Group. These twosequences are described as units F and E1(Figure. 5) and may constitute viable sedimentaryaquifers. Both units show characteristic syndypositionalgrowth towards the major boundingfaults with unit F reaching a maximum thicknessof about 600 m and unit E1 reaching a maximumthickness of about 700 m (Cooper and Waining,2008; Cooper, Waining and Pollington, 2008)(Figure 6).Inferred Resource estimates have been made onthree reservoir targets. The targets fall into twocategories of geothermal reservoir-:buried sedimentary aquifers (Hot SedimentaryAquifers –HSA) type plays, targetingsandstones units in the Crayfish Group (E1and F reservoirs); andEngineered Geothermal System (EGS/HDR),targeting Palaeozoic basement.The HSA targets were defined via sequencestratigraphic methods incorporating 2D seismicwith local and regional well data from the OtwayBasin. The EGS target has been defined by theseismic data and constitutes the basementbeneath the insulating Otway Basin sediments.A stored heat method was used to estimate aHSA inferred geothermal resource of 40,000 PJand the EGS inferred resource of 220,000 PJ.The resource covers an area of 462 km 2 and iscontained in 656 km 3 volume of rock. Theresource estimate complies with the Australiancode for reporting exploration results geothermalresources and geothermal reserves (2008edition).Geothermal Exploration Permit (GEP) 10 isavailable to utilize for power generation.Wells intersecting the Pretty Hill Sandstone in thewider Otway Basin show variable porosity andpermeability. Based on this limited data, it isfeasible that the Pretty Hill Sandstone may haveporosity in the range 10-15 % and averagepermeability of 50-150 mD at the target depth of3450 m (Fig. 7). It would be expected that thereservoir unit would need to have a thickness of >100 m of permeable rock to achieve apermeability-thickness function (Darcy-metre)required for commercial flows.Figure 7: Frequency distribution of horizontal permeabilityfrom core samples for the Pretty Hill at Waracburunah-2,Hawkesdale-1, Garvoc-1, Pretty Hill-1, and Woolsthorpe-1.The distribution is strongly log-normal with a median 204mDA 1D conductive heat flow model on data from theBellarine-1 well and extrapolated to basementfrom seismic data illustrate that the geothermalworking fluid (150 o C) is intersected at about3040m with a heat flow of 90 +/- mW/m 2 (Fig. 8).Figure 6: Depth map of the E1 marker, the top of thepotential reservoir unit in the Crayfish Group. Distribution iscontrolled by early Cretaceous growth faults.This work has led to the development of a HSAcommercial model for geothermal basedelectricity generation southwest of Geelong.This model assumes that a portion of the inferredHSA geothermal resource of 40,000 PJ present inFigure 8: Sample conductive 1D heat flow model based ontemperature data from Bellarine-1 and measured thermalconductivity data for all major lithologies in GEP 10. Themodel has been extrapolated on based on seismic depthgrids.371

Australian Geothermal Energy Conference 2009A target geothermal resource temperature of 170degrees centigrade at the modest target depth of3,450 metres with an assumed flow rate of 100litres per second, should yield sufficient heat flowto build an operating geothermal power plant.There are several possible sites for a geothermalpower plant in GEP 10 and a potential site wasselected approximately 10 kilometres northnorthwestof the Anglesea Coal Mine, 9.5kilometres from the Anglesea– Point Henryelectricity transmission line.A commercial study modelled the costs andoutcomes that may reasonably be expected fordeveloping a 10.7 megawatt (MW) geothermalpower plant. Similarly the study modelled anexpansion to establish a 48 MW geothermal plant(Cooper, Waining and Pollington, 2008).Borrowing costs were amortised over the life ofthe projects (20 years). Costs were discounted ashas the generation (MWhr) to calculate thelevelised cost (LEC) of both scenarios.The commercial model shows that over a 20 yearlife for the proposed geothermal power plant:The levelised cost of electricity (LOCE) would bein the range of $96-114 per MW hour.Generation of attractive pre-tax revenue anddiscounted cash flows for the project.Result in a displacement of at least 1.2 milliontonnes and up to 7.3 million tonnes of carbondioxide “greenhouse gases” emitted byconventional power stations.ConclusionGreenarth Energy Ltd has geothermal explorationpermits that underlie the industrial hub ofsoutheastern Australia. The permits contain inexcess of 6000 MW of brown coal fired electricitypower generation with the Latrobe Valley powerstations alone having a greenhouse gas footprintin excess of 60 mtpa.The southern Victorian Cretaceous-Tertiarysedimentary basins that straddle the permits havesubstantial seismic and well data from previouspetroleum exploration. Heat flows vary, however,in places values of up to 100 mW/m 2 wererecorded. In the Geelong and Latrobe Valley areatemperatures are estimated to reach 150 o C ataround 3 km depth. The basal units of thesedimentary pile, where they occur in the 3-4 kmdepth range have potential to contain hotsedimentary aquifers that may be suitable forpower development using organic rankin cycletechnology.The high moisture content of the brown coalsused for electricity generation may presentopportunities for direct heat application usinggeothermal fluids to dry coal. Given the high levelof greenhouse gas emission in the permit areas,these same units are a target for further researchas to their capacity to also act as reservoirs forgreenhouse gases.In the Geelong area good seismic coverage hasenabled the calculation of an inferred geothermalresource. A site was selected near the Angleseapower station for a conceptual geothermaldevelopment. At this location the potentialreservoir is interpreted to be 1000m thickcommencing at around 3.5 km depth.The costs and outcomes for conceptual 10.7megawatt (MW) and a 48 MWgeothermal powerplant were modelled. The plants would produce1.65 and 7.41 GWh of renewable electricity. Thelevelised cost of electricity (LOCE) would be in therange of $96-114 per MW hour.AcknowledgementsMuch of this paper has drawn extensively uponreports to Greenearth Energy Ltd by GraemeBeardsmore, Gareth Cooper, Denis Walsh andBen Waining of Hot Dry Rocks Pty Ltd. They areduly acknowledged for their contribution.ReferencesBeardesmore, G., 2008, Greenearth Energy Ltd, statementof estimated geothermal resource, Anglesea, GEP 10 as at04 December 2008. (Release to the Australian StockExchange by Greenearth Energy Ltd), 9ppBeardesmore, G., 2009, Greenearth Energy Ltd, statementof estimated geothermal resource, Wombat, GEP 13 as at 18December 2008. (Release to the Australian Stock Exchangeby Greenearth Energy Ltd), 9ppDepartment of Climate Change, Australian Government,2008, Fact Sheet, Australian Government renewable energytarget (December 2008), 1pDuddy, I. R., 2003, Mesozoic, in Geology of Victoria, (EdW.D. Birch). Geological Society of Australia, VictorianDivision Special Publication 23, pp239-286.Cooper, G. T. and Waining, B., 2008, Interpretation ofselected 2D seismic reflection lines in the Otway Basin (GEP10) and related sequence mapping. Report prepared forGreenearth Energy by Hot Dry Rocks Pty Ltd., 63ppCooper, G. T., Waining, B. and Pollington, N. J., 2008,Renewable energy Project: concept development forgeothermal power plants, GEP 10, Geelong area Victoria.Report prepared for Greenearth Energy by Hot Dry RocksPty Ltd, 31ppGreenearth Energy Ltd., 2009, High modeled temperaturesbenearth the Loy Yang power stations, Latrobe Valley,Victoria. Australian Stock Exchange Release, (27 May 2009),2ppHoldgate, G. R., and Gallagher, S. J, 2003, Tertiary, inGeology of Victoria, (Ed W.D. Birch). Geological Society ofAustralia, Victorian Division Special Publication 23, pp289-335.472

Australian Geothermal Energy Conference 2009St John, P., 2007, Independent geological expert’s report. InGreenearth Energy Ltd Prospectus, pp32-47Walsh, D, 2009a, GEP 12 & 13 temperature logging and heatflow investigation. Prepared for Greenearth Energy Ltd byHot Dry Rocks Pty Ltd (unpublished), 43ppWalsh, D, 2009b: Loy Yang-2 temperature correction andprojection. Prepared for Greenearth Energy Ltd by Hot DryRocks Pty Ltd (unpublished), 5pp573

Australian Geothermal Energy Conference 2009Progress at the Paralana EGS Project in South AustraliaKing J.P 1 , Reid P.W. 1* Bendall B 2 ,1 Petratherm Ltd. 106 Greenhill Rd, Unley South Australia 5066,2 Primary Industries and Resources, South Australia. 101 Grenfell St, Adelaide 5001* Corresponding author: preid@petratherm.com.auThe Paralana EGS Project, located 600km northof the city of Adelaide in South Australia, providesa natural laboratory for the development of anEngineered Geothermal System (Figure 1).Anomalously high heat production basementrocks provide the local heat source and areoverlain by a thick sedimentary package,informally termed the Poontana Basin (Figure 2),within a favourable in situ stress regime. Earlyexploration drilling indicates an elevatedgeothermal gradient and heat flow at the projectsite. Petratherm Limited, in joint venture with amajor oil and gas (Beach Petroleum) and powerindustry energy utility (TRUenergy), are initiallyseeking to build a 3.75 - 7.5 MWe commercialpower development to supply a local mine.A local microseismic monitoring network has beendeployed to record background seismicity prior todrilling of the first deep well into the resource,which commenced drilling on the 30 th June 2009.An innovative strategy for development of theEGS reservoir is planned, involving massivehydraulic stimulation of multiple target zoneswithin the sedimentary overburden. This paper willprovide a technical update on progress at theParalana EGS site.Keywords: Geothermal, Stimulation, Drilling,Micro seismic monitoring.Figure 2: Cross-section of the informally termed Poontana BasinHeat exchanger development plan –the HEWI modelOne of the principal limiting factors incommercialising EGS has been the inability tomanufacture a heat exchanger of sufficient sizeand fluid production rate. Existing technicaldifficulties in achieving a robust sub-surface heatexchanger in EGS applications generally relate tothe practice of developing the sub-surface heatexchanger within the heat producing granite rock.Granite is by nature an impermeable andmechanically strong rock. As a result it isinherently difficult for fluid to flow through granite,or to mechanically fracture the rock to develop aneffective reservoir artificially. By comparison, therocks which make up the overlying insulatingsediments tend to have greater naturally occurringporosity and permeability, are mechanicallyweaker, and more susceptible to inducedchemical and mechanical stimulation ifenhancement of the reservoir is required.Figure 1: Regional Locality Map and extent of SAHFA(SAHFA modified from Neumann et. al . 2000)174

Australian Geothermal Energy Conference 2009Figure 3: Schematic diagram demonstrating the basicconcept of an Enhanced Geothermal System using theHEWI (Heat Exchanger Within Insulator) modelThe Heat Exchanger Within Insulator (HEWI)model (Figure 3) aims to exploit naturallypermeable and porous insulating sedimentaryrocks above the granite heat source. Whereintrinsic permeability is inadequate, the HEWIapproach will deliver greater control over thereservoir development through the hydraulicstimulation of these units. This strategy moreclosely approximates the systems successfullyused in petroleum reservoirs and conventionalgeothermal projects. This enables the applicationof techniques for stimulation and geochemicalmitigation developed in these industries.Multi-Zone StimulationHistorical hydraulic fracture stimulations havegenerally been single massive stimulations in anopen hole. The limitation of this method is that theoperator has minimal control over the location anddistribution of the developing fracture network,with most fractures propagating at the base of thecasing shoe near the top of the open hole section.The inability to selectively initiate propagation offractures in the remaining open hole sectionmeans the development of the heat exchangerhas been severely compromised.Given that the development of a complex, thick,interconnected fracture network is the optimalconfiguration for the engineered reservoir, itfollows that undertaking multiple stimulationoperations initiated at different levels in the wellcould achieve the desired outcome. Such anoperation would enable greater control; both interms of the location of initiation of fracturing inthe well bore, and the potential to develop stackedmultiple fracture horizons within suitable single ormultiple geological units.Drilling StatusIn 2007 Petratherm established a joint venturewith Beach Petroleum who elected, under theterms of the Joint Operating Agreement, to“operate” the drilling and stimulation of theParalana #2 well. This was designed as aninjection well, allowing drilling comfortably withincurrent technical limits. Selection of a rig capableof drilling to the target 4000m depth and handlingthe casing strings of the well design demanded a2000 HP rig and the joint venture contractedWeatherford Drilling International to provide anew-build rig. Rig delivery was delayed bymanufacturing capacity and subsequently byHurricane Ike’s effects on the US Gulf.Manufacturing was transferred to Dubai and therig was delivered to site in May 2009 Rig-up andfinal certification allowed spud on the 30 th June2009 (the time of writing this abstract).Figure 4: WDI Rig #828 at Paralana #2 LocationThe well is designed as an injection well, with an18-5/8” x 13-3/8” x 9-5/8” x 7” casing programme.A 20-3/4”-3k x 13-5/8”-5k x 11’-10k wellheadassembly will be installed with an 11”-10k x 7-1/16-10k adaptor-seal flange allowing installationof a full-bore 7-16”-10k valve for stimulation andlater installation of a 4-16” xmas tree. All casingannulus seals are RCS metal-to-metal withpreliminary elastomer seals in the slip and sealassemblies.275

Australian Geothermal Energy Conference 2009Figure 5: Paralana #2 Wellhead at Wood Group Warehouseafter inspectionDrilling is planned to take approximately fourmonths and will be followed with logging of the 8-1/2” section and casing. The 7” casing will be setto total depth and cemented to surface.Preliminary reservoir modelling and well logresults will be used to identify the units tostimulate and to develop final plans for thestimulation programme.A local microseismic monitoring network deployedin late 2008 to record background seismicity priorto drilling was augmented in October 2009 withadditional sondes placed in deeper boreholes toprovide the planned level of monitoring and dataacquisition for the stimulation programme.Stimulation of the Paralana #2 well is expected tocommence later in 2009.TRUenergy joined the joint venture in 2008 andwill provide power generation, transmission andmarketing resources to the project’s development.ReferencesNeumann, N., Sandiford, M., & Foden, J. (2000)Regional geochemistry and continental heat flow:implications for the origin of the South AustralianHeat Flow anomaly. Earth and Planetary ScienceLetters, 183, 107-120.376

Geothermal Energy in the Perth BasinAdrian Larking & Gary MeyerGreen Rock Energy Limitedwww.greenrock.com.auAustralian Geothermal Energy Conference 2009In 2008, the Government of Western Australiaamended the onshore Petroleum Act to includerights to explore for and produce geothermalenergy. The first geothermal exploration rightsunder this legislation were granted to Green RockEnergy in the Perth Basin at the end of July 2009after a process of application by tender. ThePerth Basin straddles the south western coastwhere most of Western Australia’s population andpower infrastructure is located. This favourablelocation close to markets together with the PerthBasin’s geological potential to contain largegeothermal resources presents the opportunity tosupply energy for electricity production and directuse including air-conditioning and desalination ofwater.The Perth Basin is a 1,000 kilometre longgeological rift containing a thick sequence ofsediments in places up to 15 kilometres deep.With its thick sequences of sandstones and thepresence of thermal insulating sediments andcoals the Perth Basin has potential to housegeothermal energy resources in the form of hotsedimentary aquifers (HSA).The highest known heat flows in the Basin havebeen determined from petroleum wells in or nearproducing oil and gas fields in the northern PerthBasin. Green Rock Energy holds 6 GeothermalExploration Permits (GEPs) there near highvoltage power grids where some heat flowsexceed 100mW/m 2 . Temperatures in hotsedimentary aquifers at depths less than 4,000metres should be sufficient for the commercialgeneration of electricity provided sufficientgeothermal water flow rates can be achieved.In the central Perth Basin, where Green RockEnergy holds another two Permits, heat flows aregenerally lower and geothermal waters areexpected to be commercially suitable for directheat uses rather than electricity generation. Inand near Perth low enthalpy geothermal energyresources have been intersected in numerouswater bores drilled to 1,000 metres deep intohighly permeable aquifers. Within Green RockEnergy’s Permit GEP 1 in the western suburbs ofthe city of Perth geothermal energy recoveredfrom aquifers less than 1,000 metres. Thisgeothermal water is used to heat a number ofmajor swimming centres including the ChallengeStadium Aquatic Centre where the WorldSwimming Championships have been held twicein the past decade.At its Perth Permit, GEP1, Green Rock Energyplans to recover geothermal water to power airconditioningand heating at the main campus ofthe University of Western Australia. Geothermalenergy will be used directly to replace electricitycurrently used for air-conditioning at the Universitycampus. To achieve this objective the Companyproposes to drill one production and one injectionwell to depths between 2.5km and 3kms deep intosandstone aquifers. Preparatory work is underwayto enable this drilling to be carried out in 2010.Drilling wells to these depths should not presentany particular difficulty as there is abundanthistory of petroleum wells drilled withoutsignificant problems in the Perth Basin. Thelaterally consistent stratigraphy makes geologicalexpectations and the drilling prognosis reasonablypredictable in the Perth Basin.Commercial viability will depend on obtainingadequate geothermal temperatures and waterflow rates from the sandstone aquifers at depth.Geothermal water temperatures of between 80⁰Cand 100⁰C are required for commercial operationof the absorption chillers which will provide chilledwater for the campus. Temperatures at the targetdepths should be adequate as indicated by heatflow estimates determined from temperaturesmeasured by Green Rock in deep water boreswithin and adjacent to the Permit. A 208 metredrill hole recently completed at the UWA campusconfirmed the estimated heat flows beneath thecampus.To confirm the sub-surface structural geology andflow potential from sediments beneath theUniversity campus the Company evaluatedexisting seismic surveys and data from petroleumwells adjacent to the Perth Permit and completeda gravity survey near the proposed well sites.Hydrodynamic flow modelling has also beencarried out to model the effects of temperaturedrawdown and re-injection on the reservoirs overtime. This has indicated that geothermalproduction will be sustainable over decades usingthe targeted permeabilities and proposedproduction and injection well configuration.177

Australian Geothermal Energy Conference 2009Geothermal Energy Prospectivity of the Torrens Hinge Zone:Evidence from New Heat Flow DataChris Matthews*, Bruce Godsmark.Torrens Energy Limited. PO Box 506, Unley, SA, 5035.* Corresponding author: chris.matthews@torrensenergy.comThe Torrens Hinge Zone is a long but narrow (up to40 km wide) geological transition zone between therelatively stable Eastern Gawler Craton “OlympicDomain” to the west and the sedimentary basinknown as the Adelaide Geosyncline to the east. Itwas hypothesized from first principles that theTorrens Hinge Zone should be prospective for highgeothermal gradients due to the likely presence ofhigh heat flow and insulating cover rocks. A methodto test this hypothesis was devised, which involvedthe measurement of heat flow on a pattern gridusing purpose drilled wells, precision temperaturelogging and detailed thermal conductivitymeasurements. The results of this structured testhave validated the hypothesis, with heat flow valuesover 90 mW/m 2 recorded in several wells drilled.With several kilometres thickness of moderateconductivity sediments overlying the crystallinebasement in this region, predicted temperatures at5000 m are up to 300 o C in some areas.Keywords: Australia, Heat Flow, Thermal Gradient,Thermal Conductivity, Torrens Hinge Zone,Adelaide Geosyncline, Delamerian Fold Belt,Gawler Craton, Curnamona Craton, EngineeredGeothermal Systems, Geothermal Exploration.IntroductionFor an area to be prospective for geothermal powergeneration there must exist high averagegeothermal gradients that indicate hightemperatures at depths which can be economicallydrilled. In addition the heat must be able to beeconomically exploited. This requires the existenceof suitable reservoir rocks with either high naturalporosity and permeability, or the conditions thatallow permeability to be artificially enhanced.Favourable economics are also driven by location,and the cost of bringing the power to marketcompetitively. Geothermal resources are nontransportable, making it desirable that resources belocated proximal to a market.There is a strong economic incentive to locateEnhanced Geothermal Systems (EGS) resourcescloser to the transmission system in southernAustralia. In summary, the following criteria areoptimal for a resource to be viable for economicgeothermal power generation:High average geothermal gradientSuitable reservoir conditions, or the ability toeconomically engineer themA proximal market for the generated powerThe surface heat flow and broad thermalconductivity structure (and thus the temperaturefield) of most of Australia are currently poorlyunderstood. Preliminary estimates (e.g. Somervilleet al, 1994; Chopra & Holgate, 2005) providedbroad approximations of the Australian continenttemperature field, but suffered from a sparsegeographic distribution of heat flow and thermalconductivity data. Over most of the continent, thesedata are not available at sufficient spatial resolutionto allow temperature modelling to a high degree ofconfidence.South Australian Heat Flow AnomalyThe South Australian Heat Flow Anomaly (SAHFA;Neumann et al., 2000) is a region defined looselyby lines of longitude in the central to eastern part ofthe state of South Australia, encompassing reportedelevated heat flow values, but also a number of lowvalues evident in two higher resolution studies.Prior to 1989 less than 30 published heat flowvalues were available for the whole of SouthAustralia with, in many cases, hundreds ofkilometres between measurements (Matthews &Beardsmore, 2007). This dataset enabled only themost basic understanding of the SA heat flowregime, and required sweeping assumptions to bemade about the nature of the heat flow betweendata points. Two subsequent studies by Housemanet al (1989) and Matthews & Beardsmore (2007)collected heat flow data to a much greater spatialresolution in parts of the SAHFA.Houseman et al. (1989) revealed that heat flow isvariable by a factor of more than two in the OlympicDam area, and that the highest values correspondto the locations of the Olympic Dam and Acropolisore bodies, which represent shallow crustalradioactive heat sources (Figure 1). It is estimatedthat the mantle-derived component of heat flow (q r )in the eastern Gawler Craton “Olympic Domain”(Figure 1; Ferris et al 2002), is as low as 20–30mW/m 2 (Neumann et al., 2000). Therefore, the bulkof the surface heat flow anomalies in the OlympicDam area must be due to the crustal component(q c ) of heat flow.Matthews & Beardsmore (2007) obtained a similarspread of results in the south eastern corner ofSouth Australia to that of the Olympic Dam study,with heat flow varying by a factor of three over theregion. Furthermore, the Padthaway Ridge, ashallow crustal geological feature containingPalaeozoic heat producing granitoids - correspondsto the zone of highest heat flow.The Olympic Dam and eastern South Australiaexamples illustrate that the SAHFA is not a zone of178

consistently high heat flow, and that it may be littledifferent to the previously proposed CentralAustralian heat Flow Province (CAHFP e.g.McLaren et al., 2003). The concept is consistentwith the idea that the Proterozoic CAHFP crust hasa ubiquitous value of q r , with broadly uniformtectonothermal history and heat production depthscale (Roy et al., 1968).Geological SettingThe Torrens Hinge ZoneThe study area is located within the Torrens HingeZone (THZ). Preiss (2005) described the THZ as a“zone of syn-sedimentary faulting and flexuringwhich separates the Gawler Craton [in the west]…from the rifted basins of the Adelaide Geosynclineto the east.”Preiss (2000) described the Adelaide Geosyncline(AG) as “a deeply subsident Neoproterozoic toMiddle Cambrian basin complex…with a record ofat least five major successive rift cycles.” TheNeoproterozoic portion of the geological time scaleduring which these sediments were deposited islocally known as the Adelaidean Period (Mawson &Sprigg, 1950), and the five rift cycles are broadlyallocated to five sub-periods, named from oldest toyoungest: Willouran, Torrensian, Sturtian, Marinoanand Cambrian (See Appendix 2).The THZ is essentially a region of overlap betweenthe Gawler Craton and Adelaide Geosyncline(Figure 1). Over the whole of the THZ, theAdelaidean and Cambrian sedimentary sequencesare underlain at depths between 2,500 and 7,000m(de Vries et al, 2006), by the dominantlyMesoproterozoic Gawler Craton Olympic Domain(Ferris et al., 2002). In the south, thePalaeoproterozoic Barossa Complex (e.g. Preiss,1993) also underlies the THZ.To the east in the Adelaide Geosyncline proper, thesediments have been variably deformed by theCambro-Ordovician Delamerian Orogeny (e.g.Preiss, 2000); with that region now part of theDelamerian Fold Belt (DFB). The competent natureof the Olympic Domain basement may haveprotected the THZ region from the full effects of theDelamerian Orogeny. Thus, while the AdelaideGeosyncline is now within the DFB, the THZremains a “meridional belt of gentle folding” (Preiss,2000; see Appendix 1).Close to Port Augusta the earliest rifting phase ofthe Adelaide Geosyncline is marked by theextrusion of the mafic Beda Volcanics at around827 Ma (Preiss, 2000).Torrens Energy has undertaken two seismicsurveys: one in the Parachilna Play, the other nearPort Augusta, and the results (see Appendix 1)have confirmed the geometry of the Torrens HingeZone in the areas surveyed.Australian Geothermal Energy Conference 2009Thermal Conductivity in the THZAs stated earlier, the Adelaide Geosyncline is aNeoproterozoic to Cambrian basin complex. TheGeosyncline contains “a semi-continuous record ofshallow-water sedimentation from the basal… riftsuccession with its associated basalts, through theshallow water sedimentary sequences of theTorrensian, the Sturtian, the Marinoan and theEdiacaran into the Early Cambrian…” (Foden et al,2001).Dominantly Proterozoic in age, the sediments of theAdelaide Geosyncline are generally moremetamorphosed and less porous than mostequivalent Phanerozoic sedimentary units, and thishas previously led them to be overlooked aspotential thermal insulators. Furthermore, themajority of the geographic distribution of these unitsis in the Adelaide Geosyncline proper, and as suchthe sediments there have undergone significantorogenic deformation and metamorphism during thePalaeozoic.The vertical thermal conductivity of a rock can begreatly affected by factors such as the presence oftectonic fabrics or the tilting of bedding planes dueto deformation (Clauser & Huenges, 1995;Beardsmore & Cull, 2001).Thus the effects of deformation very likely reducethe thermal insulating ability of the sediments in theAdelaide Geosyncline region to the east of the THZdue to the effects of the Delamerian Orogeny.However, as discussed above, the THZ was largelyshielded from the deformation associated with theDelamerian Orogeny and therefore also the majorityof the negative effects of anisotropy on verticalthermal conductivity.While sedimentary rocks are generally consideredthe best insulators, mafic volcanics also have lowthermal conductivity. Thermal conductivitymeasurements on Holocene vesicular basalt rocksfrom South Australia were published by Matthews &Beardsmore (2007), with two values averaging 1.58W/mK. A total of 19 samples were analysed fromcore samples of the mafic Neoproterozoic BedaVolcanics, located in the region immediately northof Port Augusta. The harmonic mean of thermalconductivities is 2.51 ± 0.26 W/mK (Musson &Alesci, 2007). The elevated thermal conductivity ofthese samples relative to their Holoceneequivalents may be due to alteration andmetamorphism plus the removal of most of theoriginal vesicular porosity. However, the measuredvalues indicates that the Beda Volcanics are stillgood insulators.Structured Heat Flow MeasurementProgrammeAs with other potential fields, the amplitude andwavelength of surface heat flow and temperaturedistribution are directly related to the magnitude anddepth of the heat source. An intra-crustal heat279

Australian Geothermal Energy Conference 2009Figure 1: Key geological elements of central South Australia. The Torrens Hinge Zone is a narrow elongate transition zonebetween the Eastern Gawler Craton and the Adelaide Geosyncline. Heat Flow values are too widely spaced to gauge the truenature of the SA Heat Flow Anomaly. The inset shows values measured by Houseman et al (1989). Key: Triangles = Historicpublished heat flow values for the region; Stars = Torrens Energy wells. See figures 2a & 2b for heat flow results for TorrensEnergy wells.source should produce a surface heat flow anomalywith a wavelength in a similar order of magnitude asthe depth of burial (e.g. Matthews & Beardsmore,2006). Due to the status of the heat flow data set inAustralia, with most values spaced hundreds ofkilometres apart, it has been previously impossibleto adequately delineate crustal heat flow anomalies.380

The depth to crystalline basement in the THZ isestimated to be between 2.5 and 7 km depth (deVries et al 2006). An effective test of this hypothesistherefore required heat flow data to be collected ata maximum spacing of about 10–15 km to facilitatereasonable accuracy for mapping of heat flowdistribution (although this does not necessarilyallow for local variations in lithology or rock thermalconductivity which can also contribute variation tosurface heat flow distribution).To test the hypothesis that the THZ contains areasof high heat flow and therefore likely high averagegeothermal gradients, a heat flow drilling campaignwas designed in the Torrens Energy GeothermalExploration Licences (GELs). Figures 2a and 2bshow the locations of heat flow wells.Data CollectionEach well was designed to reach a depth where therock is competent enough to be fully cored foraround 200m of continuous downhole depth. Thisinvolved rotary mud drilling through the mostlyunconsolidated Cainozoic clays and sands, found tobe up to 400 m deep, followed by diamond coringthrough the underlying Cambrian andNeoproterozoic sedimentary sequences.Thermal Gradient DataA temperature log from within each heat flow wellwas taken by measuring temperature at discretedepth intervals (0.05 - 2.00 m) from the surface tothe bottom of each well. Sufficient time (at least fiveweeks) was allowed following completion of drillingactivities to ensure thermal equilibration(Beardsmore & Cull, 2001). Temperatures weremeasured to a precision of ±0.001◦C and anabsolute accuracy of ±0.01◦C using truck mountedlogging tools either from Torrens Energy’s in-houselogging equipment or contracted from the SouthAustralian Government Department of Water LandBiodiversity and Conservation (DWLBC).Geothermal gradient varies with lithology. Heat flowremains constant across a geological boundary,and there is an inverse relationship betweengeothermal gradient and thermal conductivity.Thermal Conductivity DataThe vast majority of the purpose-drilled heat flowwells contained at least 200m of continuous coresection. To allow representative thermalconductivity profiles to be established, coresamples were taken every seven to 14 metres onaverage throughout the cored section.Up to three specimens were prepared andmeasured from each sample using a steady statedivided bar apparatus.Heat Flow EstimationHeat flow can only be modelled over intervals withcoincident thermal gradient and thermalconductivity data.Australian Geothermal Energy Conference 2009The following methodology was adopted to reach aheat flow determination for each well.Three assumptions were made. These were that:Each conductivity value is representative of therocks from which the sample was extracted.The boundary between one conductivity valueand the next is the midpoint betweenmeasurement points.A dominantly conductive regime exists.The thermal conductivity profile for each well wasthen used to model a theoretical temperature profilethat would result from a given magnitude of heatflow in a conductive heat flow regime. The observedtemperature log was plotted against this theoreticalprofile, and the magnitude of heat flow wasadjusted until the modelled temperature profile bestmatched the logged temperatures.ResultsIn total, 18 purpose-drilled wells and four existingwells returned 18 new heat flow values in theTorrens Hinge Zone, with two results pending andtwo inconclusive results, providing heat flowcoverage for an area of approximately 6,500 km2 ata spatial resolution suitable for investigating heatsources in the basement.The results of the heat flow study are presented inTable 1 and Figures 2a & 2b, and formed the majorconstraint for the hypothesis test.The results of this structured test have validated thehypothesis, with heat flow values over 90 mW/m2recorded in several of the wells drilled.481

Australian Geothermal Energy Conference 2009Figure 2a: Torrens Energy’s northern tenement areas. The Parachilna Play was the first drilled bythe Company, with the Port Augusta region drilled shortly after. Historical heat flow values areunnamed but labelled, with Torrens Energy heat flow wells named and heat flow values labelled.Key to all wells: Blue = < 70 mW/m 2 ; Yellow = 70 - 89 mW/m 2 ; Red = ≥ 90 mW/m 2 . Black squaresrepresent wells which are either awaiting results or have returned inconclusive results. See Table 1for values.582

Australian Geothermal Energy Conference 2009Figure 2b: Torrens Energy’s southern tenement areas. The tenements are located in primeinfrastructure position, stretching right to inside the city limits of Adelaide. Historical heat flow valuesare unnamed but labelled, with Torrens Energy heat flow wells named and heat flows labelled. Key toall wells: Blue = < 70 mW/m 2 ; Yellow = 70 - 89 mW/m 2 ; Red = ≥ 90 mW/m 2 . Black squares representwells which are either awaiting results or have returned inconclusive results. See Table 1 for values.683

Australian Geothermal Energy Conference 2009DiscussionTorrens Energy used the heat flow and thermalconductivity data to create temperature/depthmodels for several of the regions that were drilled.The primary tool utilized to estimate temperaturewas a 3D temperature inversion software moduledeveloped through collaboration between TorrensEnergy and Hot Dry Rocks Pty Ltd.Inputs into the software included: The 3D geological model of the region inquestion Extensive thermal conductivity measurementsundertaken, plus the assignment of textbookvalues where necessary, with thermalconductivity values assigned to geological unitsin proportions based on published andinterpreted geological data. Published data about internal heat generation inthe rock column. Precision surface temperature and surface heatflow measurements.The temperature modelling software operates onthe principle of ‘inversion’. Known information aboutsurface temperature and surface heat flow isentered into the software module. The softwarethen computes in three dimensions the simplestdistribution of temperature that fits the observations,while respecting the laws of conductive heattransfer and the thermal properties of the geologicalstrata. The temperature dependence of thermalconductivity is also taken into account.Torrens Energy derived 3D temperature models inthis manner for three of its projects – theParachilna, Port Augusta and Yadlamalka Plays(Figure 1).ConclusionIt was hypothesized from geological and conductiveheat flow principles that the THZ is likely to be aregion of high average geothermal gradients andthus prospective for EGS geothermal energy.The heat flow drilling campaign designed to test theidea returned results that have validated thishypothesis.With several kilometres’ thickness of moderateconductivity sediments overlying the crystallineEastern Gawler Craton basement in this region,plus its proximity to existing power infrastructure,the Torrens Hinge Zone is now consideredprospective for economic EGS development.AcknowledgementsWell Heat Flow (mW/m 2 )Edeowie 1 74Gollum 1 106Sauron 1InconclusiveNazgul 1 120Balrog 1 110Gandalf 1 83*Treebeard 1A 91**Torrens 1 80TKHD1A 96Shelob 1 61Moria 1InconclusiveTheoden 2 101Thorin 1 94Rinjin 1 77Uwibami 1 72Raitaro 1 75Norbert 1 74Ancalagon 1 86Falkor 1 57Smrgol 1PendingFaramir 2PendingCLR 105 (Clare) 101Table 1.Surface heat flow measured in wells from this study.*Gandalf 1 displayed a departure from a simple conductiveheat flow inversion model. The best fit conductive model canbe found by applying a heat flow of 116 mW/m 2 in theinterval 375-433 m depth, and 83 mW/m 2 in the interval 433-545 m.**Treebeard 1A heat flow value is preliminaryThe authors wish to acknowledge several people.Dr Graeme Beardsmore from Hot Dry Rocks PtyLtd and Monash University provided guidance onthe measurement and modelling of thermalgradient, thermal conductivity and heat flow in thestudy. Hot Dry Rocks, Alex Musson, Andrew Alesciand Lyndon Parham carried out thermalconductivity measurements on existing rocksamples using Torrens Energy’s divided barapparatus, housed in a laboratory at the Universityof Adelaide. Prof. Mike Sandiford from theUniversity of Melbourne imparted valuableknowledge on the nature and distribution of heatflow and temperature in Australian Proterozoicterranes. Last but not least, the staff and directorsof Torrens Energy Limited (especially ChristineSealing, John Canaris and Dennis Gee) arethanked for collaborating to facilitate the heat flowstudy.784

ReferencesSomerville, M., Wyborn, D., Chopra, P., Rahman,S., Estrella, D. and Van der Meulen, T., 1994, HotDry Rocks Feasibility Study, Energy Research andDevelopment Corporation, Report 243, 133pp.Beardsmore, G. R., and Cull, J. P., 2001 Crustalheat flow; a guide to measurement and modelling.Cambridge University Press 324pp.Chopra, P.N. & Holgate F. 2005 A GIS analysis oftemperature in the Australian Crust. Proceedings ofthe World Geothermal Congress, 2005, Antalya,Turkey 24-29 April 2005, 7 pp.Clauser, C. & Huenges, E., 1995 ThermalConductivity of Rocks and Minerals. In: T. J. Ahrens(ed), Rock Physics and Phase Relations - aHandbook of Physical Constants, AGU ReferenceShelf, Vol. 3, 105-126, American GeophysicalUnion, Washington.Cull, J. P., 1982 An appraisal of Australian heatflowdata. BMR Journal of Australian Geology andGeophysics 7, 11–21.Dalgarno, C. R. and Johnson, J. E., 1966PARACHILNA map sheet. 1st Edition. SouthAustralia Geological Survey Geological Atlas1:250,000 Series, sheet SH 54-13.de Vries, S., Fry, N. & Pryer, L. 2006 OZ SEEBASEProterozoic Basins Study. Report to GeoscienceAustralia by FrOG Tech Pty Ltd.Ferris, G. M, Schwarz, M. P. and Heithersay, P.,2002 The Geological Framework, Distribution andControls of Fe-Oxide Cu-Au Mineralisation in theGawler Craton, South Australia. Part I - Geologicaland Tectonic Framework. In - Porter, T.M. (Ed),2002 - Hydrothermal Iron Oxide Copper-Gold &Related Deposits: A Global Perspective, volume 2;PGC Publishing, Adelaide, 9-31.Foden, J., Barovich , K., Jane, M. & O’Halloran, G.2001Sr-isotopic evidence for Late Neoproterozoicrifting in the Adelaide Geosyncline at 586 Ma:implications for a Cu ore forming fluid flux.Precambrian Research 106, 291–308.Houseman, G. A., Cull, J. P., Muir, P. M., &Paterson, H. L., 1989 Geothermal signatures andAustralian Geothermal Energy Conference 2009uranium ore deposits on the Stuart Shelf of SouthAustralia: Geophysics 54, 158–170.McLaren, S., Sandiford, M., Hand, M., Neumann,N., Wyborn, L., & Bastrakova, I., 2003 The hotsouthern continent, heat flow and heat production inAustralian Proterozoic terranes. Geological Societyof Australia, Special Publication 22, 151–161.Matthews, C. G. & Beardsmore, G. R., 2006 Heatflow: A uranium exploration and modelling tool?MESA Journal 41 Primary Industries & ResourcesSouth Australia, 2006, 8-10.Matthews, C. G. & Beardsmore, G. R., 2007 Newheat flow data from south-eastern South Australia.Exploration Geophysics, 38, 260-269.Mawson, D. & Sprigg, R. C., 1950 Subdivision ofthe Adelaide System. Australian Journal of Science13, 69–72.Musson, A. & Alesci, A., 2007 Thermal conductivity,magnetic susceptibility and specific gravitymeasurements of core samples of the Adelaide‘Geosyncline’ cover sequence. Unpublished reportprepared for Torrens Energy Limited, 32pp.Neumann, N., Sandiford, M. and Foden, J., 2000,Regional geochemistry and continental heat flow;implications for the origin of the South Australianheat flow anomaly. Earth and Planetary ScienceLetters, 183 (1/2), 107–120.Preiss, W.V., 1993 Basement inliers of the MountLofty Ranges. In: Drexel J. F. Preiss W. V. & ParkerA. J. eds. The Geology of South Australia,Geological Survey of South Australia Bulletin 54(1),51 – 105.Preiss, W.V., 2000 The Adelaide Geosyncline ofSouth Australia and its significance inNeoproterozoic continental reconstruction.Precambrian Research, 100, 21–63.Preiss, W. V., 2005 Mineral Explorers Guide,Primary Industries and Resources South AustraliaDVD Publication.Roy, R. F., Blackwell, D. D., & Birch, F. Heatgeneration of plutonic rocks and continental heatflowprovinces. Earth & Planetary Science Letters,5, 1-12, 1968.885

Australian Geothermal Energy Conference 2009Appendix 1: Seismic Surveys and Results.Parachilna Seismic Survey, completed January 2009Interpretation belowCambrianBase CainozoicNeoproterozoicEdiacara FaultMesoproterozoicAnd Older Basement986

Australian Geothermal Energy Conference 2009Port Augusta Seismic Survey, completed May 2009Base CainozoicNeoproterozoicMesoproterozoicAnd Older BasementRangeFrontFault1087

Australian Geothermal Energy Conference 2009Appendix 2: Generalised Stratigraphic Column for the Torrens Hinge ZoneTorrens Hinge Zone General StratigraphyAge Group Common Units PresentPleistocene/Holocene Pirie-Torrens Basin Undifferentiated Clays and GravelsOligocene-Miocene Pirie-Torrens Basin Neuroodla FormationEocene Pirie-Torrens Basin Cotabena FormationMiddle CambrianLake Frome GroupPantapinna FormationBalcoracana FormationMoodlatana FormationMiddle CambrianUnnamed GroupWirrealpa LimestoneBilly Creek FormationEarly CambrianHawker GroupWilkawillina LimestoneNeoproterozoic (Adelaidean,Late Marinoan)Neoproterozoic (Adelaidean,Late Marinoan)Neoproterozoic (Adelaidean,Late Marinoan)Neoproterozoic (Adelaidean,Early Marinoan)Neoproterozoic (Adelaidean,Early Marinoan)Neoproterozoic (Adelaidean,Late Sturtian)Neoproterozoic (Adelaidean,Early Sturtian)Neoproterozoic (Adelaidean,Late Torrensian)Neoproterozoic (Adelaidean,Middle Torrensian)Neoproterozoic (Adelaidean,Early Torrensian)Neoproterozoic (Adelaidean,Willouran)Mesoproterozoic EasternGawler CratonPalaeoproterozoicWilpena GroupPound SubgroupWilpena GroupWilpena GroupSandison SubgroupUmberatana GroupYerelina SubgroupUmberatana GroupUpalinna SubgroupUmberatana GroupNepouie SubgroupUmberatana GroupYudnamutana SubgroupBurra GroupUnnamed SubgroupBurra GroupMundiallo SubgroupBurra GroupEmeroo SubgroupParachilna FormationRawnsley QuartziteBonney SandstoneWonoka FormationBunyeroo FormationABC Quartzite (incl. Corraberra Sandstone)Brachina Formation (incl. Tregolana Shale)Nuccaleena FormationElatina Formation/Whyalla SandstoneTrezona FormationWilmington FormationAngepena FormationEtina FormationBrighton LimestoneTapley Hill Formation (incl. WoocallaDolomite Member)Wilyerpa FormationAppila TilliteOther equivalent Sturtian GlacialsSaddleworth FormationSkillogalee DolomiteRhynie SandstoneBeda VolcanicsBacky Point FormationCallanna GroupPandurra FormationGawler Range VolcanicsHiltaba Suite GranitoidsBarossa Complex1188

Australian Geothermal Energy Conference 2009Establishing Hot Rock Exploration Models: From Synthetic ThermalModelling to the Cooper Basin 3D Geological MapTony Meixner 1* , Stephen Johnston 1 , Alison Kirkby 1 , Helen Gibson 2 , Ray Seikel 2 , Kurt Stüwe 3 , DesFitzGerald 2 , Nick Horspool 1 , Richard Lane 1 and Anthony Budd 11 Geoscience Australia. GPO Box 378, Canberra, ACT, 26012Intrepid Geophysics, Unit 2, 1 Male St, Brighton VIC 31863Universitaet Graz, Heinrichstr. 26 A-8010, Austria* corresponding author Tony.Meixner@ga.gov.auA large number of exploration models for HotRock geothermal energy plays in Australia arebased on high-heat producing granites (HHPG) incombination with overlying low-conductivitysedimentary rocks providing the insulatornecessary to accumulate elevated temperaturesat unusually shallow (therefore accessible)depths. Unknowns in this style of geothermal playinclude the composition and geometry of theHHPG and its thermal properties and thethickness and thermal properties of the overlyingsediments. A series of 3D geological modelshave been constructed to investigate the range ofgeometries and compositions that may give rise toprospective Hot Rock geothermal energy plays.A 3D geological map of the Cooper Basin region,which contains known HHPG beneath thicksedimentary sequences, and the MillungerraBasin region east of the Mt Isa Inlier, have beenconstructed from gravity inversions constrained bygeological data. The inversion models delineateregions of low density within the basement thatare inferred to be granitic bodies. Thermalforward modelling was carried out usingGeoModeller software by assigning measuredand estimated thermal properties to the mappedlithologies.An enhancement of the GeoModeller softwareallows input of thermal properties to be specifiedas distribution functions. Multiple thermalsimulations were used to estimate the in-situ heatresource, thus reducing the exploration risk. Thetwo thermal modelling techniques can be used asa predictive tool in regions where little or notemperature and geological data are available.A series of synthetic 3D maps were constructedusing different granite geometries beneath varyingthicknesses of cover sediments. The gravity, heatflow and vertical temperature gradients wereforward modelled using typical density contrasts,heat production rates and thermal conductivities.Geothermal explorers in the Cooper Basin regioncan now use the results of the density modellingto identify the geometries and depth of burial ofpotential HHPG bodies, and also use the resultsof the thermal modelling to predict heat flows andtemperature gradients associated with the bodies.Keywords: 3D map, thermal modelling, stochastic,Cooper Basin, high-heat producing granites,inversion modellingIntroductionHot Rock geothermal exploration methods used inAustralia are significantly different to those usedfor conventional geothermal plays elsewhere inthe world. Hot Rock geothermal energy playsessentially comprise a heat source and aninsulating layer. In Australia, high-heat producinggranites (HHPG) are often the presumed heatsource, while low-conductivity sedimentary rocksprovide the insulator necessary to create anaccumulation of heat and elevated temperatures.Other elements of a hot rock geothermal playsuch as porosity, permeability and fracturenetworkingare also crucial, though these cansometimes be artificially enhanced byhydrofracturing or chemical treatment to achievethe required permeability.There are two fundamental unknownssurrounding the minimum requirements toproduce an Australian style Hot Rock geothermalplay. The first unknown is the amount of heatproduction required, which is linked to theconcentration of radiogenic elements, and thevolume and geometry of HHPGs. The secondunknown is the thermal insulation required fromthe overlying basin sediments, which is a functionof the thickness and thermal conductivity of theoverlying sediments above a given granite.To investigate the range of geometries andcompositions that may give rise to Hot Rockgeothermal systems, two linked processes havebeen undertaken in this study. Firstly, thermalmodelling has been conducted using a 3Dgeological map from a well-constrained area.Secondly, a series of synthetic models have beenconstructed for 3D temperature and heat flowmodelling.Cooper Basin 3D geological mapA summary of the geology of the Cooper Basinregion is provided in Meixner and Holgate(2009a,b). In brief, significant volumes of BigLake Suite (BLS) granodiorite intrude basement(Figure 1). Thick sedimentary sequences in theCooper and overlying Eromanga Basins provide athermal blanketing effect for these anomalouslyhigh-heat producing BLS intrusions, resulting intemperatures up to 270° C at depths less than5 km. The region, which straddles the189

Australian Geothermal Energy Conference 2009Queensland/South Australia border, is coincidentwith a prominent geothermal anomaly (Cull andDenham, 1979; Cull and Conley, 1983; Somervilleet al., 1994) (Figure 2). The region also formspart of a broad area of anomalously high heat flowwhich is attributed to Proterozoic basementenriched in radiogenic elements (Sass andLachenbruch, 1979; McLaren et al., 2003).Australia’s first commercial Enhanced GeothermalSystem (EGS) is under development atHabanero-1 and Habanero-3 near Innamincka(Figure 1).densities of the Eromanga/Cooper Basinsediments and the granitic bodies wereconstrained to narrow ranges based on measuredand inferred values, while the density of thebasement was left unconstrained. A perspectiveview of the interpreted sub-sediment graniticbodies in the 3D map is shown in Figure 4.Figure 1. Location of the Cooper Basin region, showing thespatial extents of the stacked Warburton, Cooper andEromanga Basins. The red dashed box indicates the extentof the original 3D map, the blue outline indicates the extent ofthe extended 3D map, and the green box indicates the extentof the test-bed thermal model.A 3D geological map for the Cooper Basin regionwas constructed as part of a previous study(Meixner and Holgate, 2009a,b). The map, whichcovered an area of 300 by 450 km (Figure 1), wasbased in part on 3D inversions of Bouguer gravitydata using the method of Li and Oldenburg(1998). The geometries and densities of theEromanga and Cooper Basin, derived from welland seismic data, as well as gravity ‘worms’(Archibald et al., 1999) were used to constrain theinversions. The 3D map delineates regions of lowdensity within the basement of theCooper/Eromanga Basins that are inferred to begranitic bodies. This interpretation is supportedby spatial correlations between the modelledbodies and known granite occurrences from drillholes in the area. Figure 3 shows a densitysection through the inversion model. TheFigure 2: Predicted temperature map at 5 km for the CooperBasin region, based on bottom hole temperatures, afterChopra and Holgate (2005). Well locations are shown.For the present study, the 3D map was extended150 km to the east and 100 km to the north inorder to cover the entire Cooper Basin region(Figure 1). In addition, the map includes moredetailed subdivisions for the Eromanga (Van DerWielen, in prep) and Cooper Basin stratigraphies,based on data from ~1000 wells. The greaterstratigraphic detail allowed for enhancedgeological constraint during the gravity inversionmodelling, as well as significantly better control onthe assignment of thermal conductivities toindividual geology units during the thermalmodelling process. Delineation of the subsedimentgranitic bodies, for this extended versionof the 3D map, was carried out using themethodology described in Meixner and Holgate(2009a,b). The original 3D inversions used singledensity values for the Eromanga and Cooperbasins that were derived from a refraction seismicsurvey in the study area (Collins and Lock, 1990).The present study used an averaged densityvalue for each individual stratigraphic unit derivedfrom well density logs. The use of enhanceddensity constraints for the sedimentary sectionenhances the credibility of the density variationsderived for the basement unit, and thereforeprovides a more accurate delineation ofinterpreted granitic bodies.290

Australian Geothermal Energy Conference 2009Figure 3: North-south density section through the lithoconstrainedgravity inversion model. Eromanga Basinsediments (dark blue: 2.3 +/- 0.2 g cm-3), Cooper Basinsediments (light blue: 2.5 +/- 0.2 g cm-3) and the graniticbodies (green: 2.6 +/- 0.2 g cm-3) were constrained to anarrow density range, while the basement (yellow-red: 2.65-2.75 g cm-3) was left unconstrained. The section is 450 kmlong and 20 km deep.a specified threshold; or b) a specified maximumnumber of iterations were reached – whicheveroccurred first. The thermal quantities computedwere: temperature, vertical heat flow, verticaltemperature gradient and total horizontaltemperature gradient.Results of the test-bed thermal modelling werecompared to 21 corrected bottom holetemperature (BHT) measurements (Chopra andHolgate, 2005), as well as 30 modelled 1D heatflow measurements (Beardsmore, 2004) fromwells in the test area. A number of thermalmodels were generated by minimising thetemperature differences between the BHTs andthe modelled temperatures, as well as minimisingthe difference between the measured andmodelled heat flow measurements. Verticaltemperature sections through the final test-bedthermal model are shown in Figure 5. Thesections show a clear rise in temperature atshallow depth in the north of the model that iscoincident with a HHPG intersected by wells.Figure 4: Cooper Basin region 3D map viewed obliquely fromthe south showing the inferred sub-sediment granitic bodies,overlying an image of gravity data.Cooper Basin thermal forwardmodellingA region 188 by 144 km, by 16 km in depth wasextracted from the initial Cooper Basin 3D mapand used as a test region (Figure 1) for modellingthe temperature, heat flow and geothermalgradients. The test region was populated withthermal properties (heat production rates andthermal conductivities) for each lithology andboundary conditions were approximated (meansurface temperature) or assumed (Neuman-typeside boundaries, constant basal heat flow). Initialheat production rates for the granites andsediments and thermal conductivities for thesediments were sourced from published literature(Beardsmore, 2004; Middleton, 1979).Temperature predictions were generated on adiscretised version of the model withinGeoModeller 1 using the method described bySeikel et al. (2009). Temperatures were solvedby explicit finite difference approximation using aGauss-Seidel iterative scheme implemented untileither: a) the sum of the residual errors fall belowFigure 5: Vertical sections through the 3D temperature modelshowing the locations of the BHT data (dark blue). Modelledtemperatures range from 27° (blue) to 390° (red).The thermal modelling has provided constraintson the possible thermal conductivity and heatproduction properties of the basement, as well asa predicted value of mean heat flow into the baseof the model. This information, together withadditional thermal conductivity measurementsfrom drill core, were then used in a thermal modelof the extended 3D map to predict thetemperature, thermal gradient and heat flow inregions where little or no temperature data exists.Cooper Basin stochastic thermalmodellingIn order to explore the uncertainty of estimates ofheat resources within the Cooper Basin region,we have used an approach based on thegeneration of multiple models. These models willreflect the full population of viable alternatives,consistent with the expected thermal propertyprobability distribution functions (for thermalconductivity and heat production rate) – but withfixed geological geometries.The initial voxet model of preferred geology(discretised from the continuous geology model)was generated in GeoModeller. From this initialvoxet model, multiple models containing theplausible ranges of varying thermal properties391

Australian Geothermal Energy Conference 2009were produced. Following forward 3Dtemperature calculations, the family of voxetmodeloutcomes (3D results for temperature, heatflow and geothermal gradient) were theninterrogated by statistical methods to yield theprobability estimates of the in-situ heat resourcefor the Cooper Basin.To implement this approach we are developing anew solver strategy for the steady-state heatequation that can be scaled to the larger volumesof rock in this study. A fast solver for theinhomogeneous heat equation in free space,following the time evolution of the solution is beingdeveloped using Fourier domain techniques. Themethod we are developing is up to 1000 timesfaster than the commonly used finite differenceand finite element methods. It can also solvemuch larger problems. This simulation workbuilds on the work of Li and Greengard, (2007)and Osterholt et al. (2009).The Millungera Basin 3D geologicalmapThe previously unknown Millungera Basin (Korschand Huston, 2009), to the east of the Mt Isa Inlierwas identified in the 2006 Mt Isa (Hutton, et al.,2009) and 2007 North Queensland seismicsurveys (Korsch et al., 2009). Geologicalrelationships suggest that the age of the basin,which underlies the Carpentaria-Eromangabasins, lies between the Mesoproterozoic andEarly Mesozoic. Non-reflective zones below thebase of the Millungera Basin that are interpretedas granite, also coincide with gravity lows. Basedon this interpretation, the region may hostpotential Hot Rock geothermal plays given thehigh-heat producing nature of nearby granites ofthe Williams Batholith (Hutton, et al., 2009) andthe thick sequences, up to approximately 3900 m,of potentially insulating Millungera sediments.A 3D geological map (192 by 315 km, 20 kmdepth extent) is currently being constructed overthe Millungera Basin using similar methodologiesto the Cooper Basin study. This 3D map will formthe basis for thermal modelling in order to gain abetter understanding of the thermal properties of aregion that contains no heat flow measurementsand few down-hole temperature measurements.Synthetic modellingA key dataset for geothermal energy explorationin Australia is the gravity anomaly map ofAustralia (Murray et al., 1997). Buried granitestypically exhibit a negative gravity anomaly inrelation to the crystalline basement they intrude,due to their lower relative density. A total of 648unique granite models have been produced,based on differing diameter circular granites(5 km, 10 km, 20 km, 30 km, 50 km and 70 km),with different depth extents (2, 4, 6, 8, 10 and 12km) embedded in basement. These models alsoinclude different depths of burial of thegranite/basement beneath sediments (varyingfrom 1000 m to 6000 m, in 1000 m increments) aswell as three different density contrasts betweenthe granites and basement (Figure 6).Figure 6: Synthetic model showing a series of granitesembedded in basement and overlain by 6 km of sediments.Granite diameters range from 5 to 70 km. Granitethicknesses range from 2 to 12 km.Forward modelling the gravity signatures from thiswide range of starting models produces acomprehensive range of gravity anomalies. Ageothermal explorer, interested in identifyingunknown potential HHPG beneath a sedimentarybasin, will be able use gravity anomaly maps toidentify gravity lows and then match theirobserved anomaly with a likely style of modelledanomaly (and associated geometry, depth ofburial and density contrast).Due to the non-uniqueness of interpretations ofgravity data, the explorer may not be able to pinpointa single model because a number ofdiffering geometries and density contrasts couldproduce a similar gravity anomaly. The explorerwill, however, have a range of potential granitegeometries for use in predicting temperature andheat flow. As more geological knowledge isgained about a particular region, such as thethickness of sediments and/or density contrastbetween the granite and basement, the number ofmodelled granite geometries that match theobserved data will become restricted.Once potential granite geometries have beenidentified, the 3D thermal models can be used topredict surface heat flow and vertical temperaturegradient. For a selected granite geometry theexplorer can then choose from a range of inputs(five different heat production rates for thegranites and five different thermal conductivitiesfor the overlying sediments) to predict the likelyheat flow and thermal gradient over the granitebody. In all, a total of 5400 unique geothermalscenarios were produced from 216 uniquegranite/sediment geometries. The gravity andthermal anomaly are displayed in graph form inorder to condense the results so they are easierto interpret and use.SummaryCase study 3D maps and thermal models, suchas the Cooper and Millungera Basin studies,incorporate all available geological knowledge intoa 3D map. Often little or no information is known492

Australian Geothermal Energy Conference 2009about the basement composition beneathsedimentary basins. Inversion of gravity data is,therefore, a valuable tool for identifying regions oflow density within the basement that arepotentially due to granitic bodies, which in turnmay be acting as a viable heat source for a hotrock geothermal energy play.Thermal forward modelling and stochastic thermalmodelling of 3D maps, which contain bothpotential heat sources and thermally insulatingcover, can be used as a predictive tool to identifythe locations of potential geothermal plays.Where case study models do not exist, syntheticmodelling provides a systematic approach to theinterpretation of exploration datasets.References1 GeoModeller is a commercially availablesoftware package and has been produced byIntrepid Geophysics and Bureau de RecherchesGéologiques et Minières (BRGM).www.geomodeller.com.Archibald, N., Gow, P., and Boschetti, F., 1999,Multiscale edge analysis of potential field data:Explor. Geophys., 30, p. 38-44.Beardsmore, G.R., 2004, Thermal modelling ofthe Hot Dry Rock geothermal resource beneathGEL99 in the Cooper Basin, South Australia:Sydney: 17th Aust. Soc. Explor. Geophys.Conference. Extended Abstracts.Chopra, P., and Holgate, F., 2005, A GIS Analysisof Temperature in the Australian Crust: WorldGeothermal Congress, Turkey, 24-29 April 2005,Abstracts.Collins, C.D.N., and Lock, J., 1990, Velocityvariations within the upper crustal basement ofthe central Eromanga Basin: Bureau of MineralResources, Geology and Geophysics, Canberra.Bulletin, 232, p. 177-188.Cull, J.P., and Denham, D., 1979, Regionalvariations in Australian heat flow: Bureau ofMineral Resources, Journal of Australian Geologyand Geophysics 4, p. 1-13.Cull, J.P., and Conley, D., 1983, Geothermalgradients and heat flow in Australian sedimentarybasins: Bureau of Mineral Resources, Journal ofAustralian Geology and Geophysics 8, p. 329-337.Hutton, L.J., Gibson, G.M., Korsch, R.J., Withnall,I.W., Henson, P.A., Costelloe, R.D., Holzshuh, J.,Huston, D.L., Jones, L.E.A., Maher, J.L.,Nakamura, A., Nicoll, M.G., Roy, I., Saygin, I.,Murphys, F.B., and Jupp, B., 2009 Geologicalinterpretation of the 2006 Mt Isa Seismic Survey:In: Camuti, K., and Young, D. eds., NorthernQueensland Exploration & Mining 2009 and NorthQueensland Seismic and MT Workshop:Extended Abstracts. Australian Institute ofGeoscientists Bulletin No. 49, p. 137-142.Korsch, R.J., and Huston, D.L., 2009.Geodynamics and Metallogeny of NorthQueensland: insights from new deep crustalseismic data: In: Camuti, K., and Young, D.eds., Northern Queensland Exploration & Mining2009 and North Queensland Seismic and MTWorkshop: Extended Abstracts. AustralianInstitute of Geoscientists Bulletin No. 49, p. 57-63.Korsch, R.J., Withnall, I.W. Hutton, L.J., Henson,P.A., Blewett, D.L., Huston, D.L., Champion, D.,Meixner, A.J., Nicoll, M.G., and Nakamura, A.,2009, Geological interpretation of deep seismicreflection line 07GA-IG1 the Cloncurry to Croydontransect: In: Camuti, K., and Young, D.eds., Northern Queensland Exploration & Mining2009 and North Queensland Seismic and MTWorkshop: Extended Abstracts. AustralianInstitute of Geoscientists Bulletin No. 49, p. 153-158.Li, J-R., and Greengard, L., 2007, On thenumerical solution of the heat equation I: Fastsolvers in free space: Journal of ComputationalPhysics 226, p. 1891-1901.Li, Y., and Oldenburg, D.W., 1998, 3-D inversionof gravity data: Geophysics, 63, p. 109-119.McLaren, S., Sandiford, M., Hand, M., Neumann,N., Wyborn, L., and Bastrakova, I., 2003, The hotsouthern continent; heat flow and heat productionin Australian Proterozoic terranes: In: Hills, R.R.,and Mueller, D.R. eds., Evolution and dynamics ofthe Australian Plate. Geol. Soc. of AmericaSpecial Paper 372, p. 157-167.Meixner, A.J. and, Holgate, F., 2009a, In searchof hot buried granites: a 3D map of sub-sedimentgranitic bodies in the Cooper Basin region ofAustralia, generated from inversions of gravitydata: Adelaide: 20th Aust. Soc. Explor. Geophys.Conference. Extended Abstracts.Meixner, A.J., and Holgate, F., 2009b, TheCooper Basin Region 3D Map Version 1: ASearch for Hot Buried Granites: GeoscienceAustralia, Record, 2009/15.Middleton, M.F., 1979, Heat flow in the Moomba,Big Lake and Toolachee gas fields of the CooperBasin and implications for hydrocarbonmaturation: Bulletin – Aust. Soc. of ExplorationGeophysics 10(2), p. 149-155.Murray, A.S., Morse, M.P., Milligan, P.R. and,Mackey, T.E., 1997, Gravity anomaly map of theAustralian region (second ed.), scale 1:5 000 000.Australian Geological Survey Organisation,Canberra.Osterholt, V., Herod, O., and Arvidson, H., 2009,Regional Three-Dimensional Modelling of IronOre Exploration Targets, Proceedings: Orebody593

Australian Geothermal Energy Conference 2009Modelling and Strategic Mine PlanningConference, Perth.Sass, J.H., and Lachenbruch, A.H., 1979,Thermal regime of the Australian ContinentalCrust, in McElhinny, M.W,, ed., The Earth: itsorigin, structure and evolution. Academic Press,London, p. 301-351.Seikel, R., Stüwe, K., Gibson, H., Bendall. B.,McAllister, L., Reid, P., and Budd, A., 2009,Forward prediction of spatial temperaturevariation from 3D geology models: Adelaide: 20thAust. Soc. Explor. Geophys Conference.Extended Abstracts.Somerville, M., Wyborn, D., Chopra, P., Rahman,S., Estrella, D., and Van der Meulen, T., 1994,Hot dry rock feasibility study: Energy Researchand Development Corporation, Report 94/243.133pp.Van der Wielen, S.E., Kirkby, A., Britt, A.,Schofield, A., Skirrow, R., Bastrakov, E., Cross,A., Nicoll, N., Mernagh, T., and Barnicoat, A.,2009, Large-Scale Exploration Targeting forUranium Mineral Systems within the EromangaBasin. Townsville 10th Soc. Geol. App. Min. DepConference. Extended abstracts. in prep.694

Australian Geothermal Energy Conference 2009Hydro-Mechanical Selection Criteria of Engineered GeothermalSystemsLuke MortimerHot Dry Rocks Pty Ltd, GPO Box 251, South Yarra, Victoria 3141, Australialuke.mortimer@hotdryrocks.comStored heat geothermal resource estimatescommonly extend across an extensive area andoften contain more than one potential GeothermalPlay. It is critical that an informed decision bemade about which exploration Play has the bestchance of commercial success. The decisionmight be between a deep Engineered GeothermalSystems (EGS) Play and a shallow HotSedimentary Aquifer (HSA) Play, or betweenseveral potential Plays at different levels. In anycase, the critical parameters are resourcetemperature, depth and potential deliverability. Astored heat resource estimate constrains the firsttwo parameters, leaving deliverability as the keyrisk.In the case of HSA reservoirs, deliverability islargely dictated by the preservation of primaryporosities and permeabilities at depths below thetarget operational isotherm. An HSA reservoirtarget may, however, lie at a depth wherecompaction processes have destroyed asignificant proportion of its primary porosity andpermeability. Such reservoirs should then beconsidered and developed as EGS or partial EGSreservoirs. In the case of EGS reservoirs,deliverability is largely dictated by the inherenthydro-mechanical properties of the reservoir rockand its fracture network, coupled with the in situstress field. This paper summarizes the keydatasets and knowledge required to makeinformed decisions about deliverability anddevelopment potential of possible EGS reservoirs.Keywords: Engineered Geothermal Systems,Discrete Fracture Network, Numerical Modelling,Stress.Development of an EGS ReservoirThe main mechanism for creating a geothermalreservoir and enhancing its in situ permeability isthe shearing of pre-existing natural fracturesduring the process of hydraulic stimulation. Thisprocess involves the accommodation of aninjected volume of water in fractures openedduring elastic compression of the adjacent rockmass, rigid body block translation and permanentfracture dilation in response to sheardisplacement. These all depend upon the natureof the in situ stress field and the inherentproperties of the host rock and its fracturenetwork. In particular, shear deformation of preexistingnatural fractures is controlled by theelastic, cohesive, frictional and dilationalproperties of the host rock and fracture networkwith preferential reservoir growth and fluid flowoccurring along fractures oriented ~parallel to thepresent-day, maximum principle stress direction.The creation of pure hydraulic fractures duringstimulation has been shown to be rare andrestricted to the near-well environment.The critical information required for optimalplanning of an EGS development includes: The nature of the in situ stress field (stressregime, orientation, magnitude and gradient).Characterisation of the primary structuralfeatures of the target reservoir (fault andfracture density, orientation and connectivitydistributions). Characterisation of the hydro-mechanicalproperties of the rock material and fracturenetwork. Preliminary identification of faults andfractures amenable to hydraulic stimulation. Predicted reservoir growth and anisotropicpermeability direction in response to hydraulicstimulation. Estimation of fluid injection pressuresrequired for controlled hydraulic stimulation.The preliminary investigation of these primaryfeatures has a major impact on the planning,design, implementation and exploitation of anEGS project. For example, this information can beused to develop reservoir injection and circulationstrategies that optimise reservoir growth andproduction whilst minimising the risk of high flowimpedance or short-circuiting. These are also thekey datasets required for coupled thermalhydrogeological-geomechanicalmodelling of ageothermal reservoir.Conceptual Reservoir TypesFrom a purely heat extraction point of view, thebest reservoir host rock is that with the highestthermal conductivity (i.e. allows the greatest rateof heat extraction). At a proposed EGS site, thehighest thermal conductor could either be the heatsource itself (high heat producing granites) or adifferent rock type within the overlying insulatingsequence. However, the ultimate performance ofan EGS reservoir is determined by the hydromechanicalproperties and behaviour of the hostrocks. These control fluid flow and residence timebetween injection and production wells. From ahydro-mechanical point of view, there are two195

Australian Geothermal Energy Conference 2009broad types of conceptual EGS reservoir targets;those with zero effective natural permeability, andthose with finite but low natural permeability.Type 1 : Hydraulically tight rocks at depth(approx. ≥ 4km)Type 1 examples include rock types such ascrystalline igneous or metamorphic basementrocks with little to no in situ porosity orpermeability. These rocks are typically of highstiffness and poor fracture density and occur atdepths with relatively high confining pressures.These stronger rock types tend to developrelatively rough fracture surfaces with higherfracture shear strengths and display a strongcoupling between shearing and hydraulicconductivity. Potentially these characteristicsallow reservoir development during hydraulicstimulation to be more easily constrained with alower probability of significant fluid losses.However, experience has found that creating areservoir in stiff and hydraulically tight rocks mayalso be difficult. They may experience poorcirculation due to high flow impedance even afterstimulation and may require high injectionpressures to open fractures and achieve thenecessary fluid volume throughput. This may leadto increased risk of runaway fracture growth, fluidpathway short-circuiting and water losses.Type 2 : Finite but low permeability rocks atshallower depths (approx. ≤ 4km)Type 2 examples may include a wide range ofrock types that occur within high temperature butrelatively shallower depth settings such as in agraben structure (e.g. Soultz). Rocks in theselocations generally have higher in situpermeabilities and may be more easily stimulateddue to lower confining pressures and rock massstiffness. Reservoir rock types may also includenon-crystalline, weaker rock types, such aslayered sediments, within the insulating horizon.Layered sedimentary units may contain higher insitu permeabilities due to relatively higher fracturedensities including bedding planes. The potentialdisadvantages of Type 2 reservoir targets are thatreservoir growth may be more difficult to constrainwith an increased probability of fluid losses.Within a sedimentary basin setting additionalcomplexities may arise from an increasedprobability of chemical alteration from basinalfluids and an increased probability of local stressfield perturbations due to major basin structuresor interbedded rock types with significantmechanical contrasts.Hydro-Mechanical Coupling in EGSReservoirsThe phenomenon of stress-dependant fracturepermeability is well documented in studies ofdeep-seated, fractured hydrocarbon andgeothermal reservoirs and nuclear repositories(e.g. Gentier et al., 2000; Hillis et al., 1997;Hudson et al., 2005). Specifically, in situ stressfields are known to exert a significant control onfluid flow patterns in fractured rocks with a lowmatrix permeability. For example, in a key studyof deep (>1.7 km) boreholes, Barton et al. (1995)found that permeability manifests itself as fluidflow focused along fractures favourably alignedwithin the in situ stress field, and that if fracturesare critically stressed this can impart a significantanisotropy to the permeability of a fractured rockmass. Preferential flow occurs along fractures thatare oriented orthogonal to the minimum principalstress direction (due to low normal stress), orinclined ~30° to the maximum principal stressdirection (due to shear dilation).Stress-dependent fracture permeability forms as aresult of the interplay between normal and shearstresses, which are the components of stress thatact perpendicular and parallel to a fracture plane,respectively. In a fractured rock mass, thesestresses are highly coupled and can causefractures to deform. Fracture deformation resultsin changes in permeability and storage becausethe ability of a fracture to transmit a fluid isextremely sensitive to its aperture asdemonstrated by the “Cubic Law”. This lawdefines the bulk hydraulic conductivity of afractured medium in the direction parallel to thefractures assuming that fractures are planar voidswith two flat surfaces within an impermeablematrix. For an isolated test interval within aborehole, it is expressed as:3(2b) gK b =(1)2B 12where K b is the bulk hydraulic conductivity (m.s -1 )(where K b = Transmissivity/test interval), 2b is thefracture aperture width (m), 2B is the fracturespacing (m), is the fluid density (kg.m -3 ), g isgravitational acceleration (m.s -2 ) and μ is thedynamic viscosity of the fluid (Pa.s).Anisotropic flow behaviour or flow channelling isparticularly strong in low fracture density and lowpermeability rocks typical of potential EGS Plays.Fluid flow is dominantly controlled by fracturenetwork density, geometry, connectivity andmineralization whilst contemporary stress fieldssuperimpose a secondary influence on preexistingfracture networks by deforming themfurther. In numerical modelling exercises, thesefeatures are best represented through the use ofcoupled hydro-mechanical, discrete fracturenetwork (discontinuum) models.Hydro-Mechanical Characteristics ofEGS ReservoirsThis study presents a methodology that attemptsto describe the hydro-mechanical character andbehaviour of a fractured rock reservoir from amulti-disciplinary approach prior to any hydraulic296

Australian Geothermal Energy Conference 2009stimulation. The results of this methodology canbe used to qualitatively to semi-quantitatively rankthe EGS suitability of potential reservoir rock unit,to identify potentially permeable structures and toestimate injection pressures and reservoir growthdirections during hydraulic stimulation. This multidisciplinaryapproach consists of four keycomponents, which include: Determination of the in situ stress field;Geological and hydrogeologicalcharacterisation;Geomechanical characterisation; andHydro-mechanical modelling.Determination of the In Situ Stress FieldThe description of any in situ stress field includesthe relative arrangement of the three mutuallyorthogonal principal axes of stress referred to asthe maximum ( 1 ), intermediate ( 2 ) and minimum( 3 ) principal axes of stress. As the Earth’ssurface is a free surface with zero shear stressthe vertical stress ( V ) is assumed to be one ofthese principal axes of stress. The other twoprincipal axes of stress consist of the two mutuallyorthogonal, horizontal stress orientations referredto as the maximum and minimum horizontalprincipal axes of stress ( H and h , respectively).In practice, far-field crustal stress regimes areclassified using the Andersonian scheme, whichrelates the three major styles of faulting in thecrust to the three major arrangements of theprincipal axes of stress (Anderson, 1951). Thesethree major stress regimes are:(a) Normal faulting stress regime where V > H > h ;(b) Strike-slip faulting stress regime where H > V > h ; and(c) Thrust faulting stress regime where H > h > V .To estimate the effective stress state (’) alsorequires that an estimate of the pore fluidpressures (P p ) within the rock formation, as ’ isdefined as the difference between the appliedstress () and the internal pore fluid pressure:’ = – P p (2)The effective stress is critical as it controlscoupled hydro-mechanical behaviour (orporoelasticity) by affecting fracture deformationprocesses as fluid pressures act to reduce thestress acting normal to a fracture plane. Forexample, high effective stresses with relativelylow fluid pressures act to close fractures whilstlow effective stresses with relatively high fluidpressures act to dilate fractures.There are several techniques for measuring themagnitude and orientation of in situ stresses,among which the following are common (Zoback,2007): Overcoring and strain relief methods.Hydraulic fracturing.Imaging of (vertical) borehole breakouts anddrilling-induced tensile fractures (DITFs).Earthquake focal mechanisms.All of the above techniques assume that V is~vertical and equivalent to the integration of rockdensities to the depth of interest. Pore fluidpressures are often assumed “hydrostatic” andequivalent to the pressure of fluid column at thedepth of interest. However, in areas of confinedfluid flow, such as deep sedimentary basins, porefluid pressures can exceed hydrostatic andrequire direct estimates from techniques thatisolate sections of formation such as drill stemtests or through the analysis of drilling mudweights.Each stress measurement technique has itsadvantages and disadvantages and any stressfield determinations should ideally combine asmany of these techniques over the greatest depthinterval possible and be quality ranked accordingto the scheme developed by the World StressMap (Heidbach et al., 2008).Knowledge of the stress field and pre-existingfractured rock mass can be used to makepreliminary predictions of fracture and reservoirgrowth directions during hydraulic stimulation. Asa generalisation, the three major fracture growthdirections are:(a) Normal faulting stress regime ( V > H > h ) formsteep to vertical dipping fractures that strikeorthogonal to 3 .(b) Strike-slip faulting stress regime ( H > V > h )form steep to vertical dipping fractures that strike h > V ) formshallow to horizontal dipping fractures that strike~parallel to 2 .Geological & HydrogeologicalCharacterisationWhere available, the geological context of thestudy site should include all information pertainingto the geological setting, lithological composition,structure, geometry, weathering, deformationhistory and stress path for each potential reservoirrock type. For example, if a particular sequencehas been metamorphosed, multiply folded oreroded at the surface before re-burial, thoseevents would have significant implications forpermeability and joint formation within the affectedrock units. Fracture network data can be obtainedfrom a variety of sources including outcrop, drillcore and borehole images. Of particular use are397

Australian Geothermal Energy Conference 2009fracture scanline maps or core logs that provideimportant detail relating to fracture orientation,spacing, length, type, mineralisation and agerelationships. Local hydrogeological data couldinclude any reported hydraulic data from a varietyof sources including well completion reports, wellyields, pump tests, core permeability tests etc.This hydrogeological data compilation adds valueas an indication of likely in situ permeabilities,hydraulic gradients, flow rates and fluidchemistries that can also provide usefulconstraints in a numerical model.Geomechanical CharacterisationThe geomechanical properties of a rock mass andfracture network are essential for predictingcoupled hydro-mechanical processes as theelastic properties of an intact rock materialtogether with fracture stiffness (strength) and porefluid pressures control the amount of fracturedeformation (dilation, closure and shearing) thatmay occur under an imposed stress field.Important intact rock material properties includeparameters such as density, bulk moduli, uniaxialcompressive strength, tensile strength, cohesionand friction angle. These parameters arecommonly estimated from laboratory tests suchas drill core triaxial compression or ultrasonicvelocity tests or from field based rock massclassifications such as those described by Hoek(2007). Furthermore, rock formations commonlycontain a fabric, which may result in a mechanicalanisotropy that needs to be determined andaccounted for in any numerical model.Fracture stiffness is primarily a function of fracturewall contact area. Normal stiffness (jk n ) and shearstiffness (jk s ) of a fracture are measures ofresistance to deformation perpendicular andparallel to fracture walls, respectively. Normalstiffness is a critical parameter that helps to definethe hydraulic conductivity of a fracture via anestimate of the mechanical aperture as opposedto the theoretical smooth planar aperture asdescribed in the Cubic Law. Ultimately, estimatesof fracture stiffness attempt to account for morerealistic fracture heterogeneity, asperity contact,deformation and tortuous fluid flow. Equations 5 &6 below describe the simplified relationshipbetween fracture stiffness and fracturedeformation (Rutqvist and Stephannson, 2002):Δμ n = jk n Δσ’ n (5)Δμ s = jk s Δσ s (6)which states (a) that fracture normal deformation(Δμ n ) occurs in response to changes in effectivenormal stress (Δσ’ n ) with the magnitude ofopening or closure dependent upon fracturenormal stiffness (jk n ); and (b) that the magnitudeof shear mode displacement (Δμ s ) depends uponthe shear stiffness (jk s ) and changes in shearstress (Δσ s ).Estimates of fracture stiffness are derived by avariety of field logging or laboratory tests, whichare well documented in comprehensive reviewsby Bandis (1993), Barton and Choubey (1977)and Hoek (2007). Standard practice is to derivestiffness estimates based upon fundamentalmeasurements of fracture surface topographyprofiles and the elastic properties of the intactrock material, although these estimates areaffected by many factors including:Joint roughness coefficient (JRC) which is astandard measure of a fracture surfacetopography profile (Barton and Choubey,1977).Joint compressive strength (JCS)corresponding to the compressive strength ofthe fracture wall rock which can be modifiedby weathering and mineralization.Magnitude of fracture stiffness increasing withincreasing effective normal stress.Fracture spacing and density and its effect onthe partitioning of strain.Intact rock material moduli such as Young’smodulus (E), shear modulus (G), bulk‏.(ע)‏ modulus (K) and Poisson’s ratioTest type (e.g. unconfined, triaxial, in situdirect shear, laboratory direct shear etc).Sample size.Definition (e.g. peak, initial or 50% during anapplied test).Fracture stiffness is probably the most difficult ofall the geomechanical parameters to characteriseaccurately principally due to the large number ofdependent variables, their heterogeneous natureand the scale dependence of key factors such asthe JRC and JCS estimates. It is also oftendifficult to gain access to sufficient amounts of drillcore or outcrop. Typically, these limitations areaddressed within numerical models through theuse of parameter sensitivity studies and/orgeostatistical-based approaches such as, forexample, Monte Carlo simulations (de Marsily, G.et al., 2005).Hydro-Mechanical ModellingThe aim of the hydro-mechanical modellingprocess is to make a preliminary evaluation of thehydro-mechanical character of each prospectivereservoir unit at the inferred target depth, stressregime and pre-stimulation stage (i.e. steady stateconditions). One example code is the UniversalDistinct Element Code (UDEC), which is a 2.5D,distinct element, discontinuum code thatrepresents a rock mass as an assembly ofdiscrete rigid or deformable, impermeable blocksseparated by discontinuities (faults, joints etc),which are treated as boundary conditionsbetween the blocks (Itasca, 2004). UDEC498

Australian Geothermal Energy Conference 2009interpolates the physical response and stressdisplacementrelationship of a fractured rockmass to an imposed stress field, which satisfiesthe conservation of momentum and energy in itsdynamic simulations with fluid flow calculationsderived from Darcy’s Law (for a comprehensivereview of the UDEC governing equations seeItasca, 2004). Based upon a conceptual fracturedrock mass model of the potential reservoir target,hydro-mechanical model simulations can providethe following useful information:Depth Below Surface (m)Mean Fracture Aperture, 2b (m)3.25E-04 3.75E-04 4.25E-04 2.25E-04 2.75E-04 4.75E-04 5.25E-040.020.0Set A (Bedding)40.0Set C60.0Set D80.0100.0Set E120.0140.0160.0180.0Structural anisotropy of the rock mass viaestimates of the fracture deformationdistribution across all individual fractures(Figure 1).An indication of the pre-stimulation, steadystate,bulk in situ hydraulic conductivity andits related anisotropy (Figures 2 & 3).An indication of potential reservoir growth andfluid flooding directions.200.0Figure 1 : Example of a UDEC fracture deformation depthprofile for individual fracture sets that comprise a largerfracture network. In this example, the initial (at surface)fracture hydraulic apertures were set at 0.5 mm with datapoints representing the calculated mean fracture aperture foreach 10 m thick depth interval. The results show aprogressive divergence in the relative amounts of fractureclosure (i.e. structural and hydraulic anisotropy) occurringacross the individual fractures.An estimate of stress magnitudes at the targetdepth horizon and an indication of theinjection pressures required for hydraulicstimulation.Model input parameters and results providethe basis for more complex, coupled thermalhydrogeological-geomechanicalmodels tosimulate the lifetime performance (e.g.pressure and thermal drawdown) of an EGSproject.Ranking of Potential Reservoir TargetsFrom a hydro-mechanical context, the process ofranking the reservoir suitability for eachprospective rock unit will require a qualitative tosemi-quantitative assessment of the advantagesand disadvantages of both Type 1 and 2conceptual targets. It is recommended that theranking criteria include the following factors: Favourable fracture set orientations withrespect to the in situ stress field.Degree of fracture network connectivity (e.g.fracture density, length etc).Fracture set strengths, mineralisation etc.Rock mass stiffness (i.e. deformability).Estimated bulk hydraulic conductivity andhydraulic conductivity ellipse.Target depth with respect to the pre-definedtarget isotherm. Target depth and its expected stressmagnitudes.Target rock unit thermal conductivity.Target rock unit thickness.Depth Below Surface (m)Mean Fracture Aperture, 2b (m)3.50E-04 3.70E-04 3.90E-04 4.10E-04 4.30E-04 4.50E-04 4.70E-04 4.90E-0401020304050607080901000.00E+00 1.00E-07 2.00E-07 3.00E-07 4.00E-07 5.00E-07 6.00E-07Mean Fracture Flow Rate, q (m 2 /s)Figure 2 Depth profile example of UDEC estimated meanfracture flow rates (diamonds, lower x-axis) and fractureapertures (squares, upper x-axis). The initial (at surface)fracture hydraulic apertures were set at 0.5mm.2703002403302103601.25E-061.00E-067.50E-075.00E-072.50E-070.00E+00180301506012090K (m/s)Figure 3 : Example of a UDEC horizontal planar hydraulicconductivity (K) ellipse for a fracture network at a specificdepth (stress) level. The degree of ellipse elongationrepresents the in situ hydraulic anisotropy of the fracturenetwork with the elongation direction equal to the maximumK direction.599

Australian Geothermal Energy Conference 2009ConclusionThis study has described how preliminaryestimates of the hydro-mechanical properties of afracture network can be combined with coupledhydromechanical, discrete fracture networkmodels to characterise reservoir potential. Thisapproach has several limitations, which arelargely due to the complexities and uncertaintiesassociated with data capture, samplerepresentativeness and spatial confidence,particularly in regard to the geomechanicalcharacterisation of in situ rock material andfractures. Furthermore, the computationallimitations of codes such as UDEC restrict theirpractical application to either detailed small-scale(

Australian Geothermal Energy Conference 2009Thermal thinking:optimal targeting for Australian geothermal explorersAlexander Musson 1,2 * , Ben Harrison 1 , Kate Gordon 1 , Sarah Wright 1 and Mike Sandiford 1,2 .1 School of Earth Sciences, University of Melbourne, Victoria 3010.2 Melbourne Energy Institute, University of Melbourne, Victoria 3010.* Corresponding author: alexander.musson@unimelb.edu.auIntroductionThe two foremost criteria that define the viabilityof a potential geothermal reservoir are: thehighest temperature at the shallowest depth, andsustainable geofluid flow rates. In addressing theformer, geothermal explorers face a difficultchallenge; a challenge starting with scarce orinaccurate thermal datasets extracted mostly fromshallow drillholes, and concluding withoversimplified interpretations andunderconstrained thermal models.In the absence of deep drilling, temperaturepredictions at a target depth of several kilometersrequire the extrapolation of thermal data obtainedfrom boreholes typically a few hundred metresdeep. Because an uncertainty of 1 ºC at a 100 mdepth translates to an error of 40 ºC at 4,000 m, itis essential that thermal data from shallowdrillholes, in particular heat flow, be wellconstrained. Often the analysis of heat flow isconsidered as a one-dimensional steady-stateand purely conductive heat transfer problem. Thissimplified view ignores transient effects andspatial variations which arise from heat and fluidtransport as well as the inherent threedimensionalheterogeneity and anisotropy of thegeological subsurface. In this context ourapproach to the problem is to establish a morerigorous evaluation in assessing the nature andsignificance of primary data. We specificallyexplore the role of heat refraction andpalaeoclimatic transients and its incidence onextrapolation methods. In certain circumstancesprimary data from shallow boreholes can beevaluated and adequately relied upon forextrapolation at target depth, independently ofdeep drilling. We propose conceptual modelsshowing why heat refraction, heat insulation, rockanisotropy and palaeoclimate cannot be ignoredand how consequently explorers can optimizetheir geothermal targets.Keywords: Australia, Latrobe Valley, heat flowmodelling, heat refraction, palaeoclimaticcorrections, Enhanced Geothermal Systems(EGS), Hot Fractured Rocks (HFR), Hot DryRocks (HDR), Deeply Buried SedimentaryAquifers (DBSA), Hot Sedimentary Aquifers(HSA).Heat refractionBecause the geological subsurface is not a layercake, heat refraction occurs due to thermalconductivity contrasts. This lateral variation in thethermal properties of rocks will always result inheat refraction effects and will invariably impacton shallow heat flow fields. When the thermalconductivity contrasts are large, the relationshipbetween temperature at target depth and surfaceheat flow is complex and non-trivial to understand.For example buried ‘insulators’ will induce hightemperatures at depth, below the insulator; yetwill display a negative heat flow anomaly at thesurface (Figure 1, Appendix). In the LatrobeValley (Victoria’s Gippsland Basin), the magnitudeof the anomaly associated with buried coals isestimated to be – 40 mWm –2 , with an inverselycorrelated temperature anomaly of + 20-30 ºC.This instance highlights the necessity to elucidatethe source of heat flow anomalies before they areused to extrapolate temperature to target depth.Furthermore it provides a stringent test withrespect to the robustness of primary dataobtained from shallow drillholes. If shallowboreholes do not record the anomaly associatedwith heat refraction, they cannot reflect purelyconductive heat flow processes and are thereforeof little use in constraining temperature at targetdepth by extrapolation methods.Palaeoclimatic correctionsPalaeoclimatic variations over the LatePleistocene have been extreme, with most proxydata indicating that surface temperatures alongsouthern Australia are now some 6-8°C higherthan at the height of the Last Glacial Maximum(LGM) some 18,000-20,000 years ago (Galloway1965, Miller et al. 1997, Barrows et al. 2002,Hesse et al. 2004, Jouzel et al. 2007). Becausesurface temperatures are warmer now than in thepast 100,000 years, surface heat has propagatedinto the shallow subsurface affecting an otherwisesteady state-gradient. This means thattemperature gradients are lower today than thoseof the LGM. This temperature anomaly needs tobe accounted for in accurate heat flow modelling.The inversion of downhole temperature isarguably the only direct method that permits todetermine palaeoclimatic ground surfacetemperatures histories from a few hundred yearsto 100,000 years (i.e. Hotchkiss and Ingersoll1101

Australian Geothermal Energy Conference 20091934, Benfield 1939, Birch 1948, Sass et al. 1971,Beck 1977, Clauser 1984, Chapman and Harris1993, Pollack and Smerdon 2004, Beltrami et al.2005, Rath and Mottaghy 2007). The use of thetransient heat conduction equation (Carslaw andJaeger 1959) with typical values of the thermaldiffusivity of rocks (i.e.Touloukian et al. 1970,Seipold 1998, Beardsmore and Cull 2001,Mottaghy et al. 2008), show that excursions inground surface temperature for 10, a 1,000 and a100,000 years ago produce maximumtemperature anomalies at depths of approximately25, 250, 2,500 m respectively. A prescribed timedependentboundary condition reveals that forevery 1 ºC of fluctuation at the ground surfacecorresponds a heat flow variation ofapproximately 1 mWm -2 at the depth of theanomaly maximum. Although the magnitude ofthis correction depends on whether the location ofthe borehole is ‘coastal’ or ‘intracontinental’, it hasimportant implications for geothermal modellingsince an uncorrected shallow heat flow estimate ismost likely an underestimate.SummaryOften the analysis of heat flow is considered as aone-dimensional, steady-state, purely conductiveheat transfer problem, given constant boundaryconditions. Because the geological subsurface isneither homogeneous nor isotropic, and becauseit is subject to various transients, one-dimensionalsteady-state modelling does not appear robustenough to develop well-constrained temperatureor heat flow maps. This holds especially truewhen thermal data are extracted from shallowdepthdrillholes. We propose through thiscontribution, an ongoing effort of the GeothermalResearch Group at the School of Earth Sciences,University of Melbourne, a more rigorousevaluation of the nature and significance ofshallow-depth thermal data. We developtheoretical and numerical models thatdemonstrate the importance of heat refraction andpalaeoclimate variations through two-dimensionalpredictive heat flow modelling.AppendixSynthetic 2D model:Burried insulatorTemperatureprofile (ºC)0 mThermalConductivity (WK -1 m -1 )TemperatureGradient (ºCkm -1 )HeatFlow (mWm -2 )- 1000- 2000- 3000- 4000a b c d e- 50000 m 5000 10ºC 50 90 130 170 0 WK -1 m -1 310 ºCkm -1 60 30 mWmˉ² 70Figures 1a, 1b, 1c, 1d, 1e: Synthetic 2D model (Fig. 1a) by finite element method, depicting a buried insulator placed between adepth of 500 m and a 1,000 m. Boundary conditions are a surface temperature of 17ºC (Fig. 1b) and a bottom heat flow of70 mWm-2 at z = –10,000 m. The side boundaries are placed in the far-field and are mirror conditions. The thermalconductivities (Fig. 1c) are arbitrarily chosen at 0.5 Wm-1K-1 for the insulator, and 3.0 Wm-1K-1 for the rest of the domain. Thethermal conductivity exerts a first order control on the gradient profile (Fig. 1d): to low thermal conductivities correspond largethermal gradients. The heat flow profile (Fig. 1e) demonstrates the large difference between the heat flow at the surface (30 to40 mWm-2) and that at depth (70 mWm-2), a result of the heat refraction induced by the large thermal conductivity contrast.ReferencesBarrows, T.T., Stone, J.O., Fifield, L.K. andCresswell, R.G. 2002. The timing of the LastGlacial Maximum in Australia. QuaternaryScience Reviews 21, 159-173.Beardsmore G.R. and Cull J.P. 2001. Crustalheat flow: A guide to measurement andmodelling. Cambridge University Press, NewYork.Beck, A.E. 1977. Climatically perturbedtemperature gradients and their effect onregional and continental heat-flow means.Tectonophysics, 41, 17-39.Beltrami, H., Ferguson, G. and Harris, R.N.2005. Long-term tracking of climate change byunder-ground temperatures. GeophysicalResearch Letters 32, L19707.Benfield, A.E. 1939. Terrestrial heat flow inGreat Britain. Proceedings of the Royal Societyof London, Mathematical and Physical Sciences173, 955, 428-450.2102

Australian Geothermal Energy Conference 2009Birch, F. 1948. The effects of Pleistoceneclimatic variations upon geothermal gradients.American Journal of Sciences 246,729-760.Carslaw, H.S. and Jaeger, J.C. 1959.Conduction of heat in solids. 2nd Edition.Clarendon Press, Oxford.Chapman, D.S. and Harris, R.N. 1993. Repeattemperature measurements in borehole GC-1,northwestern Utah: Towards isolating a climatechangesignal in borehole temperature profiles.Geophysical Research Letters 20, 1891-1894.Clauser, C. 1984. A climatic correction ontemperature gradients using surfacetemperature series of various periods.Tectonophysics 103, 33-46.Galloway, R.W. 1965. Late Quaternary climatesin Australia. Journal of Geology 73, 603-618.Hesse, P.P., Magee, J.W. and van der Kaars, S.2004. Late Quaternary climates of the Australianarid zone: a review. Quaternary International118-119, 87-102.Hotchkiss, W.O. and Ingersoll, L.R. 1934. Postglacialtime calculations from recent geothermalmeasurements in the Calumet Copper Mines.Journal of Geology 42,113-142.Jouzel, J., Masson-Delmotte, V., Cattani, O.,Dreyfus, G., Falourd, S., Hoffmann, G., Minster,B., Nouet, J., Barnola, J.M., Chappellaz, J.,Fischer, H., Gallet, J.C., Johnsen, S.,Leuenberger, M., Loulergue, L., Luethi, D.,Oerter, H., Parrenin, F., Raisbeck, G., Raynaud,D., Schilt, A., Schwander, J., Selmo, E.,Souchez, R., Spahni, R., Stauffer, B.,Steffensen, J.P., Stenni, B., Stocker, T.F., Tison,J.L., Werner, M. and Wolff, E.W. 2007. Orbitaland millennial antarctic climate variability overthe past 800,000 years. Science 317, 793-796.Miller, G.H., Magee, J.W. and Jull, J.W.T. 1997.Low-latitude glacial cooling in the SouthernHemisphere from amino-acid racemization inemu eggshells. Nature 385, 241-244.Mottaghy, D., Vosteen, H. D. and Schellschmidt,R. 2008. Temperature dependence of therelationship of thermal diffusivity versus thermalconductivity for crystalline rocks. InternationalJournal of Earth Sciences 97, 435-442.Pollack, H.N. and Smerdon, J. E. 2004.Borehole climate reconstructions: Spatialstructure and hemispheric averages. Journal ofGeophysical Research 109, D11106.Rath, V. and Mottaghy, D. 2007. Smoothinversion for ground surface temperaturehistories: estimating the optimum regularizationparameter by generalized cross-validation.Geophysical Journal International 171, 1440-1448.Sass, J. H., Lachenbruch, A. H. and Jessop, A.M. 1971. Uniform heat flow in a deep hole in theCanadian Shield and its paleoclimaticimplications. Journal of Geophysical Research76, 8586-8596.Seipold, U. 1998. Temperature dependence ofthermal transport properties of crystalline rocks– a general law. Tectonophysics 291, 161-171.Touloukian, Y.S., Powell, R.W., Ho, C.Y. andKlemens, P.G. 1970. Thermal conductivity, nonmetallicsolids. Thermal properties of matter,Volume 2. IFI/ Plenum, New York.3103

Australian Geothermal Energy Conference 2009Overview of Geothermal Resources and Exploration Activity inVictoriaDavid H Taylor, Ben C HarrisonGeoScience Victoria, GPO BOX 4440, Melbourne, VIC, 3001Corresponding author: david.taylor@dpi.vic.gov.auVictoria currently derives most of its electricitygeneration from brown coal but is keen to diversetowards lower emission energy sources.Geothermal energy offers the possibility of baseload power generation plus direct use thermalapplications. Legislation for geothermal resourcesecurity was passed in 2005. In 2006 and 2008two rounds of competitive tendering resulting inabout two thirds of the State being placed underexploration by seven different companies. Theyhave pledged to spend close to $370 million overthe next five years in the quest to find anddevelop geothermal resources. Legacy data frompetroleum exploration suggests potential for HotSedimentary Aquifer (HSA) plays in basins alongthe onshore margin of Victoria. Elsewhere thegeology may support Engineered GeothermalSystems (EGS) plays in the abundant Palaeozoicgranites. Magmatic plays may also exist inassociation with a major episode of recentbasaltic volcanism. Governments, Universitiesand exploration companies are currently collectingbasic geothermal data such as heatflowmeasurements and thermal conductivities tobetter characterise the potential of geothermalsystems in Victoria. A number of InferredResources have been declared but deep drillingto appraise these is awaiting fundingopportunities.Keywords: Geothermal, Hot Sedimentary Aquifer,Energy generation,Background HistoryThe oil shocks of the 1970s piqued interest intoalternate energy sources. Town water suppliesdrawn from thick Cretaceous-Tertiary basinsalong the Victorian coast showed temperatures ofabout 50-90C at 1-2km depth. The potential ofdirect use of this hot water was investigated (Kinget al. 1987). Petroleum exploration in the samearea also occasionally intersected a deeper basalaquifer with temperatures of about 130-150C at3.5-4km depth (Woollands & Wong 2001). Lowoil prices throughout the 1990s suppressedinterest in alternate sources but the return ofhigher prices and concerns around green housegas emissions have again sparked interest in thepotential of geothermal energy. Legislation wasput in place in 2005 and exploration companieswere invited to tender for large permit blocksestablished across the State in 2006 and again in2008. To support tender bids, a preliminaryreview of the geothermal prospectivity waspublished by the State government geologyorganisation (Driscoll 2006). This report includeda quality-controlled compilation of temperaturedata from pre-existing groundwater and petroleumbores.Geological Framework for potentialgeothermal systemsGeothermal potential depends on the interactionof a number of geological factors. The bestresources are likely to exist in regions where highheat flow passes through rocks of low conductivity(good insulation) to create high temperature atshallow depth (Duffield & Sass, 2003).Unfortunately there is insufficient published heatflow data and hardly any published thermalconductivities to allow a quantitative assessmentvia these criteria. Instead, the geothermalpotential can only be assessed indirectly, in amore qualitative manner, by looking at geologicalfactors which control the geothermal factors. Therecent publication of a geothermal systemsassessment framework (Cooper & Beardsmore2008) outlines the four factors that needconsideration: (1) a heat producing basement (2)an insulating blanket (3) a fluid to move the heataround with and (4) a reservoir to accommodatethe fluid.Applying this four factor analysis to the majorgeological provinces of Victoria gives some ideaof their relative geothermal prospectivity (Figure1). The broad diversity in the age and types ofrocks across Victoria gives some potential for allthree types of geothermal systems: EngineeredGeothermal Systems in Hot Rocks; HotSedimentary Aquifer; and Magmatic.Three broad geological/geothermal provinces canbe delineated across Victoria: (1) The Palaeozoicbedrock (2) the onshore Otway and GippslandBasins and (3) the Murray Basin.The Palaeozoic bedrock consists predominantlyof Cambrian to Devonian deep marine siliclasticsthat have been tightly folded and cleaved atvarious times in the Palaeozoic (blues, brownsand purples of figure 1). These rocks underlie theother provinces. This exposed bedrock givesgood insight into the heat producing basementfactor. Numerous granites intrude this bedrock(red blobs on figure 1). In west and centralVictoria some of them have felsic, fractionatedgeochemistry with mild enrichment in heatproducing elements so the EngineeredGeothermal System plays may be possible where1104

Australian Geothermal Energy Conference 2009Figure 1: Geological/Geothermal Province map of Victoria based on underlying geological controls. Three broad geothermalprovinces of Palaeozoic bedrock, onshore basins, and Murray basin each have a number of potential geothermal play typeswhere factors favourably align.some granites still lie buried within the bedrock orbeneath the adjacent basins? In the southwest,an extensive province of young basalts haserupted onto the bedrock in the last few million totens of thousands of years (the light pink in figure1). Thus there is the possibility of Magmatic playsrelated to residual transient heat anomalies in theupper crust that may exist because of the recentmagmatism.The Onshore Otway and Gippsland Basins areCretaceous rift basins associated Gondwanabreak-up (greens and yellow along coast in Figure1). These basins are well characterised thanks toa long history of petroleum exploration. Theycontain several kilometres of muddy sedimentsoverlying a coarser grained basal unit. Thisprovides a natural reservoir already charged withhot water beneath an insulating blanket to createan attractive fairway for Hot Sedimentary Aquiferplays. In the Otways this basal unit has beenintersected upon the basin floor but in theGippsland basin this unit has yet to be testedaway from the margins, at the depths necessaryfor a geothermal play. Beneath these basinsthere is also potential for Engineered GeothermalSystem plays in places where it is floored bygranites.The Murray Basin is a Tertiary intracratonic sagbasin (light greens and yellow inland in Figure 1).It generally contains only a few hundred metres ofsandy marly cover. This is insufficient cover toact as a heat blanket but in some places deepertroughs – such as the Wentworth, Netherby,Numurkah and Ovens - exist and can contain upto a couple of kilometres of sediment that is poorlyknown since there has been limited petroleumexploration here. Alignment of favourable factorsover the deeper troughs may allow EngineeredGeothermal System or Hot Sedimentary Aquiferplays but the favourability of the geothermalfactors in this province has yet to be validated.Science Research and CompanyExplorationMost activity by everyone – government agencies,university academia and exploration companies –2105

Australian Geothermal Energy Conference 2009is focussing on collecting the fundamentalgeothermal data sets of temperature gradientsand thermal conductivities to allow heat flowmapping.GeoScience Victoria is working with GeoScienceAustralia on the National Geothermal EnergyProject (Budd et al., 2008). In the Murray Basin, 7deep water bores were recently measured to fill alarge gap in the national heat flow database.More bores are planned to be entered as accessand the national work program permits. Inaddition to supporting the Federal program,GeoScience Victoria also has some moderatefunding to purchase a thermal logger toaccelerate State coverage and also allowopportune access to appropriate mineralexploration drill holes etc. Similar to thisgovernment work, many of the explorationcompanies have also been re-entering bores fortemperature logging and measuring cores forthermal conductivity so that heat flow calculationsand conductive 1-2-3D modelling of their permitareas can be undertaken. Several InferredResources of ‘Stored Heat’ have already beendeclared and some of these plays are now readyfor further appraisal by deep drilling.Pathways to Resource DevelopmentIn the absence of detailed, dedicated geothermaldata, most of Victoria can be viewed as ‘blue sky’or perhaps ‘green fields’ at best, in those areaswhere some legacy petroleum data exists. Mostof the Victorian geothermal explorers are smallcompanies with limited amounts of capital andcash-flow to fund their 5 year explorationprograms. Ideally, as these companies collectinformation and decrease risks and unknowns,they could call for more capital through either debtor equity raisings until it becomes probable that amajor backer would farm-in for development. TheGlobal Financial Crisis has badly affected thistraditional venture capital pathway through toresource development.At the national level the Federal government hascommitted a significant amount of funds into ageoscience investigation program and also put upmoney for co-funding deep appraisal drilling. Ifthese drilling appraisals lead to early successthen perceived risks around geothermal energymay lessen and allow easier funding for the wholeindustry from more the traditional pathway.Company announcements around InferredResources and/or conceptual targets suggest thatseveral thousand MW of electricity generationmay be possible but it is still early days for thegeothermal industry in Victoria.ReferencesBudd, A.R., Holgate, F.L., Gerner, E.J., Ayling,B.F. & Barnicoat, A.C., 2008, Pre-competitivegeoscience for geothermal exploration anddevelopment in Australia: Geoscience Australia'sOnshore Energy Security Program, in: Gurgenciand Budd (eds) Proceedings of the Sir MarkOliphant International Frontiers of Science andTechnology Australian Geothermal EnergyConference, Geoscience Australia Record2008/18, 1-8.Cooper, GT. & Beardsmore, GR., 2008,Geothermal systems assessment: understandingthe risks in geothermal exploration in Australia.Proceedings Eastern Australian BasinsSymposium III, Sydney, Australia, September2008.Driscoll, J., 2006, Geothermal propsectivity ofonshore Victoria, Australia. GeoScience Victoira,VIMP report 85.Duffield, WA. & Sass, JH., 2003, Geothermalenergy: Clean power from the earth's heat. U. S.Geological Survey circular 1249, 36pp.Graeber, FM., Houseman, GA. & Greenhalgh,SA., 2002, Regional teleseismic tomography ofthe western Lachlan Orogen and the NewerVolcanic Province, southeast Australia.Geophysical Journal International, vol. 149, no. 2,pp. 249--266.King, RL & Council, VSE 1987, GeothermalResources of Victoria, Department of Industry,Technology and Resources, Victorian SolarEnergy Council.Woollands, MA., & Wong, D., (eds.) 2001,Petroleum Atlas of Victoria, Australia, Departmentof Natural Resources and Environment.3106

Australian Geothermal Energy Conference 2009Mineralogy and Petrology of the Cooper Basin Basement GranitesVan Zyl, J.A.B. 1, 2 , Uysal, I.T. 1 , Gasparon, M. 21 Queensland Geothermal Energy Centre of Excellence, The University of Queensland, Queensland 4072, Australia2 School of Earth Science, The University of Queensland, St Lucia Queensland, 4072Email: j.vanzyl@uq.edu.auThe Australian continent is tectonically relativelystable in comparison with other continentalsettings, the radiogenic heat production within theAustralian continental crust is significantly high.One region with particularly elevated heatproduction is the Cooper Basin. The CooperBasin is an intercratonic basin that contains LateCarboniferous to middle Triassic sedimentaryrocks which are mainly of non-marine origin (Hilland Gravestock 1995).The Cooper Basin overlies granites, which haveintruded the Warburton Basin Sediments(Gatehouse et al, 1995, McLaren and Dunlap,2006, Sun, 1997). The Cooper basin in turn isoverlain by the Eromanga Basin (Gatehouse et al,1995, Sun, 1997).This paper focuses on three wells (Table 1) inwhich granites have been intersected. The aim ofthis study is to characterise the mineralogy andpetrology of these granites that may control theheat production in the Cooper Basin.The data collected in this study will be used toestablish an advanced geochemical/isotopic andgeochronological database for improving ourunderstanding of existing geothermal resources,and the definition of an investigation procedurethat can be applied as a routine exploration toolfor Hot Rock geothermal systems in Australia andin similar tectonic environments worldwide.PetrographyTen petrographic thin-sections were made fromgranites sampled in four geothermal wells thatintersect the basement of the Cooper Basin.Eight of the ten samples are highly altered withthe predominant minerals being quartz, and ahigh birefringent clay mineral (illite based on XRD)with minor oxides. In four of the sections, highlyaltered plagioclase is present (Big Lake-1 and thethree McLeod-1 sections, 3745.2, 3745.9 and3748.3) exhibiting distinct Carlsbad-Albitetwinning.In all the altered sections, three textures (Figure1-A) can be identified in terms of mineralogy andgrain size. The first texture is the primary granitetexture. This is characterised by the large grainsize of some quartz grains (> 2mm) and theoccurrence of pseudomorphic illite, through thereplacement of biotite and strongly alteredplagioclase in some of the sections. The primaryquartz (Figure 1-C) in the sample exhibitsextensive undulose extinction with someprominent striations, with the quartz being highlyfractured. The second texture is the pervasivealteration. This is exhibited by finely (< 100µm)inter-grown clay minerals with associated finegrainedquartz. The third texture is anintermediate texture; with the dominance of thelarger, more crystalline clay minerals. This thirdtexture is characterised by the clay minerals,which have a grain size between 200 µm to 1mm.Table 1: Sample Names and sampling depthWell NameSamplingDepth (m)AlterationBig Lake-1 3057 PervasiveJolokia-1 4905McLeod-1Moomba-1Minor(sericitisation)3745.2 Pervasive3745.9 Pervasive3748.3 Pervasive2847.75 Pervasive2848.7 Pervasive2851 Pervasive2857.4 Pervasive2895.2Minor(sericitisation)In one of the Big Lake 1 samples, a vein (Figure1-B) occurs that consists of mainly quartz withsome illitic clays. This vein varies in thicknessfrom 80µm to 200µm . The vein postdates thepredominant alteration of the sample as itcrosscuts all alteration minerals in the section.Some of the quartz grains (McLeod-1_3745.9,McLeod-1_3748.3, Moomba-1_2847.75,Moomba-1_2848.7, and Moomba-1_2851, Figure1-D) have small inclusions of unaltered biotite andamphibole (hornblende). It appears that theinclusions may have survived the alteration.The sample also contains some accessoryhematite and zircon. Both these minerals seem tobe associated with the third texture, which isdominated by intermediate clay minerals. Thezircon is mainly locked within the large clayminerals, with minor zircon grains locked in thelarge quartz crystals. The zircons, which areobserved within the illitic clays, tend to occur asfractured euhedral crystals with some grains1107

Australian Geothermal Energy Conference 2009containing minor opaque inclusions. The zirconsoccur as locked grains in the clay mineralscrosscutting the cleavage lamellae. The zirconsalso tend to occur as grains attached to quartzand clay mineral grains. Some of the zircons arezoned.The hematite in the sections occurs as elongatedanhedral crystals, with a minority occurring assubhedral grains. The elongated hematite occursas locked particles along the clay minerallamellae. Some of the hematite (Moomba-1_2851) occurs in distinct areas not includedwithin a particular clay mineral grain. Thehematite is being altered to Fe-oxyhydroxides(goethite/limonite) This is indicated by rimsaround some of the hematite.Two of the samples, Jolokia-1 and Moomba-1_2895.2, have less pervasive alterationcompared with the other eight samples. Thealteration in Jolokia-1 appears to have affectedonly the biotite and amphibole as they have beenreplaced by a highly birefringent clay mineral. Inthe Moomba-1_2895.2 (Figure 1-F) section, thebiotite and amphibole exhibit only small amountsof alteration, evidenced by the discoloration alongthe grain boundaries. The plagioclase in boththese samples exhibits some degree of alterationas there is some sericitisation. Primary microclineis also present and exhibits similar alteration asthe plagioclase. In the Jolokia-1 sample, evidenceof eutectic crystallisation of quartz and microclineis present. In both these sections, the opaquesand zircon are observed with the clay alterationmineral (Jolokia-1) and the biotite and amphibole(Moomba-1_2895.2).Hydrothermal alteration anddeformationThin section optical microscopy shows that thegranite samples have been severely fractured,and that the fracturing was accompanied bysignificant hydrothermal alteration. Fracturing inthe granite occurs mostly as irregular microfracturesand veining as well as planar microdeformationstructures in quartz (Figure 1-G, H).This indicates that the granite has been subjectedto a significantly high stress regime of anunknown origin with a subsequent hydrothermalfluid circulation along micro-crack systems.Hydrothermal alteration mineralogy consistslargely of a single phyllosilicate phase (illite). Inmany cases, all feldspars and micas in the granitehave been completely altered to illite.The Distribution and intensity of alterationmineralogy is irregular with depth, with somedeeper samples only slightly altered (e.g.,Moomba 1 at 2895.20 and Jolokia 1 at 4005 m) incontrast to the shallow granites showing intensefracturing and hydrothermal alteration (e.g.,Moomba 1 at 2847.75 m). The alterationmineralogy of the overlying sedimentary rocksconsists of mainly illite, and unlike the granite,also some chlorite and kaolinite.Illite crystallinityIllite crystallinity values, which were determinedby XRD, can be used as a semi-quantitativegeothermometer for burial and hydrothermalmetamorphism (Frey, 1987; Ji and Browne,2000). Illite crystallinity is defined as the width ofthe first order illite basal reflection (10 Å peak) athalf height and expressed usually in 2 values.Illite crystallinity values decrease with increasingillite crystallinity. In this study, illite crystallinityvalues were measured mainly on samples of

Australian Geothermal Energy Conference 2009ReferencesFrey, M., 1987, Very low-grade metamorphism ofclastic sedimentary rocks, In: Low TemperatureMetamorphism, (ed. Frey M), p. 9-57. Blackie &Sons, Glasgow.Gatehouse, C.G., Fanning, C.M. and Flint, R.B.,1995, Geochronology of the Big Lake Suite,Warburton Basin, north-eastern South Australia,South Australia Geological Survey. QuarterlyGeological Notes, 128, 8-16.Hill, A.J. and Gravestock, D.I. 1995 Cooper Basin,In Drexel, J.F and Preiss, W.V. (Eds), , TheGeology South Australia Vol2, The Phanerozoic.South Australia, Geological Survey, Bulletin 54,p78-87Ji, Junfeng, and Browne, P.R.L., 2000,Relationship between illite crystallinity andtemperature in active geothermal systems of NewZealand, Clay and Clay Minerals, v48: p139-144McLaren, S, Dunlap, J., 2006, Use of 40 Ar/ 39 Ar K-feldspar thermochronology in basin thermalhistory reconstruction: an example from the BigLake Suite granites, Warburton Basin, South,Australia Basin Research, 18, 189–203Sun, Xiaowen., 1997, Structural style of theWarburton Basin and control in the Cooper andEromanga Basins, South Australia, ExplorationGeophysics, 28, 333-393109

Australian Geothermal Energy Conference 2009ABQtzTexture 2Texture 3Qtz veinCDQtzQtzBtEQtzFKFlAmpQtzPlagTexture 2BtGQtzFigure 1: Transmitted light photomicrographs of some of the features observed in the various sections. Field of view in eachimage is 3417µm for photos A-F. A) A Plane Polarized Light (PPL) image of the relation between Texture 2 and 3. B) Vein in BigLake-1 3057. C) quartz (qtz) grain with undulatory extinction and with “striations” visible in extinction under crossed Nichols(XPL). D). inclusion of an unaltered Biotite (Bt) in a Quartz grain (PPL),E) Altered plagioclase (Plag) present in Moomba 1sections. F) Relatively fresh sample from Moomba 1 2895.2, G) Planar micro-deformation structures observed in quartz.4110

Australian Geothermal Energy Conference 2009Concept of an Integrated Workflow for Geothermal Exploration in HotSedimentary AquifersJ. Florian Wellmann, Franklin G. Horowitz, Klaus Regenauer-LiebWestern Australian Geothermal Centre of Excellence, UWA-CSIRO-CURTINARRC 29, Dick Perry Avenue 6165 Kensingtonwellmann@cyllene.uwa.edu.auGeothermal exploration is currently performed indifferent steps and on different scales, from theinitial, large-scale resource estimation going downto local reservoir sustainability analysis for aspecific application. With this approach, it is notpossible to explore directly for requirementsdictated by a geothermal application.If we, for example, consider the exploration for adirect heat-use application we could require apumping rate of 100 l/s at a minimum temperatureof 70°C. Economic constraints could be amaximum drilling depth and the minimum yearslifetime of the system. The direct map-basedexploration for the best locations consideringthese constraints is not possible with the standardworkflow.We present here an approach to overcome thislimitation. We combine geological modelling,geothermal simulation and reservoir estimationinto one consistent location-based method.Outcomes of this integrated workflow are mapbasedreservoir and resource analyses that candirectly be used as guidance in the exploration forthe best possible location of a geothermalapplication. Our workflow is specifically developedfor applications in hot sedimentary aquifers butcan be extended to other geothermal settings.Keywords: Geological Modelling, GeothermalSimulation, Direct Heat Use, Integrated Workflow,Hot Sedimentary AquifersGeothermal ExplorationGeothermal exploration for hot sedimentaryaquifers usually consists of the following steps(not necessarily in this order):Geological Modelling for a resource area Resource Base Estimation in a large-scaletarget area (accessible and useful resources) Market analysis and other localconsiderations (e.g. power lines,infrastructure) Above-ground installation and technicalapplication (direct heat use, powergeneration)Detailed resource analysis in a smaller scale(economic resources for a specificapplication)Local reservoir exploration and sustainabilityanalysisFinancial modellingDepending on the reservoir type, further analysesare necessary (e.g. stress-field, permeabilityoptimisation, etc.). The single parts of thisworkflow are usually performed separately and ina sequential order. Our method combines thesteps from geological modelling to sustainabilityanalysis which are briefly described below.Geological ModellingA structural geological 3-D model is an importantbasis for geothermal exploration. It allows thevisualisation of geological structures in thesubsurface and can directly be used to identifyrelevant areas (e.g. from fault structures, etc.).Also, a 3-D geological model is the basis for othertypes of analyses, like the geothermal simulation.A large variety of tools exist to constructgeological models, ranging from map-basedinterpolation of structures (2.5-D methods, e.g.depth to basement maps interpolated fromdrillhole data) to full 3-D geological modelling thatcan consider complicated structures like reversefaulting or doming structures (Turner, 2006).Geothermal SimulationNumerical geothermal simulation is the nextimportant step in the exploration. Based onphysical constraints and subsurface data, a modelof the temperature distribution below ground issimulated. This is the basis for the geothermalresource estimation and allows first estimates ofdrilling depth to a desired temperature.Figure 1: Example of a simulated fluid and heat flow field.The section shows a contour map of temperatures, the planeis a temperature isosurface, and streamlines (gray) indicatefluid flow paths.1111

Australian Geothermal Energy Conference 2009Similar to geological modelling, a variety ofdifferent methods and codes are available forgeothermal simulation. Main differences are thecomplexity of the simulation, i.e. from simple heatconduction simulation to coupled simulation offluid and heat to complex multi-phase flow andreactive transport. (Kohl et al., 2007). Theapplication of a code strongly depends on thegeothermal reservoir type. In the case of hotsedimentary aquifers, fluid flow has to beconsidered as a heat transport mechanism and asuitable code should be used.Geothermal Resource Base EstimationStandard methods for the quality estimation of ageothermal resource are based on Muffler andCataldi (1978). They describe several differentapproaches, most widely known is the volumemethod, often referred to as “heat-in-place”. Thetotal thermal energy contained in a volume V ofrock is estimated based on specific heat of rockcrand fluid c w, porosity , density and atemperature difference T :Hip(1)c c VTrrwThe calculation of heat-in-place is usuallyperformed for an estimated total volume, meantemperature and porosity of a resource rock.Other estimations are possible and depend on thegeological situation and geothermal resourcetype.The evaluated resource base has to be furthersubdivided (Fig. 2) into accessible heat, usuallydefined by the maximum depth of drilling (this iswhat is usually considered in a standard “heat-inplace”analysis). But not all heat from theaccessible heat is actually useful, based onphysical limitations, reservoir lifetime and legaland environmental considerations. Finally, only afraction of the useful heat can be considered aseconomic, which Muffler and Cataldi (1978) defineas the geothermal energy that can be extracted inthe lifetime of a reservoir at costs comparable toother energy sources.Figure 2: From the broad geothermal resource base toestimation of the economically useable resource (redrawnfrom Muffler and Cataldi, 1978).wEstimation of Extractable EnergyThe amount of extractable heat depends on manygeological, physical and technical factors. Theseare usually combined into a general “recoveryfactor” as a broad estimation.For a hot sedimentary aquifer, Gringarten (1978)defines a heat recovery factor, Rg, as a the ratioof extracted heat, Qmaxt wcwT, to the totaltheoretically recoverable heat-in-place as givenabove. Here t is the producing time, thequantity Qmaxis the maximum production flowrate that can be maintained either indefinitely (fora truly sustainable system) or over the assumedeconomic lifetime of the geothermal system and wc wis the volumetric heat capacity of water.WritingRg 1Q1c / c Vrrwwmaxtwe find the heat recovery factor is dominated byQmax t for a porosity of : the recovery factor isa function of time. The maximum sustainablepumping rateQ maxfor a doublet well (pumpingand re-injection) over a production time t canbe analytically estimated from heat and flowequations. Gringarten (1978) presents ananalytical approximation and derives the followingrelationships for the pumping rate Q:acQ 3 candwawht1Q 2ln( D / rDw)2TsThe first equation describes the pumping rate as afunction of production time, thickness h of theaquifer and distance D between pumping and reinjectionwell. The second equation includes themaximum drawdown s, the well diameter r w andtransmissivity T. Temperature is implicit in theseequations as density of water and transmissivityare a function of temperature.The combined solution of these equationsprovides an estimate of the maximum pumpingrate Qmaxand the minimal distance D requiredbetween the pumping and re-injection well in theaquifer to avoid a thermal breakthrough during theproduction lifetime of the doublet.The result can be considered a very conservativeestimate as an application may still be possibleafter thermal breakthrough for some time. Also, assoon as a natural hydraulic gradient is present, a2112

Australian Geothermal Energy Conference 2009layout of the re-injection well downstream fromthe pumping well will increase the lifetime evenmore (Banks, 2009).Limitations of the standard approachesThe presented standard methods to evaluate ageothermal resource and its sustainableapplication are performed on two different scales.Whereas the heat-in-place estimation isperformed for a whole resource, the estimates fora sustainable pumping rate are performed on thelocal scale. It is not possible to derive a locationbasedanalysis of heat in the subsurface (i.e. howis the total heat-in-place distributed in space) or toanalyse a whole area for a required pumping rate(i.e. where can a certain pumping rate beobtained for a minimum time). Thus, thecombined analysis of both factors is not possiblefor a whole resource region.To overcome this limitation, we present anapproach to down-scale the heat-in-placeestimation for a regional analysis and to extendthe Gringarten estimations to a whole area, allwithin the context of geological modelling andgeothermal simulation.Integrated Geothermal ExplorationConcept of workflowIn our workflow (Fig. 3), we combine the stepsfrom geological modelling to resource andsustainability estimations.Figure 3: workflow of our approach from geological model toefficiency estimation of geothermal applicationThe starting point for our workflow is a full 3-Dgeological model. We use GeoModeller(www.geomodeller.com) for the modelling as it iscapable of dealing with complicated 3-Dgeological settings and provides a very fast andefficient way to create realistic geological modelsdirectly based on input data (e.g. Calcagno,2008). It is thus possible to quickly test severalgeological scenarios as the starting point for thegeothermal simulation.We link the geological model directly to ageothermal simulation code. The simulation isperformed with a fully coupled fluid, heat andreactive transport simulation code (SHEMAT). Allrelevant physical properties are calculated as afunction of temperature in each time step. It isalso possible to include anisotropies in thermalconductivity and permeability (see Clauser, 2003for a detailed description). The simulation code isthus capable of dealing with complex settings(from hot dry rock to hydrothermal) and has beenapplied to many geothermal simulations (e.g.Soultz-sous-Foret (France), Waiwera (NewZealand)).Now, we process the results of the geothermalsimulation further for two analyses: (1) thedistribution of heat in the subsurface and (2)estimation of the sustainable pumping rates. Themain difference to the standard approaches is thatwe create a map view of the distribution of bothproperties in the whole resource area.The simulated temperature and fluid flow field andthe distribution of physical properties in 3-D arethen processed further with a set of programs toderive several characteristic parameters (e.g.transmissivity, mean water density, meantemperature of one formation at depth).Essentially, we analyse the physical properties inthe subsurface at every location in space. This isthen used as an input for the extended volumetricheat-in-place calculation (following Muffler andCataldi, 1978) and the well doublet spacing andmaximum pumping rate analysis from Gringarten(1978) and Banks (2009), as described above.The distribution of temperatures, local heat-inplaceand the evaluation of sustainable pumpingrates in the resource area now directly allows theexploration for a suitable area given thecharacteristics of a geothermal application. Forexample, we can now identify areas in the mapwhere we can achieve the required pumping ratefor a given minimum temperature and availableheat which, in the end, determines the economicsof a geothermal application.Example ModelWe apply our workflow for geothermal resourceestimation to a full 3-D geological model to localheat-in-place and sustainable pumping rateevaluation. The model is situated in a half-grabensetting (Fig. 4). A large normal fault in the east offsetsthe basement creating a basin. This basin isfilled with several sedimentary formations that arefurthermore displaced by normal faults, leading toan internal graben structure. The scale of themodel is 8 km x 8 km x 5 km.3113

Australian Geothermal Energy Conference 2009Figure 4: Simple geological model used for the application of the workflow. Thestructural setting is a half-graben structure; the basin is filled with sedimentaryformations that are further cut by faults.(a) Local heat-in-place(b) Sustainable pumping ratesFigure 5: Selected results of our workflow. Analyses are performed for the secondlowest sedimentary formation (light green in Fig. 4).(a) local heat-in-place, normalised to m 2 . (b) Sustainable pumping rates [m 3 /s] fora production period of 30 years. We can clearly identify the most promising areas.4114

Australian Geothermal Energy Conference 2009This structural set-up happens to be similar toareas in the Perth Basin and representative ofgeological settings in other sedimentary basins.Values for thermal conductivity and hydraulicproperties are also similar to formations in thePerth Basin.ResultsThe maps in Figure 5 show the most importantresults of our integrated workflow, i.e. the localheat-in-place and the maximum pumping rate forone formation. These maps are created in a GISframework and can directly be used for a locationbasedanalysis. We obtain the local heat-in-placein addition to the total heat-in-place which isusually estimated (it would be approximately5.2E18 J in this example).The map dimensions are the same as for themodel (8 x 8 km). Displayed is the analysis for thesecond lowest sedimentary formation (light greenin Fig. 4). We can see that most of the heat inplace (Fig. 5a) is located within the Northern partof the graben. In the same area, we can obtainthe highest sustainable pumping rates (heredetermined for a total lifetime of 30 years). Thepatterns coincide in this case as we areconsidering a simple structure with homogeneouspermeabilities and thus pumping rates arestrongly related to temperature (which is, in thissimple case, also reflected by the local heat-inplacepattern). In other cases (e.g. in lowerpermeability settings like Enhanced GeothermalSystems), we might obtain a completely differentpicture for local heat-in-place and sustainablepumping rates.DiscussionWe presented an integrated geothermal resourceevaluation workflow that combines and extendsclassical methods. Starting from a full 3-Dgeological model and relevant physical properties,we simulate the temperature and fluid flow fieldsand use these as a basis for a variety ofestimations. Firstly, we calculate the overall heatin-place,as defined in Muffler and Cataldi (1978).We extend this classical method to a locationbasedanalysis to identify directly the position of avaluable resource. We also use the results of thesimulation for an estimation of a well doubletscheme and sustainable pumping rates, afterGringarten (1978) and Banks (2009) and extend itto a resource-wide estimation. The main benefit ofour workflow is that it directly combines thesestandard methods for a location-basedgeothermal resource and sustainability analysis.As the results from our integrated workflow arelocation-/map-based, it is possible to combinethem with other relevant location factors. We can,for example, combine our analyses with a map ofthe depth of a formation and a maximum drillingdepth. Other map-based economic constraintscan directly be implemented, e.g. the distance tothe market or available infrastructure. Ourworkflow thus opens up the way to an integrationof geological, geothermal, technical and financialconsiderations within one combined framework.Furthermore, our workflow can be extended toscenario testing. All the single steps in theworkflow are linked. It is thus possible to directlytest the effect of a change in the geological modelor the physical properties on the estimation of thesustainable pumping rate. This is not possiblewith common standard approaches.The results of our simple example model (Fig. 5)are based on several assumptions andsimplifications (see Gringarten, 1978, and Mufflerand Cataldi, 1978, for a detailed description oftheir assumptions). The calculated estimationshave to be considered in the light of theseassumptions. Still, in a recent review of thesemethods, Banks (2009) points out that they areapplicable in many cases and provide a ratherconservative estimate. We interpret the numbersas a guideline but the distribution in space asvery valuable information as this directly pointsout the location of a probable geothermalresource.Our approach is flexible and can be applied insimple and complex settings. The geologicalmodelling is capable of dealing with complicatedgeological settings, like reverse faulting oroverturned folding and doming structures (e.g.Calcagno, 2008). The geothermal simulation canbe extended to include reactive transport andspecies transport (Clauser, 2003). Furthermore,the applied simulation code can also modelpumping and re-injection. This will beimplemented in the future into our workflow. It willthus be possible to directly validate the effect oflong-term pumping in the fluid and heat flow fieldin complex geological settings in an identifiedtarget area.ReferencesBanks, D., 2009, Thermogeological assessmentof open-loop well-doublet schemes: a review andsynthesis of analytical approaches: HydrogeologyJournal,Calcagno, P., Chiles, J. P., Courrioux, G., Guillen,A., 2008, Geological modelling from field data andgeological knowledge: Part I. Modelling methodcoupling 3D potential-field interpolation andgeological rules: Physics of the Earth andPlanetary Interiors, v. 171, p. 147-157Clauser, Christoph, Bartels, Jörn, 2003,Numerical simulation of reactive flow in hotaquifers. SHEMAT and processing SHEMAT.Berlin: Springer.Gringarten, Alain C., 1978, Reservoir lifetime andheat recovery factor in geothermal aquifers used5115

Australian Geothermal Energy Conference 2009for urban heating.: Pure and Applied Geophysics,v. 117, p. 297–308.Kohl, T., Baujard, C., Zimmermann, G., 2007,Modelling of Geothermal reservoirs – anoverview: ENGINE Mid-Term Conference,Potsdam, January 2007.Muffler, P., Cataldi, R., 1978, Methods for regionalassessment of geothermal resources:Geothermics, v. 7, p. 53–89.Turner, K., 2006, Challenges and trends forgeological modelling and visualisation: Bulletin ofEngineering Geology and the Environment, v. 65,p. 109-1276116

Australian Geothermal Energy Conference 2009Exergetic performance and power conversion of a CO 2 thermosiphonAleks D Atrens 1 *, Hal Gurgenci 1 and Victor Rudolph 11 The Queensland Geothermal Energy Centre of Excellence, The University of Queensland, QLD 4072* Corresponding author: aleks.atrens@uq.edu.auEngineered geothermal systems (EGS) supply thepotential to produce a significant capacity of baseloadrenewable electricity. In EGS that are nothydraulically connected to a source of waterrecharge off the opportunity to use CO 2 as a heatextraction fluid instead of H 2 O. CO 2 offers theadvantages of ease of flow through thesubsurface reservoir, an innate buoyancy drivingsimplifying surface equipment design, and lowerdissolution of compounds that lead to fouling inwellbores and surface equipment. Theseadvantages are balanced by higher frictionallosses within the wellbores, particularly theproduction wellbore due to the low density of CO 2in this process component. Here we explore theresults of these advantages and disadvantageson the exergy extracted from the geothermalreservoir, and examine the impact of direct use ofCO 2 in power conversion equipment.Keywords: Carbon dioxide, EGS, enhancedgeothermal systems, CO2, thermosiphonIntroductionThe use of CO 2 in EGS has been discussed in anumber of previous works (Brown 2000; Pruess2006; Gurgenci, Rudolph et al. 2008; Pruess2008; Atrens, Gurgenci et al. 2009a). The use ofCO 2 in EGS where CO 2 recovered from theunderground reservoir is fed directly into a turbine(known as a CO 2 thermosiphon), is significantlydifferent from H 2 O flash or binary plants.A convenient method for comparing powergeneration systems with significant internaldifferences is through the usage of exergy. Thisprovides a measure of the maximum theoreticalelectricity that can be generated from the system.As such, a comparison of the exergy available atthe surface can be used as a rough measure tocompare the different designs. Exergy availableon the surface Ψ is calculated from:Ψ = m(h prod – h inj – T 0 (s prod – s inj ))Where h prod and s prod are the enthalpy and entropyof fluid exiting the production wellhead, h inj and s injare the enthalpy and entropy entering the injectionwellhead, and T 0 is the reference temperature(ambient temperature is used).The enthalpy and entropy at the injection andproduction wellheads is calculated by methodsdescribed in previous work (Atrens, Gurgenci etal. 2009b).Exergy RecoveryFluid flow of CO 2 compared to water as calculatedfrom modelling methods in previous work isshown in figure 1 (for a reservoir of hydraulicimpedance as per Soultz-sous-Foret). Muchlarger flow-rates of CO 2 then H 2 O can beachieved due to its lower viscosity in the reservoir,particularly in the region near the injection well(where the viscosity of water is much higher).Figure 1: Injected fluid flow-ratesHowever, due to larger pressure drop in theproduction well, in conjunction with the lower heatcapacity of CO 2 compared to water, CO 2 willextract less exergy than water under mostconditions. This situation can be changed throughincrease in production well diameter size. Thischange has very large effects on the CO 2 ,significantly reducing the pressure drop in theproduction well leading to higher exergy recovery.As well diameters generally used are anappropriate size for the volumetric flows likely forwater, the effects on exergy extraction of waterare negligible. Exergy extracted for a basereference case, and with two larger diametercasing sizes for CO 2 -based systems is shown infigure 2.1117

Australian Geothermal Energy Conference 2009Figure 2: Exergy produced at the surface by the differentfluids; (a) for reference casing internal diameter size of0.2313 m; (b) for internal diameter of 0.3 m; (c) for internaldiameter of 0.4 mPower ConversionThe ability to extract exergy from the subsurfacereservoir is not the only issue of criticalimportance to an EGS power plant. Also importantis the capability to convert the exergy extractedinto electricity in an effective manner.Because CO 2 in a thermosiphon plantconfiguration is used directly in power conversionequipment, the impact of production pressure onthe ability to convert available exergy intoelectricity is significant. This means that as flowratesthrough the subsurface are increased (andexergy extraction is increased), the ability toconvert the exergy extracted into electricity isreduced (due to the reduced difference inpressures between the production wellhead andthe injection wellhead). This leads to therelationship between turbine work and exergyproduced as shown in figure 3. This is based onan assumed isentropic efficiency of the turbine of85%, while in reality higher isentropic efficiencymay be achievable. The second law efficiencyshown in this figure represents the proportion ofthe actual work out of theoretical maximum workachievable in an ideal case.This relationship can be improved through theaddition of a recompression system. In such acase, the turbine exhaust would be designed at alower operating pressure, and the effluent fromthe turbine would be recompressed after cooling,and prior to reinjection. The thermodynamicrelationship of this process change is shown infigure 4.Figure 3: Energy recov ery considerations for CO2 for thereference case; (a) Exergy produced at the surface; (b)Electricity generated; (c) Second law efficiency of the overallprocess.Figure 4: Temperature-entropy diagram showing (a) CO2-based EGS basic power cycle; and (b) recompressionmodification. Point (1) indicates the injection wellhead andheat exchanger outlet, point (2) indicates the base of theinjection well and the entry to the reservoir, point (3)indicates the base of the production well, point (4) indicatesthe production wellhead and turbine inlet, and point (5)indicates the turbine exhaust and cooling system inlet. Point(5’) indicates the turbine exhaust with recompressionmodification, point (6) indicates the compressor inlet, andpoint (7) indicates the compressor outlet.Process modification in this manner leads toperformance as shown in figure 5. This representsa significant improvement in electricity recovery,and indicates a worthwhile process modification.2118

Australian Geothermal Energy Conference 2009Figure 5: Energy recov ery considerations for CO2 as infigure 3, with recompression process modification; (a)Exergy produced at the surface; (b) Electricity generated; (c)Second law efficiency of the overall process.Reference CaseThe reference case used in this work utilises dataas given in table 1.Table 1: Reference Case DataParameterValueDepth (m) 5000Reservoir Length (m) 1000Reservoir Temperature (°C) 225Injection Temperature (°C) 25Reference Temperature (°C) 25Min. Reservoir Width (m) 0.73Max Reservoir Width (m) 251ParameterValueDepth (m) 5000Hydraulic Impedance (MPa.s/L) 0.2Reservoir Pressure (MPa) 49Wellbore roughness, ε (m) 0.0004Wellbore Diameter (m) 0.231Isentropic Efficiency, ηII 0.85ReferencesAtrens, A. D., Gurgenci, H., Rudolph, V., 2009a,CO2 thermosiphon for competitive powergeneration, Energy & Fuels 23(1): 553-557.Atrens, A. D., Gurgenci, H., Rudolph, V., 2009b,Exergy analysis of a CO2 thermosiphon, Thirtyfourthworkshop on geothermal reservoirengineering, Stanford University, Stanford,CaliforniaBrown, D. W., 2000. A hot dry rock geothermalenergy concept utilizing supercritical CO2 insteadof water. Twenty-Fifth Workshop on GeothermalReservoir Engineering, Stanford University,Stanford, California.Gurgenci, H., V. Rudolph, et al., 2008. Challengesfor geothermal energy utilisation. Thirty-ThirdWorkshop on Geothermal Reservoir Engineering,Stanford University, Stanford, California.Pruess, K. (2006). "Enhanced geothermalsystems (EGS) using CO2 as working fluid—Anovel approach for generating renewable energywith simultaneous sequestration of carbon."Geothermics 35: 351–367.Pruess, K. (2008). "On production behaviour ofenhanced geothermal systems with CO2 asworking fluid." Energy Conversion andManagement 49: 1446-1454.3119

Australian Geothermal Energy Conference 2009Radiation associated with Hot Rock geothermal powerDavid L. Battye * , Peter J. AshmanSchool of Chemical Engineering, University of Adelaide, SA 5005.* Corresponding author: david.battye@adelaide.edu.auWater in Hot Rock reservoirs is in contact withgranites containing radioactive elements(radionuclides). The wider community is generallyaware of this fact through publicity by theAustralian geothermal industry. It is less clear tothe public what radiation hazards may exist forHot Rock projects, and how significant they maybe. The aim of this study was to investigate likelyradiation hazards associated with Hot Rockgeothermal power, with a particular emphasis onradon emission. The study consisted of a reviewof literature and quantitative estimates of radonemission and dispersion from a typical Hot Rockreservoir. This information has been used todevelop a fact sheet, published by PrimaryIndustries and Resources South Australia(PIRSA, 2009).Keywords: radiation, radon, radium, uranium, HotRock geothermal.Dissolved radionuclidesThe radionuclides of interest are those with longenough half-lives to travel to the surface from thereservoir, including isotopes of uranium, thorium,radium, and radon.Uranium and thorium in granites are mostly foundin monazite, zircon and allanite mineral phases.These phases are highly insoluble under mostconditions, therefore the controlling mechanismsfor radionuclide release are dissolution at therock-water interface and alpha-recoil (ejectionfrom the rock due to alpha-decay of the parentradionuclide).Uranium solubility is a strong function of theoxidising or reducing nature of the geofluid.Uranium contents in granite groundwaters arefrequently less than the recommended limit fordrinking water (20 g/L), but may exceed 800g/L in oxidising groundwaters (Gascoyne, 1989).Uranium does not emit gamma radiation,therefore it is only hazardous if ingested orinhaled.The solubility of thorium is low since it tends toform the insoluble hydroxide. Thus, thoriumconcentrations in groundwaters rarely exceed 1g/L (Langmuir and Herman, 1980).Radium is released from the rock by alpha-recoil,but is readily scavenged from solution by sorptiononto mineral surfaces. Cations compete withradium for sorption sites, thus the solubility ofradium increases strongly with total dissolvedsolids (TDS), as indicated by groundwater datashown in Figure 1. Where natural waters exist inHot Rock reservoirs, they are typically quite highin dissolved solids, eg. TDS = 100 g/L at Soultz(MIT, 2006) and 21 g/L in the Cooper Basin(Wyborn et al, 2004). The TDS of water in anoperational field will depend on the extent ofdilution of natural water with injected water. AtFenton Hill, substantial dilution was achievedduring open-loop operation (Grigsby et al, 1983).On switching to closed loop operation, the TDSreached a steady value of ~3 g/L. Thus, naturalwater in Hot Rocks may have radium activities atthe upper end of the scale shown in Fig. 1, but theactivity can be reduced to low levels by dilution ofdissolved solids. To gain some perspective onwhat constitutes “low” levels, we note thatgroundwater sources for drinking water maycontain radium at up to or exceeding 0.5 Bq/L(NHMRC, 2004), a level corresponding to TDS 5 g/L according to the trend in Fig. 1.Hot Rock reservoirs are at significantly highertemperatures than the groundwaters for whichuranium, radium and thorium data exist. Solubilityis typically enhanced by increasing temperatureand higher concentrations of these radionuclidesthan cited above are therefore possible,depending on the other contributing factors. TheHot Rock geothermal literature reportsmeasurements of radon in solution but not otherradionuclides of interest. Such measurements incurrent and future projects would be of scientificvalue, and would directly address radiationconcerns.Deposition in surface equipmentThe Hot Rock geothermal power concept involvescirculation of water through an artificial reservoirand surface equipment in a closed loop. Coolingand depressurising of water in surface equipmentmay lead to solid deposits in the form of scalesand sludges. There is potential for these depositsto be radioactive due to inclusion of precipitatedradionuclides. This problem is encountered in theoil and gas industry, where highly saline producedwaters with significant dissolved radium arehandled. These waters tend to be saturated withbarium and strontium sulphates, which precipitateas scales and sludges. Dissolved radium readilysubstitutes for barium and strontium in the solids,creating a radioactive waste material which mustbe periodically removed. Workers are exposed togamma radiation, which is able to penetrate pipeand vessel walls. Additionally, inhalation ofradioactive dust is an exposure hazard whenremoving the deposits. Hamlat (2001) providesestimates of radiation doses received by workersin the oil and gas industry which suggest that the1120

Australian Geothermal Energy Conference 2009exposure is low - generally < 1 mSv per year -compared with the Australian occupational doselimit of 20 mSv per year (ARPANSA, 2002),provided that appropriate protective measures aretaken. This level of exposure is less than theaverage background radiation dose in Australia of1.5 mSv per year (ARPANSA, 2009).The levels of dissolved solids, radium, and ofstrontium and barium sulphates are expected tobe lower for Hot Rock waters than generallyencountered in the oil and gas industry. Hence,lesser quantities of radioactive deposits areanticipated, with lower concentrations ofprecipitated radium. The gamma radiation hazardassociated with solid deposits may therefore besmall compared to that managed in the oil andgas industry. The data of Fisher (1995) in Fig. 1 isrepresentative of waters produced from oil andgas fields, which frequently have TDS in excessof 100 g/L. Diluted water circulating in Hot Rocksis expected to have at least 10 times less TDSthan this, and therefore 7 times less radiumactivity according to the trend in Fig. 1. Thesame reduction in radioactivity of the barium andstrontium sulfate deposits can be expected.Considering that the occupational radiationexposure in the oil and gas is already relativelylow, the exposure from Hot Rock geothermalpower plants is therefore likely to be very small.However, the ALARA (As Low As ReasonablyAchievable) principle of radiation protection willstill apply, which calls for monitoring of exposureand protective measures. In particular, workersinvolved with removing solid deposits fromequipment will need to avoid inhaling dusts.RadonRadon is an inert radioactive gas which is formedby the alpha-decay of radium. It is normallypresent at low levels in ambient air. The averageradon level in Australian homes is 10.5 Bq/m 3(ARPANSA, 2009). The decay products of radoncan lodge in the lungs if inhaled, exposing them toionizing radiation and increasing the risk of lungcancer. The action limits for radon in air are 200Bq/m 3 in dwellings and 1000 Bq/m 3 in workplaces(ARPANSA, 2002).In a geothermal reservoir, radon enters solutionpredominantly by alpha-recoil and remainsdissolved until its decay. The maximum radoncontent is achieved when the rates of solution anddecay are equal This occurs if the residence timeof water in the reservoir exceeds 25 days ( 222 Rnhas a half life of 3.8 days). Radon activity inwater was a maximum of 500 Bq/L at Fenton Hill(Grigsby et al, 1983) and 200 Bq/L atRosemanowes (Richards et al, 1992).Radon emission and dispersionRadon emissions will occur during open-loopcirculation testing of newly created reservoirs,from uncontrolled flows of geothermal water, orfrom venting of light gases from steamcondensers.If the Hot Rock reservoir is assumed to consist ofplanar, parallel fractures with even spacing, theradon emanation rate, R (atoms/s) is given by:R 2FVSwhere F is the radon flux from fracture surfaces(atoms s -1 m -2 ), V the fractured rock volume (m 3 )and S the fracture spacing (m).The radon flux from plane surfaces ofCarnmenellis granite cubes in water wasmeasured at 30 atoms s -1 m -2 by Andrews et al.(1983). The granite had an average uraniumcontent of 13.5 ppm, and we have assumed that asimilar flux value is appropriate for Cooper Basingranites, which typically contain 16 ppm ofuranium (Geoscience Australia, 2008).Kruger (1995) inferred a mean fracture spacing of50 m from circulation tests at the Rosemanowessite.Steady-state emission of radon from a field canbe estimated by assuming that the emission rateat the surface is equal to the emanation rate.Decay of radon in the reservoir is neglected.Assuming the above cited values for fracturespacing and flux in the Cooper Basin, this methodyields an emission rate of 1.2 billion atoms (2520Bq) per second, per cubic kilometer of fracturedrock.Radon is emitted from steam-venting stacksduring circulation testing, therefore downwindradon levels are of interest. A simple Gaussiandispersion model was used to predict themaximum radon activity at ground level downwindof a single emission source with respect toeffective emission height (physical vent heightplus an allowance for plume rise), and windspeed. Results for a 1 km 3 reservoir are shown inFigure 2. Radon levels are generally negligible foremission heights of 10 m or more, except in calmconditions (wind speeds less than 1.8 km/h). Inthe latter case, levels are expected to be less thanthe action limit for dwellings.During an uncontrolled flow of geothermal waterfrom a well, the effective emission height is closeto ground level, eg. 2-5 m. Figure 1 suggests thatfor a 1 cubic kilometre reservoir, downwind radonlevels would be significant but not exceeding theworkplace action limit except under calmconditions. However, it should be rememberedthat Figure 1 is based on a steady-state emissionrate. If the water in the reservoir has been still fora period, its radon content will be higher thanduring circulation. Therefore the initial emissionrate will initially be higher than the steady-statevalue. For example, if still water in the reservoir2121

Australian Geothermal Energy Conference 2009attains a radon level of 500 Bq/L, then a suddenflow of 50 L/s will cause an initial emission rate of25,000 Bq/s, a value 10 times the steady valueassumed for Figure 1 and therefore increasingdownwind radon activities by the same factor.Calm conditions usually occur at night in centralAustralia and may last several hours. Estimatessuggest that during calm periods radon emissionmay be a significant hazard for the area within200 m downwind of an uncontrolled flow.However, the simple Gaussian dispersion modelresults become spurious as wind speedapproaches zero, and more advanced dispersionmodels are required to more accurately predictradon levels in calm periods.AcknowledgementsThis work was commissioned by PrimaryIndustries and Resources SA (PIRSA). We wishto thank Alexandra Long and Michael Malavazosof PIRSA for their guidance throughout theproject.ReferencesAndrews, J.N, 1983, Dissolved radioelements andinert gases in geothermal investigations,Geothermics, v. 12, no. 2/3, p. 67-82.ARPANSA, 2009, Background radiation factsheet,http://www.arpansa.gov.au/pubs/baseline/bg_rad.pdf (retrieved June 2009).ARPANSA, 2002, Radiation Protection Series No.1,http://www.arpansa.gov.au/publications/Codes/rps.cfm (retrieved June 2009).Fisher, R., 1995, Geologic, geochemical andgeographic controls on NORM in produced waterfrom Texas oil, gas and geothermal reservoirs,Final report, US Department of Energy ReportDOE/MT/92011-12.Gascoyne, M., 1989, High levels of uranium andradium in groundwaters at Canada's UndergroundResearch Laboratory, Lac du Bonnet, Manitoba,Canada, Applied Geochemistry, v. 4, p. 577-591.Geoscience Australia, OZCHEM database,http://www.ga.gov.au/gda/ (retrieved October2008)Grigsby, C.O., Tester, J.W, Trujillo, P.E., Counce,D.A., Abbot, J., Holley, C.E., and Blatz, L.A.,1983, Rock-water interactions in hot dry rockgeothermal systems: Field investigations of in situgeochemical behavior, Journal of Volcanologyand Geothermal Research, 15, p. 101-136.Hamlat, M.S., Djeffal, S., Kadi, H., 2001,Assessment of radiation exposures from naturallyoccurring radioactive materials in the oil and gasindustry, Applied Radiation and Isotopes, 55, p.141–146.Kruger, P., 1995. Heat extraction from HDRgeothermal reservoirs. Proceedings of the WorldGeothermal Congress, 1995, Florence, Italy, Vol.4, pp. 2517-2520.Langmuir, D. and Herman, J.S., 1980, Themobility of thorium in natural waters at lowtemperatures, Geochimica et Cosmochimica Acta,44, p. 1753-1766.MIT, 2006, The Future of Geothermal Energy,http://geothermal.inel.gov (retrieved October2008).NHMRC, 2004, Australian Drinking WaterGuidelines,http://www.nhmrc.gov.au/publications/synopses/eh19syn.htm (retrieved June 2009).PIRSA, 2009, Fact Sheet: Radon and NaturallyOccurring Radioactive Materials (NORM)associated with Hot Rock Geothermal Systems,http://www.pir.sa.gov.au/__data/assets/pdf_file/0013/113341/090107_web.pdf (retrieved September2009).Richards, H.G., Savage, D. and Andrews, J.N.,1992, Granite-water reactions in an experimentalHot Dry Rock geothermal reservoir,Rosemanowes test site, Cornwall, U.K., AppliedGeochemistry, v. 7, p. 193-222.Wyborn, D., de Graaf, L., Davidson, S., and Hann,S., 2004, Development of Australia’s first hotfractured rock (HFR) underground heatexchanger, Cooper Basin, South Australia, PESAEastern Australasian Basins Symposium II,Adelaide, p. 423-430.3122

Australian Geothermal Energy Conference 20091000Radium 226 (Bq/L)1001010.10.01Fisher(1995)Gascoyne(1989)Trendline0.0010.1 1 10 100 1000Total dissolved solids (g/L)Figure 1: Radium-226 activity versus total dissolved solids in groundwaters. Fisher (1995): Oil, gas andgeopressured-geothermal wells in Texas. Gascoyne (1989): Granite groundwaters, Whiteshell ResearchArea, Canada.10000Maximum ground-level radonactivity (Bq/m 3 )10001001010.1Action limit for workplacesAction limit for dwellingsAverage level in Australian homes1015Effective emission height (m) 200 2 4 6 8 10Wind speed (km/h)25Figure 2: Maximum ground-level radon activity directly downwind of a single emission source, withrespect to wind speed and effective emission height. Assumes an emission rate of 2520 Bq/s, based onsteady-state emission from 1 km 3 of fractured rock, 50 m mean fracture spacing, 30 atoms s -1 m -2 radonflux from fractures, and neglecting decay of radon. To determine radon levels at another emission rate, E(Bq/s), multiply the radon level in the plot by E/2520.4123

Australian Geothermal Energy Conference 2009Silica deposition in Enhanced Geothermal SystemsDonny S. Bhuana 1 , Peter J. Ashman 1* , Graham J. Nathan 2Centre for Energy Technology1 School of Chemical Engineering, The University of Adelaide.2 School of Mechanical Engineering, The University of Adelaide.* Corresponding author: peter.ashman@adelaide.edu.auCentral Australia has one of the hottest rockresources on earth, making it a potential regionfor developing geothermal energy usingEnhanced Geothermal Systems (EGS). However,this technology is yet to be proven under localconditions and so relatively little field data orexperimental data relevant to local conditions areavailable. Nevertheless, much can be learnedfrom the global experience due to the operation ofconventional geothermal energy plants, i.e. thoseusing heat from volcanic activity. The amount ofheat that can be extracted from high-temperatureunderground reservoirs using water as a workingfluid in a closed loop is significantly limited by theonset of silica precipitation and subsequentscaling of heat exchanger surfaces and fouling ofreservoirs as the water is cooled. Theprecipitation rate of amorphous silica is relativelyrapid, resulting in potential deposition if the wateris cooled below its saturation temperature. Withthe present level of understanding, experimentaldetermination of deposition rates in individualfields is ultimately required to determine thescaling potential of a given geothermal brine.However, in the absence of such data underconditions of relevance to EGS operationalconditions, a simplified mathematical approach isemployed to predict the deposition rate of silicaunder idealised conditions. This is seen as a firststep in developing a rigorous model of thebehaviour of silica in EGS. Such a model wouldallow the optimisation of silica managementstrategies and allow new methods of silicaremoval and/or control to be devised, evaluatedand assessed, prior to experimentalinvestigations, at low cost.Keywords: Hot dry rock, silica fouling, silicadeposition rate, silica polymerizationSilica ScalingSolid silica is present within geothermal reservoirsas quartz, and the concentration of silica in thebrine at the exit of the reservoir, typically 300-700mg/kg SiO 2 , is controlled by the solubility of quartzat the reservoir temperature (Fournier and Rowe,1966). On cooling the brine becomessupersaturated with respect to amorphous silicaand silica either precipitates from the brine asamorphous silica or polymerises to form colloidswhich may stay in solution or may deposit ontosurfaces. The fouling of heat exchanger (andother) surfaces can lead to decreased thermalefficiency, increased maintenance costs due tocleaning and increased operational costs due toexpensive abatement strategies.The mechanism of silica precipitation anddeposition is quite complex and poorly understood(Brown and Bacon, 2009). Following an inductionperiod (Gunnarsson and Arnórsson, 2005;Bohlmann et al., 1980), monomeric silica beginsto polymerize. At high degrees of supersaturation,polymerisation occurs via rapidhomogeneous nucleation. Supercritical silicaparticles grow by further reaction with silicic acidand eventually coagulate or flocculate to producea gel, followed by a cementation of the particles inthe gel by chemical bonding and further moleculardeposition among the silicic acid particles (Wereset al., 1982). The polymerization process willcontinue until the concentration of monomericsilica reduces to the saturation concentration ofamorphous silica at the fluid temperature. Thedeposition process following the polymerizedsilica is known as particle deposition, whichproduces white, fluffy, scale with dry density ofabout 0.95 g/cc. At lower concentrations ofdissolved silica, slow homogenous nucleation canoccur with direct deposition of dissolved silica onsolid surfaces being the dominant polymerisationprocess (Weres et al., 1982). Deposits that areformed by direct precipitation of monomeric silicaare more destructive and difficult to remove,producing hard, vitreous, dark coloured scale,with the density of about 2.0 g/cc. Some studieshave identified that monomeric silica is more likelyto precipitate and deposit than polymeric silica(Bohlmann, 1980; Gunnarsson and Arnórsson,2005). A number of factors effect thepolymerization rate of amorphous silica ingeothermal brine, including pH, temperature, saltconcentration, residence time, and the presenceof certain ions.Prediction of the silica deposition rateReinjection aquifers in Enhanced GeothermalSystems (EGS) have been considered to be thearea with the greatest risk of having silicadeposition problem. Predicting polymerisation anddeposition rates of dissolved silica in the EGSreinjection aquifer is complex due to a lack of datafrom operating sites. A number of factors shouldbe taken into account in modelling the realconditions, such as fluid mechanics, heat andmass transfer. Here we have taken a verysimplified approach using experimental data forthe precipitation of monomeric silica obtainedunder ideal conditions.1124

Australian Geothermal Energy Conference 2009A schematic diagram of the system model is where k + is the forward rate constant, K is theheat exchanger tube length. At the heatr SiO k(1 / )2 Q K mol.L -1 .s -1 exchanger inlet, the geofluid temperature is wellabove the saturation temperature and theshown in Figure 1. A closed loop binary cycle is equilibrium constant and Q is the activity quotient:assumed with a reservoir depth of 5000 m. Only2the flow of brine in the reservoir and through theQ ( aH SiO) /( aSiO)( aHO)4 42heat exchanger (30 m length) is considered.Water exits the heat exchanger at temperature T s1 where a i is the activity of species i. The quantity= 90 o C and is returned to the reservoir, via the Q/K indicates the degree of saturation or thereinjection well. The brine is heated to saturation ratio (S).temperature T R = 270 o C at the exit of the reservoirand returns to the surface reaching the heat Rimstidt and Barnes (1980) provide expressionsexchanger at temperature T s = 260 o C. The for k + and K, as a function of temperature allowingtemperature profiles in the production well the precipitation rate of amorphous silica to be(2 o C/km) and heat exchanger (5.67 o C/m) are simply calculated as a function of temperatureassumed to be linear. The temperature profile in and the concentration of silica in solution. Here,the reinjection well is calculated using simple heat silica in solution is assumed to be in equilibriumtransfer assumptions and follows the method of with solid quartz at the reservoir temperature andYu et al. (2009).its concentration is determined using theexpression of DiPippo (2008).The precipitation rate of amorphous silica isElectricityplotted in Figure 2 as a function of temperatureand for silica concentrations of 550, 675, 745 and800 ppm, which correspond to quartz equilibriumconcentrations at reservoir temperatures of 270,300, 320 and 340 o C, respectively. As temperatureFlashdecreases, the degree of saturation, S, increasesand so the predicted precipitation rate increasesuntil a maximum is achieved. With furtherCondenserdecrease in temperature, the forward rateconstant (k + ) decreases faster than S and so thenet rate of precipitation decreases. As aconsequence, for temperatures below about50 o C, the precipitation rate is small, despite thex = HHeat ExchangerTS1large extent of supersaturation and this,TSpotentially, provides a mechanism by which silicadeposition may be controlled or minimised.5E‐10x+Δx550 ppm 675 ppm 745 ppm 800 ppmΔx4E‐10x3E‐10TRTR12E‐10x = 0Reservoir1E‐100Figure 1: Schematic diagram of the mathematical simulation0 50 100 150 200Temperature ( o C)The kinetics of amorphous silica precipitationhave been determined by Rimstidt and Barnes(1980) for 0-300 o C. For the reversible reaction:SiO 2 (s) + 2H 2 O(l) ↔ H 4 SiO 4 (aq)the net precipitation rate, for dilute solutions, maybe expressed as:Figure 2: Precipitation rate of amorphous silica as a functionof temperature and silica concentration.Simulation results and discussionThe precipitation rate of silica in the heatexchanger is plotted in Figure 3 as a function ofPrecipitation rate of amorphous silica (mol.L ‐1 .s ‐1 )2125

Australian Geothermal Energy Conference 2009precipitation rate is negligible. As the temperaturedecreases below 140 o C, which occurs atapproximately 22 metres, the geofluid becomessaturated with respect to amorphous silica andthe precipitation rate increases substantially. Thehighest rate of precipitation in the heat exchangeroccurs at 26 metres, corresponding to atemperature of 113 o C. Thus, the final 25% of theheat exchanger is susceptible to fouling due tosilica deposition.Silica polymerisationThe disappearance of monomeric silica fromsolution may also occur via a polymerisationreaction that proceeds quite rapidly following aninitial induction period. Bohlmann et al. (1980)report that the induction period, i , may becalculated as a function of the supersaturationratio and the pH of the solution as:Precipitation rate (Mol.L ‐1 .s ‐1 )1E‐108E‐116E‐114E‐112E‐1130 metre - heat exchangertube lengthpoint in the tube where thebrine becomessupersaturated with respectto amorphous silica00 5 10 15 20 25 30 1 lni lnln( / ) C Ce 4.8 2.3(pH 4.5)Figure 5 is a plot of the calculated inductionperiod, as a function of the supersaturation ratio,for pH = 5, 6 and 7. At any supersaturation ratioabove about 1.5, the induction period is quiterapid and occurs in less than 1 minute for neutralpH. Thus, the polymerisation of silica is expectedto contribute substantially to the precipitation ofsilica from solution.8‐ Distance from the heat exchanger inlet (m) ‐Figure 3: Precipitation rate as a function of temperature inthe heat exchanger for [SiO2] = 550 ppm1.E+081.E+07Induction time of amorphous silicaThe precipitation rate of silica and the geofluidtemperature in the reinjection well is plotted inFigure 4. At shallow depths, the geofluid in thereinjection well continues to cool due to the lowertemperature of the surrounding earth. Theprecipitation rate of silica decreases accordinglyand reaches a local minimum at a depth of 330 mcorresponding to a minimum temperature of83.3 o C. With increasing depth, the precipitationrate increases to a maximum at a depth of 1350m, which occurs at a temperature ofapproximately 112 o C and corresponds to themaximum precipitation rate for [SiO 2 ] = 550 ppmshown in Figure 2. At greater depths, thetemperature increases further and theprecipitation rate decreases as the extent ofsupersaturation decreases. Thus, the upper 30%of the reinjection well is susceptible to fouling dueto silica precipitation.Precipitation rate (Mol.L ‐1 .s ‐1 )1E‐108E‐116E‐114E‐112E‐11000 1000 2000 3000 4000 5000‐ Reinjection well depth (m) ‐Figure 4: Precipitation rate and geofluid temperature (RHaxis) as a function of depth in the reinjection well for [SiO2] =550 ppm30025020015010050Geofluid Temperature ( o C)Induction time (minutes)1.E+061.E+051.E+041.E+031.E+021.E+011.E+001.E‐010 0.5 1 1.5 2 2.5Supersaturation ratiopH = 5 pH = 6 pH = 7Figure 5: Calculated induction period for amorphous silica asa function of supersaturation ratio and pHThe present study assumes that amorphous silicain solution is removed primarily via precipitation ofmonomeric silica. The rapid induction timesindicated in Figure 5 suggest that under at leastsome conditions the polymerisation reaction willbe a significant contributor to the removal of silica.Thus, there are limitations of the present workwhen applying these calculations directly topractical enhanced geothermal systems.Furthermore, theoretical based models ofprecipitation, such as those of Rimstidt andBarnes (1980) that have been determined in thelaboratory under ideal conditions, predict ratesthat are about three orders of magnitude slowerthan rates observed in the field (Carroll et al.,1998).The present work may be considered as apreliminary step towards the development of amore rigorous model of silica behaviour in EGS.Future work will include a more detaileddescription of the precipitation and polymerisationrates, based on empirical relationships3126

Australian Geothermal Energy Conference 2009determined under more realistic conditions (e.g.Bohlmann et al., 1980 and Weres et al., 1981).SummarySilica deposition occurs both via directprecipitation of amorphous silica andpolymerisation of dissolved silica to form colloids.In both cases, the final solid product may lead topersistent deposits on heat exchanger surfaces orto fouling of the reservoir due to entrainment offine particles. Precipitation rates have beencalculated as a function of temperature in the heatexchanger and reinjection well for conditionscorresponding to a typical EGS installation. Themaximum rate of precipitation occurs towards theend of the heat exchanger and in the uppersection of the reinjection well, at depths aboveabout 1350 m. Due to high geofluid temperatures,the precipitation rate is calculated to be negligibleat depths below 2000 m in the reinjection well. Inthis study, the rate of precipitation has beencalculated based on laboratory data obtainedunder ideal conditions and the rate ofpolymerisation has been neglected. Future workwill include more detailed descriptions ofprecipitation and polymerisation based onempirical measurements.ReferencesBohlmann, E.G., Mesmer, R.E. and Berlinski, P.(1980). Kinetics of silica deposition from simulatedgeothermal brines. Society of PetroleumEngineers Journal, pp. 239-248.Brown, K.L. and Bacon, L.G. (2009). Pilot plantexperiments at Wairakei Power Station.Geothermics, 38, pp. 64-71.Carroll, S., Mroczek, E., Alai, M. and Ebert, M.Amorphous silica precipitation (60 to 120 o C):Comparison of laboratory and field rates.Geochimica et Cosmochimica Acta, 62, pp. 1379-1396.DiPippo, R. (2008). Geothermal Power Plants:Principles, Applications, Case Studies andEnvironmental Impact, 2 nd edition, Butterworth-Heinemann, Oxford.Fournier, R.O. and Rowe, J.J. (1966). Estimationof underground temperatures from the silicacontent of water from hot springs and wet-steamwells. Am. J. Sci. 264, pp. 685-697.Gunnarsson, I. and Arnórsson, S. (2005). Impactof silica scaling on the efficiency of heat extractionfrom high-temperature geothermal fluids.Geothermics, 34, pp. 320-329.Rimstidt, J.D. and Barnes H.L. (1980). Thekinetics of silica-water reactions. Geochimica etCosmochimica Acta, 44, pp. 1683-1699.Weres, O., Yee, A. and Tsao, L. (1982).Equations and type curves for predicting thepolymerization of amorphous silica in geothermalbrines, Society of Petroleum Engineers Journal,pp. 9-16.Yu, Y., Lin, T., Xie, H., Guan, Y. and Li, K. (2009).Prediction of wellbore temperature profiles duringheavy oil production assisted with light oil. Societyof Petroleum Engineers, SPE 119526.4127

Australian Geothermal Energy Conference 2009Aims of a Basic EGS Model for the Cooper Basin, AustraliaDelton B. Chen 1* , Gregory Wong 11 Geodynamics Limited, PO BOX 2046, Milton, QLD 4064, Australia* Corresponding author: Delton.Chen@geodynamics.com.auGeodynamics Limited is currently undertakingfield development activities to support a proposalfor Engineered Geothermal Systems (EGS) in theCooper Basin, Australia. For feasibilityassessment it is essential that the relationshipbetween EGS design variables and both netelectrical power and return on investment areunderstood. This paper presents key aims andconcepts of a spreadsheet model that will helpprovide this information. The model, which iscurrently in development, is called the Basic EGSModel.Incorporated into the Basic EGS Model are submodelsthat quantify fluid pressures andtemperatures at key locations in the system,including within the geothermal reservoir, withinthe wells, across the heat-exchanger (of thepower plant) and across the circulation pump. Themodel will link the geothermal power result to ageneralist sub-model for a range of power plantdesigns to estimate the net electrical powerdeliverable to market. The model will then link thenet electrical power results to an economic submodelfor calculating financial performance.The EGS design variables of major interestinclude (i) well spacing, (ii) well diameter, (iii) welllayout, (iv) well depth, (v) well trajectory, and (vi)number and location of stimulated fracture zones.These design variables are discussed in contextof their potential impact on geothermal power andeconomic performance.Keywords: EGS, Australia, Cooper Basin, model,geothermal, economic, reservoir, fracture, power,sensitivity.Project and LocationGeodynamics Limited is developing EngineeredGeothermal Systems (EGS) near the small townof Innamincka in South Australia (Figure 1).Drilling and related field work began in 2003 andis currently contained within the company’sGeothermal Retention Licenses (GRL) 3 to 12,totalling 985 km 2 (Figure 1).Figure 1. Site location map showing Innamincka and Moomba townships (dots) and the well bore locations (stars). GeodynamicsLimited holds the geothermal retention licenses (GRL) and geothermal exploration licenses (GEL) shown. The location of thegranite batholith is inferred from gravity and temperature contours.1128

Australian Geothermal Energy Conference 2009The company initially aims to supply base-loadelectricity to a co-located consumer with acommercial demonstration plant (CDP), followedby the development of ten 50 MW e EGS modulesto supply 500 MW e of electricity to the nationalgrid. Each module will consist of about nine wellsdrilled to a maximum depth of 5 km, closed-looppipeline, pump, heat exchanger, air-cooledcondenser, and steam-turbine power plant. Multilayeredreservoir stimulation will be needed andthe economic life of each module will be about 20years.Status of WellsFive wells have been drilled to date, including:Habanero #1, #2 and #3, Jolokia #1, and Savina#1. At the time of writing the status of the wellswere as follows:Habanero #1 (4,421 m TVD 1 ) is aninjection well for the 1 MW e demonstrationpower plant.Habanero #2 (4,358 m TVD) is shut-inand available for a possible side-track.Habanero #3 (4,221 m TVD) was aproduction well for a 1 MW e pilot plantuntil a well rupture on 24 April 2009. On22 May 2009 the well was controlled andsecured with two cement plugs. Theprecise cause of failure and the future ofthe well were not known at the time ofwriting.Savina #1 is temporarily suspended andsecured with a cemented plug at 2,640 mTVD (100 m above a stuck pipe). The wellis available for side-track drilling.Jolokia #1 (4,852 m TVD) is temporarilysuspended whilst preparations are madefor well completion and reservoirstimulation.The drilling of Habanero #1, #2 and #3 intofractured granite, effective hydraulic stimulations,and subsequent closed-loop flow and tracer testsprovided the basis of a proof-of-concept (Grove-White, 2009; Chen and Wyborn, 2009) thatbrought the company a major step closer toachieving its long-term goal of economicallyextracting energy from a non-volcanic geothermalresource. The proof-of-concept report wasreleased to the Australian Stock Exchange (ASX)on 31 March 2009 and is available on the internetat http://www.geodynamics.com.au.Geothermal ResourceThe resource is a radiogenic granite (batholith)buried under ~3.7 km of layered sedimentary rockand it extends slightly beyond GRLs 3 to 12(Figure 1). The company also holds adjacent1 Total Vertical Depth (TVD)Geothermal Exploration License (GEL) 211 andGRLs 20 to 24. The target interval for drilling is3.7-5 km below ground where the granitetemperature is approximately 227-284C. Thegranite produces heat at a rate of 7-10 µW m -3 ,and is comprised of 75% SiO 2 and >5% K 2 O.The granite has crystalline medium-to-coarsesized grains and is saturated with brine which ispressured to ~34.4 MPa above hydrostatic.Regional confinement is provided by sedimentarylayers that have a very low porosity and lowpermeability. The granite was glacially erodedduring the early-Permian ice age (circa 300 Maago) prior to burial. There is no evidence of majorfaulting in GRLs 3 to 12.Rock stress at 4 km depthIn the project area the rock stresses at 4 km depthare characterized by: (i) a vertical minimumprincipal stress of ~90 MPa; (ii) a minor horizontalstress of ~110 MPa; (iii) a maximum horizontalstress of ~140 MPa; and (iv) a pore pressure of~75 MPa. The maximum horizontal stress isorientated east-west due to present day tectoniccompression of the Australian plate. Hydraulicstimulations in this stress field are effective atactivating fractures that are orientated subhorizontally(Grove-White, 2009). This subhorizontalfracture orientation is considered idealfor heat extraction because it promises thedevelopment of vertically-stacked fracture zoneswithin the granite.The Basic EGS ModelMain AimsThe Basic EGS Model is an empirical-analyticalthermo-hydraulic model for constant flowcirculation conditions (on a mass per time basis).The term ‘Basic’ is used in recognition that thefinal EGS model may need to be better calibratedand refined and expanded in scope to include acombination of mechanical, thermal, hydraulic,and chemical processes in time and space (e.g.Hayashi et al., 1999).The Basic EGS Model aims to predict theproduction temperature and pressure (average forall production wells), pump differential pressure,total geothermal power, and total net electricalpower over ~20 years for various EGS designs.The Basic EGS Model is coded in a spreadsheet(Microsoft Office Excel 2007) to facilitate rapiddevelopment. After the model is reviewed andvalidated (a work in progress) it may then be usedfor economic sensitivity analysis.EGS Design VariablesThe EGS design variables of major interest are (i)well spacing, (ii) well diameter, (iii) well layout, (iv)well depth, (v) well trajectory, and (vi) number andlocation of stimulated fracture zones. Otherimportant variables describe (vii) well cavity2129

Australian Geothermal Energy Conference 2009completion (e.g. under-reaming or perforationjetting), (viii) pump efficiency, (ix) pump inlet/outletpressure limits, (x) heat-exchanger dischargetemperature, (xi) power plant geothermal-toelectricalefficiency, and (xii) power plant auxiliarypower loads. The effect of well cavity completionsmay be employed in the future to reduce turbulentfriction (‘skin’) near-field of the wells with theintention of improving well bore productivity andinjectivity.Reservoir Sub-ModelThe reservoir sub-model describes the quasisteadyfluid pressure and transient fluidtemperature distributions throughout the closedloop(Figures 2 and 3). The model is limited to asteady circulation rate (mass per time) to simplifythe analysis.1PowerPlantpump2 34due to radial-diverging flow in fractures andtemperature rise due to conduction; (6-7) laminarfrictional pressure drop within the fracture networkand temperature rise due to conduction; (7-8)turbulent frictional pressure drop due to radialconvergingflow in fractures and temperature risedue to conduction; and (8-1) well bore andconstricted frictional pressure drops, hydrostaticpressure change with depth, and fallingtemperatures due to conduction.Turbulent radial flow near-field of the wells (5-6and 7-8 in Figure 2) is believed to be responsiblefor most of the pressure drop in the fracturedreservoir. A novel semi-analytical method formodelling pressures losses in the near-field ofwells is currently in development. The method,called the Radial Pipe Flow Method (RPFM)(Chen, in press), is based on empirical formulaefor laminar and turbulent losses in tubular pipes.Preliminary results using the RPFM are promisingand the method appears suitable for use in theBasic EGS Model.ProductionWellLInjectionWellSedimentaryRocks0 ‐ 3.7 kmPower Plantheat exchange from geothermalFluid to power plant8+ + + + + + + + + ++ + + + + + + + ++ + + + + + + + + + ++ + + Fracture + + + + + ++ + + + + + + + + ++ + + Fracture + + + + + ++ + + + + + + + + + ++ + + + + + + + + + +turbulent7laminar6turbulent5GraniteReservoir3.7 – 5 kmFigure 2: Conceptual fluid flow diagram for EGS based on aproducer-injector pair or ‘doublet’. The important thermohydraulicreference points are numbered.Referring to Figure 2, the main processes thatinfluence fluid temperature and pressure include:(1-2) pipe frictional pressure loss and temperaturedrop across the heat exchanger; (2-3) pressurerise forced by the pump; (3-4) pipe frictionalpressure loss; (4-5) well bore and constricted 2frictional pressure drops, hydrostatic pressurechange with depth, and temperature rise due toconduction; (5-6) turbulent frictional pressure drop2 Constrictions include changes in pipe internaldiameter and vena contracta at the well-fractureinterface.Production Wellheat loss from well fluid to rock strataReservoirheat transfer from granite togeothermal fluidInjection WellFigure 3: Conceptual heat flow diagram for a singleproducer-injector ‘sweep zone’. The Basic EGS Model iscomprised of a collection of ‘sweep zones’ as a means ofapproximating the total geothermal power output of multi-wellsystems. Each sweep zone is analysed individually using acombination of empirical, analytical and numerical methods.Red indicates relatively hot fluid and blue relatively cold fluid.heat gain from rock strata to well fluid3130

Australian Geothermal Energy Conference 2009At every location in the flow system, fluid viscosityand fluid density are influenced by temperatureand pressure. Consequently there are physicalfeedback loops affecting fluid pressure. Toaddress this inherent complexity, the fluidpressure profiles of the production and injectionwells are solved iteratively. Furthermore, thepressures at all key reference points in the model(Figure 2) are also solved iteratively to determinethe pressures that balance the entire system. Amethod has been developed for solving systempressures and the preliminary results arepromising.The most simple system diagram for heat flowinvolves four exchange processes (Figure 3): (i)heat losses to the power plant; (ii) heatgains/losses in the injection wells; (iii) heat gainsin the reservoir; and (iv) heat losses in theproduction wells.Extracting heat produces a three-dimensionalcooling front in the rock that starts at the injectionwells and grows towards the production wells(Vörös et al., 2007). Also, the heating and coolingof fluid in the well bores involves threedimensional‘radial-type’ heat flow patterns. Theseheat transfer processes are generally too complexto be modelled with just analytical methods. Thecurrent approach is to utilise the results ofdetailed numerical modelling studies (Vörös et al.,2007) in combination with analytical methods(Arpaci, 1966). This is achieved by representingnumerical results with empirically adjustedanalytical equations or ‘black-box’ empiricalequations (a work in progress).Well LayoutsThe multi-well layouts produce spatially andtemporally complex fluid flow and heat transportpatterns (Vörös et al., 2007). They also need tobe carefully designed to ensure sufficient sweepof the reservoir for achieving stated geothermalpower targets. In this modelling study, a sweepzones is defined as the planar area of thereservoir that transfers appreciable fluid betweenneighbouring injection and production wells(Figure 4).Figure 4: Two plausible EGS well layouts: (a) seven wells ona triangular grid with nine sweep zones, and (b) nine wells ona square grid with twelve sweep zones. Sweep zones arerepresented as dotted lines, producers as black dots, andinjectors as white dots.The total sweep area is principally controlled by (i)number of wells, (ii) well layout and spacing, and(iii) number of parallel fracture zones. The ratio ofsweep zones to the number of wells give a basicindication of the efficacy of a well layout. Thecurrent model approximates multi-well heatextraction by representing the reservoir ascollection of discrete sweep zones (a work inprogress). Each sweep zone is defined by anapproximately equivalent rectangular fluid-rockcontact area. Preliminary results based on thismethod are promising.Well Bore AveragingThe Basic EGS Model simplifies the flow hydraulicproblem by representing the multi-well layout withone ‘average producer’ and one ‘average injector’doublet (Figure 2). The averaging methodinvolves spreading the total flow evenly amongstthe producers and injectors and calculating theaverage geometry of the producers and injectorstaking into account well design and directionaldrilling. This well bore averaging technique andthe discrete sweep zone method (describedabove) greatly simplify the modelling task.Validation against a more accurate and provenmodelling approach is required.Power Sub-ModelThe Basic EGS Model includes a power submodelthat will provide an estimate of power plantefficiency and auxiliary equipment power load forany plausible geothermal production flow,production temperature, and ambient airtemperature.The main aim of the sub-model is to estimate themain components of the EGS power balance,namely: (i) geothermal power output, (ii) steamturbine power output, (iii) pump power load, and(iv) auxiliary equipment power load. Theauxiliaries will include air cooled condensers (asopposed to water cooled) because of waterscarcity in the Cooper Basin (Figure 5).Power plant designs should be tailored toproduction flow and temperature hence the BasicEGS Model requires a capacity to adapt thepower plant design to a wide range of possibleproduction outcomes. The design of power plantsalso requires specialised engineering skills andsoftware (Thermoflow by Thermaflow, Inc. USA).To circumvent this inherent complexity, thecurrent approach is to collate a range of suitablepower plant designs and to develop empirical(‘black-box’) regression equations for plant grosspower supply and auxiliary power load as afunction of production flow, productiontemperature, and ambient air temperature.4131

Australian Geothermal Energy Conference 2009Figure 5: Artist’s impression of a 50 MW EGS module comprising four injectors, five producers, steam turbine power plant, heatexchanger, and air cooled condensers.sub-models for the reservoir, power plant, andEconomic Sub-Modelexpected economic conditions. Early modelresults are promising and suggest that the modelcomponents are valid and will be accurate enoughfor economic sensitivity analysis. Although themodel is currently a work-in-progress, somepreliminary results may be presented at the 2009Australian Geothermal Conference in Brisbane.The economic sub-model is based on discountedcash flow analysis and calculation of Internal Rateof Return (IRR) over 20-30 years. Of interest isthe sensitivity of the IRR to the various EGSdesign variables. The following are the keyeconomic inputs: (i) drilling cost expectations, (ii)cost of power station and other capital equipment,(iii) operation and maintenance costs, (iv)electricity revenue expectations, and (v)renewable energy certificate revenueexpectations. The electricity price expectationsare taken from an economic analysis byMcLennan Magasanik Associates (2008) for theAustralian government’s Carbon PollutionReduction Scheme. The renewable energycertificate revenue expectations are taken frommarket analysis by McLennan MagasanikAssociates (2009).Implications for EGS DesignThe main benefit of the proposed modelling is theability to rank Cooper Basin EGS designs in termsof revenue potential. The work completed to datehas identified a number of optimal design points(‘sweet spots’). Two key examples are: A peak net electrical power and IRR as afunction of pump differential pressure; and A peak in IRR as a function of well spacing.SummaryA basic thermo-hydraulic model for EGS in theCooper Basin is currently being developed. It iscalled the ‘Basic EGS Model’. It is comprised ofReferencesArpaci, V.S., 1966, Conduction Heat Transfer.Addison-Wesley, Reading, Massachusetts, 1966,351 p.Chen, D., in press, Concepts of a basic EGSmodel for the Cooper Basin, Australia,Proceedings of the World Geothermal Congress2010, Bali, Indonesia, 25-30 April 2010.Chen, D., and Wyborn, D., 2009, Habanero FieldTests in the Cooper Basin, Australia: A Proof-of-Concept for EGS, Proceedings of the GRCAnnual Meeting, 4–7 October 2009, Reno,Nevada, USA.Grove-White, G., 2009, ASX Announcement 31March 2009: Stage 1 - Proof of ConceptComplete, Geodynamics Ltd., 31 March 2009.Hayashi, K., Willis-Richards, J., Hopkirk, R.J.,and Niibori, Y., 1999, Numerical models of HDRgeothermal reservoirs - a review of currentthinking and progress, Geothermics, 28, p. 507-518.McLennan Magasanik Associates, 2008, Impactsof the Carbon Pollution Reduction Scheme on5132

Australian Geothermal Energy Conference 2009Australia’s Electricity Markets - Report to FederalTreasury, 11 December 2008, Ref: J1565, 75 p.McLennan Magasanik Associates, 2009, Benefitsand Costs of the Expanded Renewable EnergyTarget – Report to Department of ClimateChange, January 2009, 38 p.Vörös, R., Weidler, R., de Graaf, L., and Wyborn,D., 2007, Thermal modelling of long termcirculation of multi-well development at theCooper Basin hot fractured rock (HFR) projectand current proposed scale-up program,Proceedings, Thirty-Second Workshop onGeothermal Reservoir Engineering, StanfordUniversity, Stanford, California, January 22-24,2007.AcknowledgementsThe authors wish to thank William Cibich, MichaelMalavazos, and Alexandria Long at the Petroleumand Geothermal Group of the PIRSA (PrimaryIndustries and Resources South Australia) forsharing EGS model developments and relatedreports.6133

Australian Geothermal Energy Conference 2009Analysis of error sources for estimating geothermal stabilisedformation temperatures using analytical and rigorous methodsEspinoza-Ojeda 1 , OM, Santoyo 2* , E and Andaverde 3 , J1 Posgrado en Ingeniería (Energía), Centro de Investigación en Energía, Universidad Nacional Autónoma de México.Priv. Xochicalco s/n, Col. Centro, Temixco, Morelos 62580, México.2 Centro de Investigación en Energía, Universidad Nacional Autónoma de México, Centro de Investigación enEnergía, Universidad Nacional Autónoma de México. Priv. Xochicalco s/n, Col. Centro, Temixco, Morelos 62580,México. *Corresponding author: esg@cie.unam.mx3 Centro de Investigación en Ingeniería y Ciencias Aplicadas, Universidad Autónoma del Estado de Morelos. Av.Universidad No. 1001, Col. Chamilpa, Cuernavaca, Morelos 62210, México.Analytical and rigorous solutions of 7 heat transfermodels were statistically evaluated, for theestimation of stabilized formation temperatures(SFT) of geothermal wells. Linear and cylindricalheat source models were selected to representthe heat flow processes present in wells drillingoperations. A statistical assessment of the mainerror sources involved with these models wascomprehensively performed. Analytical andrigorous solutions were evaluated by usingcomprehensive statistical methodologies whichenabled to determine the sensitivity parametersthat should be considered for a reliable calculationof SFT, as well as to define the constraints wherethe analytical and rigorous methods provideconsistent SFT estimations.Keywords: Static formation temperature, bottomholetemperatures, error propagation, shut-intime, circulation timeStatistical methodology of evaluationAn improved statistical methodology wasdeveloped for a better evaluation of the main errorsources associated with the most common heattransfer models used for estimating geothermalSFT. The methodology consisted of: (1) Selectionof methods, mainly those that simultaneouslypropose both analytical and rigorous solutions; (2)Creation of a geothermal database with BHT andshut-in time data sets from well drilling logs andsynthetic experimental works; (3) Application ofdifferent regression models (i.e., OLS and QR)with the algorithms of each selected method tocalculate the SFT; (4) Statistical evaluation of theexisting relationship (linear or non-linear) betweenBHT and the time function data of each method;(5) Comparative statistical analysis of the SFTestimates for each method based on the ratiobetween its analytical and rigorous solutions; andfinally (6) Evaluation of accuracy in each methodusing a statistical comparison analyses between“true” SFT measurements and SFT estimates(inferred from analytical and rigorous solutions).Selection of methodsSeven methods commonly used for thedetermination of SFT were selected: (i) the radialsource with a conductive heat flow or Brennandmethod (BM: Brennand 1984); (ii) the cylindricalheat source with a conductive-convective heatflow method (CHSM) proposed by Hasan andKabir (1994); (iii) the constant linear heat sourceor Horner-plot method, (HM: Dowdle and Cobb1975; (iv) the generalized Horner or the Kutasov-Eppelbaum method (KEM: Kutasov andEppelbaum 2005); (v) the cylindrical source with aconductive heat flow or Leblanc method (LM:Leblanc et al 1981); (vi) the cylindrical source witha conductive heat flow or Manetti method (MM:Manetti 1973); and (vii) the spherical and radialheat flow method (SRM) proposed by Ascencio etal (1994). The reader is referred to the originalreferences of each method for more details. Theanalytical methods BM, HM, KEM, LM, and MMwere derived from the well-known heat conductionequation (Eq. 1) under radial conditions.1 T 1 Tr r r r t(1)whereas, the heat conduction equation underspherical-radial dimensionless coordinates (Eq. 2)was used for the SRM method, 2 TD 2 T D 1 T D , 0 < r D < ∞ (2)2 r rDrD tDD The CHSM method was derived from a heattransfer model, based on transient heat exchangebetween drilling fluid and rock formation (Eq. 3),under conductive and convective heat flowconditions.dT w 2 dtm Ck rUT r UkwTT(3)pmDwCHSMAs far as these general equations, analytical andrigorous solutions have been proposed in theliterature. These solutions are summarized inTable 1 (Appendix).Geothermal database: BHT and shut-in timedata setsA geothermal database containing eight BHT datasets logged in geothermal borehole drillingoperations and three synthetic data sets wascreated. The BHT data were recorded fromborehole drilling reports carried out in variousworld geothermal sites: (1) Los Humerosgeothermal field, Mexico [MXCO, Verma et al2008]; (2) Mississippi petroleum wellbore, USA,1134

Australian Geothermal Energy Conference 2009characterized by temperatures with a geothermalorigin [USAM, Kutasov 1999]; (3) Larderellogeothermal field, Italy [ITAL, Da-Xin 1986]; (4)Kyushu geothermal field, Japan [JAPN, Hyodoand Takasugi 1995]; (5) Norton Sound field,Alaska [COST, Cao et al 1988a]; (6) Chipilapageothermal field, El Salvador [CH-A, González-Partida et al 1997]; (7) Roosvelt geothermal field,USA [R #9-1, Crosby 1977]; (8) Oklahomageothermal field, USA [SGIL, Schoeppel andGilarranz 1966].The synthetic data sets used here were compiledfrom experimental works reported by Shen andBeck (1986) (SHBE), Cao et al (1988b) (CLAH),and Cooper and Jones (1959) (CJON). Thesedata sets were used as they have the advantagethat these experimental works reported the “true”formation temperatures (TFT) or SFT (i.e., SHBE= 80.0°C, CLAH = 120.0°C and CJON = 20.25 o C,respectively).For example, the thermal recovery behaviour (i.e.,the BHT behaviour versus shut-in time) of somegeothermal boreholes after drilling has beenplotted in Figure 1 (a) (MXCO, USAM, ITAL andJAPN) and Figure 1 (b) (COST, CH-A, R #9-1 andSGIL).Bottomhole temperature, BHT ( o C)2402001601208012080Bottomhole temperature, BHT ( o C)16040[a]0 20 40 60 80[b]MXCOUSAMITALJAPNCOSTCH-AR #9-1SGIL0 20 40 60 80 100Shut-in time (h)Figure 1: Temperature measurements logged after cessationof the drilling mud circulation (shut-in times).Regression models (OLS and QR) to calculatethe SFTOLS and QR models were initially used toevaluate either the linear or non-linearrelationships between BHT and the time functionsof each analytical method, and afterwards, toestimate the SFT from the eight BHT data setselected and three experimental works. For theseven analytical methods under evaluation, theindependent variable x data is the time functiondata for each method (BMTF, CHSMTF, HMFT,KEM, LMTF, MMTF, and SRMTF), y, thedependent variable, as the BHT, and the intercept(a or a w ) of any regression model (OLS and QR)will provide the SFT estimates.Statistical evaluation of the existingrelationship between BHT and the timefunction data of each methodThree well-known statistical tests: (i) sequence ofsigns by Wald-Wolfowitz; (ii) regression usingsequential subsets of an ordered array of data;and (iii) residual sum of squares (RSS); wereapplied to evaluate the existing relationship (linearor non-linear) between the BHT and the timefunction data in each analytical method used.Statistical comparison of the SFT estimatesusing the analysis of the ratio betweenanalytical and rigorous solutionsFor evaluating the prediction capability of the heattransfer models described in this work, the SFTestimates (inferred from their rigorous andanalytical solutions) were statistically comparedusing an extension of the constant linear heatsource theory suggested by Drury (1984). Such atheory was originally applied for the evaluation ofthe HM using the analysis of the ratio betweenanalytical and rigorous solutions (defined as the βparameter), and under shut-in ( t ) andcirculation (t c ) times. For these purposes, βparameter and the time ratio for each method wascomputed. A plot between β parameter and thetime ratios t / t c was analyzed to evaluateboth the similarity of the two solutions and themost suitable shut-in times for a reliableestimation of SFT. For β ratios close to 1, bothanalytical and rigorous solutions provide similarresults, whereas for β ratio values > 1 theanalytical solution of the method exceeds itsrigorous solution and vice versa.Evaluation of accuracy using statisticalcomparison analyses between “true” SFTmeasurements and SFT estimatesSFT estimates (inferred from the analytical andrigorous solutions of seven methods) werestatistically compared with “true” SFTmeasurements reported in three syntheticexperiments (SHBE, CLAH, and CJON) and along thermal recovery history of the geothermalborehole CH-A. The accuracy of each method2135

Australian Geothermal Energy Conference 2009was evaluated, for the first time, from statisticalanalyses of: (i) F and t-student statisticalsignificance tests; (ii) deviation percentages(% Dev Tp Tm/Tmx100) betweenmeasured (“true” SFT) and SFT estimates(predicted by the solutions of the seven methods);and (iii) a linear regression analysis between“true” SFT and SFT estimates (where for an ideallinear correlation, the intercept a would be equalzero, and the slope b=1).Results and discussionBefore calculating the SFT using the BHT datalogged in geothermal boreholes and syntheticthermal experiments, the time functions of theseven analytical methods were calculated usingtheir respective equations. For example, some ofthe resulting relationships between the BHT andthe HMTF data were plotted in Figure 2, for thefirst group of borehole data (MXCO, USAM, ITAL,and JAPN). The plots contained in the Figure 2show the BHT build-up curves (i.e., BHTbehaviour versus time function) for the Horneranalytical method. These plots were drawn withthe goal to observe the existing trend betweenBHT and time function data. As can be observedand notwithstanding the scale effects, non-lineartendencies are clearly observed for most of theborehole and synthetic BHT-time function data,which preliminarily suggest that a non-linearregression model should be better used for areliable determination of the SFT, instead of thelinear regression model, traditionally adopted as asolution algorithm by all the analytical methods.Bottomhole temperature, BHT ( o C)24020016012080MXCOUSAMITALJAPN0 0.2 0.4 0.6 0.8HMTFFigure 2: Plots of actual BHT measurements and timefunctions of the analytical Horner method.Use of regression models (OLS and QR) toestimate the SFTOLS and quadratic regression algorithms wereindividually applied to the BHT build-up data usingthe equations of the analytical methods underevaluation. As with all observed phenomena,when statistical methods are assumed to apply,there are certain underlying assumptions whichmay not be valid. The OLS is not a statisticallyvalid model in presence of heteroscedastic errors(in any of the variables to be correlated x or y),and with x-y data that exhibit a non-linear trend,the OLS regression model is still used ingeothermal and petroleum applications. This isbasically the reason why the OLS model is stillunder evaluation in this work for the determinationof the SFT. QR was also applied to calculate theSFT from the intercepts (a) of the fitted QR2equation ( y a bx cx ). According to thenon-linear trends observed in most of the thermalrecovery histories of boreholes (actual andsynthetic), the QR model was a valid statisticalfitting tool. The SFT estimates obtained from theOLS and QR for the seven analytical methodshave been included in Table 2 (Appendix).Uncertainties of these estimates are alsoreported.Rigorous solutionSome authors have reported the rigoroussolutions of five analytical methods. Suchequations were analyzed and used fordetermining the SFT using OLS and QRregression models (see Table 3).Analysis of the β ratio resultsThe approximate and rigorous solutions for eachmethod were analyzed through a plot between βand t /t c ratios to evaluate the similarity ofboth solutions. A BHT geothermal data set (CH-A)and the synthetic data sets (SHBE, CLAH andCJON) were used for these evaluations. Figure 3shows some results. For β ratios close to 1, bothapproximate and rigorous solutions providesimilar results. For β < 1, the approximate solutionoverestimates the SFT, whereas for β > 1, theapproximate solution underestimates the SFT.Thus, BM, HM, and MM seem to provideacceptable results for SFT because β values areclose to 1 for most t /t c ratios (Fig. 3). On theother hand, the SRM 1 gives unacceptable resultsfor most t /t cratios.ratio parameter1.081.041Synthetic data set: CLAHBMHMKEMMMSRM 1SRM 22 4 6 8Dimensionless time ratio (t/t C)Figure 3: Plot of parameter β as function of ratios Δt/tc forsynthetic data set CLAH.3136

Australian Geothermal Energy Conference 2009Accuracy analysis of the SFT’s calculatedA comparison of the SFT estimates providedbetween the OLS and QR regression modelsusing the seven methods with three synthetic sets(SHBE, CLAH and CJON) and one geothermalset (CH-A) was carried out (see Fig. 4). For all thesynthetic data sets the “true” SFT was reported(indicated as reference smoothed lines). As canbe observed, for the CLAH data set using OLS,the better estimation was provided by MM,whereas for the QR model, the CHSM and MMprovide the best estimations. The SRMsystematically provide overestimations of the SFTin both OLS and QR models. Deviationpercentages from the “true SFT” were alsocalculated and represented in Fig. 5.Stabilized Formation Temperature ( o C)Stabilized Formation Temperature ( o C)132130128126124122120118116132130128126124122120118116(a) Synthetic data set: CLAH (OLS)"True" Stabilized Formation TemperatureBM CHSM HM KEM LM MM SRM(b) Synthetic data set: CLAH (QR)"True" Stabilized Formation TemperatureBM CHSM HM KEM LM MM SRMConclusionsAnalytical methodsFigure 4: Accuracy evaluation of regression models (OLSand QR) for the determination of the “true”formation temperatures (SFT) using BHT syntheticdata set CLAH.The empirical evaluation of error sources in heattransfer models for the determination of SFT ingeothermal and petroleum wells and syntheticdata sets was successfully carried out. Sevenanalytical methods (BM, CHSM, HM, KEM, LM,MM and SRM) were comprehensively evaluated.It was confirmed that the BHT build data logged inactual wellbore drilling operation exhibit a clearpolynomial tendency, which suggests the QR asthe most suitable regression model to estimatethe SFT.% Deviation121086420-2-4Synthetic data set: CLAHOLSQRBM CHSM HM KEM LM MM SRMAnalytical methodsFigure 5: Results of the criterion of evaluation (% deviation)of regression models (OLS and QR) for thedetermination of the “true” formation temperatures(SFT) using BHT synthetic data set CLAH.On the other hand, it was also confirmed thatthe OLS model, traditionally used by someanalytical methods for the calculation of the SFT,is statistically an invalid regression model, andtherefore must be abandoned. The β ratio resultsshowed that only some approximate solutions(BM, HM, and MM) provide reliable estimations ofthe SFT. Shut-in and circulations times arefundamental parameters that influence thedeterminations of SFT, and therefore they mustbe measured in the field with high accuracy andprecision, including the knowledge of theirmeasurement errors.As a final remark, further research work is stillneeded to develop new analytical methods withmore realistic assumptions of the physical modelsthat can reproduced the heat transfer involved insuch processes.ReferencesAscencio, F., Garcia, A., Rivera, J., and Arellano,V., 1994, Estimation of undisturbed formationtemperatures under spherical-radial heat flowconditions: Geothermics, v. 23(4), p. 317-326.Brennand, A.W., 1984, A new method for theanalysis of static formation temperature tests: 6thNew Zealand Geothermal Workshop, NewZealand, p. 45-47.Cao, S., Hermanrud, C., and Lerche, I., 1988a,Estimation of formation temperature from bottomholetemperature measurements: COST #1 well,Norton Sound, Alaska: Geophysics, v. 53(12), p.1619-1621.Cao, S., Lerche, I., and Hermanrud, C., 1988b,Formation temperature estimation by inversion ofborehole measurements: Geophysics, v. 53(7), p.979-988.4137

Cooper, L.R., and Jones, C., 1959, Thedetermination of virgin strata temperatures fromobservations in deep survey boreholes:Geophysical Journal of the Royal AstronomicalSociety, v. 2, p. 116-131.Crosby, G.W., 1977, Prediction of finaltemperature: 3rd Workshop on GeothermalReservoir Engineering, Stanford University,Stanford, California, p. 89-95.Da-Xin, L., 1986, Non-linear fitting method offinding equilibrium temperature from BHT data:Geothermics, v. 15(5-6), p. 657-664.Dowdle, W.L., and Cobb, W.M., 1975, Staticformation temperature from well logs - Anempirical method: Journal of PetroleumTechnology, v. 27(11), p. 1326-1330.Drury, M.J., 1984, On a possible source of error inextracting equilibrium formation temperaturesfrom borehole BHT data: Geothermics, v. 13(3), p.175-180.Gonzalez Partida, E., Garcia Gutierrez, A., andTorres Rodriguez, V., 1997, Thermal andpetrologic study of the CH-A well from theChipilapa-Ahuachapan geothermal area, ElSalvador: Geothermics, v. 26(5/6), p. 701-713.Hasan, A.R., and Kabir, C.S., 1994, Staticreservoir temperature determination fromtransient data after mud circulation: SPE Drilling &Completion, v. 9(1), p. 17-24.Hyodo, M., and Takasugi, S., 1995, Evaluation ofthe curve-fitting method and the Horner-plotmethod for estimation of the true formationtemperature using temperature recovery loggingdata: 20th Workshop on Geothermal ReservoirEngineering, Stanford University, Stanford,California, p. 23-29.AppendixAustralian Geothermal Energy Conference 2009Kutasov, I.M., 1999, Applied Geothermics forPetroleum Engineers: Elsevier ScientificPublishing Company, First ed., 347 p.Kutasov, I.M., and Eppelbaum, L.V., 2005,Determination of formation temperature frombottom-hole temperature logs-a generalizedHorner method: Journal of Geophysics andEngineering, v. 2, p. 90-96.Leblanc, Y., Pascoe, L.J., and Jones, F.W., 1981,The temperature stabilization of a borehole:Geophysics, v. 46(9), p. 1301-1303.Manetti, G., 1973, Attainment of temperatureequilibrium in holes during drilling: Geothermics,v. 2(3-4), p. 94-100.Schoeppel, R.J., and Gilarranz, S., 1966, Use ofwell log temperatures to evaluate regionalgeothermal gradients: Journal of PetroleumTechnology, v. 18(6), p. 667-673.Shen, P.Y., and Beck, A.E., 1986, Stabilization ofbottom hole temperature with finite circulationtime and fluid flow: The Geophysical Journal ofthe Royal Astronomy Society, v. 86, p. 63-90.Verma, S.P., Pandarinath, K., and Santoyo, E.,2008, SolGeo: A new computer program forsolute geothermometers and application inMexican geothermal fields: Geothermics, v. 37, p.597-621.Table 1. Analytical and rigorous solutions of the seven analytical methods.5138

Australian Geothermal Energy Conference 2009Table 2. Comparison of stabilized formation temperatures calculated by seven analyticalmethods (BM, CHSM, HM, KEM, MM and SRM) using eight actual BHT build-up data (MXCO,USAM, ITAL, JAPN, COST, CH-A, R #9-1 and SGIL) and three synthetic data sets (SHBE, CLAHand CJON).Table 3. Comparison of SFT calculated by the analytical methods rigorous solutions (BM, HM,KEM, MM and SRM) using seven actual geotermal data set (MXCO, ITAL, JAPN, COST, CH-A, R#9-1 and SGIL), one petroleum data set (USAM) and three synthetic data set (SHBE, CLAH andCJON).6139

Australian Geothermal Energy Conference 2009Field experiments for studying CO 2 mineral trap at high temperatureat Ogachi, JapanHideshi Kaieda 1* , Akira Ueda 2 , Kenji Kubota 1 , Hiroshi Wakahama 3 , Saeko Mito 3 , Kazunori Sugiyama 4 ,Akiko Ozawa 4 , Yoshihiro Kuroda 2 , Yoshikazu Kaji 5 , Heigo Suzuki 5 and Hisao Sato 61Central research institute of electric power industry, 1646, Abiko, Abiko-shi, Chiba, 270-1194, Japan2 Kyoto university, C1-2-155, Katsura, Nishikyo-ku, Kyoto 616-8540, Japan3 Research Institute of Innovative Technology for the Earth, 9-2 Kizugawadai, Kyoto, 619-0292, Japan4 Mitsubishi Material Techno Corp., 1-14-16 Kudan-kita, Chiyoda-ku, Tokyo 102-8205, Japan5 Chuo Kaihatsu Corp., 3-4-2 Nishi-aoki, Kawaguchi, Saitama, 332-0035, Japan6 Mitsubishi Material Corp., 1-297, Kitabukuro, Ohmiya-ku, Saitama, 330-8508, Japan* corresponding author : kaieda@criepi.denken.or.jpPrevious experiments at Ogachi, up until 2007,generated two important results obtained byinjecting CO 2 dissolved water into a 1,100 m deepwell, OGC-2 at Ogachi in Japan, for which thebottom-hole temperature was measured at about210 degree C. One result was that Caconcentration of the CO 2 dissolved (3 weight %)water, at a depth of 1,030 m in OGC-2, increasedto a maximum of 85.2 mg/L in a few hours. TheCa was considered to be dissolved from rock. Thesecond result was that calcite precipitation oncalcite crystal samples was observed when thesamples were held at depths of 850 m and 950 mfor an hour in the CO 2 dissolved water in OGC-2.In 2008, we reconfirmed that calcite precipitationoccurred on calcite crystal samples at a depth of950 m in OGC-2. From these results, weconstructed a model for describing a CO 2 mineraltrap mechanism at high temperature. When CO 2is injected underground at high temperature fourzones are created, one is a super critical CO 2zone, second is a dense CO 2 dissolved waterzone, third is a thin CO 2 dissolved water zone,and fourth is a formation water zone. The CO 2dissolved water zones react with rock. Cadissolves from rock in the dense CO 2 dissolvedwater zone by high CO 2 concentration (low pH)but in the thin CO 2 dissolved zone (nearly neutralpH), by mixing with formation water, Caprecipitates as calcite minerals.Keywords: CO 2 , Mineral trap, Geothermal, Calcite,OgachiConcept of CO 2 Mineral Trap at HighTemperatureUnder high temperature conditions, the followingreaction can proceed from the upper to the lowerof the formula (1) (Gale and Shane, 1905).CaAl 2 Si 2 O 8 (plagioclase) + H + -+ HCO 3 + H 2 O=CaCO 3 (calcite) +Al 2 Si 2 O 5 (OH) 4 (kaolinite) (1)According to Ueda et al., (2005), carbonate-richrock formations can be observed in mostJapanese geothermal fields. Reaction accordingto formula (1) moves towards the lower side athigher temperatures, reflecting the fact that calcitesolubility decreases with increasing temperature.Calcite and kaolinite (clay)-rich rock is produced150C°200C°250C°?CO 2Degassing?Supercritical CO 2Calcite?Calcite?Rock-Water-CO 2interactionWater +dissolved CO 2Figure 1: Concept of CO2 injection into high temperaturerock (Ueda et al., 2005)through the reaction and forms a cap rock for thegeothermal reservoir. These considerations,together with the increasing reaction rates at hightemperature conditions and the fact thatprecipitation of carbonate minerals fixes CO 2suggest that CO 2 sequestration could bepracticable by injection into geothermal fields (seeFigure 1).We have conducted some field experiments from2002 to 2008 to study CO 2 sequestration in solidminerals by injecting CO 2 dissolved in water into ahigh temperature borehole, OGC-2, at the OgachiHot Dry Rock geothermal site in Japan (Kaieda etal., 2008 and Kaieda et al., 2009). OGC-2 wasdrilled into granitic rock to a depth of 1,100 m andwas cased from the ground surface to 700 mdepth. The bottom 400 m interval of OGC-2 wasleft uncased and the bottom-hole temperaturewas measured around 210 degree C.CO 2 dissolved water injection in 2008The surface water (nearly neutral pH) wasinjected into OGC-2 at a flow rate of 50 kg/min atatmospheric pressure on September 16 th , 2008.During the water injection solid CO 2 (dry ice)blocks of a few centimetres in size were injectedat a rate of 0.4 kg/min to create 0.8 weightpercent CO 2 dissolved water (see Figure 2). Atotal of 20 tons of 0.8 % CO 2 dissolved water witha total of about 160 kg-dry ice was injected intothe open-hole region between 700 m and 1,100 m(bottom) in OGC-2 and into the surrounding rocks.1140

Australian Geothermal Energy Conference 2009Dry ice (CO 2)Waterbore wall was relatively smooth. The sonde wasinserted to a depth of 950 m in OGC-2 and heldthere for an hour. During this hold time CO 2dissolved water in OGC-2 came into the sondeand reacted with the samples. The sonde wasrecovered to the surface after the hold time andthe CO 2 dissolved water drained from the sondeduring retrieval from OGC-2. At the surface thesamples were removed from the sonde and thesurface features of the samples were observed bystereo micro-scope. Roughness of the samplesurfaces was measured by phase shiftinterferometer, comparing the Au film coveredarea to the remaining area (see Figure 4).Au sheetCalciteWell OGC-2Depth ‐950mTemp.200℃Phase shift interferometry (PSI)Surface roughnessRemove Au sheetFigure 2: CO2 (Dry ice ) injection with waterReact with fluid indeep boreholeCalcite Precipitation MeasurementAfter the CO 2 dissolved water was injected andreplaced pre-existing formation water, a speciallydesigned test sonde (see Figure 3) was insertedinto OGC-2 and calcite crystal growth tests wereconducted using the sonde. Calcite crystalsamples partially covered with Au (Gold) film wereset in the sonde to prevent the covered areareacting with the CO 2 dissolved water. He(Helium) gas filled the inside the sonde at anadequate pressure for protecting outside watercoming in. A valve (rupture disk) of the sondebreaks when the outside pressure increases highenough relative to the He gas pressure in theDownHe gassSampleholderWatersamplerRapturediskIn flowDeflationReactionFluid of wellBreak by fluidpress.200℃UpInflationDrainFigure 3: Test sonde for Calcite sample reactwith fluid in boreholesonde. In this test we set the valve to break at apressure of 950 m depth in OGC-2 where the wellCalcite with Au sheet (before)ΔhDissolveAu sheet鉱 Calcite物 試 料(Before reaction)Δh(After reaction)Figure 4: Calcite sample treatmentCalcite Precipitation ResultsCalcite with Au sheet (after)PrecipitateWe conducted calcite precipitation tests five timesbefore and after the CO 2 dissolved water injectionfrom September 15 to 19, 2008. Figure 5 showsan example of the test result which was observedwhen the crystal test sonde was set 3.6 hoursafter the CO 2 dissolved water was injected intoOGC-2. The top picture of Figure 5 shows anexample of the surface feature of the calcitecrystal sample from the stereo microscope beforethe test. X is a horizontal distance in micro-meterand Z is the elevation in nano-meter.The term‘masked’ refers to the area covered with Au film.The middle picture shows the sample’s surface atthe same point as the above picture but followingthe test. The bottom graph shows the measuredroughness of the sample surface along line A to Bmeasured by the phase shift interferometer. Theblue line represents the before test condition andthe red line represents the after test condition. Inthe masked area, the roughness of the samplesurface is relatively flat both before and after thetest, but in the other area elevation of the samplesurface was measured to increase after the test toa maximum of about 2,224 nano-meters (2.224micro meters). This means that the calcite crystalsamples grew in the test.2141

Australian Geothermal Energy Conference 20090BeforeA1.975 um0BeforeA1.75 um100um00maskedBAftermasked100200 umA-1.325 um5.7355 um100um00maskedAfterB100A200 um-1.25 um1.75 umZ (nm)Z(nm )100um2500200015001000500maskedB0AmaskedAfterBefore100test2-12224nm200 um2,224 nm-3.777 um00 -50050 100 150 200X(μm )X (μm)BV=0.206nm /sAnother result is shown in Figure 6. This resultwas obtained when the test sonde was set 22.6hours after the CO 2 dissolved water injection intoOGC-2. In this test calcite crystal growth was alsomeasured to a maximum of about 300 nanometers (0.3 micro meters).From the above results, it was considered thatCO 2 precipitation on crystals occurred quickly andCO 2 precipitation rate was faster a few hours afterCO 2 dissolved water injection but the rategradually decreased.The sample dissolutions which were observed justafter the CO 2 dissolved water injection in the 2007tests were not observed in the 2008 tests.We summarised the reaction process of CO 2dissolved water with rock as follows: 1) waterconditions in the open-hole region in OGC-2 for afew hours after CO 2 dissolved water injection wasthat of high CO 2 concentration and low pH. Forthis condition Ca is dissolved from the rock andcalcite samples are also dissolved; 2) a few hours反 応 前反 応 後Figure 5: Stereo microscope pictures and thesurface roughness along the A-B line ofthe calcite sample before and afterreaction 3.6 hours after CO 2 dissolvedwater injection into OGC-2. X ishorizontal distance and Z is elevationalong the A-B line.100umZ (nm)Z(nm )B0 100200 um0200 um500400300200100-200maskedAAfterBeforete st2 -2-1.25 um0-1000 50 100 150 200 250X(μm)X m)286nmnmFigure 6: Stereo microscope pictures and thesurface roughness along the A-B lineof the calcite sample before and afterreaction 22.6 hours after CO 2dissolved water injection into OGC-2.X is horizontal distance and Z iselevation along the A-B line.after CO 2 dissolved water injection CO 2concentration decreased and pH increased tonear neutral because of mixing with formationwater, and calcite solubility decreases withtemperature increase. For this condition, calciteprecipitates quickly, 3) after Ca and CO 2precipitation occurred, calcite precipitation rategradually decreased.CO 2 mineral trap mechanism at hightemperatureV=0.026nm /s反 応 前反 応 後Using these results we constructed a model toexplain the CO 2 precipitation (mineral trap)mechanism at high temperature. The concept ofthis mechanism is shown Figure 7.When CO 2 is injected deep underground (morethan 800 m deep) at high temperature, four zonesare created. One is a super critical CO 2 zone,second is a dense CO 2 dissolved water zone,third is a thin CO 2 dissolved water zone, andfourth is a formation water zone. Ca dissolvesfrom rock in the dense CO 2 dissolved water zoneB3142

Australian Geothermal Energy Conference 2009by high CO 2 concentration (low pH) but in the thinCO 2 dissolved zone (nearly neutral pH) wheremixing with formation water occurs, Caprecipitates as calcite minerals.To confirm this model, we need to inject supercritical CO 2 (not CO 2 dissolved water) into rockand further need to observe the CO 2concentration distribution in CO 2 dissolved waterzone around the super critical CO 2 .Formation water濃 度 の 低 いLow CO2conc. CO2溶 解 水Near neutral pH中 性 近 く濃 度 の 高 いCO2 High conc.C 溶 解 O 水2pH 低 いLow pHWe also think that the following studies areneeded as future work: the effect of calciteprecipitation on permeability changes of rock: Cadissolution rate from rock in CO 2 dissolved water;effective Ca volume in rock, and confirmation ofcalcite precipitation phenomena at differenttemperatures and with different geology.We plan to conduct permeability tests of rock inOGC-2 before and after CO2 dissolved waterinjection in Autumn 2009.ConclusionSuper C riticalC O 2超 臨 界 CO2Ca dissolved from rock岩 石 からCaが 溶 出CaCO3が precipitate析 出Figure 7: A model for describing the reaction ofCO 2 dissolved water with rock aroundsuper critical CO 2 .CO 2 dissolved water was injected into an openholeinterval between 700 m to 1,100 m depths ofOGC-2 at Ogachi which was drilled into graniticrock. The bottom hole temperature was measuredat around 210 degree C. In 2008, we reconfirmedthat calcite precipitation occurred on calcitecrystal samples which was observed in previousexperiments up until 2007. From these results, weconstructed a model for describing a CO 2 mineraltrap mechanism at high temperature. When CO 2is injected underground at a high temperature fourzones are created, one is super critical CO 2 zone,second is a dense CO 2 dissolved water zone,third is a thin CO 2 dissolved water zone, andfourth is a formation water zone. The CO 2dissolved water zone reacts with rock. Cadissolves from rock in the dense CO 2 dissolvedwater zone by high CO 2 concentration (low pH),but in the thin CO 2 dissolved zone (nearly neutralpH), where mixing with formation water occurs,Ca precipitates as calcite minerals. In 2009 wewill conduct permeability tests of rock in OGC-2before and after the CO 2 dissolved water injection.AcknowledgementThis research has been conducted as acollaboration work between the Central ResearchInstitute of the Electric Power Industry andResearch Institute of Innovative Technology forthe Earth in the Research & DevelopmentProgram "Development of innovative technologyfor the CO 2 fixation by Georeactor" under the fundfrom Ministry of Economy, Trade & Industry ofJapan.ReferencesGales, C. and Shane, H., 1905, About a case ofkaolinitisation in granite by a cold CO2 bearingwater, Zenlt. Geol. Min. Palisant., 427-467.Kaieda, H., Ito, H., Kiho, K., Suzuki, K., Suenaga,H. and Shin, K., 2005, Review of the Ogachi HDRProject in Japan, Proceedings World GeothermalCongress 2005.Kaieda, H., Kubota, K., Wakahama, H., Mito, S.,Ueda, A., Ohsumi, T., Yajima, T., Satoh, H., Kaji,Y., Sugiyama, K. and Ozawa, A., 2008,Experimental Study on CO 2 Injection into HDRGeothermal Reservoir, Proceedings, 2008Australian Geothermal Conference.Kaieda, H., Ueda, A., Kubota, K., Wakahama, H.,Mito, S., Sugiyama, K., Ozawa, A., Kuroda, Y.,Sato, H., Yajima, T., Kato, K., Ito, H., Ohsumi, T.,Kaji, Y. and Tokumaru, T., 2009, FieldExperiments for Studying on CO2 Sequestrationin Solid Minerals at the Ogachi HDR GeothermalSite, Japan, Proceedings, Thirty-Fourth Workshopon Geothermal Reservoir Engineering, StanfordUniversity.Ueda, A., Kato, K., Ohsumi, T., Yajima, T., Ito, H.,Kaieda, H., Metcalfe, R. and Takase, H., 2005.Experimental studies of CO2-rock interaction atelevated temperatures under hydrothermalconditions. Geochemical Journal, Vol. 39, pp.417-425.4143

Australian Geothermal Energy Conference 2009A Preliminary Study on Fluid-Rock Interactions of the Hot FracturedRock Geothermal System in Cooper Basin, South AustraliaGideon B. Kuncoro 1 , Yung Ngothai 1* , Brian O’Neill 1 , Allan Pring 2 , Joël Brugger 21 The University of Adelaide, School of Chemical Engineering, North Terrace, Adelaide, SA, 50002 South Australian Museum, North Terrace, Adelaide, SA, 5000*Corresponding author: yung.ngothai@adelaide.edu.auA study of the interactions between rock andcirculating fluid is essential to determine thechemical changes and mineral alteration of ageothermal system. Preliminary mineralogicalinvestigation and geothermal experiments havebeen performed to investigate the hydrothermalalteration of the Habanero geothermal system inthe Cooper Basin, South Australia. Samples ofdrill cuttings from a borehole 5 km deep werecontacted with reverse osmosis water in athermosyphon induced loop reactor at 250 o C and50 bar. Fluid and rock samples were analysedprior to, and after circulation of the water throughcrushed sample of the rock (100 – 200 μmdiameter) for 1, 2, 3, 7, 14 and 21 days. Wateranalysis was performed using ICP-MS, and rockanalyses were conducted using an opticalmicroscope, SEM and XRD. The experimentalresults indicated that mineral dissolution wasmore rapid in the early stages of the experiment.This may be a consequence of the dissolution offiner rock particles. SEM observations showedevidence of etching of the mineral surfacesconsistent with partial dissolution. XRD resultsindicated that quartz was stable throughout theexperiment, and that the albite-feldspar(NaAlSi 3 O 8 ) in the rock had partially dissolved.ICP-MS analysis on the water sample confirmedthat some mineral dissolution has occurred. Theconcentrations of most elements increased withthe exception of Ca, Ba and Mg. Future work willquantify concentrations (ppm) of the dissolvedminerals.Keywords: hot fractured rock, fluid-rockinteraction, geothermal, Cooper Basin, HabaneroIntroductionHot fractured rock (HFR) geothermal energy hasgreat potential as a future supply for electricpower generation by harnessing stored thermalenergy from high temperature granitic rocks in theCooper Basin and North Flinders Ranges. Thisroute provides opportunities for power generationwith minimal greenhouse gas emissions or longlastingnuclear wastes, at a cost competitive withthose for energy generated from fossil fuels ifcarbon costs are considered. The geothermalheat exchange occurs at great depth, up to 5 km,and the thermal energy source is radioactivedecay rather than volcanism (Geodynamics,2009). Existing reservoir granites are currently inequilibrium with the surrounding ground water.The injection of fresh water to extract thermalenergy from the host rock will alter this fluid-rockequilibrium and may cause partial chemicaldissolution or mineral species alteration, whichmay potentially increase the dissolved solids suchas silica and other metals in the water. Thesedissolution products of the components havedifferent equilibria, which will be a function oftemperature and pressure, thus precipitation orscaling of pipe work and closure of fractures in thegranite body are possible. The saturation ofmetals in fluid is volume-dependent, where verysmall volumes of fluid may require slight undercoolingbefore precipitation occurs. Clearly,characterization of fluid geochemistry is importantin the evaluation of the performance ofgeothermal systems (Grigsby et al., 1989).Moreover, understanding the chemicalinteractions due to the injection of fluid into hotgranite is crucial for problems concerning cloggingby precipitation and heat loss caused bydissolution (Azaroual and Fouillac, 1997).The study of fluid-rock interaction will allowdetermination of mineral alteration and dissolutionof minerals to the circulating water. Unfortunately,relatively little information is available on the ratesand chemical mechanisms of mineral reactions inhydrothermal solutions (Posey-Dowty et al.,1986). Furthermore, it is impossible to generalizethe actual field experience of mineral deposition ingeothermal systems into one consistent theorydue to the vast chemical and operational variationbetween field sites (Robinson, 1982). Therefore,although there have been a number of studies onfluid-rock interactions for different geothermalsites (Rimstidt and Barnes, 1980; Robinson,1982; Posey-Dowty et al,. 1986; Savage et al.,1987; Grigsby et al., 1989; Savage et al., 1992;Azaroual and Fouillac, 1997; Yangisawa et al.,2005), these are probably not directly applicableto the hot granite-based geothermal systems inthe Cooper Basin.Flow-through CellA hydrothermal reaction cell has been developedto observe chemical changes in the host rock andthe circulating fluid. A diagram and a photographof the flow through cell are provided in Figure 1.The cell is designed to operate in a flow-throughconfiguration where the fluid flows continuouslyinside the cell. The total cell volume is 345 ml. Alltubing is made from ¼ inch titanium andconnected with standard Swagelok titaniumfittings, with the reservoirs in stainless steel1144

Australian Geothermal Energy Conference 2009(a)(b)Figure 1: (a) Diagram of the flow through cell (b) Photograph of the geothermal flow through cell(SS316). The total length of the cell loop isapproximately 1800 mm. The volume of the mainreservoir is 150 cm 3 . A pressure relief systemconsisting of a relief valve and a relief vessel isemployed to the cell for safety. The volume of therelief vessel is 300 cm 3 and the relieve valve wasset to open at a maximum pressure of 100 bar. Anexpansion reservoir is employed to compensatefor changes in volume as the fluid is heated. Thevolume of the expansion reservoir is 75 cm 3 . Allvessel are rated at 344 bar. Four thermocouplesare installed to monitor the temperature changesthroughout the cell. A pressure transducer isinstalled to monitor the pressure. The operatingtemperature and pressure are 250 o C and 50 bar,respectively. Temperature is controlled by asimple relay controller and two heaters were usedand arranged in parallel. The heaters are intactwith the main reservoir and insulated with ceramicbricks.ExperimentalSamples of drill cuttings were provided byGeodynamics from the Habanero 3 well. Thesamples were analysed using optical microscope,scanning electron microscope (SEM) at theAdelaide Microscopy Centre to observe bothsurface and cross-sectional area, and powder X-ray diffraction (XRD) at the South AustralianMuseum to identify and semi-quantify theminerals. A preliminary set of experiments toobserve the fluid-rock interaction were performedin batch mode. The drill cutting was used as therock sample. The rock sample was crushed andsieved to give 100 – 200 μm size fraction andapproximately 0.7 grams of rock were used ineach batch. The sample was contained in a preweighedwire basket made from stainless steeland placed in the sample holder of the cell. Thecell was filled through a valve in the base of thecell with reverse osmosis (RO) water and then 90ml of water was drained from the cell to allow for2145

Australian Geothermal Energy Conference 2009fluid expansion upon heating. The velocity of thethermosyphon circulating fluid is estimated to beapproximately 0.1 m/s. The fluid-rock interactionperiods were 1, 2, 3, 7, 14, and 21 days. Atconclusion of this interaction period, the rocksample was dried (105 o C for 48 hours), cooled ina desiccator, and weighed to determine anyweight loss.The rock samples were analysed using SEM andXRD, and the water samples were stored andpreserved with 4% w/w of 1M nitric acid untilanalysis by ICP-MS to identify the dissolvedmetals. The silica content was quantified usingheteropoly blue method (HACH, 2009).Results and DiscussionPreliminary results from the geothermal cellexperiment illustrate that the dissolution of therock (% w/w) increases with time (Figure 2).AbKCarbFigure 3: Host rock Habanero 3 – “syenite” consisting of albite(Ab), microcline (K) with extensive carbonate (carb) alteration– field of view 2mm acrossFigure 2: Change in weight loss of rock (% w/w) versus timeHowever, dissolution appears more rapid in theearly stages of the experiment. It is probably anartefact of the rapid dissolution of fine particlespresent in the rock sample (Savage et al., 1987).The later stage of the experiment approached asteady state value. However the fluid is notnecessarily saturated with minerals (feldspar), butdue to the low dissolution reaction rate betweenthe remaining phases causes this behaviour..Detailed analyses of the mineralogical changes inthe host rock are currently underway and will bereported at a later date.Rock AnalysisPetrographic analysis was performed on the drillcuttings from Habanero 3 well. The rock is afeldspar syenite, containing albite (NaCa)AlSi 3 O 8 ,and microcline (KAlSi 3 O 8 ) with carbonatealteration, which has been subjected tohydrothermal alterations (Pring, pers. comm.2009), as shown in Figure 3.SEM images of the surface particles wereobtained using the secondary electron detector(SE) of the XL30 in Adelaide Microscopy. TheSEM images of the rock sample surfaces beforeand after the experiments are shown in Figure 4.It can be seen that fine particles adhered on thesurface of the starting rock. The fine particlesrapidly dissolved during the early stages of theexperiments and the roughness of the rocksurface also becomes more apparent with longerinteractions with the fluid. Etching is evident onthe surface of the rocks and again developed inthe later stages of the experiment. This indicatesthat a dissolution reaction has occurred in theinteraction period.SEM analyses of the cross section of the rocksamples (images not presented) were alsoconducted. These images were obtained usingthe backscattered electron detector (BSE) andanalysed using the energy dispersive x-rayspectrometer. The results suggest that the rock iscomposed of albite-feldspar, microcline andquartz. The feldspar was variably veined and wasreplaced by patches of fine grained carbonatewith a magnesium and iron-rich composition. Therock also contains minor amounts of pyrite (FeS 2 ),sphalerite (ZnS), fluoropatite (Ca 5 (PO 4 ) 3 F and anumber of other accessory minerals. Preliminaryobservation of the SEM analysis on the rocksamples after the experiment indicates minimalalteration. However, it was evident that thecarbonates have dissolved in the early stages ofthe experiment.3146

Australian Geothermal Energy Conference 2009(a)(b)(c)(d)(e)Figure 4: SEM images of the rock sample surface (a) starting rock (b) after 1 day experiment (c) after 1 week experiment (d)after 2 weeks experiment (e) after 3 weeks experiment21 days14 days7 days3 days2 days1 daystartFigure 5: Compiled XRD analysis results from geothermal cell experiments4147

Australian Geothermal Energy Conference 2009Traces of iron, manganese, magnesium, andstrontium were found in the solutions after theexperimental runs. Some of the iron may becontaminants from partial dissolution of metalsfrom the stainless steel basket and/or thestainless steel reservoir of the geothermal cell.The results from the X-ray diffraction analysis ofthe rock sample from different stages of theexperiment are presented in Figure 5. It is seenthat the peaks showing intensity do not changesignificantly in different experimental runs. Thelines in the XRD trace for albite and microclineshow slight decrease compared to those ofquartz, which is quite stable. Quantitative phaseanalysis using the X-ray diffraction data isplanned for future work.Water AnalysisThe initial pH of the water was 5.5. This did notchange significantly in all batch experiments.Figures 6 – 9 show the concentration of elementsversus time from the ICP-MS analysis on thecirculating water after 1, 2, 3, 7, 14, and 21 daysof fluid-rock interactions.Figure 8: Concentration of Na and K in experimental liquidversus timeFigure 9: Concentration of Si in experimental liquid versustime (standard deviation 0.0067)Figure 6: Concentration of Fe, Mn, Mg and Li inexperimental liquid versus timeWater analysis results showed that there wasenhanced release of the minerals, indicated bythe concentration increase of minerals in the liquidphase. The rapid dissolution is probably aconsequence to the dissolution of fine particulateswhich adhere to the mineral grains of the rocksample to the fluid phase (Figure 4a). The use ofpure water (very low concentration of dissolvedmineral) would also explain the rapid dissolutionreaction. The increase in concentration ofelements Si, Na, and K in the water wouldindicate the dissolution of albite and microclinefeldspars. The increase in the concentration of Feand Mn may be the consequence of thecarbonate dissolution to the liquid. Traces of Al,Fe, Mn and Mg may be contaminants from thedissolution of accessory minerals. Concentrationof all analysed elements showed a net increaseduring the experiment, except for Ca, Ba, and Mg.Figure 7: Concentration of Al, Ca and Ba in experimentalliquid versus time5148

Australian Geothermal Energy Conference 2009ConclusionThe petrographic and diffraction analysis showedthat the rock is composed chiefly of feldsparsyenite, quartz, albite and microcline withcarbonate alteration. The fluid-rock interactionexperiment showed that dissolution reactionsoccur predominantly in the early stages of theexperiment probably due to the dissolution of fineparticulates in the rock. In addition, thecarbonates have also dissolved in the earlystages of the experiment. Results of XRD showedthat feldspar experienced a slight reduction;however, quartz remained stable throughout theexperiment. Liquid analysis showed higherconcentrations of Na, K, Si, and Al compared toother analysed elements. These results suggestthat the dissolution reaction occurs primarily forthe feldspars.The dissolution of feldspar would suggestpotential silica scaling. The concentration of silica(72 ppm released from 0.7g rock sample) wasreleased to the liquid phase throughout theexperiment. Unfortunately the quantification of theminerals has not been concluded, therefore themass balance and mass transfer rates are stillunclear at this stage.Future WorkThe current work has used reverse osmosis waterfor the fluid-rock interaction and does notrepresent the actual interaction. Therefore futurework will conduct the experiment using a morecomplex fluid system Na – Cl – H 2 O and willprogress with the actual fluid from the field.Quantification of the minerals will be performedusing electron microprobe to understand the masstransfer occurring in the interaction. Modelling ofthe fluid-rock interaction will be performed in thelater stage of this research using GeochemistWorkbench.AcknowledgmentsThe research described in this paper has beensupported by The Department of PrimaryIndustries and Resources of South Australia(PIRSA) and Geodynamics. The author would liketo thank Geodynamics for supplying the drillcuttings, and the South Australian Museum andAdelaide Microscopy for the equipment access.ReferencesAzaroual, M., and Fouillac, C., 1997,Experimental Study and Modelling of Granite-Distilled Water Interaction at 180 o C and 14 Bars:Applied Geochemistry, V. 12, pp. 55-73.Geodynamics, 2009, Power from the Earth.Habanero 3,http://www.geodynamics.com.au/IRM/Company/ShowPage.aspx?CPID=1403, accessed 10January 2009.Grigsby, C. O., Tester, J. W., Trujillo JR., P. E.,and Counce, D. A., 1989, Rock-Water Interactionsin the Fenton Hill, New Mexico, Hot Dry RockGeothermal Systems I, Fluid Mixing and ChemicalGeothermometry: Geothermics, V. 18, 629-656.HACH, 2009, DR/2010 PortableSpectrophotometer Procedures Manual.http://www.hach.com/fmmimghach?/CODE%3A4930022286|1, p 767 – 772, accessed September2008Posey-Dowty, J., Crerar, D., Hellerman, R., andClarence, D. C., 1986, Kinetics of Mineral-WaterReactions: Theory, Design, and Application ofCirculating Hydrothermal Equipment: AmericanMineralogist, V. 71, pp. 85-94.Pring, A., 2009, personal communication.Rimstidt, J. D., and Barnes, H. L., 1980, TheKinetics of Silica-Water Reactions: Geochimica etCosmochimica Acta, V. 44, pp. 1683-1700.Robinson, B. A., 1982, Quartz Dissolution andSilica Deposition in Hot Dry Rock GeothermalSystems, Thesis, Cambridge, MassachusettsInstitute of Technology.Savage, D., Cave, M. R., Milodowski, A. E., andGeorge I., 1987, Hydrothermal Alteration ofGranite by Meteoric Fluid: An Example from theCarnmenellis Granite, United Kingdom:Contributions to Mineralogy and Petrology, V. 96,pp. 391-405.Savage, D., Bateman, K., and Richards, H. G.,1992, Granite-Water Interactions in a FlowthroughExperimental System with Applications tothe Hot Dry Rock Geothermal System atRosemanowes, Cornwall, U.K.: AppliedGeochemistry, V. 7, pp. 223-241.Yangisawa, N. Matsunaga, I., Sugita H., Sato, M.,and Okabe T., 2005, Scale Precipitation DuringCirculation at the Hijiori HDR Test Field,Yamagata, Japan: Proceedings WorldGeothermal Congress 2005, Antalya, Turkey, 24-29 April 2005.6149

Australian Geothermal Energy Conference 2009The End Point of Geothermal Developments:Modelling Depletion of Geothermal ResourcesJ V Lawless*A W Clotworthy; *G UssherSinclair Knight MerzPO Box 9806, Newmarket, Auckland, New Zealand: JLawless@skm.co.nzAny finite quantification of the “capacity” of ageothermal resource implicitly involves a startpoint and an end point for energy extraction. Theissue addressed in this paper is: at what time andwhy does energy extraction cease from ageothermal resource, and what are theimplications for resource assessment?The point of cessation can be referred to as the“end point” and the reason for cessation as the“failure mode”. The objective of this paper is todefine the various ways that geothermal energyextraction development can be quantified andmight have to cease, and then look at to whatextent these can be built into predictive models.Useful insights can be gained from experience in“conventional” geothermal projects based on hightemperature naturally convective systems withlong operating histories, in excess of 50 years insome cases. This study is theoretical in thesense that to date, no whole geothermal powerschemes anywhere have been decommissioneddue to the resource reaching the end point andfailing (though individual plants have ceased tooperate). However, this will eventually be thecase.These issues will became increasingly importantin Australia as projects move from InferredResource estimates to higher Resource andReserve categories.Stored Heat EstimatesIn a simple stored heat estimate with no naturalheat or fluid recharge over the project lifetime, theimplicit assumption is that the project will ceasewhen all of the available energy has beenextracted. So the “failure mode” is a temperaturedecline. This is implicit in all of the InferredResource estimates that have been public inAustralia so far, since they are all based on storedheat estimates.In many of those assessments the “cut offtemperature” which represents the minimumisotherm for defining the resource volume isbased on an assumed power plant inlettemperature, and the “base temperature” whichthe available energy is referenced to is based onthe plant rejection temperature. But even thoseapparently straightforward assumptions can besignificant oversimplifications.In a system with reinjection, practically speakingenergy extraction will have to cease when thefluid coming out of the production wells dropsbelow the minimum inlet temperature requirementof the power plant. But at that time there will be atemperature and pressure gradient laterallythrough the reservoir from the reinjection to theproduction wells, so the average resourcetemperature at that time will be less than thepower plant inlet temperature. That averagetemperature should more logically be the cut offtemperature for the stored heat assessment.The next level of refinement is to consider thatbecause of the change in water viscosity withtemperature, the lateral pressure and thereforetemperature gradient between the reinjection andproductions wells will definitely not be linear,which means the fraction of the resource volumefrom which energy can usefully be extracted is notjust a simple proportion. That could readily beaddressed by a dynamic reservoir model,provided suitable data on the formation propertiesare available for calibration.A related consideration which has arisen in onerecent resource estimate is that the, use of a “cutoffisotherm” may not be the most appropriatemethod to apply to a series of vertically stackedsedimentary aquifers or horizontally fracturedgranite, in which heat flow is conductive and notconvective, i.e. temperature is stratified, low at thetop and high at the bottom, so wells at differentdepths or wells with multiple feed zones mayproduce fluid with a wide range of temperatures.In such a system there could be the freedom toset the cut-off temperature at such a level, whichensures that the mixed geothermal fluid producedat the well head remains above the power planttemperature. Adoption of this approach couldmean that the cut-off temperature to define thegeothermal reservoir is lower than the power plantinlet temperature. The adoption of a lower cut-offisotherm could be beneficial in situations wherethe benefits of increasing the total volumeoutweigh a modest decrease in the temperatureof the fluid produced.Further considerations to take into account are:heat loss up production wells, which could beconsiderable where wells are deep and flow ratessmall; heat loss between the wells and powerplant; heat loss between the separators (if any)and power plant and reinjection wells; and heatgain down the reinjection wells. There are alsopower systems aspects to consider such asprocess and thermodynamic issues as well asparasitic pumping etc. loads. Site-specific1150

Australian Geothermal Energy Conference 2009ambient temperatures and humidity will dictatepractical cooling options.Furthermore, if the production temperaturedeclines over the lifetime of the project which iswhat would be expected in a heat miningoperation and is therefore implicit in a stored heatestimate, the power plant efficiency would alsodrop and the production pumping requirementswill change as the fluid density and viscositychanges. That would be exacerbated by reservoirpressure changes. All of these factors can andideally should be modelled as resourceassessments become more accurate, even whenjust using a stored heat approach.Dynamic Resource EstimatesAn alternative approach is to assume that acertain rate of extraction is indefinitely physicallysustainable on a human time scale, in which casethe field “capacity” is better expressed as MWth orMWe (making suitable assumptions as toconversion efficiency) rather than PJthermal orMWthermal-years in place and recoverable. Thisappears to be the case with fields such asWairakei in New Zealand, where reservoirmodelling predicts that extraction will bephysically sustainably for at least 100 years –which is perhaps simply an expression of the factthat our perception of the “resource” is too limitedin that it does not include the deeper heat source.But even there other factors may come into playwhich could mean the project cannot in factsustain output for all of that period.Based on practical experience of geothermalsystems that have been exploited for a longperiod of time, there are other possible failuremodes as follows.With dynamic reservoir simulation, which is themost common means of assessing appropriatecapacity in advanced existing conventionalschemes without pumping, the “failure mode” isoften predicted to be pressure decline rather thansimply temperature decline. In a single phase(liquid) reservoir, pressure decline will be due todraw down in liquid pressure, as in a groundwateraquifer. In a two-phase reservoir such as Wairakeiin New Zealand, Cerro Prieto in Mexico, or manyof the other high temperature “conventional”projects worldwide which have been exploited,pressure draw down will to some extent bebuffered by boiling, but if wells tap two-phasezones, pressures will be linked to temperatures,so can decline if cool water invades the reservoir(as has happened at Ohaaki for example).In a dry steam system such as The Geysers inCalifornia pressure decline can be due to thereservoir drying out. Water loss within EGSprojects is an obvious parallel though of adifferent origin.Pressure decline has two importantconsequences. Initially it will cause declines inwell mass output (though that may becompensated for by rising enthalpy if boilingoccurs so the available energy output actuallyincreases). It is also possible that pressures mayeventually fall to the point where steam turbinesbecome inoperable. In both cases considerableunrecovered thermal energy may remain withinthe reservoir.To some extent these effects can be countered bydrilling make up wells or adopting pumping, but apoint of no return may be reached at which drillingfurther wells is not considered economic.Linked to and synergistic with reservoir pressuredeclines, there can be incursion of groundwater,either laterally or from above. This has been welldocumented and studied in New Zealandresources such as Wairakei, Ohaaki and Kawerauas well as in some fields in the Philippines. Aswell as chemical monitoring of well productionphysical and chemical parameters, repeat microgravitymeasurements are an appropriate tool fortracking fluid movements.Incursion of cool ground waters may be severelydetrimental by reducing well enthalpies, as atOhaaki. But it can also causing undesirablechemical effects such as scaling and corrosion.The ground water above and around hightemperature geothermal systems may be high inspecies such as bicarbonate and sulphate and oflow pH, developed by separation, absorbtion andoxidation of gas phases. Wells have failed in NewZealand fields due to external corrosion by suchsecondary fluids. They can also contribute toscaling in production wells by anhydrite from theadmixed sulphate and/or more commonly calcitefrom the bicarbonate.Premature reinjection returns to production wellsare also a common limiting factor in somedevelopments, and can leading to a low % energyrecovery though not usually total failure of theproject.Excessive environmental effects on the surfaceare another factor that can limit geothermalenergy extraction well before thermal energydepletion. At Wairakei in New Zealand forexample, many years of geothermal fluidextraction with very limited reinjection havecaused severe localised surface subsidence(possibly up to 21m) and increases in thermalactivity including hydrothermal eruptions. Thepossibility of such effects extending into populatedareas has been a constraint on furtherdevelopment. At Rotorua, power generation iseffectively precluded because of concerns overeffects on thermal activity which is crucial to thetourist industry.2151

Australian Geothermal Energy Conference 2009Ability to Predict Failure Modes andModel End PointsThe ability to predict what will be the failure modeof a geothermal project and hence its end pointfor resource estimation varies both according tothe nature of the reservoir and the amount ofknowledge available. At an early (pre-drilling)stage stored heat with its implicit assumption oftemperature depletion is the most appropriatetool.Once exploration wells are drilled and tested,stored heat estimates can be refined, but datamay start to become apparent which indicateother possible end points, such as prematurereinjection returns. At this stage such effects canbe qualitatively modelled by analogies anddynamic reservoir simulation, but probably as aseries of “what if” scenarios rather than adefinitive quantitative prediction. To do so willrequire more attention is paid to permeability datathan has been typically the case so far.It is only once some production history becomesavailable either through operation of a small scaleinitial power generation scheme or long term welltesting, that dynamic reservoir simulation canreally come into its own and can be used to givereliable forward predictions.Implications for Resource EstimationThe methodology for meaningful resource andreserves estimates will change over time asprojects become more advanced. While storedheat estimates are adequate for InferredResource estimates, more advanced projects andhigher resource categories should take intoaccount other possible end points and adjust theestimates accordingly, in many instances mostparticularly through numerical reservoirsimulation.In many cases this approach will cause the laterresource estimate to be lower than the initial ones– though strictly speaking that should not be so ifthe risks and uncertainties have been consideredproperly in the initial estimates. That is not alwaysnecessarily the case however. At Wairakei forexample a significant stimulation of heat and fluidrecharge has occurred which has increased theresource available.3152

EGS & "The Law of Averages"Peter Leary* & Peter MalinInstitute of Earth Science & Engineering, University of Auckland58 Symonds Street, Auckland 1142, New Zealand*Corresponding author: p.leary@auckland.ac.nzAustralian Geothermal Energy Conference 2009Enhanced Geothermal Systems (EGS) seek toproduce high permeability flow systems whereNature has provided only low permeability flowsystems. We take a science-based modellinglook at the flow heterogeneity character of highpermeability geothermal systems to betterunderstand the in situ systems EGS is dealingwith. Our flow modelling is based on percolationthrough grain-scale fractures, with grain-scalefracture density η(x,y,z) allowed to fluctuate inspace on all scale-lengths in line with well-logpower-law scaling phenomenology recorded inboth sedimentary and crystalline basement rock.Massive hydrofracturing in EGS drill holes can inprinciple introduce high permeability quasi-planarmega-fractures into our natural poroperm mediumbut almost certainly EGS induced fractures cannotbe expected to completely define the hydraulicconnectivity between an induced fracture and theremaining drill holes in the EGS plumbing system.At some point in an EGS volume, the naturalfracture hydraulic connectivity is likely to controlthe fluid system throughput We therefore suggestthat it is highly relevant for EGS developments totarget crustal volumes in which the naturalfracture permeability is higher rather than lower.For spatially variable porosity φ(x,y,z) proportionalto fracture density η and spatially variablepermeability κ(x,y,z) proportional to fractureconnectivity factor η!, then the identity δη ~δ(log(η!)) reproduces the poroperm spatialfluctuation relation δφ ~ δlog(κ) documented in oiland gas field well-core data. We model 3D fluidflow in numerical media constructed for 3 degreesof spatial correlation of grain-scale fracturedensity: (1) no spatial correlation -- grain-scaledensity does not cluster and "the law of averages"holds; (2) intermediate spatial correlation -- grainscaledensity clusters are diffuse andunpredictable whence the law of averages fails;(3) strong spatial correlation -- grain-scaleclustering compartmentalizes rock volumes andthe law of averages has rough validity over limitedspatial domains. Our flow simulations indicatethat geothermal reservoir pressure and flow dataare far more likely to resemble case (2) thancases (1) or (3). We infer that, at least for scalelengthscharacteristic of geothermal reservoirs,the in situ low permeability flow systems that EGSseeks to enhance into high permeability flowsystems are likely to be spatially erratic andunpredictable at all relevant scale-lengths, andhence that the resulting EGS flow systems arealso likely to be more spatially erratic andunpredictable than expected from “the law ofaverages”. Supplementary fracture-sensitivedata, e.g. microseismic and/or MT surveys, canthus be useful in completing EGS projects.Keywords: fractures, heterogeneity, percolation,permeability, flow modellingIntroductionTo date flow models for both geothermal andhydrocarbon reservoirs have had little predictivevalue. The failure of reservoir modelling can ingood part be attributed to ignoring the pervasivefracture-heterogeneity of crustal rock attested bywell-log and well-core fluctuation systematics. Insitu fluctuation systematics indicate that geofluidsflow via spatially erratic fracture-percolationnetworks that cannot be predicted from traditionalsmall-scale reservoir sampling (Leary 2002).In geothermal reservoirs, spatially erratic in situpercolation flow networks can potentially bemapped using flow data observed at suitably largescale lengths. A possible means of flow-structuremapping is afforded by systematically recordingand interpreting inter-well flow connectivity data.Such reservoir model-building tactics supersedethe standard approach based on “the law ofaverages”.The law of averages supposes that for every earthproperty, variations in one direction are sooner orlater balanced out by variations in the oppositedirection. The law of averages thus says thatreservoir geological formations can be describedin terms of “effective medium properties” aboutwhich reservoir physical properties fluctuatebenignly. Moreover, effective property values canbe determined by a few small scale samples.Typically the small-scale samples of formationporosity, say, are taken from well logs andformation permeability samples are taken fromwell core.Formation property averaging, however, leads toaccurate reservoir flow models only if in situfluctuations of relevant properties are spatiallyuncorrelated. The necessary and sufficientcondition for spatially uncorrelated in situgeophysical properties is that spatial fluctuationsin these properties have a “flat” or “white” Fourierpower spectrum in spatial frequency k, S(k) ~1/k 0 .Well-logs show, however, that the characteristicspectrum of in situ geophysical propertyfluctuations is S(k) ~ 1/k 1 rather than S(k) ~ 1/k 0.The necessary condition for “the law of averages”to apply in situ is universally and systematically1153

Australian Geothermal Energy Conference 2009violated at all relevant wavelengths for virtually allphysical properties of crustal reservoirs (Leary2002).Percolation phenomenology forspatially correlated grain-scalefracture-density fluctuationsWe compute percolation flow of geofluids in anumerical framework capable of embodying welllogfluctuation systematics. In this heterogeneityframework, the spatially fluctuating numericaldensity η(x,y,z) of grain-scale fractures attestedby well-log data is modelled by power-law-scalingnumerical fluctuations within the model volume.Numerical fluctuations η(x,y,z) are connected togeofluid flow by the empirical relation log()observed to hold for well-core porosity and wellcorepermeability . In this expression, andlog() are respectively the zero-mean unitvariancereductions of the porosity andlog(permeability) fluctuation sequences for coredreservoir intervals (Leary & Walter 2008).The empirical well-core poroperm fluctuationrelation log() is conceptually equivalent toa mathematical identity δη ~ δ(log(η!)) iffluctuations in porosity are proportional tofluctuations in grain-scale density η(x,y,z) andfluctuations in permeability are proportional to thefluctuations in the combinatorial factorial termη(x,y,z)! representing the number of ways η(x,y,z)grain-scale fractures can combine to produce apercolation pathway. If a rock volume has ηgrain-scale fractures per unit volume at location(x,y,z) and η +η grain-scale fractures at location(x,y,z)+(x,y,z), the percolation-relatedpermeability in the two volumes can be expectedto vary as the combinatorial terms η! and (η+η)!.Stirling’s formula, η! (η + ½)log(η) – η, applied tothe two fracture connectivity expressions reducesto the empirical well-core fluctuation expressionη log(η!).Percolation flow in spatially correlatedfracture networksSingle phase flow in heterogeneous media issimulated using SUTRA (Voss and Provost 2008),a finite-element solver for Darcy’s law inpermeability-heterogeneous media, ∂ t P =((x,y,z)P), P = geofluid pressure. Modelporosity (x,y,z) is proportional to numericalfracture density η(x,y,z), and model permeabilityκ(x,y,z) is given by the well-core relation log().Figure 1a-c: 3D numerical spatial noise distributions withincreasing degrees of correlation: (top) uncorrelated whitenoise, fluctuation power spectrum S(k) ~ 1/k 0 ; (mid)intermediate correlation 1/f-noise, power spectrum S(k) ~1/k 1 ; (bottom) strong correlation Brownian noise, powerspectrum S(k) ~ 1/k 2 .To see the effect of spatial correlation on reservoirflow, we compute flow for three degrees of spatialfracture correlation parameterized by powerspectralexponent p, S(k) ~ 1/kp, k = spatialfrequency. The degrees of spatial connectivityare: (i) p = 0, spatially uncorrelated or white noisefluctuations (Figure 1a); (ii) p = 1, moderatelyspatially correlated “1/f” noise fluctuations (Figure2154

Australian Geothermal Energy Conference 20091b); (iii) p = 2, strongly spatially correlatedBrownian noise fluctuations (Figure 1c). Each ofthese 3D numerical heterogeneity constructs hasthe same mean and standard deviation. The onlydistinguishing feature is the degree of spatialcorrelation/clustering of the numbers representinggrain-scale fracture density.Finite-element solutions to fluid flow in and out ofelementary digital volumes or cells are robustagainst spatial variations in the porosity andpermeability of cells. The fact that these propertyspatial variations occur at all scale lengthsthroughout numerical medium has no effect onthe speed or stability of the flow computations. Ofcourse, the greater the number of cells, the morerealistic will be a specific flow simulation, but it iscurrently feasible to run simulations with64x128x128 = 2 6 x2 7 x2 7 cells, giving six octaves ofvertical fluctuation power and seven octaves oflateral fluctuation power, equivalent to factors 8and 11, respectively, in amplitude fluctuations.Flow systematics for 1/k 0 , 1/k 1 & 1/k 2grain-scale fracture density spatialcorrelationSimulation pressure histories plotted in Figures2a-d reflect the distinct character of 1/f-noiseheterogeneity flow evolution (red traces)compared with those of white noise (black traces)and Brownian noise (blue traces). Each figurerepresents a different source well flow simulationfor the three heterogeneity types. For eachsource well, a colour-coded quartet of flow historytraces shows time-evolving pressure signalsrecorded at observation wells at four offsets fromthe source well.The Figure 2 colour-coded pressure curves showthat the different heterogeneity types result insubstantially different pressure histories. Allpressure histories evolve more or lessconsistently within a heterogeneity class. Theuncorrelated heterogeneity (white noise = blacktraces = Figure 1a) and strongly correlatedheterogeneity (Brownian noise = blue traces =Figure 1c) both generate essentially monotonicpressure evolution. The black curves ofuncorrelated heterogeneity are relatively subduedin pressure history difference as expected from amedium that is essentially uniform within astandard deviation about a mean permeability;there is no evidence of flow complexity that mightbe associated with significant spatial trends inporoperm distribution. The blue curves ofBrownian-noise heterogeneity have a strongerdegree of temporal evolution that is the same forthree of the source-sensor well pairs, butsubstantially different for the fourth source-sensorwell-pair. The amplitude discrepancy is due tothree of the sensor wells being inside the Figure1c high-porosity volume while the fourth sensorwell is on the edge of the high porosity volume. Inboth amplitude cases, however, pressureevolution at the sensor well is monotonic.These simulation flow data are understandable interms of simple considerations. Flow in spatiallyuncorrelated media conforms to the standardstatistical expectation that randomness tends toaverage out. Flow in strongly spatially correlatedmedia tends to be simply diffusive over eachrange of coherent spatial properties.The red curves of 1/f-noise (Figure 1b)heterogeneity present an unfamiliar degree of flowcomplexity. The Figure 2a-d observation wellpressure histories in red are responding to aconsistent but complex spatially-correlatedheterogeneity structure, and the spatialcomplexity generates temporally complexevolution signals. In conspicuous contrast withthe monotonic well-pair histories for theuncorrelated and strongly correlated poropermheterogeneity, 1/f-noise poroperm heterogeneityconsistently exhibits large-amplitude temporalfluctuations about a diffusion trend history.If we now compare the three Figure 2a-d pressurehistory types to a sample of in situ pressurehistories in Figures 3a-d, we see little evidence infield pressure data for essentially monotonicdiffusion-flow characteristic of uncorrelated 1/k 0and 1/k 2 spatial correlation, but see ampleevidence for pressure histories that systematicallyfluctuate about long-term diffusion trends that aremodelled by flow simulations in 1/k 1 poropermheterogeneous media. The correspondencebetween in situ flow data fluctuations (Figures 3ad)and model flow data fluctuations (Figures 2a-d)indicates that spatial poroperm heterogeneitybased on well-core and well-core empirics has ageneral validity for in situ fractures and fracturebornepercolation flow.DiscussionThe “law of averages” incorporates three workingassumptions:Fluctuations balance out on all scale lengths; No significant trends develop at any scalelength; Small scale samples yield good indicators oflarge scale properties.These working assumptions are highly convenientbut are unfortunately formally invalidate for in situspatial fluctuations in reservoir propertiesrecorded by well logs; well logs have powerspectrathat scale inversely with spatial frequency,S(k) ~ 1/k 1 , rather than as the form S(k) ~ 1/k 0required for the law of averages.3155

Australian Geothermal Energy Conference 2009Figures 3a-d: Geothermal field flow-related well data: (a-c)Chloride abundances, Palinpinon field, Philippines (Horne2008); (d) Pressure and mass discharge (Sorey and Fradkin1979).Figures 2a-d: Quartets of simulation flow pressure historiesfor (top to bottom) 4 different source well locations in Figure1 numerical reservoir volumes: black traces = Figure 1a;blue traces = Figure 1b; red traces = Figure 1c.The in situ geothermal reservoir flow data ofFigures 3a-d go beyond mathematical formalismto give additional and perhaps more practicalrebuttal to the law of averages applied to reservoirprocesses. The different types of in situ fracturedistributions in Figures 1a-c are seen to have realmeaning in terms of reservoir flow. Figure 3a-d insitu flow data imply that we can be more confidentin understanding that long-range trends in fracturedensity and fracture connectivity are characteristic4156

Australian Geothermal Energy Conference 2009of in situ rock permeability over a range of scalelengths characteristic of reservoir flow. It isvisually clear from Figures 1a-c that such in situtrends cannot be adequately modelled by dataaveraging (Figure 1a is not a valid smoothedversion of Figure 1b), nor can valid statisticalinferences about large-scale flow structures bemade from acquiring small-scale samples (a fewsamples from Figure 1a fix the likely values ofother samples; this is clearly not true of samplefrom Figure 1b).As a general statement, fracture heterogeneity inthe form of Figure 1b must be addressed bymaking suitable in situ measurements at theappropriate scale lengths.Applying this statement to EGS projects seekingto enhance in situ fracture permeability, it seemsclear that EGS fracture enhancement is bestconducted in rock volumes that host large-scalefracture clustering. Even if EGS induced fracturesare thought of only in terms of massive planarflow structures, such structures must naturallyterminate in country rock. In terms of Figure 1b,country rock volumes with high fracture densitiesdenoted by warm colours are far more promisingEGS targets than are rock volumes with lowfracture densities denoted by cool colours.A practical implementation of this statement is toassociate in situ fractures with earthquake failureand/or fracture-borne fluid electrical conductivity.While it is common to regard with alarmearthquake failure in a reservoir environment, thisattitude is likely to be naïve and counterproductive.Enhanced reservoir flow is likely to beessentially concomitant with earthquake failure.Given the comprehensive failure of the law ofaverages applied in situ and the use of smallscalesample to infer large-scale in situ flowproperties, a more informed point of view wouldbe systematically use micro-earthquakes as anexploration tool to locate in situ fracture clustersthat are likely to be large-scale permeabilitysystems for which input and output flow can beengineered/enhanced. Microseismicity data canbe supplemented by MT detection of electricallyconducting volumes at depth.A compelling logic associates earthquakes withfluid-rich fracture clusters. Such clusters are theweakest and more compliant part of the rockmass, and fluid pressures tend to lower normalfrictional stresses that work against slip failure.Seismicity is almost universally induced by themodest crustal loads of water ponded behinddams, indicating that the crust is everywhere nearfracture failure. The most fractured crustalvolumes being the most likely to fail,microseismicity, either natural or induced, is alikely indicator of fluid-rich fracture systems.Conversely, absence of microseismicity implies alower potential for in situ fracture systems.Exploration wells instrumented with seismicsensor arrays to detect the range and azimuth ofbackground seismicity could be the most directway to assess EGS prospectivity. Fibre opticalseismic sensor technology is on the verge ofmaking seismic assessment of elevatedtemperature EGS prospects a viable explorationoption.SummaryThe law of averages does not apply to the spatialor temporal properties of in situ reservoirs. In situreservoir fracture systems have a tendency todevelop long-range spatial trends in fracturedensity that generate localised fracture/flowclusters that could be plausible EGS targets, butsuch trends can equally be towards low fracturecontent and therefore unpromising EGSprospects. Because the law of averages fails forreservoirs, small-scale sampling of in situ crusthas little bearing on the location and/or propertiesof EGS prospects. EGS prospect assessmentcan logically be conducted through systematiclarge-scale microseismic and or MT dataacquisition.ReferencesHorne, R.N., 2008, Geothermal data mining –Value in antiques, Proceedings of 30 th NewZealand Geothermal Workshop, New ZealandGeothermal Association, p. 82-90.Leary, P.C. and Walter L.A., 2008, Crosswellseismic applications to highly heterogeneous tightgas reservoirs, First Break, 26, p.33-39.Leary, P.C., 2002, In: J.A. Goff & K. Holliger(Eds.) Heterogeneity of the Crust and UpperMantle - Nature, Scaling and Seismic Properties,Kluwer Academic/Plenum Publishers, New York,p.155-186.Sorey, M.J. and Fradkin, L., 1979, Validation andcomparison of different models of the Wairakeigeothermal reservoir, Proceedings of 5thWorkshop on Geothermal Reservoir EngineeringStanford, CA, USA (1979), pp. 119–204.Voss, C.I. and Provost, A.M., 2008, SUTRAVersion 2.1, U.S. Geological Survey Water-Resources Investigations Report 02-4231,http://water.usgs.gov/nrp/gwsoftware.5157

Australian Geothermal Energy Conference 2009Summary of AGEG Technical Interest Groups Research ProjectsAlexandra Long*, Barry A. Goldstein, Tony Hill and Michael MalavazosPetroleum and Geothermal Group, PIRSA, GPO Box 1671 Adelaide, SA, 5000* Corresponding author: long.alexandra@saugov.sa.gov.auThe Australian Geothermal Energy Group(AGEG) has the vision that geothermal resourceswill provide the lowest cost emissions freerenewable base load energy for centuries tocome. The AGEG is working towards this visionthrough its Technical Interest Groups (TIGs)which focus on topics that have been prioritisedby the Australian geothermal industry. Thepriorities are thus aligned with those of theInternational Energy Agency GeothermalImplementing Agreement (GIA) and theInternational Partnership for GeothermalTechnologies (IPGT). Increasingly, priorities arealso coming into line with the oil and gas industrywith opportunities to drive innovation.This paper will provide an update and overview ofthe scope and research findings of projectscompleted for the AGEG by members since thelast Australian Geothermal Energy Conference.Many of the projects focus on topics relevant tothe advancement of Enhanced GeothermalSystems (EGS) in Australia, including reservoircharacterisation, research and development intopower cycle design for the Australian conditionsand other studies to reduce the uncertaintiessurrounding EGS and ensure responsiblemanagement of projects.It is expected that detailed presentations will begiven on many of these projects by the projectinvestigators, so this paper intends to provide abrief introduction of each project’s aims and todemonstrate the range of research that is coveredby the AGEG TIGs.Keywords: Australia, EGS, Hot Rock geothermalThe Australian Geothermal EnergyGroupThe AGEG was formed to bring together allparties involved in geothermal development inAustralia, in order to work together andcooperatively advance the industry as a whole.The method of this advancement is through thework of the Technical Interest Groups which arebroadly separated into the stages of a geothermalproject and so encompass land access andexploration through to power systems andtransmission or connectivity to the NationalElectricity Market. The 12 AGEG TIGs are brieflydescribed in Table 1.The TIGs have transformed somewhat since theirconception in 2007. In particular TIG 2 has formedthe joint AGEG and AGEA Resource andReserves Code Committee, who released andnow administers the first uniform geothermalreserves and resources reporting code. The TIGfor policy advice has led to the creation of theAustralian Geothermal Energy Association(AGEA), the national industry body representingthe Australian geothermal industry. TIG 5 hasheld some informative workshops and hasbecome the AGEA working group on issuesrelating to the national electricity market whichalso reports back to the AGEG. The order of thegroups has been re-organised such that the firstfour groups cover best practice protocols andcommunication and TIGs 5 to 12 covergeothermal technology development (Outlined inred).TIG 1 Land AccessTIG 2 Reserves & ResourcesTIG 3 PolicyTIG 4 OutreachTIG 5 Getting to MarketsTIG 6 Power PlantsTIG 7 Direct UseTIG 8 Information & DataTIG 9 Reservoir Development & EngineeringTIG 10 Exploration & Well Log TechnologiesTIG 11 Drilling & Well ConstructionTIG 12 EducationTable 1 - The AGEG's Technical Interest GroupsThe AGEG and the AGEA have agreed tocoordinate research efforts through the AGEG’sTechnical Interest Groups. This will facilitateAustralian companies, research experts andgovernment agencies (including regulators) toconvey and take note of international bestpractices for the full-cycle of below-ground andabove-ground geothermal energy operations andstewardship.The structure of the AGEG and the TIGs is shownin Figure 1. The AGEG's TIGs will have activelinks to the International Energy Agency's (IEA)geothermal research annexes, the IPGT, and willaim to attain strong linkages to all other reputableinternational geothermal research clusters, toensure that Australia's comparative advantages inHot Fractured Rock (HFR) geothermal resourcescan be leveraged into accelerated development ofhigh priority geothermal technologies, methodsand the sharing of lessons learnt. On this basis,the AGEG and the AGEA have agreed that theAGEG should become the Australian affiliate forthe International Geothermal Association.1158

Australian Geothermal Energy Conference 2009Figure 1: Diagram showing the structure of the AGEG, including the Technical Interest Groups and linkages to national andinternational geothermal groups.Further information on the AGEG and its TIGs canbe found on the AGEG website athttp://www.pir.sa.gov.au/geothermal/agegGeothermal Research ProjectsAlready some significant projects have beencompleted within the AGEG TIGs with supportfrom the Department of Primary Industries andResources, SA (PIRSA) tied grants, geothermalcompany contributions and in-kind contributionsfrom members providing their valuable time.Completed projects of note include the firstuniform code to guide the reporting of geothermaldata to the market, The Geothermal ReportingCode and the accompanying Lexicon, which weredeveloped by the Australian Geothermal CodeCommittee (AGCC) and released in 2008. Sincethe Code’s release a number of operatingcompanies have reported their geothermalexploration results according to the Code. TheCode is intended to be a living document and assuch a second version is expected to be releasedin 2009.Under the TIG for land access and environmentalissues, PIRSA commissioned research studies onthe potential for induced seismicity associatedwith the fracture stimulation of EGS wells in theCooper Basin (Hunt and Morelli, 2006), followedby a report on the analysis and management ofseismic risks (Morelli and Malavazos, 2008 andMorelli, 2009). These studies were completed atthe Australian School of Petroleum at theUniversity of Adelaide and have been reported onpreviously.Further to these research projects, 6 moreprojects have been completed in the last year andanother 5 are expected to be completed by theend of 2009. These projects are described inmore detail below and the reports will be madefreely available from the AGEG website.An assessment of radiological hazards in HRgeothermal systemsBattye and Ashman (2008) were commissionedby PIRSA to conduct a literature review and somemodelling to assess the risk of radiologicalhazards for HR geothermal systems. The studyfound that isotopes of Uranium, Radium, Thorium,Radon and Lead will be likely to be present in thecirculating ground waters.The main risks of exposure to these NaturallyOccurring Radioactive Materials (NORMs) for aHR geothermal system would be throughexposure to radon gas if the geo-fluid and steamare emitted to atmosphere, or exposure to thescales and sludge that may form in the aboveground system.2159

Australian Geothermal Energy Conference 2009If the HR geothermal power plant is operated inan entirely closed loop configuration then therewould be little to no risk of radon exposure. For anopen loop situation the levels are probably stillbelow the action levels for workplaces in Australia(1000Bq/m3) but are very dependent on windspeed and the residence time of the geo-fluid inthe reservoir, so thorough monitoring should takeplace to ensure that the exposure is known andthere is no risk, or else the risk is managedappropriately.The other way there could be exposure is fromthe scales or sludge that may be deposited in theabove ground equipment, depending on thegeochemistry and the plant conditions.Experience from conventional geothermalsystems and from the oil and gas industry showsthat these scales and sludge can contain radionuclidesthat have been carried with solidparticles suspended in the solution and thendeposited, or from particles that precipitate out atsurface. Only the Radium isotopes can emitgamma radiation that could penetrate the pipework. Radium isotopes are less likely to be foundin waters with low concentrations of barium andstrontium sulphates, and the report states that asthe radium concentrations will be expected to belower than for the oil and gas industry the gammaradiation from these residues would be expectedto be at insignificant levels.The other isotopes that may be present could behazardous if inhaled as a fine dust, so precautionsshould be taken during all cleaning operations.Geochemistry, corrosion and scaling in HotDry Rock energy extraction systemsThis project investigates an important element ofthe Hot Rock geothermal energy system. The firstobjective is to study geo-fluid chemistry and itscontribution to the corrosion and scaling in pipesin the above ground equipment of a geothermalpower plant. Understanding the fluid chemistry isalso vital to maintain open pores within theunderground reservoir, by avoiding clogging of thefracture network caused by mineral precipitation.The project has involved sampling the geo-fluidfrom a Hot Rock EGS system and also the rockitself to determine the mineralogy andcomposition of each. The researchers at theUniversity of Adelaide and the Museum of SouthAustralia then intend to re-create the aboveground and below ground conditionsexperimentally. Using a specially designedexperimental apparatus they first study theinteraction between the geo-fluid and the rock attemperatures and pressures equivalent to those inthe geothermal reservoir. The results of theseexperiments will be used to calibrate and furtherdevelop geothermal modelling tools to determinepotential scaling and pore blockage issues andconsequently possible solutionsCharacterisation of Adelaidean rocks aspotential geothermal reservoirs (HeatExchange Within Insulator)The main objectives of this project are todetermine the extent of pre-competitive dataavailable to characterise the reservoir parametersof the Adelaidean formations within the AdelaideGeosyncline. This will involve reviewing andcompiling all available data and publications.Further to this, maps would be compiled to showthe areas in the region possibly suitable for bothgeothermal development and geosequestration,with the intention to provide a temperaturegradient for the region.Three dimensional reconstruction of theAdelaide geosyncline – application togeothermal explorationBacké and Giles (2008) developed a robustintegrated methodology to construct a 3D modelof the Lake Torrens – Central Flinders zone inSouth Australia. Using Gocad, they incorporatedvarious tectonic structures (including faults, foldsand mini-basins) without geomorphic expressionat the surface.The Gocad model was then exported into 3Dthermal modelling software to provide an inferredgeothermal resource over the Parachilna area ofthe southern Flinders Ranges, South Australia.Full life-cycle water requirements for deepgeothermal energy developments in SouthAustraliaCordon and Driscoll (2008) documented the likelywater usage for each stage of geothermalexploration and development, including issues ofwater loss, and compiled an atlas of waterresources for South Australia to assist explorersin understanding the quality, availability andlegislative requirements associated with theseresources. Although the atlas of this report is forSouth Australia, the full life-cycle waterrequirements for deep geothermal energydevelopments that are outlined in this report areapplicable world-wide.Preliminary assessment of the impact of geofluidproperties on power cycle designWhile the effects of geo-fluids in terms ofcorrosion and scaling are known, there has notbeen a thorough assessment of the scope ofthese issues for Australian geothermal projects,and in particular with reference to the power cycledesign to accommodate the Australian conditions.Information on the composition of the water thatcan be expected for geothermal projects is difficultto find, which causes great difficulty in forwardplanning for power plant design as theseelements greatly affect the choice of systems andmaterials.3160

Australian Geothermal Energy Conference 2009The first project aim was to compile a database ofavailable water composition and quality from aconsortium of AGEG members. This aim wasrevised, for at the time the researchers werecompleting this section the only available datawas from the Geodynamics wells. From this dataset, the most difficult set of conditions have beenselected and a preliminary design will becompleted using these conditions in order toprovide guidance for how to manage them. Thepreliminary design will also allow furtherinvestigation of where opportunities lie forgeothermal companies to achieve cost savingsthrough better design and highlight areas offurther research. This project is expected to becompleted in 2009.Preliminary assessment of the potential forunderground cooling on power cycle designDally et al. (2009) have reported on a novelconcept of using a large underground network ofpipes instead of large cooling towers or large aircoolers. Large cooling towers are unlikely to befeasible due to their water requirements whichpreviously left large air coolers as the only option.Underground cooling offers the possibility toprovide increases in efficiency for power cyclesfor geothermal plants operating in locations wherethe ambient temperatures are very high. Theconcept and initial results of this study have beenreported (Dally et al., 2008) and the final reportprovides further insights.A thermodynamic model of the underground pipewas used to determine the required length of pipeand depth of burial for a set of harsh conditionsand a 5 MW power plant output. The modelresults were then used to determine the feasibilityof such a design. The authors found that a pipelength of 25 km was needed but this would onlyneed to be placed 10 cm deep to be beneficial –this requires a total area of approximately 5 km 2 .While this is a large area it was estimated that thecost for the system would be lower than for an aircooled system and provide more constant outputincluding greater power output than a fan/aircooler system during peak daytime temperatures.State-of-the-art in power cycles for geothermalapplications and bottoming cyclesResearchers from Newcastle University and theUniversity of Adelaide are working jointly on thisstudy to compile a detailed comparison of existinggeothermal power plants, their performance andoperating conditions, compared with theconditions expected for the Australian geothermalindustry. Using models of the Kalina, Supercritical, flash and Organic Rankine cycles theresearch aims to estimate modifications thatwould be required to adapt those existing powerplants to Australian conditions.The development of a geothermal power plantpreliminary cost estimator – Stage 1: basicestimatesStage 1 of this project aims to develop a costestimator for power generation by a geothermalpower plant in Australian conditions. Theestimator will initially be designed around a set ofassumptions which define the geothermal system,providing the ability for the user to specify thevalues of certain variables such as the geo-fluidtemperature, the ambient conditions, well depth,reservoir porosity and surface pressure. The costestimator will calculate the average cost of powergeneration for a specified period and thepredicted net power under a range of conditions.This model will be designed to be used inconjunction with the MIT cost calculator (Herzoget al., 1997), and to include some factorsimportant for the Australian geothermal industry.Important factors include the effect of ambientconditions on the cooling cycle, the water qualityand level of treatment required, and the pressurerequired for reinjection. The model will also bedesigned to be able to expand over time andinclude more options for power cycle design, arange of options for working fluids and differentcooling systems and corrosion mitigationmethods.Forward prediction modelling of spatialtemperature variation from 3D modelsThis report was prepared by Intrepid Geophysics(2008) and involved the development of asoftware module in 3D GeoModeller to calculate3D temperature directly from a 3D geology model.The method for 3D temperature predictionincorporated heat flow contributions fromconductive and in situ heat production sourcesand honoured known boundary conditions.During the module testing, a simple case of heatadvection, honouring a known internal boundarycondition was proven. Furthermore, the capacityto compare outcomes of model-generatedtemperatures, with observed temperatures andheat flows was demonstrated using real–world 3Dgeology models in the Mount Painter and CooperBasin regions of South Australia.The ability to commence a forward 3Dtemperature run, starting with a non-GeoModeller3D geology model was demonstrated for theCooper Basin, South Australia. This project wascompleted in 2008 and included the provision ofan informative workshop.Alternative carriers for geothermal energy inSA - an investigation of the systems needed togenerate hydrogen and methane from a 50 MWgeothermal demonstration.Dickinson et al. (2009) were commissioned jointlyby the Electricity Supply Industry Planning Counciland PIRSA to assess the system requirements for4161

Australian Geothermal Energy Conference 2009hydrogen production as a potential primaryelectricity load for a geothermal demonstrationpower plant output.The objective of this study was to assess thepossibility that hydrogen, methanol or syntheticmethane production facilities co-located withgeothermal energy production could have anattractive benefit to cost ratio. This studyconcluded that the costs to design and construct a45MW electrolysis plant and an associated 5 MWrefrigeration plant with all of the required pumpsand ancillary equipment, could be economicallymore attractive than using the same geothermalenergy to fuel a 50MW capacity power plant toreach distantly located markets via high voltagetransmission lines. Locating the electrolysis plantnear to existing gas transmission (pipeline)infrastructure suggests that synthetic methanecould have the lowest transport costs.Geothermal Centres of ExcellenceAustralian geothermal research will now be furtherstrengthened through the work of threegeothermal Centres of Excellence. TheQueensland Geothermal Energy Centre ofExcellence (QGECE) was established in 2008with support from the Queensland governmentand the University of Queensland. The WesternAustralia Geothermal Centre of Excellence(WAGCoE), announced in 2008, is a joint venturebetween the CSIRO, Curtin University, theUniversity of Western Australia and thegovernment of Western Australia. Given the goodresults attained with its earlier grants, the SouthAustralian Government announced the firstproject to be funded from a South Australian(state-based) Renewable Energy Fund will be theSouth Australian Centre of Excellence (CoE) forGeothermal Research at the University ofAdelaide.Each centre will have areas of expertise whichcomplement the research and expertise of theother centres.Industry Support for GeothermalResearchThe geothermal research projects to date havebeen completed with support from federal andstate governments and co-contributions or in kindsupport from geothermal companies and researchinstitutes such as universities, GeoscienceAustralia and the CSIRO. Moving forwardgeothermal companies will be expected to makecontributions to collaborative research in order tocontinue to progress geothermal technology.Geodynamics has taken the lead in this endeavorwith an announcement this year that the companyhas committed $5 million over a five year periodfor their Geothermal Technology Plan (GTP)(Geodynamics, 2009). This significant contributionwill leverage private and public sector co-fundingto develop geothermal technology which willbenefit Geodynamics’ Cooper Basin project andthe geothermal industry both nationally andinternationally.ConclusionThe Australian geothermal industry has advancedsignificantly since 2005 and is assisted bysupportive government initiatives, the efforts ofthe Australian Geothermal Energy Associationand the collaborative determination of industrypriorities and research work through theAustralian Geothermal Energy Group.A number of interesting research projects areunderway and have already been completedrelating to topics that will aid the Australiangeothermal industry, with some projects focussedin the area of EGS or HR geothermal systemsand more specifically to adapting to the Australianconditions. All of the outcomes of these researchprojects and their final reports will be madeavailable through the AGEG website.ReferencesAustralian Geothermal Code Committee (AGCC),2008, The Geothermal Reporting Code,Australian Geothermal Energy Group, Adelaide,Australia. Available from:http://www.pir.sa.gov.au/geothermal/ageg/geothermal_reporting_codeBattye, D.L. and Ashman, P.J., 2008, anassessment of Radiological hazards in Hot Rockgeothermal systems, Consulting report2008/2314-1, CHEMENGTEST, The University ofAdelaide, Australia.Backé, G. and Giles, D., 2008, Three Dimensionalgeological modelling of the Adelaide Geosyncline– application to geothermal exploration, FinalReport Tied Grant 4.4 for Australian GeothermalEnergy Group, University of Adelaide, Australia.Cordon, E. and Driscoll, J., 2008, Full Life-CycleWater Requirements for Deep Geothermal EnergyDevelopments in South Australia, Final ReportTied Grant 4.5 for Australian Geothermal EnergyGroup, prepared by Hot Dry Rocks Pty Ltd,Melbourne, Victoria.Dally, B.B., Hew, F.L., Nathan, G.J. and Ashman,P.J., 2008, 163-4, Feasibility of UndergroundCooling for Geothermal Power Plant Applications,in Proceedings of the Sir Mark OliphantInternational Frontiers of Science and TechnologyAustralian Geothermal Energy Conference, editedby Gurgenci, H. and Budd, A.R., GeoscienceAustralia Record 2008/18.Dally, B., Nathan, G., Watson, S., Heath, A.,Howard, C., and Ashman, P., 2009, Feasibility ofUnderground Cooling for Geothermal Powercycles, PIRSA Tied grant 6.2 Final report , theUniversity of Adelaide, Australia.5162

Australian Geothermal Energy Conference 2009Dickinson, R.R., Battye, D.L. Linton, V.M.Ashman, P.J. and Nathan, G.J., 2009, Alternativecarriers for geothermal energy in SA - Aninvestigation of the systems needed to generatehydrogen and methane from a 50 MW geothermaldemonstration. Consulting ReportCHEMENGTEST 2009/2355, the University ofAdelaide, Australia.Geodynamics, 2009, Geodynamics commits $5million towards advancing geothermal technology,ASX Announcement 23 April 2009, available fromhttp://www.geodynamics.com.au/IRM/Company/ShowPage.aspx?CPID=1955&EID=82963744&PageName=Geodynamics commits $5 million togeothermal technologyHerzog, H.J., Tester, J.W. and Frank, M.G., 1997,Economic Analysis of Heat Mining, EnergySources, 19, 19-33.Hunt, S.P. and Morelli, C., 2006, Cooper BasinHDR hazard evaluation: Predictive modelling oflocal stress changes due to HFR geothermalenergy operations in South Australia, Prepared byThe University of Adelaide for South AustralianDepartment of Primary Industries and Resources,University of Adelaide Report Book 2006/16,Adelaide, SA.Intrepid Geophysics, 2008, Forward Prediction ofSpatial Temperature Variation form 3D GeologyModels, Final Report Tied Grant 9.1 for AustralianGeothermal Energy Group, the University ofAdelaide, Adelaide, SA.Morelli, C.P. and Malavazos, M., 2008, Analysisand Management of Seismic Risks AssociatedWith Engineered Geothermal System Operationsin South Australia, in Proceedings of the Sir MarkOliphant International Frontiers of Science andTechnology Australian Geothermal EnergyConference, edited by Gurgenci, H. and Budd,A.R., Geoscience Australia Record 2008/18.Morelli, C.P., 2009, Analysis and Management ofSeismic Risks Associated with EGS operations inSA, Final report for the Department of PrimaryIndustries and Resources, SA, Report book2009/11, Adelaide, SA.6163

Australian Geothermal Energy Conference 2009Geothermal Applications:Development of new state of the art drilling rigs for geothermal useAndy Lukas 1 *, Thomas Steinbrecher 2 and Jörg Uhde 31 AJ Lucas Group Ltd, Level 2, 394 Lane Cove Road, Macquarie Park NSW 2113.2 BAUER Resources Australia Pty. Ltd, P.O. Box 3423, Terrey Hills, NSW 20843 BAUER Resources GmbH, BAUER-Straße 1, DE-86529 Schrobenhausen* Corresponding authorGeothermal energy is the most promising ofrenewable energy sources. In Iceland, forexample, oil and gas for heating purposes havenearly disappeared from the market, with nearly85 % of its heat coming from geothermal energyresources. One of the biggest geothermal energypower plants of the world is called "The Geysers"in the North of the US state California. It providesan electrical power of about 1,400 Megawatts andis therefore able to cover the biggest part of thepower requirement of San Francisco´s municipalarea, which is located 170 km in the South.Further geothermal energy power plants exist inother countries including, Kenya, Turkey, NewZealand, Philippines, Indonesia, Japan, Mexico,El Salvador, the Carribean and the Azores.Australia is experiencing an impressive upswingin the field of Deep Geothermal Energy.Deep Geothermal Energy in GermanyIn Germany 3 regions are especially suited forgaining geothermal energy (Fig. 1):the North-Germany lowlands,the Upper Rhine Graben and the South-German Molasse basin.The first geothermal energy power plant inGermany began operations in Neustadt-Glewe(Mecklenburg-Vorpommern) in November 2003.Hot water of 98 °C from the depth of 2 250 mactivates a turbine. The power plant delivers 230kilowatts of power. Warm water which is incomingafter the power generation and which is about70 °C is fed into the local district heating grid.The Malm Karst of the Southern German / UpperAustrian Molasse basin is one of the mostimportant hydrogeothermal energy reservoirs inCentral Europe. The Malm (Upper Jurassic) whichis present throughout almost the whole of the areais a highly-productive aquifer which dips fromFigure 1: Geothermal Regions of Germanynorth to south to increasing depths andtemperatures.A Production well to a depth of 3,577m sources awater aquifer with a temperature of 127 o C inUnterhaching (Munich). A geothermal energypower plant utilizes these fluids for generatingpower and long-distance heating.Almost 100 applications for exploration ingeothermal energy in Bavaria show the greatinterest in deep geothermal energy in the Molasse(Fig. 2). Even the first interstate geothermalpowerplant at Braunau/Simbach between Austriaand Germany was realised in the Molasse basin.1164

Australian Geothermal Energy Conference 2009Figure 2: Geothermal projects in the Southern German / Upper Austrian Molasse basinMany of these projects are currently being drilltested and many others will soon begin drillingoperations. The whole potential in South Bavariais estimated to be about 500 MW. This isapproximately 5.6 % of the total Bavarian poweruse. 3,500 MW of thermal power would have tobe added into the thermal energy provision fordistrict heating systems provided that there wouldbe sufficient consumers. Further projects areplanned for the Upper Rhine Graben, in the Southof Hesse and in Brandenburg.Expert panel for the seismic risk ofgeothermal projects establishedFollowing an M L =2.7 seismic event occurring onAugust 15th near the site of a geothermal powerplant at Landau (Germany) (Fig. 3), theDepartment of the Environment Rheinland-Pfalzestablished an expert group to analyse andevaluate the seismic risk associated with thegeothermal system. An expert panel with expertswho contribute know-how acquired from similarprojects, e.g. the Basel and the Soultz-sous-Forêts geothermal systems.The Landau project will be allowed to continueoperating while the review panel deliberates. Likeother earthquakes that have been attributed togeothermal plants, the Landau tremor wassudden and brief and was accompanied by asound that in some cases has been likened to asonic boom.There were no injuries and there was no knownstructural damage to buildings in the city. But the2.7 magnitude quake has stoked fears and set offdebate in the state parliament, which subsidizedthe construction of the plant, about the method’ssafety. The officials of the operating companyinitially denied any responsibility for the tremorand continue to dispute the government’s datalinking the project to the quake. The panel will,among other things, have to sort through theFigure 3: Configuration scheme of the Landau geothermalpower plant2165

Australian Geothermal Energy Conference 2009conflicting data presented by the company andgovernment scientists. But some experts in thefield say they worry that projects like the one inGermany, if the managers deny responsibility forinducing earthquakes or play down the effects onpeople’s lives, could damage the reputation ofgeothermal energy, even in highlyenvironmentally conscious areas of the world likeCalifornia or Western Europe.The demonstration project GeneSys -development of new concepts for the direct usegeothermal heatThe GeneSys project of the Federal Institute forGeosciences and Natural Resources (BGR) andthe Leibniz Institute for Applied Geophysics -LIAG aims at the development andimplementation of new concepts for the direct usegeothermal heat. The location Hannover is anexemplary one: Target rocks are the formations ofthe Mid Triassic. In a depth of 3,700 m to 4,000m,these thick formations have a temperature of130°C to 160°C. These rocks are a common typefor northern Germany. In most cases, theirpermeability is not sufficient for the conventionalproduction of hot water. Therefore, an artificialfracture will be created in the bedrock which actsas a heat exchanger. The heat energy of theproduced hot water will be extracted by a surfaceheat exchanger and fed into a heating circuit. Thecooled down water is then going to be injectedinto a shallower rock layer via the same borehole(Fig. 4).Since June 2009 a 4,200 m deep geothermal wellis being drilled at the premises of theGEOZENTURM in the city of Hannover. Largescale artificial fractures are going to be created ata depth of approximately 3,800 m which will actas a heat exchanger. This will be followed by along term test-operation in order to determine theperformance of the geothermal system. Couplingthe geothermal sub-surface system with theGEOZENTRUMs heating system can provideheat energy for several decades. The GeneSysproject Hannover is funded by the FederalMinistry of Economics and Technology.Figure 4: GeneSys project - Schematic illustration ofthe flow regimes at low (left) and of the flowregimes at high (right) injection rate, due tohydromechanical fracture opening.The new Bauer Deep Drilling Rigs TBABauer Maschinen are developing new deepdrilling rigs which will go into operation betweenthe middle of 2009 and the middle of 2010. Therig family will consist of three types of TBA rigs.Type Hook Load Operating Weight Power[tonnes] [tonnes] [MW]TBA 300 250 - 400 500 - 600 3 - 4TBA 200 150 - 220 200 1.5 - 2TBA 100 60 - 120 100 1.5The rigs of the TBA 300 Series are particularlywell suited for the installation of deep geothermalboreholes, including directional ones, to around5000 metres. Projects of this type are to be foundin Germany, specifically south of Munich, inSwitzerland, Austria and the USA, althoughimportant projects are also under development inAustralia.Depending on the geographical areas and theprevailing deposits, Bauer deep drilling rigs aresuited for the exploration of onshore oil and gasdeposits. The size and type of drilling rig for aparticular drilling project is determined by theintended drilling depth, the degree of intentionaldeviation and also the borehole diameter.The highly mobile rigs of the TBA 100 Series areideally suited for all operations associated with themaintenance or overhaul of existing extractionwells. Due to their modular construction, theworkover rigs can always be tailored to the exactneeds of the client.By attaching a top drive, the workover rig can alsobe used for drilling operations.TBA 300The TBA 300 (Fig. 5) is a high performancedrilling rig that meets the most modern demands.Due to its patented and unique hybrid drive, thedesign of the rig is optimised for the two mostimportant work processes during deep drillingoperations:Rapid installation and extraction of the drillstring; the installed triple cylinder facilitatestrip times up to 400m per hour for maximumdrill string loads up to 120 tonnes.High-performance installation of drill casingswith maximum loads up to 280 tonnes, forwhich the 8-part main hydraulic winch isoptimised.3166

Australian Geothermal Energy Conference 2009cylinders operated from the control station. Then,only the plug-in connections have to be made forthe hydraulic hoses and electric cables.Figure 5: TBA 300The combination of both systems – fast trip timesfor smaller loads as well as slow installation of drillcasings for high loads - ensures energy savings ofaround 30% over conventional systems, whereeither the hydraulic crowd cylinders or the winchdrives have to be designed for both load cases.The BHS 400 pipe handling system mounted onthe side of the deep drilling rig enables drill pipesof all kinds to be installed automatically at speedsup to 400 m per hour without manual intervention.Safety is of utmost importance during all operatingprocedures on the drilling rigs of the TBA Series.This applies in particular to the trip-in and trip-outprocesses. The drill pipes, which are stored safelyon the drill site in a horizontal position, are placeddirectly in the drill axis by the manipulator.During the development of the drilling rigs, it wasimportant to optimise and thus minimise thesetting up and transportation processes. Allcomponents are fitted with container cornercastings and their dimensions also correspondwith conventional 20 or 40 ft. containers, enablingfast and secure transportation by standardcontainer lorries. Only a few of these transportsexceed normal heights or weights over 20 tonnes(Fig. 6).To accelerate rig assembly with a greater degreeof safety, the heavy duty pins, used for examplefor connecting the mast sections, are no longerinserted by hand, but with the use of hydraulicFigure 6: Container-size componentsAs the mast head and the main winch aretransported together, the main hoist rope with adiameter of 40mm can always remain reeved.This reduces rigging and de-rigging times, andsignificantly increases safety by avoiding thisdifficult, and at times dangerous, operation.A further significant innovation is the Bauer topdrive TDK 65. Generally operated hydraulically, itcan also be equipped with an electric motor at theclient’s request.With its installed power of 530 kW, the Bauer topdrive develops a torque of up to 65 kNm and aspeed of 180 rpm. The top drive is designed for a3¼“ flushing head with pressures of up to 5000psi. When making connections, the variation inlength of drill pipe is allowed for by way ofhydraulic cylinders. Commercial elevators withbreak-out clamps up to 100 kNm breaking torquecan be used for installing the drill string.In order to introduce a new level of safety in thisarea as well, all Bauer top drives can alternativelybe supplied with a clamping and breaking devicefor drill pipes up to 8” and casings up to 13 3/8”diameter.For operation of the drilling rig, up to threeelectrically operated Bauer mud pumps, each withan input power of 900 kW, a maximum deliveryrate of 2,450 l/min and a maximum pressure of5000 psi can be connected and controlled (Fig. 8).These pumps are also fitted into 20” containerframes and are, therefore, easy to transport.4167

Australian Geothermal Energy Conference 2009Figure 7: Two mud pumps at the rear of the TBA 300TBA 200As for the TBA 300, the advantages andinnovations of the TBA series are also integratedin the TBA 200 (Fig. 8):Hybrid drive with crowd cylinders for running indrill pipes and winch pull-down for installing drillcasings with corresponding energy saving. Thediesel driven power pack with an output of 403kW serves also as counterweight. Due to thecompact design of the entire unit, which ismounted on a frame complete with winch andmast, it is possible to rig or de-rig the drillextremely quickly within approximately one day.The telescopic mast and all other rigging functionsare powered via a small integrated power packeven before the main power pack is connected.The TDK 35 can also be equipped with elevator oroptionally with clamping head technology.The pipe handling system mounted on the rig caneither be the BHS 400 or the conventional V-DoorSystem with front loading.The VFD container and driller’s control cabin aresimilar to those on the TBA 300. Once again, upto three mud pumps can be connected andoperated, although only two mud pumps aregenerally required for the boreholes of a TBA 200.Workover rigsThe design concept of the TBA 60 to 120 wasalso adopted for the workover rig with the resultthat by simply adding a rotary table and adaptingthe peripheral equipment, the same rig can carryout both functions – workover or drillingoperations.Mud treatment plantsBauer Maschinen is also developing, jointly withits subsidiary MAT, the entire mud treatment andseparation plant (Fig. 9).Figure 9: Mud treatment plant TSA 5000Apart from the conventional technology of slurryregeneration by way of fine screens andcentrifuges (as for example in the TSA 5000 withthe capacity of 5000 l/min) the latest treatmentand separation systems which combine screens,cyclones and centrifuges are also being built. Thisincludes the TSA 4000 with a capacity of 4000l/min. These latest types of plant have anextremely high output capacity with minimal spacerequirements.ConclusionDrilling for geothermal energy deposits is basedon the same technology which is used in the oiland gas industry. The mast, hoisting system, mudpumps (including mud circuit) and the blow-outpreventerare the main components of the drillingrigs. Today the Top-drive-Rotary-systems areapplied in modern deep drilling rigs. The BAUERdeep drilling rigs are designed both for theemerging markets for the development ofgeothermal resources and conventional oil andgas drilling.Figure 8: Deep drilling rig TBA 2005168

Australian Geothermal Energy Conference 2009Power Generation Potential of SC-CO 2 Thermosiphon for EngineeredGeothermal SystemsAlvin I. Remoroza*, Elham Doroodchi, Behdad Moghtaderi1 Priority Research Centre for Energy, School of Engineering (Chemical Eng.), Faculty of Engineering & BuiltEnvironment, University of NewcastleUniversity Drive, Callaghan, NSW 2308, Australia* Corresponding author: Alvin.Remoroza@studentmail.newcastle.edu.auNumerical modelling was conducted to assessthermodynamic properties and power generationpotential of SC-CO 2 thermosiphon for EngineeredGeothermal Systems (EGS) and compared withH 2 O-based EGS with Organic Rankine Cycle(ORC).Keywords: SC-CO 2 thermosiphon, EnhancedGeothermal System, Hot Dry RockFindings from the SimulationThe methodology and reference data (Table 1)adopted in this paper is similar to that used byAtrens et al (2009) for computing the overall flowin an EGS. The calculations are divided into twoparts, injection and production sections. Theinjection calculations include fluid well-bore flowfrom the surface to the bottom of the injection welland fluid flow through the reservoir. Theproduction calculations only include fluid well-boreflow from the bottom of the production well to thesurface.The following sets of equations with theassumptions of adiabatic flow and negligiblekinetic energy at the wellbore, and reservoir Darcyflow of constant cross-sectional area (singlechannel flow) with linearly increasing temperaturewere used in the injection calculation;Pinj Pres Pzf , wellV Pf , res gzzm 22P f , well f D 2 f 82 5D 6.9 1.8log f Re 3.7 D P f , resmL A1.112In the production section, the adiabatic flowdefines the following relationship,Pprod Pres gz Pf, wellWhere V = fluid velocitym = mass flow ratef = friction factor = densityRe VD4m D = pipe roughnessD = pipe diameterg = gravitational constant, 9.81 m/s 2 = homogenous permeabilityA = swept area of the fluid flow in thereservoirPinj= injection pressurePres= reservoir pressure at the bottom ofthe production well = frictional losses at the well = reservoir pressure lossesPf , wellPf , res L = incremental reservoir length z = incremental vertical distanceThe total exergy generated from SC-CO 2thermosiphon EGS was dominated by exergyassociated with change in enthalpy. The specificexergy can be expressed asX HWhereh h T S )0 0( S0XH= exergy associated with change inenthalpyh = specific enthalpyS = specific entropyT = temperature in KelvinThe subscript 0 denotes initial conditions.Numerical simulations were carried out usingEngineering Equation Solver (EES). EEScalculates thermodynamic properties for carbondioxide using the fundamental equation of statedeveloped by Span and Wagner (1996) andviscosity and thermal conductivity based on thework by Vesovic et al (1990). EES givesthermodynamic properties of water using the 19951169

Australian Geothermal Energy Conference 2009Formulation for the Thermodynamic Properties ofOrdinary Water Substance for General andScientific Use issued by The InternationalAssociation for the Properties of Water and Steam(IAPWS).Table 1: Reference values used in the exergy analysisParameter Values(Artens, 2009)Values(this study)Reservoir Length 1000 m 1000 mReservoir 225 0 C 225 0 CTemperatureReinjection 25 0 C 25 0 CTemperaturekA (inverse 2.1E-19 m 4 2.1E-19 m 4impedance)ReservoirPressure, PresHydrostatic(49.05MPa)Hydrostatic(49.05MPa)Wellbore 400 micrometer 400 and 40Roughness ( )micrometerWellbore 0.2315 0.2315Diameter, DReferenceTemperature25 0 C 25 0 CEffect of Pipe RoughnessPipe frictional losses at the injection well arehigher for SC-CO 2 than for H 2 O because piperoughness affects CO 2 mass flow rates more thanit affect H 2 O mass flow (Figures 1 and 2).higher kinematic viscosity (μ/ρ) at the given T-Pdomain in the reservoir (plots not shown).Figure 2: Total exergy provided by SC-CO2 and water atdifferent injection pressures and roughness values.Pressure and Temperature Well Profile of theInjection WellFigure 3: Temperature (left plots, lower X-axis) and pressure(right plots, upper X-axis) well profile at the SC-CO2 injectionwell (Note: pipe roughness used is 40 microns).Figure 1: Injectivity of SC-CO2 and water at different injectionpressures and roughness values.Bottomhole pressures at the injection well withH 2 O circulation are, in theory, greater than withSC-CO 2 circulation because (a) H 2 O has higherdensity than CO 2 at the same pressuretemperatureconditions, and (b) CO 2 has higherpipe frictional losses than water for the samemass flow rate. Reservoir pressure losses aresignificantly higher for H 2 O than SC-CO 2thermosiphon based system because of H 2 O’sFor SC-CO 2 adiabatic flow at the injection well,the SC-CO 2 temperature at the bottom may behigher (at lower injection pressure) or lower (athigher injection pressure) than the injectiontemperature (Figure 3). Specific enthalpy of SC-CO 2 is affected by temperature and pressureswhereas specific enthalpy of H 2 O is affected bytemperature and only slightly by pressure(Pruess; 2006, 2008).Effect of Injection TemperatureInjection temperature affects SC-CO 2 and H 2 O insomewhat different ways (Figure 4); For SC-CO 2 , lowering the injectiontemperature increases the pipe frictionaland reservoir losses due to increased2170

Australian Geothermal Energy Conference 2009density and viscosity. However, the gainin the pressure head (i.e. increase inbottomhole pressure) due to increaseddensity is far more than the total lossesresulting in net overall gain in buoyantforce driving natural convection. For H 2 O, decreasing the injectiontemperature actually decreases the pipefrictional losses, slightly increasesbottomhole pressure and increasesreservoir pressure losses. Overall,reservoir losses are greater than thecombined head gain and less pipefrictional losses resulting in slightdecrease in injectivity.Single Channel versus Radial Reservoir FlowRadial pressure distribution in the reservoir froman injection well can be described in the followingequationVP( r)ln( r)2KLRWhere = absolute viscosity = volumetric flow rate of theV m fluidK = homogenous permeabilityLR= reservoir depth or thicknessThe pressure difference between the injection wellface, rWand the production well located atdistance, rR(equals 1000 m in our previousassumptions) can be approximated using thefollowing equation Pf , well * m2* * * K * LRrln(rWR)Figure 4: Effect of injection temperature on injectivity.Figure 6: Effect of reservoir flow model choice on injectivity.Figure 5: Effect of reinjection pressure and temperature ontotal exergy.Whenever reinjection temperature of 15 0 C or lessare possible, SC-CO 2 thermosiphon based EGScan have slightly higher thermal heat extractionefficiency at injection pressures lower than ~13.0MPa (Figure 5).Figure 7: Effect of reservoir flow model choice in total exergyof a SC-CO2 thermosiphon EGS.Comparing single channel (constant crosssectionalarea, i.e. pipe flow) and radial reservoirflow showed that radial reservoir flow gives higherinjectivity and consequently improved total exergy(Figures 6 and 7). This behaviour is due to lower3171

Australian Geothermal Energy Conference 2009reservoir pressure losses in radial reservoir flowcompared to single channel flow.Sensitivity of Exergy to Well-ConfigurationWell configuration (ratio of the number of injectionto production wells) does not significantly affectthe injectivity of the fluid but it affects theperformance of the production wells. Highernumber of production wells lowers the frictionallosses because of lower mass flow rates in eachwell since the mass flow rate of the circulatingfluid is equally divided by the number ofproduction wells. For single channel reservoirflow, 1 injection to 2 production well ratio gives theoptimum total exergy while the five-spot wellconfiguration (1 injection to 4 production wellratio) gives the optimum total exergy for radialreservoir flow. On the basis of per drilled well(sum of injection and production wells), thedoublet configuration (1 injection to 1 productionwell) gives the highest total exergy both for singlechannel and radial reservoir flow (Figures 8 and9).H 2 O-based EGS with Organic Rankine Cycleversus SC-CO 2 Thermosiphon Power CycleAnalysisH 2 O based EGS can not be used in athermosiphon power cycle since the productionpressure is always lower than the injectionpressure.In SC-CO 2 power cycle analysis, the grosspotential electrical power is calculated based onCO 2 isentropic expansion in the turbine with 85%turbine efficiency (Figure 10). Temperatureentropydiagram of a SC-CO 2 power cycle atinjection pressure of 7.5 MPa is given in Figure11. It shows that super-critical CO 2 exists in allstages of the process. Auxiliary powerrequirement is not included in the calculations, i.e.power used in cooling tower, etc. It is assumedthat no pump will be used in the SC-CO 2thermosiphon power cycle.Figure 8: Effect of well configuration on total exergy of SC-CO2 on single channel reservoir flow.Figure 10: Schematic Diagram of a SC-CO2 ThermosiphonPower Cycle.Figure 9: Effect of well configuration on total exergy of SC-CO2 on radial reservoir flow.It can be deduced that if five-spot wellconfigurationis used, the radial reservoir flowmodel would be more appropriate to implement innumerical modelling. Doublet and 1 injection to 2production well configurations would commandthe implementation of single channel reservoirflow modelling. Based on the results, doubletconfiguration is the most efficient in extractingheat based on the total exergy per drilled well.Figure 11 Temperature-entropy diagram of SC-CO2thermosiphon power cycle.4172

Australian Geothermal Energy Conference 2009Power cycle analysis of H 2 O-based EGS ORC(Figure 12) assumes the use of isopentane as thesecondary fluid with circulating pump pressure of2.793 MPa (T sat = 175 0 C) and condenser pressureof 101.325 kPa (atmospheric condition). Thiscirculation pump pressure is chosen so thatexistence of two-phase is avoided duringexpansion at the turbine while giving themaximum power (Figure 13). The pump isassumed to be 75% efficient and isentropic.The power generated from H 2 O based EGS withORC is calculated as turbine power minus pumppower for H 2 O injection and circulation of theworking fluid and does not include power used inthe cooling tower and other auxiliary equipment.W WturbineWinjectionWORC,circulationincreases with injection pressure whereas for SC-CO 2 thermosiphon EGS the relationship isparabolic (see Figure 14).Figure 14: Potential electricity generation comparison of aSC-CO2 thermosiphon and H2O based EGS with ORC(assumes 85% turbine efficiency and 75% pump efficiency).Figure 12: Schematic diagram of binary organic rankine cyclefor H2O based EGS.Figure 13: Temperature-entropy diagram of ORC withIsopentane as working fluid.Power cycle analysis showed that H 2 O basedEGS is better in mining heat and transferring thatheat in secondary fluids for electrical powergeneration than SC-CO 2 thermosiphon EGS (itmaybe different for pump CO 2 EGS because ofpossible higher injectivity). The optimum powerthat can be generated from SC-CO 2 thermosiphonis 8.6 MW at 9.5 MPa injection pressure at radialreservoir flow model while for H 2 O-based EGSwith ORC, the electrical power potential at thesame conditions is 25.8 MW. For single channelreservoir flow model, the optimum electrical powerpotential of a SC-CO 2 thermosiphon is 6.3 MWwhile for H 2 O-based EGS is 9.4 MW. Electricalpower potential of H 2 O-based EGS linearlyThe less number of equipment of a SC-CO 2thermosiphon power cycle (no injection pump andcirculation pump for secondary fluid) and relativeinertness of CO 2 with regards to rock-interactionand associated mineral dissolution, precipitationand fouling of equipment warrant furtherevaluation. However, SC-CO 2 thermosiphonpower cycle will require research anddevelopment of SC-CO 2 turbine.Sensitivity of Exergy to Reservoir DepthThe performance of SC-CO 2 thermosiphon EGSon shallower hot dry rock geothermal resourcewas also investigated. The numerical simulationused single channel reservoir flow model anddoublet well configuration, the same resourcetemperature of 225 0 C and injection temperature of25 0 C, and changing well depth to 3000 m andassuming reservoir pressure at the producer wellto 29.43MPa (assumes hydrostatic pressure).The over-all effect of shallower reservoir depth ofthe HDR geothermal resource at SC-CO 2thermosiphon EGS were lower total exergy andlower electricity generation potential due to lowerproduction pressures (Figures 15 and 16).However, SC-CO 2 injectivity increased atshallower HDR geothermal resource depth. Thetotal exergy of H 2 O-based EGS increased atdeeper reservoir depth but the electricitygeneration potential were similar.5173

Australian Geothermal Energy Conference 2009Figure 15: Effect of reservoir depth on SC- CO2thermosiphon on electricity generation potential (assumes85% turbine efficiency).Figure 16: Effect of reservoir depth on SC-CO2 thermosiphonon injectivity and production pressure.RecommendationsThe less complicated design of CS-CO 2thermosiphon EGS and relative inertness of CO 2with regards to rock-interaction and associatedmineral dissolution, precipitation and fouling ofequipment warrant further economic andgeochemical evaluation. Research anddevelopment of high efficiency SC-CO 2 turbine isalso necessary to prove the viability of thissystem. The use of pump for SC-CO 2 circulationin EGS may also be investigated.Economic and thermodynamic analyses over thefull life of SC-CO 2 and H 2 O based EGS should becarried out to compare their overall environmentaland economic performances. One can determinethe total amount of CO 2 that will be created andsequestered plus the amount of conventional CO 2emissions that will be avoided during the entirelife cycle of CS-CO 2 thermosiphon and H 2 O EGSprojects. It appears from this study that H 2 Obased EGS can generate more electrical powerthan CS-CO 2 thermosiphon EGS.The amount of CO 2 that may be sequestered andstored in a SC-CO 2 thermosiphon EGS is only anadded ancillary benefit since the amount isnegligible compared to the current total CO 2emission. Another concern will be the issue ofpossible CO 2 leakage in EGS.This paper merely present the results of athermodynamic and power cycle analysis, it doesnot prove or disprove the viability of using SC-CO 2 circulation EGS.ReferencesAtrens, A. D., Gurgenci, h. and Rudolph, V.(2008). Carbon Dioxide ThermosiphonOptimisation, in: Gurgenci, H. and Budd, A.R.(eds.), Proceedings of the Sir Mark OliphantInternational Frontiers of Science and TechnologyAustralian Geothermal Energy Conference,Geoscience Australia, Record 2008/12,149-152.Atrens, A. D., H. Gurgenci, and V. Rudolph(2009). CO 2 Thermosiphon for CompetitiveGeothermal Power Generation. Energy & Fuels23(1): 553-557.Atrens, A. D., H. Gurgenci, and V. Rudolph(2009). EXERGY ANALYSIS OF A CO 2THERMOSIPHON. PROCEEDINGS, Thirty-Fourth Workshop on Geothermal ReservoirEngineering, Stanford University, Stanford,California.Pruess, K. (2006). Enhanced geothermal systems(EGS) using CO 2 as working fluid - A novelapproach for generating renewable energy withsimultaneous sequestration of carbon.Geothermics 35(4): 351-367.Pruess, K. (2008). On production behavior ofenhanced geothermal systems with CO 2 asworking fluid. Energy Conversion & Management49(6): 1446-1454.Pruess, K. and M. Azaroual (2006). On thefeasibility of using supercritical CO 2 as heattransmission fluid in an engineered hot dry rockgeothermal system. PROCEEDINGS, Thirty-FirstWorkshop on Geothermal Reservoir Engineering,Stanford University, Stanford, California.Span, R. and W. Wagner (1996). A New Equationof State for Carbon Dioxide Covering the FluidRegion from the Triple-Point Temperature to 1100K at Pressures up to 800 MPa. J. Phys. Chem.Ref. Data 25: 1509-96.Vesovic, V., W. A. Wakeham, G. A. Olchowy, J.V. Sengers, J. T. R. Watson, and J. Millat (1990).The Transport Properties of Carbon Dioxide. J.Phys. Chem Ref. Data 19(3): 763-808.6174

Australian Geothermal Energy Conference 2009Modelling Reservoir Behaviour during StimulationTests at Habanero #1Baotang Shen *CSIRO Exploration and MiningPO Box 883, Kenmore, QLD 4069, Australiabaotang.shen@csiro.auThis study was to characterise the undergroundheat-exchange reservoir at Habanero #1 welloperated by Geodynamics Ltd. Several threedimensionalcoupled mechanical/fluid 3DECmodels have been studied to understand the rockmass reaction to the stimulation tests that wereconducted in November-December, 2003. Themicroseismic monitoring results by TohokuUniversity and the falloff test results on 12December 2003 were used to estimate some keyinput parameters for the numerical modelling. Theseismic results were also used as benchmarks formodel verification tests. Different fractureorientations, rock mechanical properties and fluidproperties were used in this study to investigatethe effect of varying these parameters on rockmass response to fluid injection. The studyprovided an improved understanding of thefracture system that was activated during thestimulation tests.BackgroundA program is being undertaken by GeodynamicsLtd to develop the Hot Fractured Rock (HFR)geothermal energy resource in the Cooper Basin.Habanero #1 was the first well drilled in thisprogram and it reached a depth of over 4,400 mwith a bottom hole temperature of over 240C.Following the completion of the drilling,stimulation of the reservoir was conducted duringNovember-December 2003 by injecting highpressure water into the fractured granite toactivate the fractures and hence increase thepermeability of the heat exchange reservoir. Theresponse of the reservoir to injection has beenmonitored by Tohoku University using advancedmicroseismic monitoring systems. The locationand timing of the seismicity associated withfracture movement were then mapped.Understanding the characteristics of the heatexchange reservoir is the key for the design ofongoing operations. Because of the depth to thegranite, there are very limited measurementtechniques available that can be used tocharacterize the reservoir, apart from pressureand injection rate monitoring and microseismicmonitoring. Numerical modelling hence becomesan important tool for this purpose.The aim of the modelling is to provideinterpretation and understanding of the reservoirbehaviour during the stimulation tests, which willprovide guidelines for future circulation tests.Numerical modelsThe numerical models use a three-dimensionaldistinct element code, 3DEC, that can simulatecoupled geomechanical-fluid processes and isespecially suited to simulating coupled fluid flowand deformation in fractured rock masses (Itasca,2003). 3DEC has the following main features: It simulates the joints/fractures explicitly. The fluid flow in the rock mass is consideredto occur only in the rock fractures. The coupled process between fluid flow androck fracture deformation is simulated.In the granitic rock mass targeted for the HFRstimulation and circulation operations, fluid flow isbelieved to occur mostly in the fractures. Intactrock porosity and permeability is low and rockmatrix flow is assumed to be insignificant. In thiscase, 3DEC is considered to be suitable andhence was chosen for this study.Based on the seismic monitoring data, twodifferent fracture patterns have been interpretedby different research teams. One interpretationshowed that there are four shallow dipping majorfractures, see Figure 1 (Wyborn, 2004, personalcommunication), whereas the other consideredthere is only one large fracture. The firstinterpretation has been used in this study.SW fractures:Dip direction S58WDip angle 28 degH1 WellboreSeismic eventsNE fracture:Dip direction N45EDip angle 10 degFigure 1. The major fractures delineated from the seismicmonitoring data (based on one of the two interpretations).Fractures are shown in three dimensions with a viewingdirection from SE to NW.The four fractures considered may be large scaledistinct fractures or they may represent fracturezones with some thickness (say, less than 150m).The limited accuracy on the location of theseismic events, and the fact that seismicity canoccur both on and off the major fracture planes,does not permit a definitive location of the fractureplanes.1175

Australian Geothermal Energy Conference 2009The granite section of the Habanero #1 well waslogged for natural fractures. There are threedominant fracture sets:Set 1 – dip = 28, dip direction = 238Set 2 – dip = 75, dip direction = 230Set 3 – dip = 35, dip direction = 155These fracture sets are considered to be smallerscale fractures intersecting the four majorfractures in the reservoir, as shown in Figure 1.The 3DEC model was constructed with an overalldimension of 4000m (E-W) x 4000m (N-S) x1800m (depth), see Figure 2.NMain fractures (SW)barrierFracture set 2 (75/230)barrierH1H1Fracture (90/290)Fracture set 1 (28/238)Main fracture (NE)Figure 2. 3DEC model. Top figure – plan view of a 3DECmodel (one block was hidden to show the detailed zone).Bottom figure – view of the detailed zone only.A detailed region is defined as shown in the lowerpicture of Figure 2. This region is approximately thezone where seismic events have been detectedduring stimulation operations. The main subhorizontalfractures delineated in Figure 1 definethe upper and lower border of the detailed region.Note that in this model, the north-east trendingsub-horizontal fracture in Figure 1 is considered tobe a fracture zone with a thickness ofapproximately 150m, bounded by two 10 dippingfractures at the top and bottom.The model shown in Figure 2 also includes twofracture sets with spacing of 150m. The 28/238fracture set is included in the north-east part ofthe model, and the 75/230 fracture set is in thesouth-west part. One vertical fracture (90/290) isalso included in the model to simulate a hydraulicbarrier observed in the microseismic data. All thefracture sets are confined to the detailed region ofthe model.The numerical modelling requires detailedmechanical and fluid properties of the rock massand fluid to be specified. Due to the lack ofdirectly measured data, most of the propertiesused were estimated based on existingknowledge and past studies for granitic rock(Barton, 1986; Evans, 2004; Choi, 2004, Hillis etal., 1997; Jeffrey, 2004; Shen, 2004). The valuesof the properties used in this study are listedbelow: Young’s modulus = 65GPa Poisson’s ratio = 0.25 Friction angle = 33 Cohesion = 0 Dilation = 5 Maximum aperture = 93 m Residual aperture = 50 m Fluid density = 990 kg/m 3 Dynamic viscosity = 0.1510 -3 Pa sec Bulk modulus = 810 5 Pa Pore pressure at a depth of 4250m = 74MPaWellbore storage = 210 -8 m 3 /Pa In-situ stress at a depth of 4250m: H = 149MPa (N85E) h = 112MPa (N5W) v = 98MPaModel resultsSeveral models with different fracture geometriesand input parameters were used in this study. Themodel which produced the best match to themeasurement data is discussed in this section.The best-fit model is judged by matching thenumerical results with the following data: Falloff test data on 12 Dec 2003. Seismic results interpreted by TohokuUniversityMatching the falloff test dataThe injection-falloff test is a hydraulic testconducted by injecting into the reservoir at aconstant rate which produces an associatedincrease in pressure. The injection is thenstopped and the well is shut in with the pressuredecline after shut in monitored. This is a standardtest method to measure permeability of thereservoir. Longer injection and falloff periods2176

Australian Geothermal Energy Conference 2009result in measurement of permeability deeper intothe reservoir.An injection-falloff test was conducted on 12December, 2003 after the completion ofstimulation at Habanero #1. At that time, seismicactivities in the reservoir had all ceased whichindicated that fracture slip was no longeroccurring. The bottom-hole pressure wasincreased from the in-situ pore pressure (74MPa)to 84.5MPa within about 2 hours by injectingwater. Then the well was shut in and pressuredropped back to 74.5MPa within 3 hours. Themeasured pressure variation is shown in Figure 3.To match the injection-falloff test results, threekey input parameters in the numerical model wereadjusted: They are:o Bulk modulus of the fluido Fracture maximum aperture.o Wellbore storage.The fluid bulk modulus was found to affect theslope of the pressure build-up curve and the falloffcurve; the maximum fracture aperture affects themagnitude of the peak pressure; and the wellborestorage affects the slope of the falloff curve.Botto m-h ole pressure (MPa)8684828078767472700 .0 0 1.00 2.00 3 .0 0 4.00 5 .00 6 .0 0 7.00 8 .00Tim e (hours)m e asu re m ent3DEC model8.60E+018.40E+018.20E+018.00E+017.80E+017.60E+017.40E+017.20E+017.00E+01Figure 3. Matching of the numerical results with themeasurement data for the falloff test.The best match was obtained with an apparentfluid bulk modulus of 810 5 Pa for the reservoir,maximum fracture aperture of 93 m and wellborestorage of 210 -8 m 3 /Pa, see Figure 3.The resultant fluid bulk modulus for the reservoiris much lower than that of water at roomtemperature. The low bulk modulus required forthe match is thought to be a result of the 3DECmodel neglecting fluid storage in the rock matrix.The maximum fracture hydraulic aperture of 93m is equivalent to a permeability-height product(i.e. kh) of 200 mdm to the south-west of theborehole with three parallel main fractures. Thisagrees with the finding by Evens (2004) that “thefar-field kh is 100 mdm or more”.The wellbore storage of 210 -8 m 3 /Pa is based ona wellbore volume of 41 m 3 and fluid bulkmodulus of 2.0GPa. The 3DEC models did notinclude the wellbore therefore the effect ofwellbore storage had to be considered as aseparate effect.Matching the seismicity monitoring dataThe numerical model as shown in Figure 2 wasused to investigate the fracture activation duringstimulation process. The actual injection operationwas done in 4 stages as shown in Figure 4. The 1 ststage was the fracture initiation stage, and the2 nd -4 th stage are actual fracture stimulation.79.5 l/sFracture initiationStimulation(1) (2) (3)06/Nov 11 16 21 26 01/Dec 06 11 16 21Figure 4. Summary of injection record (after Davidson,2004).After completion of the 4 stages of initiation andstimulation in the numerical model, the modelresults were extracted and processed. Themodelled evolution process of fracture sliding wascompared with that of microseismic events afterinitiation stage and stimulation stage as shown inFigure 5 and Figure 6. In the figures, the black dotpoints indicate the locations of the seismic eventsobtained from the microseismic monitoring. Thered dot points represent the centre of a fractureelement which has exceeded its shear strength(i.e. is sliding). Both the measured and predictedresults are the cumulative results.In the fracture initiation stage (Figure 5), themodelled fracture sliding in general matched wellthe microseismic records. The model resultshowever did not match the isolated cluster ofseismic events in the southern side of thewellbore. The run-away seismic cluster could becaused by localised stress concentration or highlyconductive fractures in the rock mass. The modeldid not include any of these special features.In the stimulation stages (Figure 6), the modelledfracture sliding matched reasonably well with theseismic records, both in the horizontal plan viewand the cross section view.3177

Australian Geothermal Energy Conference 2009(Plan view)Initiation2000Events3D E C15001000wellbore5000-2000 -1500 -1000 -500 0 500 1000 1500 2000-500-1000-1500(South – North section)Ini tia tion-2000-2000 -1500 -1000 -500 0 500 1000 1500 2000Events3DEC-2500wellbore-3000-3500-4000-4500-5000-5500Injection pressureThe model-predicted time history of bottom-holepressure of all phases is shown in Figure 7. Ingeneral, the predicted injection pressure showsthe same trend as that recorded during the actualstimulation tests (see Figure 4). As the injectionflow rate increases from 5 bpm (barrel per minute)to 9 bpm, the injection pressure increasesaccordingly.-2000-6000150Initiation-2000-2000 -1500 -1000 -500 0 500 1000 1500 2000Events3DEC-2500-3000-3500-4000-4500-5000-5500-6000(West –East section)wellboreFigure 5. Comparison of the predicted fracture sliding andmicroseismic monitoring events during fracture initiation.Events3DEC(plan view)Stimulation 3200015001000wellbore5000-2000 -1500 -1000 -500 0 500 1000 1500 2000-500-1000-1500-2000Stimulation 3-2000-2000 -1500 -1000 -500 0 500 1000 1500 2000Events3DEC-2500-3000-3500-4000-4500-5000-5500-6000wellbore(West –East section)(South – North section)Stimulation 3-2000-2000 -1500 -1000 -500 0 500 1000 1500 2000Events3DECwellbore2kmScaleFigure 6. Comparison of the predicted fracture sliding andmicroseismic monitoring events during stimulation phase 3.Because the main fractures in the 3DEC modelwere bounded by the border of the seismic events(except in the northern part where the mainfractures extend to the model boundary), it is notsurprising that the final locations of modelledfracture sliding matched well with that of theseismic events. However, a good match has alsobeen obtained during the different stages and it islikely that the model is accurately calibrated(although it is possible that other combinations offracture geometry and input parameters wouldproduce similar matches.)-2500-3000-3500-4000-4500-5000-5500-60002kmScaleInjection pressure (MPa)14013012011010090807060FractureinitiationStimulation 1(flowrate=5bpm)Stimulation 2(flowrate=7bpm)500 2 4 6 8 10 12 14Injection Time (days)Stimulation 3(flowrate=9bpm)Figure 7. Predicted injection pressure at the wellbore usingthe 3DEC model.The predicted magnitude of the injection pressureat the bottom of the wellbore, however, is higherthan that calculated using the measured surfacepump pressure (with consideration of pressureloss). At the later stage of the injection(stimulation stages 2 and 3), the predictedbottom-hole pressure is actually higher than theoverburden stress. Two factors in the numericalmodel may have contributed to this: (1) Themodel has fixed boundaries on the top and bottomat a distance of 900m from the injection section.The fixed boundaries may have restricted theopening displacement of sub-horizontal fracturesand hence resulted in higher fluid pressure. (2)The current 3DEC version only allows a singlemaximum fracture aperture defined for both shearand open joints. The maximum aperture of 93mused in the model may not be suitable for openjoints although it is reasonable for shear joints.Figure 8 shows the predicted fluid pressuredistribution in the main fractures when theinjection flow rate is 9 bpm at the end of thestimulation tests. The fluid pressure in theimmediate vicinity of the injection hole is over100MPa. Fracture in this area would be openedby such pressure. The pressure dropped below100MPa at about 50m away from the injectionhole, implying fracture shearing rather thanopening takes place beyond this distance.Measured pressures were, however, close to orbelow the fracturing opening pressure for allinjection periods.4178

Australian Geothermal Energy Conference 2009the observed seismicity, although they mayhave some effect on fluid flow.The in-situ stresses inferred from backanalysisof the borehole breakout data arebelieved to be correct at Habanero #1 site(Shen, 2004). With the horizontal stressesbeing the major and intermediate principalstresses, the most favourable fractureorientation for sliding is about 28. Thisagrees well with observation, particularly inthe south-west of the wellbore.Figure 8. Fluid pressure distribution in the sub-horizontalmain fractures at the end of the stimulation test.Discussion and ConclusionsThe study was the first step towardcharacterisation of the underground heatexchangereservoir in the vicinity of the Habanero#1 well. The modelling results improved ourunderstanding of the fracture system that hasbeen activated during the stimulation tests. Thekey findings from this study are: To the south-west of the wellbore, theobserved seismicity was likely due to fracturesliding along three large parallel fractures witha favourable dip (about 25 - 30). Thesefractures were predicted to slide during theearly stage of the stimulation tests, agreeingwell with the seismic monitoring results.To the north and north-east of the wellbore,the observed seismicity was possibly causedby the shear movement in many relativelysmall fractures in a fracture set with aprobable dip (dip/dip direction=28/238). Theapparent main fracture with a dip of 10,delineated from the seismic data, is unlikely tohave any major contribution to the seismicityand it was predicted to remain inactive duringstimulation tests. This apparent fracture maynot exist in the form of a single explicitfracture. The fracture permeability in the stimulatedzone in south-west is estimated to be around200mdm (i.e. fracture aperture = 93m) afterstimulation.Fracture sets (35/155 and 75/230) which wereobserved from the borehole log werepredicted to remain inactive during stimulationtests. They are unlikely to have contributed toReferencesBarton, N.R., 1986, Deformation phenomena injointed rock. Geotechnique. 36, No.2, 147-167.Choi, X., 2004, 3-Dimensional Finite ElementModelling Study of Habanero #1CSIRO Petroleum Confidential Report No. 04-035.Davidson, S.C., 2004, Habanero #1 StimulationOperation Review. Geodynamics Ltd report.Evans, K., 2004, Comments to Q-Con’s firstanalysis of the injection test of 12th December,2003. Report for Geodynamics Ltd.Hillis R.R., Meyer J.J., Magee M. E., 1997, Thecontemporary Stress Field of the NappamerriTrough and Its Implications for Tight GasResources. Report of Department of Geology andGeophysics, University of Adelaide, SA 5005,Australia.Itasca, 2003, 3DEC – Three-Dimensional DistinctElement Code (User’s manual). Itsaca ConsultingGroup, Inc. Mill Place, 111 Third Avenue South,Suite 450. Minneapolis, Minnesota 55401 USA.Jeffrey, R., 2004, Stimulation of Habanero 1 andpositioning of production well. CSIRO PetroleumConfidential Report No. 04-008.Shen, B., 2004, Using borehole breakout data toestimate in situ stresses in deep granite atHabanero #1 Hot Dry Rock well. CSIROExploration and Mining Report 1166C(confidential).AcknowledgementsThe study was sponsored by Geodynamics Ltd.The author wishes to thank Dr Doone Wyborn ofGeodynamics Ltd and Mr Steve Davidson for theirinput to this study.5179

Australian Geothermal Energy Conference 2009Magnetotelluric Monitoring Of Geothermal Fluid FlowStephan Thiel 1 , Jared Peacock 1 *, Graham Heinson 1 , Louise McAllister 21 TRaX, School of Earth and Environmental Sciences, University of Adelaide, SA 50052 Petratherm Ltd, Adelaide, Unley, SA 5061*Corresponding author: jared.peacock@adelaide.edu.auMonitoring fluid flow in enhanced geothermalsystems (EGS) is vital to reservoir growth andproduction. Geothermal fluids are innatelyconductive due to high temperature and pressureand dissolved enhanced ion concentration. Thiscan be exploited by geophysical measurementssensitive to subsurface conductivity changes atseveral hundreds of meters to a few kilometersdepth, such as magnetotellurics (MT). It isproposed that fluid flow can be monitored bymeasuring subsurface conductivity as a functionof space and time using the magnetotelluricmethod constrained by other geophysical andgeological data. 3D MT forward modelling studiesdemonstrate the feasibility of the method. MT datawill be collected in the near future across the EGSsite at Paralana, South Australia.Keywords: Magnetotellurics (MT), geothermal,monitoring, microseismicProblem:EGS reservoirs consist of lowpermeability/porosity rock volumes which need tobe stimulated by forcing high pressure fluids intothe hot rock layer in order to produceeconomically feasible amounts of heat. Theprocess of stimulation induces fractures throughwhich fluids can flow and absorb heat. Inducedrock fractures can be remotely measured usingmicroseismic methods. Rial et al. (2005) exploreshear wave splitting as a viable method tomeasure microfracture growth. The method isbased on the principle that shear waves travellingparallel and perpendicular to the principle fractureplane propagate at different velocities and thatchange in velocity is proportional to fracturedensity. However, shear wave splitting analysiscannot provide any information about fluid contentnor connectivity of the fracture system.Therefore, another method is needed tocomplement the microseismic data.Magnetotellurics passively measures the earth’sresponse to changes in the earth's magnetic fieldand is sensitive to material properties, primarilythe electrical conductivity of rocks and fluids in thesubsurface. Hot fluids under pressure with highion concentrations have enhanced conductivitycharacteristics, which can be measured with MT.Furthermore, multiple MT surveys over the samegrid at different time intervals could produce atime lapse of subsurface fluid movement,effectively monitoring geothermal reservoir fluidflow. Spichak and Manzella (2008) claim that MTis the most effective electromagnetic method fordefining conductive reservoirs.The main goal of this project is to show thatmagnetotellurics is a viable method forcharacterising and monitoring enhancedgeothermal systems. First, a forward model willbe created using existing geological information ofthe test site. Then, before fractures are inducedto produce a reservoir, a grid of MT stations willbe set up at the test site such that a 3D resistivityimage can be produced from the data. A few MTstations will be deployed permanently during thefracturing process from which conductivity will bemeasured as a function of time. After fracturing,another survey will be collected with plans tocollect more surveys at intervals on the order ofmonths. These surveys will provide spatialsubsurface conductivity images as a function oftime.Hypothesis:Geothermal fluids have enhanced conductivitiesdue to high temperatures and pressures and highdissolved ion concentration. The dissolved ionswill be a mixture of initial concentrations of saltsas well as ions dissolved into the fluid picked upfrom lithology. Ussher et al. (2000) demonstratethat there are two conduction mechanisms in clayrichsediments; firstly, conduction via pore waterand secondly, through the double layer of cations.Temperature is the measurement of how fastparticles are moving, which means at highertemperatures charges can move faster and easierunder the influence of an external electromagneticfield, increasing the conductivity. When thesefluids enter the fractured system, conductivity mayincrease by an order of magnitude or more, whichwill cause a change in the MT response. MTmeasurements crossing an area of a fracturedsystem with two perpendicular lines will allow thedelineation of the vertical and horizontal extent ofthe fluid-filled fractured rock. Other materialproperties of the fluids could also be estimatedfrom the MT response such as temperature,porosity, permeability and salinity (Spichak andManzella, 2008).Another interesting phenomenon that might beexplored in these surveys is seismoelectric effectsdue to fracturing. Seismoelectrics is based on thetheory that seismic events cause charges to movewhich creates currents. More precisely, thedouble layers between pore electrolytic fluids andpore wall geometries emit an electric signal whendisplaced by seismic activity (Pride and Haartsen,1180

Australian Geothermal Energy Conference 2009Illustration 1: Interpreted geological cross-section across the EGS site at Paralana.1996). If the seismic, electric and/or magneticfields are measured simultaneously, relationshipsbetween various material properties can bederived, such as resistivity and seismic velocity(Garambois and Dietrich, 2001, Haines et al.,2007).The test site at Paralana, South Australia, has aconductive sedimentary layer near the surfacewith a few hundreds of meters thickness. Thesedimentary layer overlies a more resistive basin.Two faults bound the proposed reservoir, whichhas a lateral extent of a few hundred meters atabout 3-4km depth.Procedure:First, a geological model of the test site atParalana will be produced using existinggeological information such as regional structuresalong with well log data. This information will thenbe used to forward model the MT response of theexisting geology before fracturing is induced. Thiswill provide a control with which to comparechanges in conductivity of the fractured layer. Tosimulate fluid injection, a conductive layer will beinserted in the Mt forward model at a depth of theproposed fracturing. A range of conductivityvalues will be used reflecting expected valuescalculated from Archie’s Law using providedparameters (Archie, 1942). The conductive layerwill then “flow” through the model by laterallyexpanding the conductive area of the forwardmodel in incremented steps. At each step the MTresponse will be calculated. This will provideinformation about the type of MT responsespredicted for the test site, which will give vitalinformation about the measurement spacing andfrequency ranges to be used.Next, preliminary MT surveys will be collected atthe test site in late November to early December2009. The survey will include two perpendicular2D lines and a small grid that covers the proposedreservoir. The MT data of the 2D lines will beinverted to obtain a 2D resistivity image of thesubsurface underneath the drill site. This willprovide constraints of the resistivity distribution inthe east-west and the north-south direction. Theadditional MT sites outside the two 2D linesacross will provide additional constraint.Fracturing will then be induced into the reservoirin January 2010, which should take around onemonth to complete. A microseismic network willbe in place during the fracturing process tomonitor seismic events associated with the opingof the fractures. A few MT stations, covering agrid extending over the reservoir and powered bysolar panels, will be deployed to collect data whilefracturing is induced. This will provide time lapsedata as well as detect possible seismoelectriceffects when correlated with microseismic data.The data will be downloaded at intervals on theorder of weeks and processed to produce 3Dimages of subsurface conductivity (Newman etal., 2008), from which the extent of the fluid-filledreservoir can be estimated if the resolutionpermits.During and after fracturing, MT measurements willbe repeated along the two 2D lines and comparedto the MT data collected before the stimulation.Thus, this survey will provide information aboutthe change of conductivity as a function of time,and will help to relate the outcomes with theextent of the fluid-filled reservoir.2181

Australian Geothermal Energy Conference 2009ReferencesArchie, G., 1942, The electrical resistivity log asan aid in determining some reservoircharacteristics: Trans. A.I.M.E., v.146, p. 54-62.Garambois, S. and Dietrich, M., 2001,Seismoelectric wave conversion in porous media:Field measurements and transfer functionanalysis: Geophysics, v. 66, p. 1769-1778.Haines, S. S., Pride, S. R., Klemperer, S. L.,Biondi, B., 2007, Seismoelectric imaging ofshallow targets: Geophysics, v. 72, no. 2, p. 9-20.Newman, G. A., Hoversten, M., Gasperikova, E.,Wannamaker, P. E., 2008, Three-dimensionalmagnetotelluric characterization of the Cosogeothermal field: Geothermics, v. 37, p. 369-399.Pride, S., and Haartsen, M. W., 1996,Electroseismic wave properties: Journal of theAcoustical Society of America, v. 100, p. 1301-1315.Rial, J. A., Elkibbi, M., Yang, M., 2005, Shearwavesplitting as a tool for the characterization ofgeothermal fractured reservoirs: lessons learned:Geothermics, v. 34, p. 365-385.Spichak, V., and Manzella, A., 2008,Electromagnetic sounding of geothermal zones:Journal of Applied Geophysics,doi:10.1016/j.jappgeo.2008.05.007.Ussher, G., Harvey, C., Johnstone, R., Anderson,E., 2000, Understanding the resistivities observedin geothermal systems: Proceedings WorldGeothermal Congress, Kyushu-Tohoku, Japan, p.1915-1920.3182

Australian Geothermal Energy Conference 2009Completion of Habanero Closed-loop Circulation TestDoone Wyborn 1* .1 Geodynamics Limited. PO Box 2046, Milton, QLD, 4064.* Corresponding author: doone.wyborn@geodynamics.com.auGeodynamics has been working towards its“Proof of Concept” Enhanced Geothermal System(EGS) since drilling its first deep well in 2003 intothe basement granites beneath the centralCooper Basin, NE South Australia. By 2008 therewere two successful wells 560m apart connectedby a stimulated fracture system located at a depthof 4,250m where the rock temperature is 247°C.Initially open loop testing was employed involvingproduction to a pit then re-pressurization back toreservoir pressure with oil industry “frac” pumps.In late 2008 a high pressure pipe line wascompleted connecting the two wells at surface,and by December 2008, after initial pump failures,a six week circulation was commenced. Thecirculation involved flow from Habanero 3 usingthe natural artesian pressure, keeping the fluid atfull flowing wellhead pressure through the surfacepipeline, cooling the fluid near the re-injection wellHabanero 1 with an air cooled heat exchanger,and using a 41-stage centrifugal pump to re-injectthe fluid back into the reservoir.The results of the circulation test and of theassociated tracer testing will be presented. Thesuccess of the circulation led Geodynamics toannounce completion of its “Proof of Concept” inMarch 2009.Keywords: Enhanced Geothermal System,circulation test, tracer test, stimulated reservoir.BackgroundGeodynamics formed as a single purposecompany in November 2000 to develop hotfractured rock (now generally known as EnhancedGeothermal Systems, EGS) geothermal energyfrom a unique non-volcanic environmentrepresented by basement high-heat-productiongranites overlain by insulating sediments. Oilindustry drilling had identified the central part ofthe Cooper Basin in an area known as theNappamerrie Trough as an ideal site for suchdevelopment. In addition the oil exploration hadreported that the stress field is close to overthrustwith minimum principle stress vertical. Under suchconditions hydraulic stimulation of fractures wouldin preference take place on sub-horizontalexisting natural fractures. These conditions wereenvisaged to be ideal for large scale multi-wellEGS development.The first well (Habanero 1), drilled in 2003,identified high fluid overpressures in the existingnatural fractures, and these overpressurescaused difficulty in drilling. In order to controlthese overpressures the use of heavy drilling mudresulted in mud losses that caused damage to thenatural fractures reducing their ability to flow.Habanero 1 was completed to a depth of 4,421mand a fracture system at about 4,250m wasstimulated by massive injection in late 2003 wherethe rock temperature is 247°C.A second well, Habanero 2 was drilled 500m tothe SW of Habanero 1. However difficulty with theexisting drilling method and the fractureoverpressures resulted in an eventual suspensionof a side track in the well with stuck drill pipe leftin the hole 79m below the top of the granite at3,784m. Prior to the sidetrack the well hadintersected the stimulated reservoir at a depth of4,325m and the well flowed at rates up to 20kg/second with surface flowing temperatures up to210°C. Pressure responses in Habanero 1 whilstflowing from Habanero 2 indicated strongconnection via the fracture system at 4,250mbetween the wells.A second massive stimulation from Habanero 1was completed in 2005 which extended thestimulated reservoir outwards to occupy an areaof approximately 4 km 2 in plan view. Thisreservoir resulted from the injection of 40,000 m 3of water in total in 2003 and 2005. It was definedby the location of 45,000 micro-seismic events.The 2005 stimulation proved that stimulationcreated permanent enhanced fracture flowcapacity as the 2005 micro-seismic eventscommenced essentially where the 2003 eventsfinished.Habanero 3, the new production well wascompleted in February 2008 at a distance of560m NE of Habanero 1 or slightly more than 1km from Habanero 2. The stimulated reservoirwas intersected at the predicted depth at 4,181m,and a pressure response at Habanero 1 wasobserved before drilling parameters wererecognised as detecting the intersection.Immediately after reaching TD of 4,221m the wellwas logged with the Baker Atlas circumferentialborehole imaging tool (CBIL). The tool wasdeployed to the fracture zone area as quickly aspossible and proceeded to log down. The toolmanaged to log the whole of the fracture zonebefore the temperature rendered it inoperable at adepth of 4,207m. Its temperature rating is 205C,but the tool actually continued to operate to atemperature of 220°C, a very commendableperformance. The image through the main part ofthe fracture is shown in the picture below (Figure1).1183

Australian Geothermal Energy Conference 2009pipeline to a steam separator. The fluid level inthe separator was adjusted by a control valve onthe liquid outlet side. In this outlet line there wasalso placed a magnetic flow meter and electricalconductivity meter. The steam flow rate wasmeasured by a pitot tube located in the steamvent line.Figure 1 CBIL image of main fracture zone at 4181m (13,716ft). The dark area in the centre of the image represents acavity in the borehole formed where a large fractureintersects the wellbore.Open-Loop Circulation TestThe open-loop flow test was designed todemonstrate communication between Habanero 1and 3 along the fracture zone stimulated fromHabanero 1 in 2003 and 2005, and to determinethe impedance or friction loss associated withcirculation between these wells. The impedancegoverned the pumping requirement for closedloop operation, which in turn dictated theoperability of the pump that had been purchasedfor this phase. If the impedance was too high, thepump would not be suitable and a number ofremedial actions would need to be effected.Habanero 3 was drilled to 40m below the mainintersection of the reservoir and completed with a7 inch perforated liner. The rig demobilised withthe well left with a mud weighted to accuratelybalance the fluid overpressure from the fracturezone. The fracture pressure was estimated at 74MPa at a depth of 4,181m or 34 MPa abovehydrostatic. This pressure is the same as theshut-in pressure observed at Habanero 1.In order to bring the well on to flow a coil tubingunit was used to progressively clean out the mudto water. By the time the coil had reached about2,000m depth it was clear that the well wasflowing so the coil was removed. The well wascleaned of mud and filled with water derived fromthe fracture system.Open-loop testing was based on flowingHabanero 3 through a wing valve and two chokes,a fixed sized choke and a variable choke inparallel, with the fluid flashed to low pressurethrough the chokes and delivered in an 8 inchFigure 2 Mud cleanout with coil tubingHabanero 3 was opened to flow for the first timeon 14 March 2008, and to the separator on 15March.The open loop testing can be divided into anumber of phases as shown in Table 1 below:Table 1; Open-Loop Operations in 2008OperationFlow testingfrom Habanero3 withHabanero 1shut-inMain openloopcirculationDate(2008)14 to 21March22 to 25MarchHDC injection 26MarchPost HDCinjectionStimulationHabanero 3of26March18-19AprilCommentA stable flow of 16 kg/sec ata flowing pressure of 27 MPawas achieved with a 14mmfixed choke. Wellheadtemperature reached 209CInjection 18.5 kg/sec at 51.7MPa (7,500 psi), productionof 20 kg/sec at 27.5 MPa, anincrease of 4 kg/sec over theearlier test with Habanero 1shut-in. Temperature reached212CSlow injection of HDCchemical barite dissolvingagent in Habanero 1 toincrease injectivityInjection at 18.5 kg/sec at50.3 MPa (7,300 psi), animprovement of 1.4 MPa.Expect further improvementswith longer injection duringclosed loop operation.Injection of 2,173m 3 of waterat injection pressures up to64 MPa, resulting in 276microseismic events close toHabanero 3. Expectedincrease in productivityDuring the initial flows from Habanero 3 in midMarch, Habanero 1 was shut-in, but pressure wasmonitored with a highly accurate quartz pressuregauge. Any change in flow conditions at2184

Australian Geothermal Energy Conference 2009Habanero 3 was immediately recognised by theHabanero 1 pressure gauge indicating idealconnection between the wells in the main fracturezone (Figure 3).Figure 3. Pressure response of Habanero 1 pressure gaugeduring flow from Habanero 3 from 14 to 18 March 2008.Pressure on Y axis is in psi.At the end of the main circulation on 25 March apressure-temperature-spinner (PTS) logging toolwas run to the main fracture and the well wasshut-in. The flowing pressure at the fracture wasstable during flow at 62.95 MPa, and rose within20 minutes to 71.5 MPa after shut-in. This rapidrise indicates that most of the friction associatedwith flow is very close to the well-bore. Thebottom hole temperature measured during loggingwas 244.5°C.The HDC (barite dissolving agent) injection on 26March (Table 1) was aimed at the 2,000 barrels ofbarite-rich drilling mud lost in the fracture systemwhen Habanero 1 was drilled in 2003. Previouswell test analysis of Habanero 1 indicated that themud is inhibiting flow from Habanero 1 into thefracture system. The injection resulted in someimprovement in the injectivity of Habanero 1.Closed Loop Circulation TestCirculation ImpedanceThe circulation pump was sized according to theunderstanding that the injectivity of Habanero 1would be substantially better with Habanero 3flowing than with Habanero 3 not flowing. Thiswas a view that had been held since before flowtesting of Habanero 2 in 2005, but it was neverproven.During the open loop circulation in March 2008 itbecame apparent that the injectivity intoHabanero 1 was restricted and HDC was used totry to improve this. Once the circulation wasachieved this improvement was not as good ashoped. Under the conditions at the time, at apump design pressure differential of 11 MPa thepump could only deliver around 12 kg/second intoHabanero 1. It is most likely that the lack ofresponse at Habanero 1 to Habanero 3 flow iscaused by the drilling mud lost around Habanero1 in 2003.Despite the injectivity problems of Habanero 1,the pump was capable of carrying out circulationoperations that would allow the determination ofreservoir parameters from injection of chemicaltracers, so preparation for the tracer testing phasebegan. The six-week circulation and tracer testwas likely to improve the injectivity of Habanero 1because (i) longer term cooling of the fracturesimmediately surrounding Habanero 1 would resultin a contraction of the rock adjacent to thefractures and the fractures would open slightlydecreasing impedance, and (ii) it was envisagedthat the lost drilling mud in Habanero 1 would begradually washed further into the reservoir withlonger term flow, thus reducing the restriction.Initial Closed-loop OperationsStart-up closed-loop operations in August 2008were beset with problems involving (i) blockage ofthe grit arrestor at Habanero 3, (ii) pump inlet sealfailure, (iii) cooling fan vibrations, (iv) generatoroverheating, (v) leaking plugs, (vi) a flangewashout and (vii) gradual loss of efficiency of theair cooler.The air cooler efficiency loss turned out to becaused by scaling of the antimony sulphidemineral stibnite. The cooling of the formationwater from over 200°C to less than 100°Cresulted in its precipitation. Fortunately thismaterial is relatively easy to remove as it does notadhere to pipe like other common scales (calcite,anhydrite, and silica).The pump inlet seal failure required the pump tobe sent to Singapore for refurbishment. As aresult the circulation test did not commence untilDecember 2008.Circulation operationsA data logging unit was installed to collectpressure and temperature readings every 30seconds at a number of points on the system.Flow rate was measured using an orifice plate setimmediately after the air cooler, and before the reinjectionpump. The orifice plate was calibratedusing two turbine flow meters set on a temporaryflow line to a pit. During the calibration, flow wasdirected to the pit via the flow cross on theHabanero 1 wellhead. A sampling panel on a sidecapillary line was used to collect fluid samples fortracer analysis. The sampling panel also hadinstalled pH, conductivity and dissolved oxygensensors.Between the pump and the Habanero 1 wellheada 700 ml pressure vessel was installed on a 1inch sideline for collection of fluid at high pressureand at a defined temperature. The chamber waswrapped in a heating blanket that controlled thetemperature. This apparatus was designed tomeasure the polymerisation rate of silica at reinjectiontemperature. Fluid samples were left inthe chamber for a pre-determined period and then3185

Australian Geothermal Energy Conference 2009collected and immediately measured formonomeric silica (H 4 SiO 4 ) using the ammoniummolybdate method. In this way the rate ofpolymerisation could be determined to asses thepotential for silica scaling in the re-injection well.By 11 December 2008 the pump had been reinstalledafter its trip to Singapore. The operationwas run for several days to assess reliability ofequipment and data collection. In the afternoon of17 December 2008 the system was shut down for5 hours while 1000 l of fresh water with 100 kg on1-3-5 naphthalene tri-sulphonate and 50 kg offluorescein was injected down Habanero 1. Thetracer chemicals were injected using a pressuretesting injection pump (the tracer story isdescribed in an accompanying paper at thisconference (Yanagisawa et al., 2009)). The pumpwas then re-started and the six week tracer testcommenced.Operating pressure conditions and flow rateswere initially as expected, based on earlierunderstanding of the drilling mud damage atHabanero 1. The stable flow rate was slightly lessthan 12 kg/second. During the following weeksthe system was shut down for short periods andafter each shut down the stable flow rateincreased slightly. It was noticed that during initialpump start-up with each shut-down that the pumpcould inject at a higher flow rate whist thereservoir was pressurizing up. The flow rateduring these start-ups was greater than 20kg/second and it was not until several hours laterthat the flow rate settled to a stable rate once theinjection pressure had also stabilised.Progressively over the circulation test the stableflow-rate increased so that by the end of the testthe flow rate was 15.5 kg/second, and was stillincreasing. The pump differential of 11 MParemained essentially the same throughout the testso that the overall circulation efficiency increasedby 30% over the test period. Barite and finegranite particles were collected from the flow fromtime to time indicating clean up of the fracturenetwork, and this most likely explains theincreasing efficiency. The high flow rates on pumpstart-up most effectively contributed to the cleanup explaining the slight increases in stable flowafter each start-up.The tracer results (Yanagisawa et al., 2009)indicated a tracer swept pore volume of 18,500m 3 . On the basis of the modelling of stream-lines(Figure 4, unpublished data from our reservoiranalysis consultants Q-con GmbH) it can bereasoned that the pore volume of the wholereservoir (black polygon in Figure 4) is close to40,000 m 3 .Figure 4; Stream-lines of circulation modelled on the limits ofthe reservoir based on the stimulation area (black polygon).Red lines represent stream flow, blue lines isobars.Modelling carried out by Q-con GmbH.The estimated pore volume of the reservoir isapproximately equal to the volume of fluid injectedduring the 2003 and 2005 stimulations. Thus itappears that the stimulation created new porespace about equal to the fluid volume pumped,and that the fracture fluid volume prior tostimulation was quite small. This attests to theeffectiveness of stimulation and its necessity.SummaryThe six-week Habanero closed-loop circulationtest took place over the period December 2008 toFebruary 2009. The test enabled Geodynamics toannounce its “Proof of Concept” in March 2009.During the test the circulation efficiency increasedby 30% and this was mainly attributed to thecleaning out of drilling mud lost into the fracturesduring the drilling of Habanero 1 in 2003. Thepore volume of the reservoir is approximatelyequal to the fluid volume pumped during thestimulations in 2003 and 2005.ReferencesYanagisawa, N., Rose, P., and Wyborn D., 2009.Habanero Tracer test in the Cooper Basin,Australia: Key Results for EGS Development.Australian Geothermal Conference 2009,Brisbane.4186

Enhanced Geothermal Reservoir SimulationAustralian Geothermal Energy Conference 2009Huilin Xing * , Ji Zhang, Yan Liu, Hans Mulhaus.The University of Queensland, Earth System Science Computational Centre, St Lucia, QLD 4072.* Corresponding author: h.xing@uq.edu.auThis paper introduces the current state of art incomputer modelling of enhanced geothermalsystem (EGS) and expends our research efforts inhigh performance simulation of EGS. We includea brief introduction of our integrated geothermalreservoir simulator PANDAS and its applicationsin: (a) model benchmark, (b) fracture andpermeability evaluation based on recordedmicroseismic events and (c) simulation andevaluation of a certain multiple well EGS. Wedemonstrate the usefulness and efficiency of oursoftware PANDAS.Keywords: enhanced geothermal reservoir,simulation, finite element, permeability,HDR/HFR/HWR, microseismicity.IntroductionA large amount of research and testing on EGS,such as HDR (hot dry rock), HFR (hot fracturedrock) and HWR (hot wet rock) geothermalreservoirs, have been accomplished worldwide inthe past 30 years including reservoir construction,fluid circulation and heat extraction. A successfulEGS reservoir strongly depends on thermal-fluidflow distribution at any given time. This is primarilydetermined by: (1) the nature of theinterconnected network of hydraulic stimulatedjoints and open fractures (including bothstimulated and natural) within the flow-accessiblereservoir region; (2) the mean temperature andpressure in the reservoir; (3) the cumulativeamount of fluid circulation (reservoir cooling) thathas occurred; and (4) water loss (e.g. Brown etal., 1999). In order to understand, model andpredict the thermal power performance of an EGSreservoir, it is necessary to have good measuresand understanding of the following twointerrelated reservoir properties: (a) the effectiveheat transfer volume at high temperature; and (b)the fracture/joints and its distribution within theeffective heat transfer volume. Both highly affectsthe reservoir characteristics (i.e. permeability),which are complicated and are functions of theapplied reservoir pressure/stress that arecontrolling the nature and degree ofinterconnection within the network of fractures.EGS – A THMC coupled systemA literature survey (e.g. Bjornsson andBodvarsson, 1990) on thermal, hydrological andchemical characteristics of geothermal reservoirsand their relevant parameters - permeability,permeability-thickness, porosity, reservoirtemperature and concentration of dissolved solidsand non-condensable gases – suggests thatreservoir permeability, porosity and total dissolvedsolids tend to be a function of temperature.Permeability and porosity generally decline withincreasing temperature, while the concentration ofdissolved solids increases with increasingtemperature, reflecting a general increase inmineral solubility. A possible explanation ofdecreasing permeability with temperature is alocal increase in crustal stresses caused bythermoelastic phenomena. Thermal expansion ofthe reservoir rocks will reduce the number voidsand cracks in the rock matrix and hence reducepermeability. Another major factor that affects thepermeability is mineral deposition. For example,the solubility of calcite decreases with increasingtemperature, causing clogging of pore spaces athigh temperatures. All the above demonstratesthat an EGS is a complicated Thermal-Hydro-Mechanical-Chemical (THMC) coupled system,which requires more comprehensiveunderstanding and modelling of coupledprocesses than is commonly done in standardreservoir engineering.Recent studies on computer modellingRecent studies on computer modelling theconventional geothermal reservoir engineeringand the EGS/HDR system are reviewed byO’Sullivan et al. (2001) and Sanyal et al. (2000)respectively. They show that computer modellingis routinely applied in conventional hydrothermalreservoir engineering, but it is comparativelypremature in EGS simulation which still rely muchon the EGS expertise and feedback of practicalactive modellers and engineers. Based on theabove and other recent studies, existingsimulators are faced with following challenges: (1)Geomechanical deformation/rock stress and itsfully coupling with the multiphase thermal-fluidflow and chemicals are not addressed yet. Suchcoupled models are critical for analysing thegeothermal reservoir system especially for EGS.Further research is needed in exploring differentapproximations for coupled processes with vastlydifferent intrinsic spatial and temporal scales.Such a coupled treatment can potentially providea more realistic description of geothermalreservoir processes during natural/stimulatedevolution as well as during exploitation. It can alsoprovide added constraints that can help reducethe inherent uncertainty of geothermal reservoirmodels; (2) a reliable fully-coupled treatment of3D fluid flow and mass transport with detailedchemical interactions between aqueous fluids,gases, and primary mineral assemblages stillrequires further research. This is currentlyavailable in hydrothermal code TOUGH2, but not1187

Australian Geothermal Energy Conference 2009available in the other codes including all the HDRsimulators/FEM simulators; (3) the relevantreservoir model generation and meshing are stilldifficult and time consuming especially for fracturedominated EGS. The finite differential method iswidely used in geothermal modelling but requiresregular rectangular mesh structure. The populargeothermal code TOUGH2 may handle irregularmeshes theoretically, but most of models set upusing TOUGH2 contain some structure, such aslayering. It is impossible to explicitly describe thecomplicated fractures in an EGS reservoir withsuch mesh structures. Unstructured mesh may bea better choice, but no unstructured mesh basedsolver-finite element solver- as powerful as suchas TOUGH2 is available for geothermal simulationyet; (4) no module for visualizing microseismicityand evaluating the relevant rupture andpermeability distribution for the further simulationhas been integrated into the simulator so far; (5)No multiscale computing or parallel computinginvolved in the widely available geothermalsimulators yet despite their well-studied andwidespread application in other fields.In conclusion, further computational model andcode developments are urgently needed toimprove our understanding of geothermalreservoir and the relevant natural and/orenhanced evolution such as of enhancedgeothermal reservoir system, and achieve a moreaccurate and comprehensive representation ofreservoir processes in more details, to reduce theuncertainties in models, and to enhance thepractical utility and reliability of reservoirsimulation as a basis for field development andmanagement (e.g. O’Sullivan et al., 2001, Sanyalet al., 2000). This presentation will focus on ourresearch efforts towards high performancesimulation of enhanced geothermal reservoirsystems.An Integrated Geothermal ReservoirSimulatorPANDAS - Parallel Adaptive static/dynamicNonlinear Deformation Analysis System - forsimulating the coupled geomechanical-fluid flowthermalsystems involving heterogeneouslyfractured geomaterials is being developed usingfinite element method (FEM). It addresses the keyscientific and technological challenge indeveloping enhanced geothermal energy.Namely, it is targeting a new predictive modellingcapacity spanning different temporal and spatialscales with the potential to yield breakthroughs inunderstanding how to enhance the flow of waterthrough the enhanced geothermal field and howto sustain it over decades such that the trappedheat energy can be extracted.Currently, PANDAS includes the following five keycomponents: Pandas/Pre (for visualizing andevaluating microseismic events and the relevantruptured zone and permeability, meshgeneration), ESyS_Crustal (FEM solver for aninteracting fault system), Pandas/Thermo (FEMthermal solver), Pandas/Fluid (FEM solver forporous media flow) and Pandas/Post (forvisualizing computing results). All the abovemodules can be used independently or together tosimulate individual or coupled phenomena (suchas interacting fault dynamics, heat flow and fluidflow) with or without coupling effects. It aims toprovide (a) visualization the recordedmicroseismic events and further evaluation of thefracture location and evolution, geological setting,the reservoir characteristics (e.g. permeability)and mesh generation; (b) a non-linear finiteelement based numerical solution to model andevaluate a certain geothermal reservoir undervarious affecting factors. For more details, refer toXing et al (2002; 2006a; 2006b; 2007; and 2008).Benchmark and Application ExamplesPANDAS has been applied in several differentcases. We list a few of examples to show itsaccuracy, stability, usefulness and efficiency insimulating the enhanced geothermal reservoirsystem.Benchmark of computational modelVerification and benchmark testing of our finiteTemperature (℃)30025020015010050abc00 20 40 60 80 100 120Time (year)element based geothermal code PANDAS areaccomplished by comparing the availableanalytical solutions and/or the widely acceptedresults with those calculated by PANDAS. So far,the following cases have been tested; only thecase 3) is further described here.abcd200m300m400m500mFigure 1: Comparison of FEM result with analytical one (curves)on thermal-fluid flow in fractured rocks. It shows the fluidtemperature evolution at different positions of the fracturedzone. Around the production well (500m), the temperatureremains above 150℃ at 60 years. Assuming an allowablemaximum temperature decrease of 40℃ at the projection well,it will last up to 50 years with the injection rate of 0.017litre/s.Refer to Xu et al., (2007) for the detailed model description.d2188

Australian Geothermal Energy Conference 20091) Heat transfer/Darcy flow in porous media(analytical solution available)2) Convection dominated thermal-fluid flow inporous media (analytical solution available)3) Thermal-fluid flow in fractured rocks(analytical solution available for a singlefracture)4) Two phase thermal-fluid flow in porous media(water and vapour, DOE (Department ofEnergy, USA) benchmark result).Fluid flow in most enhanced (HDR/HFR)geothermal reservoirs is dominated by fracturesand their distribution, which corresponds to thebenchmark case 3). How the fractures affect theheat transfer between the fluid and the rock massduring injection process must be criticallyaddressed. To investigate the advancement of thethermal fluid during the injection process into thefractured reservoir system, PANDAS is verifiedthrough comparison with the analytical solution ofa simplified reservoir system consisting of ahorizontal fracture intersecting an injection welland a production well as detailed in Xu et al.(2007). The analysed zone spans 30m thicknessalong the vertical direction and is composed of amain horizontal fracture and a permeable rockmass. To be analysed by both the analytical andfinite element methods, in which the permeabilityof the 30m thick (D=15m) fracture zone is takenas 1.0E-30 in FEM simulation (close to zero tocompare with the analytical solution). Thetransmissibility of the main fracture with theaperture H=0.01m down the middle of the fracturezone is 1 Darcy metre; and the temperature ofinjected fluid is 90℃, the initial temperature ofrock matrix is 260℃. Figure 1 shows thebenchmark result of two wells with the distance of500m. The FEM calculation result agrees wellwith the analytical solution.Microseismicity and EGS reservoirHydraulic stimulation is a basic concept ofimproving the residual permeability of the in-siturock mass at depth and still remains the mainmechanism to be envisaged for the creation of anenhanced geothermal reservoir (i.e.HDR/HFR/HWR). PANDAS has been developedand applied to visualize the microseismic events,to monitor and determine where and how theunderground rupture proceeds during a hydraulicstimulation process, to determine the domain ofthe ruptured zone and to evaluate the materialparameters (i.e. the permeability) for the furthernumerical analysis. Figure 2 shows thepermeability distribution of a geothermal reservoircalculated from the microseismic events recordedduring a hydraulic stimulation process. A virtual 8-well geothermal reservoir (i.e. 1 injection well + 7production wells in a reservoir with thedimensions of Length x Width x Height:Figure 2: An example of the calculated permeability distributionof a geothermal reservoir thorough the microseismic eventsrecorded during a hydraulic stimulation process.H1Figure 3: The simulated fluid flow in a certain fracturedgeothermal reservoir with 7 production wells and 1 injectionwell H1. It is calculated in 3D but shown in a certain crosssectionhere.Figure 4: The simulated hydraulic pressure distribution at 5years in a certain fractured geothermal reservoir with 7production wells and 1 injection well H1(Figure 3).3189

Australian Geothermal Energy Conference 2009Figure 5: The simulated temperature distribution at 40 years ina certain fractured geothermal reservoir with 7 production wellsand 1 injection well H1 (Figure 3)4000 m x 3000 m x 1750 m) is designed andfurther analysed using PANDAS. The snapshotsof the relevant results are shown in Figures 3, 4and 5 with one injection well located at H1 (Figure3).SummaryWe discuss the key improvements required insimulating an enhanced geothermal reservoirsystem (HDR/HFR/HWR) for further improving ourunderstanding of geothermal reservoir and therelevant natural and/or enhanced evolution suchas of EGS based on relevant studies. The goal isto achieve a more accurate and comprehensiverepresentation of reservoir processes in moredetail and reduce the uncertainties in models, andenhance the practical utility and reliability ofreservoir simulations as a basis for fielddevelopment and management. Our research inPANDAS towards high performance simulationsof enhanced geothermal reservoirs is introducedand then verified using relevant benchmarks. It isfurther applied in a virtual design and assessmentof a multiple well reservoir system based on thepermeability distribution calculated from therecorded microseismic events. Both benchmarkand application examples demonstrate itsaccuracy, stability and potential usefulness insimulating the enhanced geothermal reservoirsystem. PANDAS will be further developed for amultiscale simulation of multiphase dynamicbehaviour for a specific geothermal reservoirsystem. More details and additional applicationexamples will be given during the presentation.AcknowledgementsSupport is gratefully acknowledged by theAustralian Research Council and GeodynamicsLimited through the ARC Linkage projectLP0560932. The authors are grateful to Dr DooneWyborn of Geodynamics Limited for hisconstructive advice and support, to Dr Hehua Xu,Mr Wenhui Yu and Dr Enlong Liu for theircollaborations in the relevant research.ReferencesBjornsson, G. and Bodvarsson, G. 1990, ASurvey of Geothermal Reservoir Properties:Geothermics, v. 19, no. 1, p. 17-27.Brown, D., DuTeaux, R., Kruger, P., Swenson, D.and Yamaguchi, T. 1999, Fluid circulation andheat extraction from geothermal reservoirs:Geothermics, v. 28, p. 553-572.O’Sullivan M. J, Pruess, K. and. Lippmann, M. J.2001, State of the art of geothermal reservoirsimulation: Geothermics, v. 30, p. 395–429Sanyal, S K, Butler, S J, Swenson, D andHardeman, B. 2000, Review of the state-of-the-artof numerical simulation of enhanced geothermalsystems: Proceedings World GeothermalCongress 2000, Tohoku, Japan, May28-June 10.p. 3853-3858.Xing, H.L., and Makinouchi, A. 2002, Threedimensional finite element modelling ofthermomechanical frictional contact between finitedeformation bodies using R-minimum strategy:Computer Methods in Applied Mechanics andEngineering, v. 191, p.4193-4214Xing, H. L., Mora, P. and Makinouchi, A. 2006a, Aunified frictional description and its application tothe simulation of frictional instability using thefinite element method: Philosophical Magazine, v.86, no.21-22, p. 3453-3475.Xing, H. L., Mora, P. 2006b, Construction of anintraplate fault system model of South Australia,and simulation tool for the iSERVO institute seedproject: Pure and Applied Geophysics, v. 163, p.2297-2316. DOI 10.1007/s00024-006-0127-xXing, H. L., Makinouchi, A. and Mora, P. 2007,Finite element modeling of interacting faultsystem: Physics of the Earth and PlanetaryInteriors, v. 163, p. 106-121.doi:10.1016/j.pepi.2007.05.006Xing, H. L. 2008, Progress Report:Supercomputer Simulation of Hot Fractured RockGeothermal Reservoir Systems:ESSCC/ACcESS Technical Report, TheUniversity of Queensland, p.1-48Xu, H, Xing, H. L., Wyborn, D and Mora, P. 2007,Analytical and numerical investigation of thermofluidflow of fracture dominated geothermalreservoir, in Yong Shi, Geert Dick van Albada,Jack Dongarra, and Peter M.A. Sloot (eds),Lecture Note in Computer Science (LNCS) 4489(Computational Science-ICCS2007), Springer-Verlag, Berlin, Heidelberg. P. 1156-1163,4190

Australian Geothermal Energy Conference 2009Fracture Simulation for Deep Crystalline RockChaoshui Xu 1 and Peter A. Dowd 2 *1 School of Civil, Environmental and Mining Engineering, University of Adelaide2 Faculty of Engineering, Computer and Mathematical Science, University of Adelaide* Corresponding author: Peter.Dowd@Adelaide.edu.auThis paper describes the application of simulatedannealing for fracture modelling in crystalline rock.The technique is capable of incorporating thespatial correlations of fracture properties within afracture set or across different fracture sets sothat more realistic fracture systems can besimulated.Keywords: marked point process, discrete fracturenetwork, K-function, simulated annealingIntroductionRealistic fracture models are crucial for the designand performance assessment of geothermalreservoirs, especially in hot dry rock (HDR)applications. The model is the fundamental inputrequired for the modelling of fluid flow through the3D fracture network comprising initial fracturesand new fractures created by hydraulicstimulation. The characterisation of rock fracturenetworks is an extremely difficult problem notleast because accurate field measurement of asingle discontinuity is difficult and measurement ofall discontinuities is impossible. For thesereasons, in practical applications, there is noobservable reality of the 3D network on anymeaningful scale and the only realistic approachis via a stochastic model informed by sparse dataand/or by analogues.The first step in stochastic fracture modelling isdata collection and statistical analysis, from whichmodel parameters are derived. Data normallycome from surveys of analogues, such as rockoutcrops, or from direct or indirect observations ofthe rock mass such as drill cores, boreholeimaging, geophysical surveys or seismicmonitoring during fracture stimulation. In general,the outcomes of this step include the identificationof fracture sets, the distribution characteristics offracture locations, and statistical distributions offracture properties, such as orientation, size andaperture. On the basis of these parameters it isthen possible to generate a 3D fracture networkfor the reservoir, which is a possible “reality” in thesense that all statistical characteristics of thenetwork are reproduced.The two most commonly used mathematicalmethods for stochastic fracture simulation arePoisson planes (Dershowitz and Einstein, 1988)and random object models (Stoyan et al., 1995,Molchanov, 1997), with the latter more popularbecause of its flexibility for adaption to a widerange of applications. Current practice in randomobject models is to generate fractures via aBoolean-type approach (Stoyan et al. 1995,Molchanov 1997, Chilès and Delfiner 1999). Thefractures are divided into sets and parameters forlocation, size and orientation are modelledseparately for each set. The final fracture modelis the combination of each set of fracturesgenerated independently. Spatial correlation isconsidered only for modelling the fractureintensity which defines the number of fractures ina particular area (2D) or volume (3D). Otherspatial correlations, either auto-correlation for anindividual variable or cross-correlations betweenpairs of variables, within a fracture set or betweendifferent fracture sets, are generally ignored.These correlations, however, must be included togenerate realistic fracture models.Boolean object modelIt is common practice to classify observedfractures (traces) into sets according to theirorientations and to study each set independently.The separation of fractures into different sets isbased on the belief that fractures formed bytectonic activity are likely to be oriented inapproximately the same direction and to displaysimilar properties (e.g., size, aperture). It istherefore reasonable to study the sets individually.The generation of a Boolean object model isrelatively straight-forward (Xu and Dowd, 2009).For a given fracture set, the fracture locations aregenerated first, usually by a Poisson distribution inwhich fracture intensity for a particular area (2D)or volume (3D) is either assumed to be constantor is derived from geostatistical estimation orsimulation. Secondly, the orientation of eachfracture is generated, most commonly from aFisher distribution. Finally, the size of eachfracture is generated from a specified distribution,the most common being exponential, lognormal orgamma. Other fracture properties, such asaperture and joint strength, can then be addedinto the network by additional Monte Carlo steps.Options for fracture intersections andtermination/truncation can also be incorporated.Additional fracture sets can be generated in asimilar fashion (independent simulation) toproduce the final fracture model.A common approach to the statistical analysis offracture models is to use marked point processes.Fracture locations are represented by points(centre point or a random point on the fracture) inspace and all fracture properties, such asorientation, size and aperture, are represented bymarks associated with the points. In this contexta Boolean object model can be described as a1191

Australian Geothermal Energy Conference 2009realisation of a point process with independentmarkings. A two-dimensional example is given inFigure 1, which shows fracture traces on a YuccaMountain outcrop, as mapped by Barton andLarson (1985). Similarly, three-dimensionalrepresentations of fractures by marked points canalso be constructed provided the shapes of thefractures are assumed.different times, which raises the possibility that theformation of newer fractures is likely to beinfluenced by existing fracture networks. Theextent and significance of the correlations canvary but can cover various aspects of the fractureproperties. For example, five fractures sets areidentified for the fracture pattern in Figure 1a; theauto- and cross- K-functions of the fracturelocations shown in Figure 2a and b (Xu andDowd, 2008) show that the fracture locations ofdifferent fracture sets have some association andare not independent. Either a hierarchical model(Lee et al. 1990) or plurigaussian simulation(Dowd et al. 2007, Xu & Dowd 2008) can be usedto incorporate these correlations into the fracturemodel. A cluster point process is another type ofmodel that can takes the correlation of fracturelocations into account during fracture modelconstruction.(a) Fracture traces(b) Point representationFigure 1 Two-dimensional fracture pattern and thecorresponding point representation, Barton and Larson(1985)This simplistic fracture model assumes no spatialcorrelation among the fracture sets, and no spatialcorrelation between fracture properties andfracture locations and among fracture propertiesthemselves. The only spatial correlation modelincluded in the model is the fracture point densitydefined as the number of fracture representationpoints per unit area (2D) or per unit volume (3D).This correlation is imposed either by using ageostatistical model to simulate the fracture pointdensity or implicitly by various types of pointpatterns (homogeneous, non-homogeneous,cluster or Cox point process).Spatial correlations in fracturemodellingIn general, fractures sets tend to be correlated(Chilès and Marsily, 1993). This is supported bythe observation that different fracture sets may beformed by different tectonic events active atFigure 2 Auto- and cross- K-functions for the point datasetFigure 1bFracture properties can also be correlated and thecorrelation can be among fractures in the sameset or across different sets. These correlationsare ignored in the Boolean object model, i.e.,marks generated in the model are spatiallyindependent. Practical observation and statistics(Priest 1993, Lee and Farmer 1993, Baghbananand Jing 2007, Chilès and de Marsily, 1993)suggest high correlation between fracture sizeand aperture. Sizes and locations of fractures arealways spatially correlated, even if the fracturesbelong to the same fracture set. The generalpractice of classifying fractures in sets and their2192

Australian Geothermal Energy Conference 2009independent treatment is an indication thatfracture properties are highly correlated withorientation. For realistic fracture modelling thesecorrelations cannot be ignored.Demonstration of the incorporation ofcorrelations in fracture modelFigure 3a shows a simulated 3D fracture systemgenerated in a volume of interest of size100100100. In reality, such an image is difficultto obtain and we are restricted to the use ofexposed 2D images such as rock outcrops orquarry faces. An example of this type of image isshown in Figure 3b, which was obtained bycutting Figure 3a by a north-south vertical crosssectionalplane (shown), thus simulating anexposed quarry face. The fracture trace lines onthe image can now be analysed to construct apossible model to describe the pattern. Using themid-points of the trace lines, the correspondingpoint dataset for the fractures is shown in Figure3c.We consider here two marks for each point, thefracture trace length, , and orientation . Angle is measured clockwise from the verticaldirection and it is, therefore, necessary to makethe transform to = - /2 (0 /2) for theconvenience of analysis. After thistransformation, small values correspond to nearhorizontal lines (parallel to Northing direction inFigure 3a) and large values suggest the linesare nearly vertical (parallel to vertical direction inthe Figure 3a).The correlation coefficient between and isestimated as 0.48 and the distributions of and are estimated using a kernel density estimatewhich show lognormal and uniform typesrespectively. We fit an approximate lognormaldistribution with a mean of 0.8 and a variance of2.0 in logarithmic scale for . The positivecorrelation between and indicates that the twomarks are highly correlated, i.e., vertical fracturestend to be longer than horizontal ones. Insummary, for the example,1. follows a lognormal distribution (withestimated mean of 0.8 and variance of 2.0in logarithmic scale).2. and follow a uniform distribution onthe interval [0, ].3. and are positively correlated withcorrelation coefficient 0.48, i.e., inphysical terms vertical fractures tend tobe longer.100755025(b)NS Plane(a)(c)00 25 50 75 100Figure 3 Simulated example: (a) 3D fractures, (b) Fracturetraces on the plane, (c) Representing point patternTo quantify the spatial correlations between and, we use the cumulative spatial mark correlationfunction introduced by Xu et al. (2007):1 gw tg g 1 ( f )K ( t) u ( u)dum K ( t)f 2 2m 0gwhere wg / (1 g / 2)is the volume ofthe unit ball in g , K(t) is the second order K-( f )function, is the point density, 2is the secondorder f-product density function for the point fieldand f in this definition is the applicationdependentmark function. Based on this3193

Australian Geothermal Energy Conference 2009definition, K m (t) 1 if there is no correlationbetween marks at distance t.For the example (Figure 3), Figure 4a shows thespatial auto-mark correlation function for fractureline length and Figure 4b shows the spatialauto-mark correlation for fracture orientation .The spatial cross-mark correlation functionbetween and is given in Figure 4c. The MonteCarlo (MC) simulation envelope (average valueand 95% bounds) for the case of spatiallyuncorrelated marks is also plotted on the graphs.These three figures reveal some important spatialcharacteristics between the marks in thesimulated example dataset; briefly:4. Smaller values of Kˆ( t)for small tindicate that fractures (points) close toeach other tend to be shorter (smallermark ). In physical terms, aggregatedfractures tend to be shorter in length.Although this feature is not apparent inFigure 3b, it is widely observed in practicethat short fractures in rock tend to occurin clusters as the result of local thermaleffects and long fractures caused bygeological movement (forces) tend to bemore isolated or sparsely distributed.5. Smaller values of Kˆ( t)for small tsuggest that fractures (points) close toeach other tend to be horizontal andshorter. In physical terms, aggregatedfractures in this particular dataset aremore horizontally oriented and longerfractures tend to be more verticallyoriented and more sparsely distributed.6. The flat appearance of Kˆ( t)suggeststhat, in terms of fracture orientation, thereis no preferential direction of the patternof fracture aggregation.The aim of simulating a fracture set thatresembles Figure 3b now becomes two fold:i). The point pattern of the simulated fracturesmust resemble the point pattern in Figure3c in such a way that the point intensityfield (X) and the first and second momentmeasures, such as the inter-event distancefunction H(t) and the K-function K(t), arehonoured (Stoyan et al. 1995).ii). The simulated fractures must follow themark distribution, the multivariate markcorrelation and their spatial auto- andcross-mark correlations as described in 1 –6 above.10 -210 -2K m (t)K m (t)MC simulationKˆ () tMC simulationK ˆ () t10 -2K m (t)MC simulationKˆ () t(a)(b)(c)Figure 4 Corresponding cumulative mark correlationfunctions K ˆ () t vs distance t (a), K ˆ () t vs t (b) andKˆ () t vs t (c) for the simulated example (Figure 3). TheMonte Carlo (MC) simulation envelops shown are obtainedfor spatially uncorrelated marked point processProblem i) can be solved, for example, by fittingan optimal non-parametric model (Xu et al.,2003). The second problem, however, cannot beeasily resolved. Conditions 1 - 3 can be met byusing a joint probability density function of and () for mark generation. We use simulatedannealing to incorporate the spatial auto- andcross-correlation conditions (e.g., 4 - 6 above), asproposed in Xu et al. (2007).Figure 5a shows a point realisation of the markedpoint process using a non-parametric model. Thisrealisation is generated by a Boolean object4194

Australian Geothermal Energy Conference 2009model and therefore initially the spatial auto- andcross-mark correlations of , and between and are non-existent. The realisation is then refinedby simulated annealing and, after 1300 markswaps, the final spatial mark correlation functionsare given in Figure 6a and 6b, which indicate thatthe spatial mark correlation functions are closelyreproduced at the end of the annealing process.(a)(b)Figure 5 Simulated annealing process for the example shownin Figure 3 (a) One realisation from non-parametric model,(b) One realisation of the simulated fractures after annealing,The final image of the simulated fractures, shownin Figure 5b, is not an exact replica of the originaldata (Figure 3b), but resembles the original datain the sense that the first and second moments ofthe characteristics of the corresponding markedpoint process (first and second order pointintensity characteristics, mark distributions,multivariate mark correlations and spatial markcorrelation functions) are reproduced.ConclusionsParameters of rock fractures (e.g., locations,orientation, size, aperture) are in generallyspatially correlated. The correlations must beincorporated into the fracture model for realisticsimulation of rock fracture system. Thecorrelations can be quantified by cumulativespatial mark correlation function and thecorrelations can be effectively incorporated in thefracture model by simulation annealing.1.51.31.10.9K (t)0 2005000.7Target13000.5 1000 (number of swaps)(a)0.30.94 24.35 47.76 71.18 94.591.3K (t)1.201.1 200 50010.90.8 Target13000.71000 (number of swaps)0.6(b)0.50.94 24.35 47.76 71.18 94.59Figure 6 Simulated annealing process for the example shownin Figure 3 (a) K ˆ () t vs distance t, (b) Kˆ () t vs t, (e)ReferencesBaghbanan, A. and Jing, L., 2007, Hydraulicproperties of fractured rock masses withcorrelated fractures length and aperture,International Journal of Rock Mechanics andMining Science, v. 44, p. 704-719.Barton, C.C. and Larson, E, 1985, Fractalgeometry of two-dimensional fractures networksat Yucca Mountain, Southwest Nevada,proceedings of the International Symposium onFundamentals of Rock Joints, O. Stephanson(ed.), Centek Publishers.Chiles, J.P. & de Marsily G., 1993, Stochsticmodels of fracture systems and their use in flowand transport modelling, in Flow and ContaminantTransport in Fractured Rock, eds: Bear J., Tsang,C-F, and de Marsily, G., Academic Press.Dershowitz, W. S. and Einstein, H. H., 1988,Characterizing rock joint geometry with jointsystem models, Rock Mechanics and RockEngineering, v.21, p. 21-51.Dowd, P. A., Xu, C., Mardia, K. V. and Fowell, R.J., 2007, A comparison of methods for thesimulation of rock fractures, MathematicalGeology, v.39, p. 697 – 714.5195

Australian Geothermal Energy Conference 2009Lee, C. H. & Farmer, I., 1993, Fluid Flow inDiscontinuous Rocks, Chapman & Hall, London.Lee, J. S., Veneziano, D., & Einstein, H. H., 1990,Hierarchical fracture trace model. Rockmechanics contributions and challenges,Proceedings of the 31th US Rock MechanicsSymposium, Hustrulid, W. & Johnson, G. A.(eds.), Balkema, Rotterdam.Molchanov, I., 1997, Statistics of the Booleanmodel for practitioners and mathematicians, WileySeries in Probability and Statistics, Wiley.Priest, S. D., 1993, Discontinuity Analysis forRock Engineering, Chapman & Hall, London.Stoyan, D., Kendall, W. and Mecke, J., 1995,Stochastic geometry and its applications, 2 ndedition, John Wiley & Sons, 436p.Xu, C. and Dowd, P. A., 2009, A new computercode for discrete fracture network modelling,Comps & Geosc. (in press).Xu, C. and Dowd, P. A., 2008, Plurigaussiansimulation of rock fractures, Proceedings of theEight International Geostatistics Congress, (eds.J.M. Ortiz and X. Emery), pub. Gecamin Ltd.,ISBN 978-956-8504-17-5; v. 1, p. 41-50.Xu, C., Dowd, P. A., Mardia, K. V., Fowell, R. J.and Taylor, C. C., 2007, Simulating correlatedmarked point processes, Journal of AppliedStatistics, v.34, 9, p. 1125 – 1134.Xu, C., Dowd, P.A., Mardia, K.V. and Fowell, R.,2003, Stochastic approaches to fracturemodelling. Internat. Assoc. for MathematicalGeology Conference, Sept., Portsmouth, UK6196

Australian Geothermal Energy Conference 2009Habanero Tracer Tests in the Cooper Basin, Australia: Key Results forEGS DevelopmentNorio Yanagisawa 1 *, Peter Rose 2 , Doone Wyborn 31 National Institute of Advanced Industrial Science and Technology,1-1-1,Higashi, Tsukuba, Ibaraki, 305-8567,Japan.2 Energy and Geoscience Institute, University of Utah, 423 Wakara Way Suite 300, Salt Lake City, Utah, USA3 Geodynamics Ltd, Suite 6, Level 1, 19 Lang Parade, Milton, QLD 4064* Corresponding author: n-yanagisawa@aist.go.jpThe first tracer test of an Enhanced GeothermalSystem (EGS) in Australia was conducted inDecember 2008 and January 2009. The testinvolved circulating fluid (~14 kg s -1 ) between aninjection well, Habanero #1, and a productionwell, Habanero #3, for about 66.5 days through aclosed-loop system in order to characterize theconnection between the wells (560 m separation)and to estimate the tracer-swept volume of thereservoir. Two tracers were used: uranine and1,3,5-naphthalene trisulfonate.The tracer ‘breakthrough’ occurred after 4 daysand the peak concentration occurred at 9 days.The tracer-swept pore volume was calculated tobe 18,500 m 3 which is comparable in size to thereservoir of an EGS project located in Soultzsous-Forêts,France.Keywords: Cooper Basin, Australia, EGS, HDR,granite, tracer, fluorescien, uranine, naphthalenetrisulfonate, circulationIntroductionGeodynamics Ltd began developing its EGSproject in the Cooper Basin, South Australia, in2002. Since then Geodynamics has drilled 4 deepwells (Habanero #1, #2 and #3 and Jolokia #1),commenced drilling a fifth (Savina #1), and hasconstructed the Habanero closed-loop system.The project site is located in the remote north-eastof South Australia as shown in Figure 1.In March 2008, an open loop test was carried-outachieving a 20 kg s -1 production rate at Habanero#3. On 9 December 2008 a six week circulationtest commenced. The test involved the circulationof 12 to 15 kg s -1 of geothermal fluid fromHabanero #1, through the reservoir (at a depth of~4,200 m) to Habanero #3 located 560 m away. Aweek later a tracer test was initiated with the aimof estimating the reservoir tracer-swept porevolume. Tracer testing is considered useful forestimating EGS and Hot Dry Rock (HDR)reservoir volumes (e.g., Robinson at al., 1987;Matsunaga et al., 1996). Reservoir volume isimportant because it influences the efficiency ofheat extraction and the thermal and economicpotential of EGS and HDR projects. This paperpresents the results of the first tracer test at theHabanero well field in the Cooper Basin,Figure 1: Location of the Geodynamics Limited Cooper Basingeothermal exploration sitesMethod of tracer testThe tracer test was designed with two tracers:1,3,5-naphthalene trisulfonate (1,3,5-NTS) andsodium fluorescein (‘uranine dye’). The 1,3,5-NTSdose was 100 kg in 800 l of water, and thesodiuim fluorescein dose was 50 kg, resulting in atotal tracer-mix volume of ~900 l. There were nofluid losses and the background concentrations of1,3,5-NTS and sodium fluorescein werenegligible. The tracer mix was injected intoHabanero #1 and the circulation pump wasrestarted at 16:00 on 17 December 2008. Thetracer injection and system is shown in Figure 2.Figure 2: The tracer injection system at the Habanero site1197

Australian Geothermal Energy Conference 2009Tracer Concentration (ppb)6000500040001,3,5-nts300020001000fluorescein00 10 20 30 40 50 60 70Days after start of injectionFigure 3: The fibre-optical fluorometer (left hand side) andfluid sampling panel (right hand side) used in the testcarried out at the Habanero site.Tracer concentrations in the Habanero closedloopwere monitored for about 66.5 days. A fibreopticfluorometer and fluid sampling panel areshown in figure 3. The fibre-optic fluorometer wasused to used to obtain real-time fluorescence‘counts’ which is useful for optimizing the bottledsamplesampling-rate and for comparing withlaboratory measurements (Matsunaga et al.,2001,Matsunaga et al.,2002, Yanagisawa et al.,2002,Yanagisawa et al.,2003). Fluid samples weretaken from sampling panel located downstream ofthe cooling tower. The bottled samples were sentto AIST, Japan, and to the University of Utah,USA, for chemical analysis.ResultsResults of the Continuous Field SamplingFluorescence counts were made at 5 minuteintervals between 18 December and 25 February2009 (see Figure 4). Mineral scale formed on theoptical fibre (the fluid pH was about 5.5) causingthe fluorescence counts to be relatively low andspiky. The presence of barite drilling mud andother particles in the fluid may have alsocontributed to the scatter.Figure 5: 1,3,5-NTS and fluorescein concentrations versusdays after start of injection measured in samples taken fromthe sampling panelThe fluorescence record shows a tracerbreakthrough at 4 days and a peak concentrationat about ~9 days.Results of the Laboratory AnalysisFluorescein and 1,3,5-NTS concentrations of thesamples collected over the 66.5 day sampleperiod are shown in Figure 5. Due to unscheduledpump stoppages and the need to remove scalefrom the optical fibre, the circulation was stoppedtemporarily on several occasions during the tracertest. Hiatus periods included 4 to 18 January and4 to 10 February. The data shown in Figure 5 arebased on actual sampling time regardless ofwhether the fluid was circulating or not.After 4 days of circulation the tracers weredetected and concentrations reached a peak atabout 9 days, consistent with the real-timemonitoring results. An adjusted time curve (i.e.with hiatus periods removed) was calculated byassuming a flow rate of 14 kg s -1 and by dividingthe total produced mass by the mass flow rate ateach point in flow-time (see Figure 6).Figure 6 shows the total flow volume at tracerbreakthrough was about 4000 m 3 and was about9000 m 3 at the peak concentration.6000Tracer C oncentration (ppb)500040003000200010001,3,5-ntsfluorescein00 5000 10000 15000 20000 25000 30000 35000 40000Production (m 3 )Figure 4: Habanero tracer test, fluorescein counts by opticalfibre analyzerFigure 6: 1,3,5-NTS and fluorescein concentrations versustotal fluid production measured in samples taken from thesampling panel2198

Australian Geothermal Energy Conference 2009Normalized nts/Fl3025201510500 10 20 30 40 50D ays after start of injectionFigure 7: Plots of the residence time distribution function E(t)(upper curve) and the deconvoluted E(t) (lower curve) versustimeTo compare this with the Hijiori HDR volumes: atthe first tracer test of Hijiori site, the tracer peakvolume between HDR-1 and HDR-3 occuredabout half month after starting the long circulationtest, and was about 100 m 3 . This is 90 timessmaller than the tracer peak volume at Habanero.However, the separation distance of theHabanero wells (560 m) is four times greater thanfor the Hijiori HDR-3 site (130m).Estimation of Reservoir Tracer-Swept PoreVolumeThe tracer-swept pore volume at the Habanerosite was calculated using a program developed atIdaho National Laboratory (INL) that provides astandardized method of interpreting tracer returncurves (Shook and Forsmann, 2005).The program first calculates a residence timedistribution function E(t):C(t) QE( t)Equation 1M twhere C(t) is tracer concentration, ρ is fluiddensity, Q is mass flow rate, and M t is the mass oftracer injected. The program then conducts a “deconvolution”calculation, which subtracts theeffects of tracer recirculation to create a new E(t)function.This calculates what the tracer return curve wouldlook like if the tracer had been removed from thecirculation fluid at the production well after makingonly one pass through the reservoir. The programthen extrapolates the return curve to infinite timeassuming exponential decay. It then calculatesthe fraction of tracer-returned, a mean reservoirresidencetime and the reservoir pore volume.As described above, a constant flow rate of 14 kgs -1 was assumed for the duration (41 days) inwhich 50.4 tonnes of brine was circulated. Shownin Figure 7 (upper curve) is a plot of the residenceFigure 8: Normalized tracer concentration ratio 1,3,5-nts (nts)and fluorescein (fl) versus time.time distribution function E(t). The lower curve isthe de-convoluted E(t) curve.Based on the assumptions described above, themean residence time was 23.7 days and thefraction of tracer returned was 0.78. Thecalculated tracer-swept pore volume was 18,500m 3 . For comparison, a calculation using the samesoftware and the tracer and flow data associatedwith the 1997 GPK1-to-GPK2 doublet test atSoultz-sous-Forêts, France, yielded a porevolume of 16,000 m 3 (Rose et al, 2006). Thedistance between production and injection well ofthe Habanero site is around 560 m and similar tothe Soultz site.Estimation of Reservoir TemperatureFluorescein will decompose at temperaturesgreater than 200 ° C, whereas 1,3,5-NTS isthermally stable. From the ratio of 1,3,5-NTSconcentration to fluorescein concentration, thereservoir temperature may be estimated with priorknowledge of the temperature-to-half-liferelationship for fluorescein.The concentration ratio of 1,3,5-NTS andfluorescien normalized by injected tracer amountis shown in Figure 8. At about 13 days, theconcentration ratio rapidly changed from 2.2 to 7and after 13 days, the ratio gradually increasedfrom 7 to 10. This means that the half-life of thefluorescein was ~3 days and the reservoirtemperature was approximately >250 ° C.The scatter in the chart may have been due, inpart, to the cooling effects of re-injection (referFigure 7).SummaryThe first EGS tracer test in Australia was carriedout at the Habanero well field in the CooperBasin, South Australia, in 2008-2009. The mainresults of tracer test are as follows:3199

Australian Geothermal Energy Conference 20091) Tracer breakthrough occurred 4 days aftertracer injection and tracer peak occurred about 9days after tracer injection;2) Based on an average flow rate of 14 kg s -1 thetotal flow volume at tracer breakthrough was~4,000 m 3 and the total flow volume at tracerpeak-concentration was ~9,000 m 3 ;3) The tracer-swept pore volume of the Habaneroreservoir is about 18,500 m 3 and is comparable insize to the Soultz-sous-Forêts EGS reservoir; and4) Based on the thermal properties of fluorescienand 1,3,5-NTS, the reservoir temperature isestimated to be >250°C.AcknowledgementsThe research described in this paper has beensupported by Geodynamics Ltd. The authorswould like to thanks Kevin Brown, Lew Bacon,Leonard Spencer and Bill Austin for helping ourtests and providing samples and data.ReferencesMatsunaga, I., Tao, H and Kimura A.,1996,Preliminary Characterization of the Hijiori HDRDeeper System by Fluid Geochemistry and TracerExperiments of a One-Month Circulation Test,Proceedings of 3rd International HDR Forum, p.25-26.Matsunaga, I. Sugita. H., and Tao, H., 2001,Tracer Monitoring a Fiber-Optic FluorometerDuring a Long-Term Circulation Test at the HijioriHDR Site, Proceedings of 26th StanfordWorkshop on Geothermal Reservoir Engineering,p.74-77.Matsunaga, I., Yanagisawa, N., Sugita. H., andTao, H., 2002, Reservoir Monitoring by a Tracertesting During a Long-Term Circulation Test at theHijiori HDR Site, Proceedings of 27th StanfordWorkshop on Geothermal Reservoir Engineering,P.101-104.Robinson, B.A., Aguilar, R.G., Kanaori, Y., Trujillo,P., Counce, D., Birdsel, S., and Matsunaga, I.,1987, Geochemistry and tracer behavior during athirty day flow test of the Fenton Hill HDRreservoir, Proceedings of 12th Workshop onGeothermal Reservoir Engineering, 121-135.Rose, E. P.,1998, The Use of PolyaromaticSulfonates as Tracers in High TemperatureGeothermal Reservoirs, Proceedings of 20th NZGeothermal Workshop, p.239-243.Rose, P.E., Mella, M., and McCullough, J., 2006,A Comparison of Hydraulic StimulationExperiments at the Soultz, France and Coso,California Engineered Geothermal Systems,Proceedings, Thirty-First Workshop onGeothermal Reservoir Engineering, StanfordUniversity, SGP-TR-179.Shook, G.M. and Forsmann, J.H., 2005, TracerInterpretation Using Temporal Moments on aSpreadsheet, Idaho National LaboratoryTechnical Report.Yanagisawa, N., Matsunaga, I., Sugita, H. andTao, H., 2002, Reservoir Monitoring by TracerTest of a 2001 Long Term Circulation Test at theHijiori HDR site, Yamagata, Japan, GeothermalResources Council Transactions, 26, p.267-271Yanagisawa, N., Matsunaga, I., Sugita, H. andTao, H., 2003, Reservoir Monitoring by TracerTest of a 2002 Dual Circulation Test at the HijioriHDR site, Yamagata, Japan, GeothermalResources Council Transactions, 27, p.785-7904200

Australian Geothermal Energy Conference 2009Two Basic Problems for Hot Dry Rock Reservoir Stimulation andProductionXi Zhang, Rob Jeffrey*, and Bisheng WuCSIRO Petroleum Resources, Melbourne, Australia*Tel: 03-95458354, E-mail: rob.jeffrey@csiro.auA numerical analysis is made for heat extractionfrom a geothermal reservoir in a naturallyfractured rock mass. We consider in particular twoissues: long-term prediction of fluid temperaturearound a single fracture and the initial stages offracture development in a naturally fractured rock.For the first problem, the evolution of outlet fluidtemperature is considered as a function of timeand injection rate. The rock temperature around asingle fracture in the reservoirs is also calculated.The second problem is motivated by the fact thatinjection pressure is highly dependent on thedetails of fracture geometry near the borehole.High treatment pressure are associated with theformation of opening mode hydraulic fractures innaturally fractured rock and recent result that canexplain the origin of these pressures are appliedhere to the problem of high injection impedance atpressures below the jacking pressure.Keywords: Hot Dry Rock, fluid flow, thermal effect,crack growth, numerical methodIntroductionIn stimulation and operation of an EnhancedGeothermal System (EGS), fluid circulation isinfluenced in both the short and long-term bythermal-hydro-mechanical deformation. In otherwords, the efficiency for hot-dry-rock reservoirstimulation and production depends on fractureinterconnectivity and thermal flux interchangesbetween rock and fluid coupled to fracturepermeability (Bodvarsson, 1969; Hallow andPracht, 1972; Gringarten, et al., 1975; Abe et al.,1976; Cheng et al., 2001). We present resultsfrom two problems that, at this point, includelimited coupling. The first problem involvescalculation of the evolution of heat transferbetween rock and fluid over a long period of timeand the second problem considers the effect ofpre-existing fracture interconnectivity along a nonplanarpath on injected fluid pressure and crackgrowth. Both problems are useful indemonstrating the importance of coupledprocesses, e.g., thermal-hydraulic coupling for thefirst problem and hydraulic and mechanicaldeformation coupling for the second problem. Weare working towards a thermal-hydraulicmechanicalcoupled analysis of both problems.We first address the interaction between the longtermheat extraction and fluid flow and heatconduction in both rock and fluid. The cooling ofrock around an axisymmetric reservoir containinga single conductive fracture is discussed. In thesecond part of this paper we give a detailed studyon how a fracture propagates through a fracturenetwork that guides its path. The spatially varyingfracture conductivity that results from stressdependentfracture permeability has a strongeffect on the fluid pressure distribution. As aresult, the injection pressure is found to beelevated.Thermal Analysis of Penny-ShapedFracture Reservoirsp=p ir er wFigure 1: An axisymmetric penny-shaped geothermalreservoir.Fracture conductivity and fluid flowFor a large naturally fractured geothermalreservoir, Pine and Batchelor (1984) found thatthe fracturing during injection was dominated byshear and associated dilation. For simplicity,shear deformation caused by far-field stressesinteracting with the injected fluid pressure is notconsidered in this simple thermal-fluid modelpresented here and the reservoir is considered toconsist of a impermeable layer of a finitethickness H, as shown in Fig.1. The reservoirlayer is assumed to axisymmetric, with productionwells located at the periphery of a circle with aradius re. The conductivity between the injectionand production wells is provided by a singleconductive fracture located at the midplane of thereservoir for the analysis of fluid flow and heatconduction. Practically, this closed but conductivefracture model, which uses an effective hydraulicaperture (

Australian Geothermal Energy Conference 20092w0k (1)12where k is the fracture permeability and w 0isthe effective hydraulic aperture for the closednatural fracture. We assume that the smallroughness present and induced changes in thehydraulic aperture along the natural fracture canbe ignored because the aperture change occurswith a small slope so that the cubic law is stillvalid (Brown et al. 1995).Darcy’s law is used to describe fluid flux inresponse to fluid pressure gradient pqfk pf(2)where is the fluid dynamic viscosity.Problem statementAs shown in Fig. 1, a fluid (at temperature T i) isinjected into the reservoir at a constant rate Q .The production wells are assumed to be uniformlydistributed along the periphery of the reservoirwith a constant production pressure po, so thatthe fluid flow and temperature changedistributions are axisymmetric. The reservoirheight is H, which also represents the spacingbetween conductive fractures in the reservoir orthe designed fracture interval.Based on fluid mass continuity, the governingequation for pressure diffusion in theaxisymmetric fracture is given bypft p cr2f(21 pf )r rf(3)where c k / and is the elastic porecompressibility.The solution to the above equation at givenboundary and initial conditions can be found in themonograph by Carslaw and Jaeger (1959).Let qhdenote the heat flux from rock to fluid atthe fracture surface. Based on previous studies(Abe et al., 1983; Cheng, et al., 2001), the heatdissipation and storage along the fracture can beneglected. For the axisymmetric problem posedabove, the heat transfer equation along thefracture surface can be written as (Abe et al.,1983; Cheng, et al., 2001)Tfwcqw f. qh0r(4)where Tfis the temperature along the fracture,and wand cware the mass density and specificheat of the fluid.In the presence of heat exchange between rockand fluid, the rock temperature will vary in theform oftre2 1 rrTrT q3/2 hI0 [4 ( )] 2 ( )0 rttrw rtt2 2 2 r rzexprdrdt 4 r( tt)(5)where T is the initial uniform temperature of therock, the rock thermal diffusivity isr Kr /( rcr)in which Kris the rock thermalconductivity, and rand crare the mass densityand specific heat of the rock. Finally, I 0is themodified Bessel function of the first type.Based on the continuity of temperature across thefracture surface, the governing equation fortemperature change can be established byconsidering the equivalence of fluid temperaturecalculated by Eq. (4) and the rock temperature atthe fracture surface by Eq. (5). This leads to anintegral equation, which can be solvednumerically by the collocation method. Moreover,the corresponding initial and boundary conditionsare not listed here to save space.Numerical resultsAs an example, we consider the case of reservoirradius re=300 m and wellbore radius r w=0.1 m,and initial rock temperature of 270°C (or 543 K).Water with a constant viscosity =0.0004 Pa·s,although we recognise that the viscosity willdepend on temperature, is injected into thefracture at a constant rate Q=20 l/s and at aninitial temperature of 70°C (or 343 K). Thereservoir height or thickness is H=0.5 m. Thefracture hydraulic aperture w0is 1 mm. The rockthermal conductivity Kr=2.4 W/m·K, and the rockmass density and heat capacity are r=2700kg/m 3 and cr=1000 J/kg·K, respectively. The fluidtemperature at the outlet is plotted againstelapsed time in Fig. 2 and the temperaturecontours in the rock, at 1.92 and 14.26 years afterthe start of injection, are shown in Fig. 3.2202

Australian Geothermal Energy Conference 2009Normalised Temp (T/T 0 )1.110.90.80.710.19 Yearsinjection temperature T w14 Years3D problem, it is here treated as a plane strainproblem instead.Q0=0.0004 m^2/s30 MPa4m0.4mE=50 GPa=0.22K IC =1.0 MPa m 0.50.60.E+00 1.E-03 2.E-03 3.E-03 4.E-03 5.E-03 r *t/r e /r eFigure 2 Normalised fluid temperature at production wellagainst timez(m)z(m)40302010t=1.92 years00 50 100 150 200 250 30040302010r(m)temperature (K): 340 360 400 440 460 500 520 540t=14.26 years00 50 100 150 200 250 300r(m)Figure 3 Temperature contours in the reservoir rock betweenthe injection and production wells. The production well is atr=300 m.Fracture Growth along an OffsetNatural FractureAs the geothermal reservoir is comprised ofnaturally fractured rock, the injected fluid will moreor less follow the path defined by existingconductive fractures. In particular, injected watermay reach a pressure sufficient to open someportions of natural fractures near the injectionwellbore. The fluid flow is guided by theconductive channels and analysis of this probleminvolves tracking the strong coupling betweenrock deformation and fluid flow. The induced nearboreinflow restriction can limit fluid productioneventually. To start, we idealise the fracturegeometry as shown in Fig. 4. We consider thepressure and crack opening responses wheninjection is located at the start of a natural fracturethat contains several offsets along its path (Fig.4). The fracture geometry including the step andoffset sizes and their intersection angle areshown in the figure, along with the far-fieldstresses and material constants used. The closednatural fracture is assumed to be conductive withan initial hydraulic aperture w 0. In this section,w0is 0.01 mm for all cases, unless otherwisespecified. Although the real situation results in a15 MPaFigure 4 Schematic of an offset natural fracturewith fluid injected at one end. KICis the fracturetoughness of the rock.Fracture slip modelFracture frictional slip along parts of the fracturecan be important in this case since there is astrong horizontal compressive far-field stress. Weuse the Coulomb frictional law, which is appliedlocally to the cohesionless, but frictional fracture,to provide a limit on the frictional stress sinterms of the normal effective compressive stress, ,np f p )(6)s(n fwhere is the coefficient of friction and ( n pf) is the frictional strength. For the dryportion of the fracture pf 0 . In this paper, =0.8 for all cases.Hydraulic fracturing modelAs fractures can be opened by fluid pressure,elastic deformation associated with fluid flow mustbe considered here. The governing equation forfracture equilibrium is given as follows in thepresence of multiple cracks,Nl1 r 1 0 11xr ( x,t) ( x) [ G ( x,s)w(s)G12(nNl1 r 1 0 21xrs( x,t) ( x) [ G ( x,s)w(s)G22(, s)v(s)]ds(7), s)v(s)]ds(8)where N is the number of cracks, G ( ,=1,2) are Green’s functions, wv , are openingand shearing displacement discontinuities acrossthe fracture surface, and 1, 1are the normaland shear stresses, respectively, acting along thefracture direction at location x generated by thefar-field stresses.In the existence of fracture opening (hydraulicfracturing), the fluid flow along the fracture can be3203

Australian Geothermal Energy Conference 2009described by Reynolds’ equation as follows(Batchelor, 1967)(w ) ( w ) [ts 123Pfs](9)where . It should be noted that the totalhydraulic opening is the sum of fracturemechanical opening and initial hydraulic aperture . Furthermore, the hydraulic aperture can varywith the effective stress in the closed fracturebased on a liner spring model, that is,d/ dpf (10)in which is a small constant for characterizingthe compliance of a natural fracture with respectto pressure change (1/Pa), and is assumed to beless than 10 -8 /Pa for most cases.The above system of equations provides allgoverning equations for hydraulic fracture growth.The required initial and boundary conditions arenot given here and the reader can refer to ourprevious work for more details (Zhang et al, 2008;Zhang and Jeffrey, 2008).Numerical resultsFor the case that water is used as injection fluid,the fracture opening along the offset fracture isshown in Fig. 5, at a time when the fluid justreaches the fracture tip. It is clear that there is anarrow channel at the offset locations. Anincrease in the offset angle results in a narroweropening in this portion of the fracture (Fig. 5).through the narrow offsets, which have loweropening compliance and are subjected to higherconfining stresses.Injection Pressure (MPa)22212019181716Hydraulic fractureStraight natural fracture150 10 20 30 40 50 60 70Time (s)Thita=45, offset natural fractureFigure 6 Pressure at the borehole against timecorresponding to the cases shown in Fig. 5.The effect of narrow offsets on the injectionpressure, at pressures below the openingpressure, can be seen in Fig. 7 where the fluid isinjected into the fracture at a very low injectionrate Q0=1E-7 m 2 /s. The initial hydraulic aperturew0of the steps is increased to 0.05 mm toaccount for the relatively lower confining stressacting across them. Fig. 7 shows the variation ofinjection pressure against time when the kinkangle is 45 degree. Even though the injected fluidpressure is below the confining stress so that nofracture opening occurs, a pressure increase isevident when the fluid front crosses the narrowoffset region. Near-wellbore injection impedancemay partly result from the injected fluid flowingalong such tortuous pathways.0.0180.016small initial conductivity (w 0=0.01mm)4.0E+003.5E+00Opening (m)0.0140.0120.0100.0080.0060.004thita=90thita=75thita=45thita=0Injection Presure (MPa)3.0E+002.5E+002.0E+001.5E+001.0E+000.0025.0E-010.0000 5 10 15 20Position along the fracture (m)Figure 5 Fracture opening along the offset natural fracturewhen a hydraulic fracture is growing along it.Figure 6 shows the time-dependent variation ofthe injection pressure for the offset naturalfracture. Although the pressure decreasessmoothly in time for a hydraulic fracture and foropening of a natural fracture without offset, itoscillates at an elevated level in the case of offsetnatural fractures. This reflects the differentresistance for fluid flow along steps and offsets.When the fluid propagates along the steps, it willmove at a lower pressure gradient. This results inpressure decreasing with time, in contrast to theincrease in pressure occurring when flow is0.0E+000.0E+00 2.0E+03 4.0E+03 6.0E+03 8.0E+03 1.0E+04 1.2E+04Time (s)Figure 7 Pressure at the borehole against time in the case oflow injection rate.Summary and DiscussionWe have presented numerical results for twobasic problems, which are associated with thethermal-fluid coupling and fluid-mechanicalcoupling problems that arise in predictingtemperature and fluid flow through a naturallyfractured hot rock reservoir. From the analyses,the coupling between different mechanisms playsan important role in correctly predicting thetemperature and fluid pressure changes. We4204

Australian Geothermal Energy Conference 2009intend to next implement thermoelastic coupling inthe 2D model used above.In the first model, we have not considered theeffect of elastic deformation. As we know, sheardeformation assisted by surface roughness caninduce fracture shear-induced dilatation thatincreases the fracture conductivity. Also, thereduction in effective stress caused by fluidpressure and the thermoelastic deformationresulting from cooling of rock can increase thefracture permeability. Chemo-mechanicalprocesses should also be considered. Theseeffects have been studied by coupled reservoirmodels (Min et al., 2008). Our approach is toextend our 2D hydraulic fracture model to includethermoelastic effects and apply it to the coupledmechanics of complex fracture geometries toanalyse mechanism leading to local near-wellboreelevation of injection impedance. The results ofthis detailed mechanical modelling can then beincorporated in a more simplified way intoreservoir-scale models.ReferencesAbe, H., Mura, T., and Keer, L. M., 1976, Growthrate of a penny-shaped crack in hydraulicfracturing of rocks, J. Geophysical Research vol81, p5335-5340.Abe, H., Sekine, H. and Shibuya, Y., 1983,Thermoelastic analysis of cracklike reservoir in ahot dry reock during extraction of geothermalenergy, J of Energy Resources Technology vol105, p503-508.Batchelor, G.K., 1967, An Introduction to FluidDynamics, Cambridge University Press,Cambridge, U.K.Bodvarsson, G., 1969, On the temperature ofwater flowing through fractures’, J GeophysicalResearch vol 74, p1987-1992.Brown, S. R., Stockman, H. W. and Reeves, S. J.,1995 Applicability of the Reynolds equation formodelling fluid flow between rough surfaces,Geophysical Research Letter vol 22, p2537-2540.Carslaw, H. S. and Jaeger, J. C. 1959,Conduction of heat in solids, Oxford UniversityPress, Oxford, U. K.Cheng, A. H.-D., Ghassemi, A. and Detournay, E.,2001, Integral equation solution of heat extractionfrom a fracture in hot dry rock, Int. J. forNumerical and Analytical Methods inGeomechanics vol 25, p1327-1338.Gringarten, A. C., Witherspoon, P. A. and Ohnishi,Y., 1975 Theory of heat extraction from fracturedhot dry rock, J. Geophysical Research 80, p1120-1124.Hallow, F. H. and Pracht, W. E. 1972 A theoreticalstudy of geothermal energy extraction, J.Geophysical Research vol. 77, p7038-7048.Min, K.-B., Rutqvist, R., and Elsworth, D., 2008,Chemically and mechanically mediated influenceson the transport and mechanical characteristics ofrock fractures, International Journal of Rockmechanics and Mining Science vol. 46, p80-89.Pine, R.J. & Batchelor, A.S., 1984, Downwardmigration of shearing in jointed rock duringhydraulic injections, International Journal of Rockmechanics and Mining Science andGeomechanics Abstract vol. 21, p249–263.Tsang, Y. W. and Witherspoon P. A., 1981,Hydromechanical behavior of a deformable rockfracture subject to normal stress, Journal ofGeophysical Research vol. 86, p9287-9298.Zhang, X. Jeffrey, R. G. and Thiercelin, M., 2008,Escape of fluid-driven joints from beddinginterfaces: A numerical study, J. StructuralGeology vol. 30, p478-490.Zhang, X. and Jeffrey, R. G., 2008, Re-initiation ortermination of fluid-driven fractures at frictionalbedding interfaces, J. Geophysical Research vol113, B08416.5205

Australian Geothermal Energy Conference 2009The Feasibility of a Nocturnal Radiative Heat Dissipation System forRemote Geothermal ApplicationsJoshua S Brimblecombe, Thomas J Vos.University of Queensland, Q 4067Supervisor: Hal GurgenciAs the worldwide demand for energy increases,focus has shifted from conventional coal or gasfired plants towards the development ofsustainable ‘green’ energy sources such as solar,hydroelectric, wind and geothermal. Energysources can be deemed sustainable if the rate atwhich energy is replenished is greater than therate of energy used. Geothermal energy hasadvantages over solar and wind in that operationof a geothermal plant is not sensitive to theweather conditions. Geothermal power stationsuse the heat from beneath the surface of the earthto operate a power cycle rather than the burningof hydrocarbons.Types of Geothermal EnergyThere are four main types of geothermal source –hydrothermal, geopressured, magma and hotfractured rocks (HFR). Of these, the onlytechnology currently in use in power stations ishydrothermal. A hydrothermal plant uses anaturally occurring underground artesian aquiferto provide heat to the cycle. Two bores are drilledto allow the hot brine to be pumped to the surface.The concept of hydrothermal power is not newwith many plants operating in countries aroundthe world. There is currently an estimated45000MW of generating capacity in hydrothermalgeothermal resources worldwide (RISE 2008).Hot Fractured RocksMost of Australia’s geothermal potential, however,is in HFR. HFR geothermal energy is the onlyknown source of renewable energy able tocontinuously meet base load power requirements.For a site to be acceptable for HFR energyextraction, however, it has to meet certainimportant criteria. The geology of the site mustconsist of hot granite (at least 250°C) at a depthof around 4km beneath the surface of the earth.This “Hot rock” layer must be insulated by at least3km of sedimentary rock.Figure 2 shows the crust temperature variationthroughout Australia at a depth of 5km. At atypical site, two holes would be bored into thecrust. Cold fluid would be pumped down oneside, heated by the hot granite layer and drawn upthe other side. Typically, granite layertemperatures in Europe are around 180°C,illustrating the potential Australia has for this sortof power generation.Figure 1 - Typical geological layout of a HFR site. This diagramcan be obtained from the Geodynamics website:http://geodynamics.com.au/IRM/content/educationroom.htmlFigure 2 – Crust temperature at a depth of 5km. This imagecan be downloaded from the Research Institute forSustainable Energy at:http://www.rise.org.au/info/Res/geothermal/index.html. AfterSomerville et al. 1994.It is only recently, with research into Hot FracturedRock technology, that the implementation ofgeothermal energy in Australia has becomefeasible. Potential sites have been identifiedthroughout Australia for the development ofgeothermal power. The Cooper Basin is one ofthe largest geothermal resources in the world withan estimated 1.9 × 10 21 J of available energy(Somerville et al. 1994).Design ChallengeThe remote location of Australia’s geothermalresources presents a problem with respect tocooling. Typically, a power station will use a wet1206

Australian Geothermal Energy Conference 2009cooling tower to dump waste heat from the powercycle. In Australia alone, coal fired power plantsconsume 300 gigalitres of water per year –quantities which are not feasible at theselocations. In order to operate an efficientgeothermal plant, a new method of cooling mustbe developed.One potential solution is the implementation of anocturnal cooling system (NCS). CentralAustralia typically experiences minimal cloudcover. This, combined with low humidity, allowsfor large radiative heat losses at night time. Thisis commonly referred to as nocturnal cooling. ANCS makes use of these conditions at night todissipate heat from a coolant fluid and store the“coolth” for use during the daytime.InvestigationThe aim of this investigation is to explore thefeasibility of a nocturnal radiative cooling systemfor a remotely located geothermal power plant inAustralia. This has been aided by theconsideration of the following aspects:Theoretical and experimental effectiveness ofradiative heat dissipation techniques,Evaluation of coolant mass options, and Associated heat exchangers.This investigation will look into the performance ofa test facility operating under specified conditionsat a location near Innamincka. Weatherconditions for the nearby town of Moomba wereassumed to be indicative of ambient conditions inthis area.This investigation will consider a binarygeothermal system heating brine to 225°C tosupply heat to a transcritical CO 2 Brayton cycle forthe generation of work (Dostal, Driscoll andHejzlar 2004). The details of the design pointcycle are included in Table 1.Table 1 - Cycle PropertiesDesign ParametersValueAmbient Temperature T a 30°CBrine Temperature T b 225°CH-Ex Pinch Points ΔT 8 °CCold-side Pressure P c 8 MPaHot-side Pressure P h 22 MPaIn order to operate successfully, a power plantmust have a constant power output. One of thekey disadvantages of the transcritical CO 2 cycle isits high sensitivity to ambient conditions. For thepurpose of this investigation, the design pointambient temperature is 30°C. With ambienttemperatures peaking at almost 50°C, it can beseen that the power generation from the plantdrops to almost 30% of the design power. ItFigure 3 - Sensitivity of Power Generation against AmbientTemperaturebecomes apparent that a secondary system isrequired to maintain design performance.As such, a two stage cooling system wasinvestigated with the assumption that a drycooling tower exists with the capacity to cool thecycle fluid to within 8°C of the ambienttemperature. The design of such a tower,however, is not within the scope of this report.Experimental InvestigationThe purpose of the experimental analysis is toassess the cooling capacity for a typical night timeperiod in Brisbane by estimating the effective skytemperature. This directly influences the radiativeheat flux.Experimental setup involves measuring thetemperatures of a flat plate exposed to the nighttime sky. The plate, acting as a lid, is positionedon top of an insulated enclosure that is kept at aconstant temperature throughout the testingperiod. It is expected that radiation rather thanconvection will dominant the heat loss from thesurface.The test plates are approximately 35 x 25 cm andare made of mild steel (coated and uncoated) andPVC. Emissivity is influenced by materialproperties as well as the surface finish. As heatloss due to radiation is proportional to emissivity(see Equation 1), different test plates areexpected to have different heat fluxes.(1)Since the walls and bottom of the enclosure areinsulated, all heat will be dissipated through thetest plates. At equilibrium, the boundaryconditions for the setup can be describedaccording to equation 2:(2)The heating for the experiment is supplied by twoincandescent light bulbs.2207

Australian Geothermal Energy Conference 2009Ideal testing conditions are when the sky is clear,humidity levels are low, and little wind isexperienced. Using that data gathered from theexperiments, a statistical analysis will provideestimates for the effective night time skytemperature. The results will be compared toempirical relations set out by Berdahl and Martin(1984).Tests will be conducted on the roof of the HawkenEngineering building at the University ofQueensland.Coolant SystemThe aim of the proposed NCS is to maintain aconstant compressor entry temperature ofT c =38°C both during the day and night throughoutthe entire year. The proposed system consists ofa number of separate components, including: Coolant mass,Coolant storage system,Heat exchangers, and Radiative arraysA detailed performance analysis has been carriedout on the completed system for the purpose ofevaluating the steady-state performance undervarying atmospheric conditions. Figure 4 showsthe typical power output throughout the year for aparticular design solution. Dark points representa power output below the design point (35MW).Coolant Mass and Storage systemA simple coolant system with a fixed coolant flowrate has been considered in this case. It wasfound that the flow rate of coolant through theradiative arrays had only a minor influence on theamount of heat dissipated, so long as the flowrate was sufficiently high as to avoid largechanges in temperature in the coolant.Simulations carried out with moderate coolanttank sizes give reasonable results – almost 100%design point operation can be attained with 10 8 kgwater. Moderate operation, however, isachievable with masses as low as 4×10 7 kg with3% operation below design point and a minimumoutput work of 32MW (DP=35MW).Radiative ArraysIn order to dissipate heat, a simple tube-finradiative system was assessed. A pipe of length(L) has two radial fins (each of length x andthickness t). The temperature distribution (andhence heat flux) through these fins is governed byEquation 3.2d T dAs4 4 TT2e(3)dx A k dxcEquation 3 is solved numerically to yield thetemperature distribution along the radial directionof the fin. A typical temperature distributiondescribed by this equation is shown in Figure 5.Note that heat flux along the direction of the pipewas considered negligible. This is a validFigure 4 – Typical Seasonal variation of power output for Mc=6.4x10 7 kg coolant, Pipe length, L=100m,3208

Australian Geothermal Energy Conference 2009Temperature, T (K)31030029010.8Figure 5 – Typical Temperature Distributionassumption, as the temperature gradient isapproximately 0.02 K/m whereas the gradientalong the fins is on the order of 10 K/m. For thepurpose of this investigation, both copper andsteel plates were considered with a surface finishgiving an emissivity of 0.8.Economic EvaluationEvaluation of this system and recommendationswill be based on both power output and economiccost. Estimates of the initial capital andmaintenance costs for each section of the stationare to be made. Also included will be the revenuefrom the power generated with the aim ofproviding a break-even date.Summary0.6 0.4Fin Width, x (m)Because of the remote arid location of Australia’smain geothermal sources, conventional coolingprocesses are not feasible. The climaticconditions in this area, however, are ideal for0.200200100Tube length,L (m)nocturnal cooling. This investigation will examinethe viability of nocturnal radiative cooling incombination with thermal storage.ReferencesDostal, V, Driscoll, M, Hejzlar, P 2004, ‘Asupercritical carbon dioxide cycle for nextgeneration nuclear reactors’, PhD Thesis,Massachusetts Institute of Technology,Massachusetts.Geodynamics 2006, HFR Geothermal EnergyFact Sheet, viewed 2nd April 2009, .Laird, J 2008 Optimisation of a Solar-GeothermalHybrid Power Plant, Undergraduate thesis, TheUniversity of Queensland, Australia.Massachusetts Institute of Technology 2006,Future of Geothermal Energy, U.S. Department ofEnergy, Idaho .Parker, D 2005, Theoretical Evaluation of theNightCool Nocturnal Radiation Cooling Concept,FSEC-CR-1502-05, Florida Solar Energy Centre,Cocoa.Research Institute for Sustainable Energy 2008,Geothermal Energy, Murdoch University,Australia.Somerville, M., Wyborn, D., Chopra, P., Rahman,S., Estrella, D. and Van der Meulen, T. 1994. HotDry Rocks Feasibility Study. Energy Researchand Development Corporation. Report 243.133pp.4209

Australian Geothermal Energy Conference 2009Low Temperature Difference Electricity Generation Using ORCDr. Matthew Bryson 1* , Simon St Hill 2 , Vikram Joshi 2 , Chris Dixon 11 RMIT University, PO Box 71, Bundoora, Vic 3083.2 Air International Thermal Systems, 80 Turner Street, Port Melbourne, Vic, 3207.* Corresponding author: matthew.bryson@rmit.edu.auMany geothermal sites in Australia have lowtemperature water as an available heat source.Often this temperature is under 75°C, inconditions where ambient temperatures can climbinto the mid 30°s on a regular basis. These heatsources have often been considered to have aninsufficient temperature difference, with respect tothe atmospheric heat sink, to be worthwhile fordriving a heat engine. As the temperaturedifference reduces, the maximum achievableefficiency must also reduce as demonstrated byclassical thermodynamics. Thus, as thetemperature difference drops, it is a matter ofimproving component efficiencies while reducingcosts to make such systems viable. Lowertemperature systems frequently use an OrganicRankine Cycle (ORC) heat engine. As thetemperatures drop, the key parameters in thedesign of such systems become cost andefficiency. Of prime importance is the cost of theexpander, efficiency of the heat exchangers, andthe precision of the control system. The maininvestigations presented are: The reduction in system cost throughselection of alternatives to turbine expanders. The selection of an optimised working fluid forlow temperature operation.Keywords: Organic Rankine Cycle Heat Engine,low grade heat, low temperature differenceelectricity generation, hydrothermal energy, lowtemperature geothermal.Low Grade Heat Sources in AustraliaLow grade heat (LGH) sources, here defined asbelow 100°C, are available throughout Australia.The utilisation of renewable energy sources (suchas geothermal and solar thermal power) has beena topic in vogue recently and these sources lendthemselves cost effectively to providing LGH thatcan then be transformed into other forms ofenergy. Low grade waste heat sourced fromindustrial processes can also be converted intoelectricity and therefore improve the efficiency ofthese industrial processes and consequentlyadvance the pursuit of cost reduction andsustainability in industry. LGH is widely availablefrom these industrial sources and includes theheat energy not utilised in absorption chillers,process condensate and cooling water from arange of industrial processes.Australian hydrothermal resourcesAustralia has hydrothermal resources at a numberof locations throughout the continent. Notableareas where hydrothermal energy is easilyaccessible include the Otway and GippslandBasins (King et al 1985; Sinclair Knight Mertz2005), the Perth Basin (Ghori 2008) as well as theGreat Artesian Basin (Burns et al. 1995; Pirlo2004). Direct heating applications have beenapplied to the heated waters of the Gippsland andOtway Basins (Burns et al. 2000) and the GreatArtesian Basin has been used to produceelectricity on a small to moderate scale with theMulka Station (now closed) and Birdsville ORCinstallations (Sawyer 1991; Burns et al. 1995;Burns et al. 2000). The Great Artesian Basingeothermal resource, used as the heat source forthe Birdsville plant, has the highest temperature ofthe resources described. The power stationutilises a 1230m deep bore delivering 27l/s of98°C water to provide heat energy to the plant(EPA Qld 2005). The other three hydrothermalresources mentioned previously in this sectionhave considerably lower temperatures associatedwith them. The reason for exploiting these lowtemperature hydrothermal resources is tocapitalise on the relative ease in accessing themand thus save on drilling costs.Figure 1: Map of projected temperatures at 5km depth andheat flows for Australia. The areas of darkest blue indicate atemperature of 80°C at 5km depth. The image ofAustherm07 from proprietary information owned by EarthEnergy Pty Ltd (sourced from Geoscience Australia 2007).Figure 1 is a diagram that many people arefamiliar with and is a projection of thetemperatures at a depth of 5km. It can beobserved from the figure that for most of thecontinent, the projected temperature at that depth1210

Australian Geothermal Energy Conference 2009is around 80°C. It can also be seen that theselow temperature areas cover the nationalpopulation centres and the higher projectedtemperatures are a considerable distance fromthe major cities.In 1999 Kanoglu and Cengel calculated that thecost of drilling to a depth of 5km could cost 2 ½times the cost of the power plant itself. Ruge(1999) contended that to drill 3.5 km into theDilwyn Aquifer in the vicinity of Portland Victoriawould cost A$1.98 million. For current projects,drilling to the depths to utilise ‘hot dry rock’ energyin Australia would be between A$15 million andA$37 million according to Goldstein et al (2008).This costing is backed up by a report prepared forthe Australian Geothermal Energy Association bythe consultants McLennan Magasanik AssociatesPty Ltd (2008). One proponent of the studyconducted by McLennan Magasanik AssociatesPty Ltd (2008) suggested ‘the cost of drilling to4,500 metres was four times the cost of drilling to3,000 metres’. One way to avoid the high costs ofdeep drilling is to avoid going to such depths as isrequired with Australia’s geology to source highgrade heat. Instead, it may be more cost effectiveto instead utilise lower grade heat.Heat Engines for ElectricityGeneration from Low Grade HeatSourcesCurrently, the lowest cost method of convertinghigh grade heat into electricity is through the useof a heat engine. This statement holds true forlower temperature heat sources as well, but asheat source temperatures drop, the units have tobe scaled up to achieve the same output. This isdue to the compounding effects of 1) the amountof energy contained in lower temperature streamsbeing less and 2) the efficiency of conversionbeing lower. The result is increased capital costsper unit output. The way to improve the utilisationof lower temperature heat sources, and therebymake use of underexploited resources or reclaimwasted energy, is to reduce the costs ofemploying heat engines for converting lowergrade heat into a higher form of energy such aselectricity. Investigations have been conductedinto the cost drivers for ORCHEs by those suchas Schuster et al. (2009) and Leibowitz et al.(2006), albeit for source temperatures around100°C and above. These studies showed thepossibility of designing commercially viable heatengines for those temperatures. Care has to betaken with the design of the employed cycle andthe selection of components for use within theseheat engines as the capital cost makes up thevast majority of the lifecycle cost of theequipment.Thermodynamic cycle selectionOne of the more fundamental design decisions tobe made when developing a heat engine for usewith LGH is the choice of thermodynamic cyclearound which the machine will be based.Considerable amounts of research have beenconducted looking at various cycles that areapplicable to LGH and some of the more recentinvestigations include examinations of transcriticalcycles (Cayer et al 2009), the trilateral flash cycle(Bryson 2007) and the Rankine cycle (Mago et al.2008). Trials of various working fluids for use inlow temperature heat engines have also beenconducted and include Tchanche et al. (2009)investigating pure fluids, and Wang et al. (2009)studying zeotropic mixtures. The availableresearch suggests that the Rankine cycle, using alow boiling point working fluid, provides the lowestprice (per unit output of electricity).Working fluid selectionThe use of less traditional working fluids, eitherpure or in mixtures, is another topic that has seena considerable amount of research beingconducted over a number of years. Recently,Tchanche et al. (2009) have examined a range offluids for use with an ORC utilising LGH andconcluded (as have many before them) the idealworking fluid would be one which exhibits highcycle and heat exchange efficiencies, low turbineoutlet volume flow rate, manageable high sideand low side pressures, develops a favourablepressure ratio upon evaporation, no ozonedepletion potential, low global warming potentialand is non-flammable, non-toxic and should haveno material compatibility problems. Also to beconsidered are: the specific volume of the liquidworking fluid, the thermal conductivity, theviscosity, the surface tension, the thermal stabilityas well as the cost and availability of the fluid.Availability of the working fluid has become moreof a concern in recent times due to the restrictionsput on ozone depleting substances and therestrictions on the use of working fluids with ahigh global warming potential.When selecting the working fluid for use within aparticular heat engine that operates on a chosencycle, the most critical variables upon which tobase the choice are the heat source and sinktemperatures. The heat source is usually fixed bywhat is available at the source of the heat energy,although, in the case of geothermal energy, thereis the option of expending more on the drillingcosts and accessing a higher temperature. In thecase of the low temperature heat sink that mustbe used to make the engine function, this isusually dictated by the site of the plant (usually afunction of a wet or dry bulb temperature or anavailable watercourse temperature). The workingfluid choice, amongst other things, then dictates(for a given heat exchanger effectiveness) thepressures experienced by the high pressure side2211

Australian Geothermal Energy Conference 2009and the low pressure side of the engine, theresulting pressure and volumetric ratios, thepumping power required to circulate the fluid andthe efficiency of the conversion of heat energyinto mechanical energy and then ultimately intoelectricity.Figure 2 is a plot of the gross thermal efficiency ofa regenerative Rankine cycle with refrigerant toptemperatures between 50°C and 100°C. Themodel presented, developed by Air InternationalThermal Systems (AITS), has been run with astipulation of 0°C expander entry superheat and a20°C condensing temperature. In order to keepthe unit from falling below atmospheric pressurein the condenser, a minimum condenser pressureof 130 kPa (absolute) was set. If, at 20°Ccondensing temperature, the pressure in thecondenser (for the fluid being trialled) resulted inan absolute pressure below the set minimum of130kPa, then the condensing temperature usedwas the saturation temperature of that of fluid atthat minimum pressure. The requirement that theheat engine not fall below the minimum pressureis to avoid the possibility of air being drawn intothe machine and consequently prevent the cycleattaining the design pressures. This is a problemexperienced by conventional steam plants andvarious strategies are employed to allow for theremoval of the trapped non-condensable air.It can easily be seen from Figure 2 that, within thetemperature range examined, that neopentanegives the highest cycle efficiency over the entirerange. The fluids with the next highest efficiency(within 1% of neopentane at 75°C) are indescending order: R114, n-butane, RC318,isobutane, R236ea, R236fa, R227ea, R124,R245fa and R142b. The Carnot efficiency hasbeen included on the plot to give a benchmark.In accordance with the list of working fluidselection criteria mentioned previously, several ofthe working fluids examined can be immediatelydiscounted from anything but academicconsideration. This list includes the fluidscontrolled under the Montreal Protocol due to theirozone depletion potential (R114, R124 andR142b). Consideration must also be given to thelong term availability of working fluids with highglobal warming potential (the hydrofluorocarbonsRC318, R227ea, R236ea, R236fa and R245fa))as these fluids are coming under more and morestringent regulatory control. This eliminationleaves the naturally occurring hydrocarbons, withtheir lack of ozone depletion potential and nodirect global warming potential, as the remainingchoices from this process. There is the concernabout the flammability of these substances andalso a heat engine must be designed with theircost and availability in mind.Rankine cycle heat engine componentsA simple schematic diagram of a heat engineusing a regenerative Rankine cycle can be seenin Figure 3. As can be seen from the diagram,such a device is made up from six majorcomponents. The largest expense for a singleitem is the expander for most systems.Figure 2: Efficiency figures for an ideal Rankine cycle with a 20°C condensing temperature (or a 130 kPa-abs condensingpressure if the saturation temperature is below this at 20°C) for a range of potential working fluids neglecting any parasitic loads.3212

Australian Geothermal Energy Conference 2009Figure 3: Simple schematic diagram of components used in aregenerative Rankine cycle heat engine.From the diagram it can also be seen that in aregenerative Rankine cycle, there are threecomponents responsible for heat exchange thesebeing the evaporator, condenser and theregenerator. It is obvious that there is arequirement for the expander and the three heatexchangers to be sourced cost effectively, whilststill performing to an acceptable level, in order forthe low temperature heat engine to be acommercially viable option for converting heat intopower.The goal for the design of a heat engine is toproduce electricity at the lower price possible perunit of energy sent out. This leads to the twocompeting design drivers being the maximising ofefficiency of energy conversion while minimisingthe capital outlay. It is usual to find that a moreefficient or effective a component is, the moreexpensive it is. Therefore an optimal balance hasto be sought between component efficiency andcost.Expanders for use with organic Rankine cycleheat enginesAs mentioned previously, the single componentthat has the greatest bearing on the viability of alow temperature heat engine is the expander.Depending upon the configuration, design andmaterials chosen the cost of sourcing a state ofthe art expander can easily cost more than therest of the components combined. Mostcommercially available turbines developed forpower production purposes were designed forservice with steam power plants and are now inmass production making them relativelyinexpensive to purchase. These units are not,however, suitable for use with many low boilingpoint working fluids such as hydrocarbons. Thisis due to the significantly higher molecular massof the low boiling point working fluids requiring theshafts to carry significantly higher torque atsubstantially lower rotational speeds. While it ispossible to source such a turbine with a very highefficiency, the relatively low numbers inproduction cause such a unit to be sold at a pricehigh enough to make the ORC unit economicallyunviable.Scroll and screw type compressors lendthemselves well to operating in reverse as ORCexpanders. They are both mass producedleading to their cost effective application to lowtemperature ORC units. Scroll compressors arewidely used in the refrigeration and airconditioning industries and from experiencegained in those industries, some concerns havebeen raised about the durability of the scroll end“tips”. There is not the same concern regardingscrew compressors. In addition to this,experience has shown that the largest size ofscroll compressor able to be sourced costeffectively on a commercial scale is 500kW. Thisis significantly smaller than that required for mostcommercial power production applications. Theuse of low temperature heat sources allows theselection of screw machines whose normal dutywould be compressing gases such as air. Thereare many of these units produced each year andso their selection means that they are a costeffective part for use in ORC engines.ORC Experimental apparatusFigure 4: Photograph of the AITS ORC test apparatus.In order to conduct a parametric experimentalinvestigation of a small scale ORC, AITS has builtand instrumented a unit by adapting partsmanufactured for other purposes. A photographof the experimental unit, as tested by RMIT and4213

Australian Geothermal Energy Conference 2009AITS, appears in Figure 4. The heat engine,constructed almost entirely from automotive partseither built or supplied by AITS, includes a rangeof pressure and temperature probes and is part ofa closed loop automated system that ensures thatthe required test parameters are controlled towithin the testing tolerance specification. Thesystem uses an air conditioning scrollcompressor, operating in reverse, as anexpander. A range of tests have been performedand include (amongst others) a chargedetermination procedure and an evaporator exitsuperheat sensitivity trial.Results from the AITS experimental ORC rigFor the purposes of exploring the effect of varyingthe heating source fluid temperature upon thisspecific unit, experiments were conducted wherethe heat source fluid temperature was variedwhile holding the cooling source fluid temperatureat 14.3°C ±1°C and the superheat of the workingfluid was maintained at 10°C ±1°C. The amountof working fluid superheat was controlled to withinits tolerance band by the computerised controlsystem via varying the flow rate of the workingfluid pump. It should also be noted that the fluidflow rates of the heat source and sink were heldconstant for all of the tests. Figure 5 shows a plotof the power output as the heat source fluid isvaried. The output power is given a normalisedpercentage of the output power of the apparatuswhen the heat source fluid temperature was 75°C.source fluid were also undertaken. Theexperiments were conducted with a 75°C ±1°Cheating source temperature throughout the testsand the superheat of the working fluid wasmaintained at 10°C ±1°C. As with the testsexamining the sensitivity of the unit to the heatsource temperature, the amount of working fluidsuperheat was controlled in the same manner asfor the heat source sensitivity tests. Figure 6shows a plot of the power output as the coolingfluid temperature is varied. The power out ispresented as a normalised percentage of theoutput power of the apparatus when the coolingsource fluid temperature was 14.3°C.Figure 6: Normalised power output as a function of thecooling source fluid temperature for a constant heat sourcetemperature.Figure 5: Normalised power output as a function of theheating source fluid temperature for a constant coolingsource temperature.Figure 5 indicates that there is a high degree oflinearity in the relationship between thenormalised power and the temperature of theheating source. The figure also shows that, forthe experimental apparatus examined, the poweroutput at 95°C source temperature isapproximately double that at 75°C, while at asource temperature of 64°C is approximately halfthat produced at 75°C.Tests trialling the sensitivity of the power output ofthe apparatus to the temperature of the coolingFigure 6 also shows a high degree of linearity inthe relationship between cooling fluid temperatureand the output power of the rig. At a cooling fluidsink temperature of -3°C, the output of the rig isapproximately 1.8 times that of the 14.3°Cbenchmark trials. At the top cooling fluidtemperature of 28°C the output is approximately30% of the nominal power output.ConclusionsThe available literature on the cost effectiveproduction of electricity using ORC heat enginesthat employ low temperature heat sources islimited. Although the preliminary results of thisinvestigation have been concerned with theperformance of the ORC, the indications are thatit is cost effective to recover and convert lowgrade heat to electricity. For heat sourcetemperatures of 75°C and below, the selection ofthe expander is a key concern due to the trade offbetween efficiency and capital cost. The selectionof a working fluid that achieves a favourable idealcycle efficiency is also of great impact upon theviability of these machines that utilise low gradeheat. Results from the experiments jointlyconducted by Air International Thermal Systemsand RMIT University show a direct proportionalitybetween achieved power output and heat sourcetemperature within the range examined. It was5214

Australian Geothermal Energy Conference 2009also found that, within the range examined, therewas also a direct proportionality between the heatsink temperature and the achieved power output.Also notable is the fact that power was able to beproduced by the experimental unit from around a55°C heat source temperature while using a14.3°C heat sink.ReferencesBryson, M.J., 2007, The conversion of low gradeheat into electricity using the ThermosyphonRankine Engine and Trilateral Flash Cycle, [Ph.D.thesis]: Melbourne, RMIT University.Burns, K.L., Creelman, R.A., Buckingham, N.W.,and Harrington, H.J., 1995, Geothermaldevelopment in Australia: Proceedings of theWorld Geothermal Congress 1995, Florence,Italy, p. 45-50.Burns, K.L., Weber, C., Perry, J., and Harrington,H.J., 2000, Status of the geothermal industry inAustralia: Proceedings of the World GeothermalCongress 2000, Kyushu - Tohoku, Japan, p. 99-108.Cayer, E., Galanis, N., Desilets, M., Nesreddine,H., and Roy, P., 2009, Analysis of a carbondioxide transcritical power cycle using a lowtemperature source, Applied Energy, v. 86, p.1055-1063.EPA Qld, 2005, Fact Sheet – BirdsvilleGeothermal Power Plant, EPA Qld, viewed 1 May2009,.Geoscience Australia, 2007, Australian radiogenicgranite and sedimentary basin geothermal hotrock potential map, viewed 1 July 2009,Ghori, K.A., 2008, Western Australia’s geothermalresources, 2008 American Association ofPetroleum Geologists Annual Convention &Exhibition, San Antonio, Texas.Goldstein, B.A., Hill, A.J., Malavazos, M., Coda,J., Budd, A.R., and Holgate, F.L., 2008, Hot rockenergy projects - Australian context, SPEInternational Thermal Operations and Heavy OilSymposium 2008, Calgary, Alberta.Kanoglu, M., and Çengel, Y.A., 1999, Economicevaluation of geothermal power generation,heating and cooling, Energy, v. 24, no. 6, p. 501-509.King, R.L., Ford, A.J., Stanley, D.R., Kenley, P.R.,and Cecil, M.K., 1985, Geothermal resource ofVictoria - a preliminary study, Department ofIndustry, Technology and Resources and theVictorian Solar Energy Council, Melbourne.Leibowitz, H., Smith, I.K., and Stosic, N., 2006,Cost effective small scale ORC systems for powerrecovery from low grade heat sources, 2006American Society of Mechanical EngineersInternational Mechanical Engineering Congressand Exposition, Chicago, Illinois.Mago, P.J., Chamra, L.M., Srinivasan, K., andSomayaji C., 2008, An examination ofregenerative organic Rankine cycles using dryfluids, Applied Thermal Engineering, v. 28, p. 998-1007.McLennan Magasanik Associates Pty, 2008,Installed capacity and generation from geothermalsources by 2020, Infrastructure Australia, viewed13 July 2009,.Pirlo, M.C., 2004, Hydrogeochemistry andgeothermometry of thermal groundwaters fromthe Birdsville Track Ridge, Great Artesian Basin,South Australia, Geothermics, v. 33, p. 743-774.Ruge, P., 1999, An Overview of the potential forproduction of geothermal electricity at Portland,Glenelg Shire Council, Portland.Sinclair Knight Mertz, 2005, The geothermalresources of Victoria, The Sustainable EnergyAuthority of Victoria, viewed 1 June 2009,.Schuster, A., Karellas, S., Kakaras, E., andSpliethoff, H., 2009, Energetic and economicinvestigation of organic Rankine cycleapplications, Applied Thermal Engineering, v. 29,p. 1809-1817.Tchanche, B.F., Papadakis, G., Lambrinos, G.,and Frangoudakis, A., 2009, Fluid selection for alow temperature solar organic Rankine cycle,Applied Thermal Engineering, v. 29, p. 2468-2476.Wang, X.D., and Zhao, L., 2009, Analysis ofzeotropic mixtures used in low-temperature solarRankine cycles for power generation, SolarEnergy, v. 83, p. 605-613.6215

Australian Geothermal Energy Conference 2009Seasonal Storage of Air Cooled Water for Arid Zone GeothermalPower PlantsRobert CollinsEnreco Pty Ltd P.O. Box 690 Alice Springs NT 0871Email: enreco.geothermal@gmail.comThis paper presents a new option for heatrejection from geothermal plants. Our 20 yearsexperience with small geothermal plants at MulkaStation and Birdsville has convinced us that heatrejection is a major issue in Australian conditions.In arid zones air cooling has been the option ofchoice due to lack of water and the availability ofindustrial air condensers. This option has provedexpensive, with costs in the U.S. of 20 - 30% ofthe total capital costs, including wells for 5 majorgeothermal plantsAs noted previously by several authors this optionalso comes with severe performance penaltiesdue to the extreme summer daytimetemperatures. When the demand for electricity isgreatest the geothermal electric output will dropby up to 40%. The geothermal industry needs tobegin development and testing of new heatrejection options to solve this problem.Just as the desert presents problems with highdaytime temperatures, it offers opportunities withvery low night time temperatures, large areas ofland available and in most regions, shallow, salineaquifers suitable for water storage. A simple heatrejection system taking advantage of thesecharacteristics is illustrated in Figure 1. A watercooled condenser using saline water from ashallow aquifer provides the heat rejection sink forthe geothermal plant. The area of the aquifer usedis sized to provide approximately 6 months ofcooling water. The water that is returned to theaquifer is intermittently cooled by air coolers whenthe air temperature is below a set value. As longas the heat rejected to the air during coolerperiods matches the heat going into the waterform the condenser over the year, a constantwater temperature will be maintained.While the conditions necessary for this concept towork occur in most desert regions, the focus ofthis paper is on the geothermal areas of interest inthe North East of South Australia above theCooper Basin. Details of this concept, along withadvantages and issues, and a design for anillustrative 2 MW geothermal plant cooling systemare provided below. Also the matching of thisconcept with CO 2 as the geothermal fluid as wellas plant working fluid is consideredSYSTEM CONCEPTThe system has 3 separate energy loops. The firstis the circulation of the saline groundwater fromproduction bores through the geothermal plantcondenser and into the reinjection bores. Thesecond energy loop is the intermittent air coolingof the groundwater after it leaves the condenser.This loop rejects to the atmosphere during coolerperiods of the year, the heat from the condenser.The third energy loop is also an intermittent aircooling of the groundwater. This loop takesgroundwater part of the way between theproduction and re injection bores and also cools itintermittently during cooler periods. The purposeof this third loop is to provide the extra coolingcapacity to compensate for the intermittentoperation.The massive energy storage capacity of theshallow aquifer means that the heat rejected bythe condenser can be balanced out over the yearby the heat rejected to the atmosphere from theaquifer. The temperature of the water reinjectedinto the aquifer will vary from 40 C on a summerday to due to no air cooling to 15 C on a winternight with air cooling. These temperaturevariations will be smoothed over the year as thewater slowly migrates in the aquifer from thereinjection to production bores.The air coolers used for aquifer water cooling willbe air to water coolers rather than air condensers.This will allow more efficient counter flow heatexchange compared to constant temperaturecondensing. However, they will have to transferthe same amount of heat only operatingintermittently for 1/2 of the year. A major benefit ofthe intermittent operation is that they can beoperated when desired during periods of minimaldemand. This will remove the heavy parasiticpower load during peak periods, increasing thenet power output of the geothermal plant by 10-15% above its rated capacity.Using saline ground water for cooling should notbe a problem as seawater fed condensersoperate around the world. Scaling problemsshould be minimal if the water temperature is keptbelow 40 C. The 2 potential scaling problemswith this groundwater are silica and calciumcompounds. Both can be serious if there is anyevaporation which brings them closer tosaturation in the solution. Calcium can be aproblem if there is heating beyond 40 C as itssaturation limit rapidly declines above this. Neithercondition exists for this concept.The cost of this complete condensing system willbe greater than a standard air cooled condenser.The air to water coolers will have to have doublethe heat rejection capacity of an standard1216

Australian Geothermal Energy Conference 2009continuously operating air condenser, since theywill only be operating ½ the time. There will alsobe additional components such as the watercooled condenser, the saline aquifer bores, andsubmersible pumps. We estimate the cost for thecomplete system will add approximately 10% tothe cost of a geothermal plant. The benefits faroutweigh this cost. Instead of a 2 MW plantproducing 1.2 MW on a hot day due to highercondensing temperatures, it would produce itsrated 2 MW plus an extra 0.3 MW of reducedparasitic power loss not required for air coolingfans. Thus the useful output is nearly doubledwhen it is most needed and high value.SALINE AQUIFERSShallow saline aquifers are nearly ubiquitous inthe areas of interest above the Cooper Basin.This is not surprising as Cooper Creek is part ofthe Lake Eyre Basin, which is the largest internaldrainage basin in the world. Cooper Creekspreads out into a vast meandering area ofephemeral channels that are normally dry.Saline groundwater is normally found at depths of10 - 100 metres and even closer to the surfacenear salt pans. Aquifers can be 10s - 100s ofmetres thick. This water is of no economic valuebecause it usually has too high a salt content forstock watering or cropping. Salt content is quitevariable.The bores for production and reinjection would beapproximately 40 metres deep and cased withslotted PVC pipe. For a 2 MW geothermal plantapproximately 20 of each would be required.These shallow bores should be relatively cheap todrill at 50 metre spacings. There are manysuitable patterns for the bores, but probably thesimplest is 2 parallel lines of bores separated by asuitable distance for the required 6 monthsstorage requirements. For the other air coolingloop an additional 20 production and re injectionbores would also be requiredIf we assume an aquifer thickness of 30 metres,soil porosity of 30%, then there is 10 thousandmega litres of water available per km 2 . Thickeraquifers are better as they provide greater storagein the same area and also have higher flowrates/bore, requiring less bores. Typical shallowaquifer water temperatures in the Cooper basinare 23 C. This is a substantial cold water storagesystem that is freely available.Pumping from the aquifer would be viasubmersible pumps in the production bores. Sinceit is a closed circulation system, the head requiredwould be primarily friction losses in piping, thecondenser and air cooler. Total pumping head forthe cooling system is estimated at 20 metres.2 MW GEOTHERMAL PLANTOPERATIONA 2 MW geothermal plant has been chosen toillustrate the cooling concept. Assumed designparameters are 15% thermal efficiency and aworking fluid condensing temperature of 40 C.The heat rejection rate required is 11.3 MW. Forwater entering at 23 C and exiting at 40 C therequired flow rate to capture this heat is 159litres/sec. To provide 6 months storage requires2514 mega litres.Assuming the saline aquifer parameters describedin the preceding section, we require an aquiferarea .25 km 2 or a square 500 metres on a side.This could be satisfied by our parallel lines ofproduction and reinjection bores spaced 600metres apart. The geothermal plant would be inthe middle between these 2 lines. A single largediameter pipe would connect the 2 lines of boresto the geothermal plant, so that a top view lookedlike the letter H. The bores would be spaced 50metres apart on 1 kilometre lines forming thesides of the H.To make up for the intermittent cooling, a secondidentical set of bores would be placed inside theH, forming a smaller H. These would operate atthe same time to double the air cooling capacity.The production bores and re injection bores wouldbe 200 metres apart and the 2 lines of thesewould be 200 metres inside the lines of the firstset of bores.These bores would operate counter flow to thefirst set of bores. They would provide additionalcooling to aquifer water that had been reinjectedseveral months before. This would make up forthe intermittent operation of the cooling system.The relatively huge capacity of the aquifer and soilwould smooth out the daily and seasonaltemperature variations of reinjected water.The power requirement to pump 159 litre/sec flowrate against a 20 metre head would be 50 kW or2.5% of the plant capacity. This would be full time.The air cooler fans (300 kW) would operateintermittently when air temperatures were below25C and when power demands allowed. Use ofvariable speed drives on the fans would alloweven greater flexibility to cool the water at theoptimum times.The total fan power and pump power for both setsof bores and air coolers would be approximately700 kW or 35% of the plant capacity to providedouble the normal heat rejection to theatmosphere. Based on climate data from MoombaSouth Australia the fans would run approximately1/2 of the year, during cooler, lower demandperiods.2217

Australian Geothermal Energy Conference 2009ReinjectionBoresIntermittentAir CoolerGeothermal PlantCondenserProductionBoresShallow Saline Aquifer50metres600 metresFigure 1. 2 MW geothermal plant cooling system using aircooled water with a shallow saline aquiferCO 2 GEOTHERMAL SYSTEMSCO 2 geothermal systems, where CO 2 is used asboth the geothermal fluid for heat extraction, andas the working cycle fluid, offer significantadvantages. There is a very big issue on thecooling side as the supercritical temperature forCO 2 is 31 C. Above this temperature there is ahuge performance penalty on the plant of up to40%. Conventional air cooling systems could notmeet this requirement most of year in the Cooperbasin. The proposed cooling system in this papercould provide the necessary cooling to condensethe CO 2 below its critical temperature. This wouldbe critical during the summer periods of peakelectricity demand.CONCLUSIONSThe seasonal storage of water with air coolingoffers a possible solution to the significantproblem of summer heat rejection fromgeothermal power plants in arid regions. Thepresence of shallow saline aquifers in the CooperBasin appears to offer a straight forwardimplementation of this concept in this region.The additional costs are more than compensatedfor by the much greater plant output in peakperiods and the flexibility to schedule parasiticcooling loads. The same benefits accrue to CO 2geothermal systems.Heat rejection is a major issue for geothermalplants in terms of capital cost, performance, andmaintenance costs in Australian conditions. Newconcepts beyond just simple air condensers needto be developed and tested.3218

Australian Geothermal Energy Conference 2009Feasibility Assessment of Underground Cooling for GeothermalPower CyclesBassam Dally * , Graham Nathan, Sean Watson, Andrew Heath and Carl Howard1 School of Mechanical Engineering, The University of Adelaide, SA, 5005.* Corresponding author: bassam.dally@adelaide.edu.auGeothermal heat sources offer significantpotential for electricity generation in Australia byHot Fractured Rock, HFR, technology and otherapproaches. However, all of the sites of greatestgeothermal potential are situated remote from anysignificant surface water source, which poses asignificant challenge to the method by which theworking fluid in the power cycle will be cooled.The need for cooling in any thermal power cyclehas driven many conventional power plants to belocated close to a river, lake, or ocean to providean environmental heat sink (Department ofEnvironment, 2001). Where this is not realistic,cooling towers are almost invariably used toprovide greater cooling than is possible by aircoolingalone, utilising the evaporation of water,much like a large evaporative air cooler. However,the water consumption due to evaporation andfouling losses, even for a conventional powerstation with comparatively high efficiency, istypically 1363 L/MW.h per day (Ricketts et al.,2006), and will be greater for typical geothermalplants owing to their low thermodynamicefficiency.Indeed, the recent increase in demand for aircooledcondensers is a direct result of watershortages at potential plant sites and increasinggovernment legislation limiting the use of water inthe wet cooling systems (Ricketts et al., 2006). Asnoted above, the regions in which geothermalheat is the most viable are arid or semi-arid, withno readily available source of surface water forcooling. While underground water is present,notably from the Great Artesian Basin, it isunlikely that environmental regulators will allow itto be utilised because of the very large waterconsumption required by any large thermal powerplant. Therefore, alternatives to conventionalwater-based cooling methods are expected to berequired for these power plants.The present commercially available alternativemethod of heat dissipation is through the use ofconventional fin-and-tube air cooled heatexchangers. Fins on the surface of the heatexchanger are typically used to improve the heattransfer by increasing convection and radiationaway from the surface. Such systems are used ina number of geothermal plants, e.g. in the Mokaiplant in New Zealand. However, in the areas ofinterest, such as the Cooper Basin, daily ambientair temperatures can reach 45ºC in the summer,in which case the minimum temperature of theworking fluid temperature must be in the range48-50ºC, owing to the fact that the effectivenessof a heat exchanger is always less than 100%.Such high condenser temperatures result in a lowefficiency of the power cycle. For example,Langman et al (2008) estimate that the outputfrom a geothermal plant at a typical site in SouthAustralia would drop by 40% as the ambient airtemperature is increased from 15 to 45ºC.Furthermore, the peak demand, and hence peakprices, in the national grid are greatest during thevery time when the output is lowest. Such ascenario could significantly influence theeconomic viability of a plant. Fans may beemployed to force air over the fins to improve theperformance of the heat exchanger, but consumelarge amounts of energy and hence reduce thenet amount of electricity produced by the plant.A potential solution to the problem of cooling theworking fluid is to install a heat exchangerunderground where temperatures are lower andmore stable. Heat in the working fluid may then berejected to the soil and in turn dissipated to theatmosphere. For this reason, the aim of thepresent investigation is to assess the feasibility ofunderground cooling for such a geothermal plant.Keywords: geothermal, power cycle, condenser,underground cooling.Approach and MethodologyThe heat transfer processes within anunderground heat exchanger are time dependentand three dimensional. Analytical solutions areunable to account for such variations in soil andatmospheric conditions. Hence we opted for amodelling strategy that accounts for temperaturevariation and heat flow over 24-hour period,repeated for many days. In this approach we areable to account for the radiation in the day andnight and the temperature variation of soil and theair over an extended period.In order to simplify the problem while maintainingthe core issue intact, the following assumptionswere made: the soil is homogeneous;there are no phase changes in water, and nolatent heat effects;the soil emissivity, absorptivity and reflectivityare constant;convection over the surface is a function ofwind speed, which is fixed;the pipe depth is fixed, and1219

Australian Geothermal Energy Conference 2009the effects of the pipe wall on conduction arenegligible.A block of soil with sides of approximately equallength, shown in Figure 1, is analysed. A piperepresenting the heat exchanger is buriedunderground at a certain depth, l, and the workingfluid of the power cycle is passed through the pipeat a temperature T i . Since the soil is at a lowertemperature than the pipe, heat energy is lost tothe soil, such that the fluid exits the pipe at somelower temperature T o . It should be noted that theboundaries of the block of soil are assumed to besemi-infinite, and thus heat may be lost throughthe faces of the block with negligible resistance.Figure 1: Schematic diagram of a pipe buried in soilThe pipe depth l is an important parameter andwill have a crucial effect on the behaviour of themodel. It is known that fluctuations in temperatureover a period of time decrease with soil depth,depending on the properties of the soil (Pavelkaet al. 2006). The measured change intemperature over the period of one day for varioussoil depths is presented in Figure 2. Thus, at adepth of just 30cm the temperature fluctuation forsoil over a day can be small (typically 1 to 2ºC).Figure 2 Temperature fluctuations at various soil depths, incm, over 24 hours period [Paveleka et al., 2006]For the present comparative assessment, it issufficient to assume a typical temperature for theworking fluid entering the condenser. We havechosen this to be 100ºC. This is typical of thetemperature at which the geoliquid is expected tobe returned underground from EnhancedGeothermal Systems (EGS) under conditions incentral Australia (Langman et al, 2008). Whilebeing somewhat higher than expected condensertemperatures, for the present comparativepurposes it is sufficient to ensure that both thegeothermal and air-cooled temperatures arebased on the same reference condition. The heatbeing lost to the soil through conduction is termedQ cond in Figure 1 and depends on a number ofparameters, including the conductivity of the soil.The conductivity of soil changes as the moisturecontent of the soil increases or decreases and islargest when the soil is wet. However, as rain israre in the arid regions being considered, the soilconductivity is assumed to be that of dry soil, andis assumed to be constant. Note that thisassumption is conservative, since the presence ofmoisture will increase the thermal conductivity.One report suggests that thermal conductivityvalues for sandy loams range from 0.54W/mK to1.94W/mK (Abu-Hamdeh and Reeder, 2000).Exact data for the geomorphology of the CooperBasin region is difficult to obtain, as reportssuggest that the region contains both wetlandsand desert, which have widely varying soilproperties (Burdon, 2006). To allow for aconservative solution for conduction then, it wasdecided to use a value of 0.75W/mK for thethermal conductivity of all models, which is typicalof sandy loam soils.The heat transferred to the surface by radiationfrom the Sun during the day is termed Q rad , shownin Figure 1. Solar radiation is made up of twocomponents, namely direct radiation and indirectradiation. For the purposes of the present model,the direct and indirect radiation are grouped into asingle quantity. Measured data for the daily andseasonal variation in Q rad , are readily available.The infra-red radiation from the soil is shown inFigure 1 as Q emit . It is assumed that the soil is agray body and will emit radiation as a function ofthe emittance of the soil and the temperaturedifference between the soil and the air. Theemittance of the soil is assumed to be constantand equal to 0.75 (Mills, 1999). Radiant lossesare assumed, conservatively, to be to the air atambient temperature. Measured data for the dailyand seasonal variation in ambient temperatureare readily available.Heat is also dissipated through convection fromthe surface, termed Q conv in Figure 1. Thisdepends on the wind speed of the air flowing overthe surface and the ambient air temperature. Theaverage daily wind speeds for the month ofJanuary were obtained from Energy Efficiencyand Renewable Energy (2008) and wereaveraged to provide a monthly average value.2220

Australian Geothermal Energy Conference 2009This monthly average value was used to calculatethe convective heat transfer coefficient.The finite quadrilateral elements for the 2-dimensional longitudinal cross section model witha 50mm diameter pipe, 0.1m deep and 50m longis shown in Figure 3. Owing to constraints of theANSYS package (ANSYS, 2007), to model aninfinite boundary condition, it is necessary for theboundary of the problem to be circular as shownin the model below.conditions in the Far North East of the state ofSouth Australia (EERE, 2008). The choice ofJanuary was due to it being in the middle ofsummer with the hottest daily temperatures. Thiscorresponds to the worst loading conditions forthe heat exchanger.Figure 4: Water temperature drop plotted against the pipedepth after 20 days. Pipe diameter 0.05m, pipe length 50m.Figure 3 Finite element model of the 2-D Longitudinal CrossSection. Pipe diameter 0.05m, depth 0.1m and length 50m.The thermal properties of the soil and the air,used in the model, are shown in Table 1.Table 1: Soil and air thermal propertiesSymbol Soil Airk(W/mK) 0.75 0.0271C(J/kgK) 1000 1900(kg/m 3 ) 1500 1.225 0.77 -The inlet temperature of the water was assumedto be 373K. The heat dissipated by theunderground pipe system was set to 5MW. Themass flow rate of water in the 0.005m diameterpipe was assumed to be 16 kg/s. The heattransfer coefficient inside the pipe was calculatedusing the Dittus-Boelter correlation for turbulentflow inside a smooth pipe.NuD0.80.023ReDThe pipe thermal conductivity is estimated at 0.41W/mK. Thermal resistance between the soil andthe pipe was assumes to be negligible. Inpractical systems this resistance can beminimized through proper compactness of the soilsurrounding the pipes.Weather data including the hourly averageambient temperature and an average hourlyradiation for all days in the month of January wereobtained from a weather station in the town ofOodnadatta, which is representative of summerPr0.4The daily average wind speed for the month ofJanuary was used to calculate the heatconvection coefficient to be 23.6W/m 2 K.Results and DiscussionsPresented in Figure 4 is the temperature at thepipe exit plotted versus the pipe depth at end of a20-day period. The 20-day period ensures that thetemperature reaches pseudo-steady stateconditions. It is clear from the figure that a depthof 10 cm is the most appropriate and provides thehighest temperature loss for a fixed length of pipe.The drop in temperature appears to be quite smallfor the 50 m length of the pipe amounting to0.15K. However this amounts to 10 kW of heatwhich was dissipated away from the pipe and intothe atmosphere. Worthy of note too, is that therewas no attempt to enhance the pipe design whichwould have increased the amount of heat lost perlength of pipe. Such enhancement can includefins, surface protection from sun radiation andother methods to increase heat loss during thenight.Figure 5: Calculated Temperature drop along a 50m length,repeated over a 7.4km length of pipe3221

Australian Geothermal Energy Conference 2009The longitudinal model was also used to obtain anestimate of the overall pipe length to dissipate5MW of heat. The 50m geometry, in Figure 3, waslooped multiple times to calculate a temperaturedrop over 7.4km. In other words the exittemperature from the first 50m pipe after 20 dayswas used as inlet temperature to the second 50mpipe and the process was repeated 148 times togive the exit temperature at accumulated lengthyof 7400m. The exit temperature from each run ispresented in Figure 5 for every 50m. A trend-linehas been applied to this data and the equation ofthe trend-line is also shown on the graph.Noteworthy is that the temperature differencebetween the pipe and the surrounding soil, whichdrives the potential for heat transfer, drops andhence the effectiveness of a meter length of pipedrops too. Hence extrapolating the curvegenerated above to longer pipes may not beaccurate. Nonetheless, the curve fit is for almosthalf of the temperature reduction required (70ºC)and a reasonable estimate can be generatedusing this method. Thus, solving for length, andusing a value of 300K (27ºC) for the pipe exittemperature, the length of pipe required isapproximately 22km. To account for the issuesdiscussed above a conservative estimate wasdeemed to be prudent and a factor of safety wasintroduced. Hence for the cost analysis, theoverall length of pipe required for the undergroundcooling process was set to 25km.The present preliminary cost estimate wasundertaken for the above conditions without anyspecific reference to a relevant geothermalthermal cycle. That is, it does not consider theinfluence of the cooling cycle on the performanceof the power plant. Nonetheless, these roughestimates, which considered worse weatherconditions, have shown that in comparison to aircooled heat exchanger our approach is highlycost effective both from the initial investment andoperating cost. It is anticipated that with furtheroptimisation and accounting for year long weatherconditions the above conclusions will hold.Future work will focus on proving this conceptexperimentally and expanding the modelling workto a specific location accounting for local soilproperties, likely thermal cycle and adoptingstanding heat transfer enhancing methods suchas fins. This work will then give us further groundsto build a prototype to accurately quantify thebenefits.SummaryA preliminary assessment has been undertaken ofthe technical and economical feasibility of usingsoil to store energy during the day and dissipate itduring the night. The assessment is based onconditions in the Copper Basin region of SouthAustralia. Several approaches were used tocalculate the rate of heat transfer and the viabilityof the concept, including analytical and anadvanced computational technique, FiniteElement Analyses, (FEA). It was estimated thatthe optimal depth to burry the heat exchangerpipes is about 0.1 m. This depth was arrived atthrough modelling the soil absorption of the heatdissipated from the pipe and the impact of the sunradiation, air temperature and wind speed on heattransfer from the soil to the atmosphere.A two dimensional longitudinal model was used toestimate the length of pipe required to dissipate5MW of heat by cooling a working fluid (Water)from 100ºC to 30ºC. The model revealed that anapproximate length of 25km of 50mm diameterpipe is required to achieve the required heattransfer. The cost of dissipating heat through awater-based system at low pressure wasestimated to be less than that of a conventionalair cooled heat exchanger. Several otheradvantages are anticipated, such as avoiding theneed for fans and a power output that is muchless dependent on ambient temperature.However, a detailed assessment of its impact onthe performance on the plant, or the economicfeasibility is yet to be undertaken.In addition, as with all models, a number ofsimplifications and approximations have beenrequired, so that further model development andexperimental validation are required to help betterestimate the benefits. Further work is alsorequired to optimise the design and consider itsintegration into specific geothermal cycles with aview to justifying a demonstration prototype.AcknowledgementsThe authors acknowledge the financial support ofthe Primary Industry and Resources in SouthAustralia, PIRSA under the Australian GeothermalEnergy Group Tied Grant scheme.ReferencesSomerville, M., Wyborn, D., Chopra, P., Rahman,S., Estrella, D. and Van der Meulen, T., 1994, HotDry Rocks Feasibility Study, Energy Researchand Development Corporation, Report 243,133pp.Abu-Hamdeh, N. H., & Reeder, R. C. (2000). SoilThermal Conductivity: Effects of Density,Moisture, Salt Concentration, and Organic Matter,Soil Science Society of America Journal , Vol. 64,No. 4, pp1285-1290.ANSYS. 2007, ANSYS v11.0 ReleaseDocumentation, v.11.0, computer program,ANSYS Inc., Pittsburgh, PA, USABurdon, A 2006, 'The Strzelecki Track', AustralianGeographic, Issue 82, pp42-57Australian Government, Department ofEnvironment, Water, Heritage and the Arts, 2001,4222

Australian Geothermal Energy Conference 2009Energy Efficiency and Renewable Energy (EERE)2008, Statistics for SA Oodnadatta Airport,Department of Energy, USALangman, A.S., Nathan, G.J., Ashman, P.J. andBattye, D. (2008) “Preliminary Investigation of theMech. Systems Needed to Extract Geoth. Energyfrom a Typical South Australian Site”, Report to:Electricity Supply Industry Planning Council,Consulting Report MECHTEST MT-0949, School.Mech. Eng., University of Adelaide.Mills, A. (1999). Heat Transfer 2nd Edition. NewJersey: Prentice HallPavelka, M., Acosta, M., Marek, M., Kutsch, W., &Janous, D. (2006). Dependence of the Q10values on the depth of the soil temperaturemeasuring point, Plant & Soil , Vol. 292, 1/2,pp175Ricketts, C, Myint, M, Nirmalakhandan N &Gadhamshetty V 2006, Improving Air-CooledCondenser Performance in Combined PowerCycle Plants, Journal of Energy Engineering, Vol.132, No. 2, pp81-88.5223

Australian Geothermal Energy Conference 2009Dry Cooling Technology in Chinese Thermal Power PlantsZhiqiang Guan* and Hal GurgenciThe Queensland Geothermal Energy Centre of Excellence (QGECE), the University of Queensland, St Lucia,Brisbane, Qld 4072* Corresponding author: guan@uq.edu.auDesign of efficient dry cooling system is of criticalimportance for geothermal power conversiontechnologies. In fact, dry cooling may be the onlyoption for most geothermal power plants plannedto be established in areas with limited access towater. The heat exchange performance, flowgeometry optimisation and cost are key factors indetermining suitability of dry cooling towers forgeothermal power plants.China has made advances in recent years inR&D, manufacturing, and utilisation of dry coolingtowers in its coal rich but water scarce Northernprovinces. One driver for the surge inapplications of dry cooling systems is thegovernment regulation that requires all new coalfiredpower plants built in Northern China regionto use dry cooling systems. Northern China hasplenty of coal but no water for wet cooling in itscoal-fired power plants.A straightforward copying of the technology fromcoal-fired power industry to geothermal powerindustry is not expected to deliver a cost-effectivesolution and should be avoided. Benefits would begained by reviewing the development of drycooling technologies in Chinese coal-fired powerplants. The Queensland Geothermal EnergyCentre of Excellence (QGECE) has supported DrZhiqiang Guan to apply for the QueenslandInternational Fellowship aiming to review theadvance of the dry cooling technology in China.In this paper a summary of dry cooling technologywill be given with a focus on the Chinese practice.Keywords: Geothermal energy, Cooling tower,natural draft cooling technology, Coal-fired powerplants.Cooling Technology in Thermal PowerPlantThermal power plants make use of a steam cycleto transport energy from large boilers to turbogenerators.An important part of this steam cycleis the condensation of the steam downstream ofthe turbine. A Cooling Tower is a heat rejectiondevice that extracts waste heat to the atmosphereby either cooling a stream of hot water from thecondenser (indirect wet or dry cooling) or cooling(condensing) the steam downstream of theturbine directly (direct dry cooling). Cooling towersare classified as either wet or dry cooling.A wet cooling is a recirculation water system thataccomplishes cooling by providing intimate mixingof water and air, which results in cooling primarilyby evaporation. As shown in Fig.1, the hot waterleaving the condenser is piped to the coolingtower and is pumped and distributed across thedistribution deck where it flows through a series ofnozzles onto the top of the tower's fill material. Fillmaterial is used in cooling towers to create asmuch water surface as possible to enhanceevaporation and heat transfer. The water, afterbeing cooled by a combination of evaporation andconvective heat transfer, is pumped through thecondenser to condense the turbine steam in acontinuous circuit.Wet cooling towers are characterised by themeans by which air is moved. Mechanical draftcooling towers rely on power-driven fans to drawor force the air through the tower. Natural draftcooling towers use the buoyancy of the exhaustair rising in a tall chimney to provide the draft.Fig.1 Wet cooling tower [GEA Aircooled Systems (Pty) Ltd]Dry cooling towers rely on convection heattransfer to reject heat from the working fluid,rather than evaporation. The cooling takes placethrough air-cooled exchangers similar to radiators.Fig.2 shows configuration of natural draft drycooling tower used by the thermal power plants.In natural-draft cooling towers, the volume flowrate of air across the heat exchanger bundle isdirectly proportional to the height of the coolingtower. There are some options in natural draftcooling tower to use fans to enhance the air flowthrough the tower.If fans are used as the mechanism to circulate air,then there is no need for a tall tower as shown inFig.3. While such systems are cheaper to build,the power needed to drive the fans is significant,especially in low-efficiency cycles whereproportionally more heat must be dumped foreach MW of electricity generated.1224

Australian Geothermal Energy Conference 2009generating capacity of 2x600 MW. The studyassumed the plants operate 5500 hours yearlyand the results are shown in Table 1. It is seenthat the water saving is 8.8x10 6 m 3 per year fromthe dry cooling system. This is based on the factorthat the water consumption for other equipmentsin the plants is the same.Fig.2 Natural draft dry cooling [GEA Aircooled Systems]Fig.3 Zhenglan Inner Mongolia Province — ACC for 4 x 600MW Coal Fired Power PlantWet / Dry Cooling TowersTheoretically a wet cooling tower could cool thewater to a temperature approaching the ambientair wet bulb temperature. This cooling system ismore efficient, relatively cost effective to installand easy to operate. They are, however,becoming less attractive since they consumelarge amounts of water through evaporation andhigh blowdown rates. Dry cooling towers, on theother hand, cools the water to a temperaturegoverned by the ambient air dry bulb temperature.No water is used and therefore the operatingcosts are lower due to the savings on the cost ofwater and the water treatment. Since the dry bulbtemperature for air is higher than the wet bulbtemperature, dry cooling towers requiresignificantly larger heat exchange areas and theyare more expensive to build than wet towers.Water consumptionCoal-fired plant using wet cooling system wouldrequire huge amount of water annually to replacecooling tower evaporation, blowdown and driftlosses. Under certain conditions, a wet coolingtower plume may present fogging or icing hazardsto its surroundings. Fig.4 is a photo of naturaldraft wet cooling towers at a power plant.Zhu and Guan (2006) have studied waterconsumption by comparing the water usagebetween two wet and dry cooling coal-fired powerplants in China. The plants have the same powerFig.4 Natural draft wet cooling tower in power plantTable 1. Comparison of water consumption between wetand dry cooling systemsDry cooling Wet CoolingWater consumption Index ~0.13 ~0.5(m 3 /s.GW) (yearly average)Water consumption hourly rate 560 2160(m 3 /hrs) (yearly average)Total water consumption in a year 3.08x10 6 11.88x10 6(m 3 )Water saving (m 3 ) 8.8x10 6Coal consumptionSince evaporation process is governed by theambient air’s wet bulb temperature, which issignificantly lower than its dry bulb temperature,power plant using a wet cooling system is moreefficient than a similar power plant using a drycooling tower – if the same size of cooling tower isused in both cases. Zhu and Guan (2006) havestudied the coal consumption of the above twogenerators and the results are shown in Table 2.The cooling towers are of the same size but oneplant uses a dry cooling tower, the other is wet.The result shows that, for a 2x600MW powerplant operating 5500 hours in a year, the wetcooling plant uses 145200 tonnes less coal thanthe dry cooling plant.Table 2. Coal consumption between wet and dry coolingsystemsDry cooling Wet coolingSub critical generator 332 310Coal consumption (g /(kW*h)Super critical generatorCoal consumption (g /kW*h)317-320 2982225

Australian Geothermal Energy Conference 2009Capital costChai (2006) conducted a cost study on four2x600MW power plants, one with wet cooling andthe other three with dry cooling systems. Theresult is shown in Table 3.Table 3. Capital cost comparison (10 6 Chinese Yuan)Stand wetcoolingplantDatongpowerplantToketopowerplantYangChenpowerplantEquipment 135.66 492.11 346.40 420.70costConstruction 58.98 69.80 122.16 145.29costInstallation 58.98 68.66 96.68 68.11Total 256.82 630.57 565.24 634.10Results of a similar analysis conducted for USplants was presented by Maulbetsch (2008) in anAdvanced Cooling Workshop in Charlotte, NC andthe US results according to this study arepresented in Fig.5. Based on these limitedsamples, in US, the capital costs of dry coolingsystems appear to be about 3.0 - 3.6 times higherthan wet cooling systems and, in China 2.0 - 2.5.It should be noted that the operating cost will varydepending the cost of water and water treatment.Fig.5 Cost comparison by Maulbetsch (2008)Market Potential of Dry Cooling inChinaBased on the current GDP growth rate in China,the demand for electrical power is significant. Ithas been predicted that the increase of theelectricity must be at least 7% to maintain thecountry’s GDP growth. Reportedly usingconservative assumptions, Liu (2007) predicts thetotal electric energy demand for 2010 and 2020 tobe 818 GW and 1186 GW, respectively, as shownin Table 4.Chen (2008) predicts the demand for dry coolingsystems for heat exchanger manufactures asshown in Table 5. Based on his prediction, therewill be about 30 new dry cooling power plants in2007, 40 in 2008, 45 in 2009 and 45 in 2010 withaverage capacities equivalent to 600MW, to berequiring heat exchangers for their dry coolingsystems. The market is expected to get evenbigger if water becomes more expensive.Table 4. Electricity demand predicted by LiuYear 2006 2010 2020Total power (GW) 622 818 1186Coal Power (GW) 484.05 624.5 780Hydraulic (GW) 128.57 180 320Nuclear (GW) 6.7 8 40Wind (GW) 2.589 5 40Other (GW) 0.091 0.5 6Table 5. Air cooling power plant potentialNew installed aircooling plant(GW)Year 2007 2008 2009 201018 24 27 27Heat Exchanger ManufacturersHeat exchangers are the most expensive and themost critical components in dry cooling systems ofthermal power plants.Due to the attractive market potential for heatexchangers, international and local Chinesecompanies are competing to produce highperformance and cost-effective heat exchangersand cooling towers. Two leading internationalcompanies, SPX and GEA, have set upproduction lines and factories inside China. Thereare four major Chinese local manufactures thathave emerged in recent years in competition toSPX and GEA.Finned tube bundle design shown in Fig.6 is theonly heat exchanger element used in thermalpower plants. In this figure, extended surfaces orfins are used to increase the heat transfer surfacearea. The challenges for the manufacturers are toproduce low-cost finned surfaces that must resistcorrosion, be lightweight but have adequatemechanical strength.Fig.6 Finned tube heat exchangerSPX Cooling Technologies is the leading full-line,full-service cooling tower and air-cooled3226

Australian Geothermal Energy Conference 2009condenser/heat exchanger manufacturer. SPXhas set up finned tube heat exchanger plants inZhang Jia Kou and Tianjing respectively. Theirmarket share is almost 35% in Chinese coal-firedpower plants.GEA has also set up a subsidiary in Longfan tomanufacture finned tube heat exchangers. It alsohas two joint ventures with local Chinese partnersin Shang Xi and Changshu. The market share ofGEA is about 30%.Harbin air conditioning Co., Ltd. is the largestlocal heat exchanger manufacturer in China. Theirdry cooling products cover about 20% in coal-firedpower plants and about 50% in the petroleum andchemistry processing plants.Other heat exchanger manufacturers in Chinainclude Beijing Longyuan Cooling TechnologyCo., Ltd., Shouhang IHW Cooling Technology(Beijing) Co., Ltd. and Jiangsu ShuangLiang AirconditioningEquipment Co., Ltd.Dry Cooling Research and CoolingTower DesignWhile most large heat exchange manufacturerscan provide design, manufacture and installationfor the entire cooling system including heatexchangers and the cooling tower, most of thenatural draft cooling tower design and installationare done by power design and research institutesin China.The China Institute of Water Resources andHydropower Research (IWHR) is acomprehensive research organization in thermaland nuclear power. The institute has a divisionspecializing in cooling tower design, coolingprocessing optimization, efficiency improvementof heat exchange and the cooling towersimulation.IWHR has conducted intensive studies on theoptimisation of the natural drafting cooling towersto improve the cooling efficiency.Beijing University and Tsinghua University play aleading role in CFD, heat exchanger research andnatural draft cooling tower optimisation.Other universities specialised in heat exchangeand cooling tower related research include NorthChina Electric Power University, ChongqingUniversity, Harbin Institute of Technology, andXi’an Jiaotong University.Cooling Tower in Geothermal PowerPlantThe heat rejection per kWh(e) of net generationfrom geothermal power plants will be four or moretimes as great as from fossil-fuelled plants(Kroger, 2004). This will require larger coolingtowers at higher costs.Water shortage exists in most proposedAustralian geothermal sites. The dry cooling willbe the only option for these geothermal powerplants. Mechanical draft consumes a largeamount of power for driving fans so natural draftcooling system may be more attractive, providedthe capital cost is acceptable.Surrounding environment conditions have also asignificant impact on the performance of powerplants with dry cooling systems. Most proposedgeothermal sites experience large dailytemperature differences. An excessive rise incooling water temperature during periods of peakambient temperature will result in a loss ofefficiency. In this case, hybrid cooling towercombining dry and wet cooling system (such asthe system shown in Fig.7) may prove more costeffective.In this design, both dry and wet sectionsare operated at the peak ambient temperaturewhile only the dry section is used for the rest oftime.Fig. 7 Natural draft hybrid cooling systemOther options for geothermal plant cooling includeprecooling the entering air by humidification ordeluging the air side of the heat transfer surfacewith water during the high cooling demand.Fans may also be used to enhance the naturalcooling during high ambient temperature.SummaryAn appropriate and well-designed cooling systemcan have a very significant positive impact ongeothermal power plant performance andprofitability.The combination of theoretical and experimentalstudies as well as extensive practical experiencein dry cooling technology in Chinese coal-firedpower industry may offer good examples towardsa cost-effective design and operation of suchcooling systems for Australian geothermal powerindustry.4227

Australian Geothermal Energy Conference 2009ReferencesZhu, X, and Guan, X., 2006, Economic analysis ofdry cooling on supercritical generator, thermalpower, December, 2006.Chai, Q. Y., 2006, Application of dry cooling andeconomic analysis in thermal power plants,Proceedings on water saving technology in powerplants 2006, Qindao, China, October 2006.Liu, J. X., 2007, Harbin air conditioning Co., Ltdbusiness report, Sinolink Securities, September2007.Chen, Y. C., 2008, Introducing air coolingindustries, Southwest Securities, July 2008.Kroger, D. G., 2004, Air-cooled heat exchangersand cooling towers, PennWell Corporation, Tulsa,Oklahoma.5228

Australian Geothermal Energy Conference 2009How to Increase Geothermal Power Conversion EfficienciesHal GurgenciQueensland Geothermal Energy Centre, School of Mech. and Mining Engrg, The Uni. of Queenslandh.gurgenci@uq.edu.auGeothermal power plants in dry regions typicallyuse air cooling and consequently suffer fromreduced efficiencies during hot days. In thispaper, it will be demonstrated it may be possibleto use solar boosting to maintain the geothermalplant power generation in such instances. It willbe shown that commercial feasibility of solarboosting is improved when the cycle fluid isheated over a variable temperature range insteadof the steam or organic Rankine cycles with fixedevaporation points. Results with supercritical CO 2cycles will be compared against moreconventional alternatives.Keywords: power conversion; supercritical cycles;solar energy; hybrid plants; hot rock geothermal.IntroductionTwo factors prevent widespread adoption of HFR(Hot Fractured Rock) geothermal power inAustralia: Compared to other renewables, there is ahigher technical risk in HFR projects, namelyin locating, establishing and exploiting areservoir. This risk will be constrained withprogress but will never disappear since eachnew prospect will be unique. Compared to coal- or gas-fired plants,geothermal plants need to dump severaltimes more waste heat per MW of electricitygenerated. Without easy access to water,this can be a problem.Higher potential rewards make risks moreaffordable. The reward from HFR investment isthe electricity generation. If this reward can beincreased, then higher risks would be acceptableto the investors.The electricity generation from a given geothermalfluid source depends on: the fraction of the heat extracted from thegeothermal fluid; and the efficiency of converting the extracted heatto electricity.Let us start with the second one, a.k.a. thethermal efficiency. The thermal efficiency for apower conversion cycle is defined as the netturbine shaft power divided by rate of heat inputinto the cycle working fluid. The theoretical limiton thermal efficiency is the efficiency of theCarnot cycle, which represents ideal powerconversion conditions. The actual efficiencies areusually much lower than the theoretical efficiencydue to unavoidable losses. A good indicator ofthe maturity of a technology is what fraction of itsCarnot efficiency it is able to deliver in actualoperations.In Figure 1, we plot the fraction of thecorresponding Carnot efficiencies realised byoperating geothermal, nuclear, coal, andcombined-cycle gas turbine plants. Thegeothermal plant efficiencies are for binary plantscalculated from data provided in Tester (2006)and the other plant data are from Willson (2007).Figure 1: Fraction of the theoretical limit realised by differentpower generation technologies.The important message from Figure 1 is that lessthan 40% of the ideal efficiency is realised inactual geothermal practice and the ratio is as lowas 30% for low reservoir or high ambienttemperatures. In contrast, any other modernpower technology is able to enjoy around 70% ofits ideal efficiency limit. Clearly, the geothermalenergy practice has room to improve.A significance source for efficiency loss ingeothermal power plants is the irreversibility in theheat exchangers, e.g. see Demuth(1979),Larjola(1996), Vargas(2000), Chen(2006),Bronicki(2008).Such irreversibilities can be significantly reducedby continuously matching the cycle fluidtemperature against the temperature of thegeothermal fluid during the heat exchangeprocess. This is not possible in a conventionalRankine-cycle plant but easy in a supercriticalcycle.Case Study DefinitionThe analysis will be based on conditions that canbe found in a typical Cooper basin HFRgeothermal reservoir. We are assuming that hotbrine is produced from a number of productionwells at a temperature of 250 o C at the rate of 500l/s. The ambient air temperatures change from1229

Australian Geothermal Energy Conference 2009about 0 C during a cold winter night to 45 C ona hot summer day.We will consider two power plants to exploit thisresource. One will be based on a supercriticalCO 2 cycle and the other on a steam cycle. Thesteam cycle is conventional technology although itis usually employed at higher temperatures. Thesupercritical CO 2 cycle is a new technologydevelopment being pursued by the QueenslandGeothermal Energy Centre of Excellence.Supercritical Cycle vs ConventionalTechnologyFigure 2 shows the supercritical CO 2 diagram ontemperature-entropy coordinates. A regenerator isused to recover some of the heat in the turbineexhaust stream.could only generate 29 MWe from the samereservoir and have an efficiency of 13.7%.In other words, the supercritical CO 2 plantproduces than more than twice the amount for thesame resource. The performance varies throughthe year with the ambient temperature and thesupercritical plant is more sensitive to the ambienttemperature than the steam plant. Nevertheless,the expected annular electricity generation by thesupercritical plant is 50% higher than that by thesteam plant for the same geothermal resourceand the same climate. The full comparisonbetween the supercritical plant and theconventional technology is shown in Table 1.Table 1. Comparison of supercritical CO2 cycle andconventional plant performanceCO 2cycleSteamcycleBrine temperature, o C 250 250Brine flow rate, kg/s 500 500Brine return89 150temperature, o CDesign-point power 63 29generation, MWeAnnual generation, 401 256GWhWaste heat, MWth/MWe 4.5 6.4Wet cooling tower water 8.0 8.2use, kg/kWhFigure 2. The supercritical CO2 cycleThe case study temperatures are too high for anorganic rankine cycle. The conventionaltechnology for this temperature range is offeredby a steam Rankine cycle. This is shown inFigure 3.Figure 3. Conventional steam cycleCycle computations indicate that a power plantbased on the supercritical CO 2 cycle has thecapacity to generate 63 MWe at an efficiency of18.1%. In comparison, the proven technologyBoth plants operate on the same geothermalresource with the same subsurface investment.At an electricity sale price of 10¢/kWh, thedifference in annual revenue would be aboutA$15m.The water usage in Table 1 is provided only forcomparison purposes. Otherwise, the analysis inthis section assumes conventional dry coolingtower technologies with a heat exchangerapproach temperature difference of 8oC. On hotdays, this reduces the plant output significantly.Using innovative cooling technologies asexplained in the next section, this vulnerability tohigh ambient temperatures can be minimised.Dry Cooling Tower TechnologiesWhether one uses new technology or establishedtechnology, for each MW generated severalmultiples of that amount must be dumped atwaste heat. A more efficient plant would dump alesser amount per MWe but large amounts heatmust be dumped for either cycle.In many geothermal plant locations, water isscarce and air cooling is the only option. Aircooling can be done by using fans or by usingnatural draft through a cooling tower. The fandrivensystems can be built quickly and atrelatively low cost but their operating costs arehigher due to their higher maintenance2230

Australian Geothermal Energy Conference 2009requirements and the parasitic losses associatedwith running the fans.The Queensland Geothermal Energy Centre ofExcellence will do system studies, developadvanced heat exchanger technologies, andexplore innovative systems towards better naturaldraft cooling towers. One of the optionsconsidered by the Centre is a low-cost air-liftcooling tower as depicted in Figure 6.The system depicted in Figure 7, aims to cool astored medium by using radiative coolers at night.The night-time sky temperature is about 0 o Cthrough the year in most of Central Australia.Either sensible or latent storage can be used toextend nighttime cooling through the day. Therequired investment is smaller for a supercriticalcycle where the first T of cooling can be done byair (e.g. from 90 o C to 40 o C) and the second Tby the stored coolth (e.g. from 40 o C down to20 o C).Supercritical Rankine CycleIf a geothermal plant has access to cold water orif some of the cooling technologies of the previoussection can be judiciously implemented, it mightbe possible to design a plant at an even higherefficiency. In a supercritical Rankine cycle, CO 2would condense at a temperature below 30 o Cand it would then be heated to supercriticaltemperatures and expanded as a supercriticalgas. The temperature-entropy diagram for asupercritical CO 2 Rankine cycle is shown inFigure 6.Figure 4. Innovative cooling tower designFigure 4 shows an innovative cooling towerconcept being investigated by the QueenslandGeothermal Energy Centre of Excellence.The tower is built as a flexible shroud and is heldin place in tension by the buoyancy force actingon the toroidal rings filled with lighter-than-air gas.There are a few issues associated with thisconcept but the Centre is expecting to be ready tobuild a prototype by mid-2010.The motivation for the air-lift cooling tower shownin Figure 4 is to enable construction of very tallcooling towers at an acceptable cost.Taller towers would increase the suction airvelocity and the heat transfer at the heatexchangers and they also would enjoy lowertower exit temperatures.Another system innovation under considerationtargets the exploitation of clear and dry nighttimeskies typically found in the Australian outback.Figure 5. Nocturnal cooling for power plantsFigure 6. Supercritical CO2 Rankine CycleThe cycle shown would deliver even higherpower. Since the critical point for CO 2 is about 30o C, this plant would require access to a coolingmedium well below 30 o C.That is why a supercritical Rankine cycle may notbe feasible for most Australian geothermal plantlocations unless it is combined with otherinnovative cooling options as described elsewherein this paper.Geothermal + Solar Hybrid PlantsAnother interesting opportunity with supercriticalcycles is to use solar heat to maintain the plantoutput on hot days.For example, by adding solar boosting to the plantof Figure 2, one can maintain the design output atambient temperatures as high as 45 o C. Thesupercritical cycle with solar boosting under theseconditions is shown in Figure 7.3231

Australian Geothermal Energy Conference 2009injection well and the hot CO 2 would rise in theproduction well. No significant compression inputor downhole pumping would be necessary to drivethe system described in Figure 8.Figure 7. Supercritical CO2 Brayton cycle with solar boostingIt is difficult to make solar boosting economicallyfeasible with steam plants. This is because mostof the heat added to the Rankine cycle is latentheat at the saturation temperature correspondingto the turbine design inlet pressure. It is notpossible to significantly shift this temperatureupwards without changing the turbine inletpressure. Changing the pressure requires aseparate turbine. Therefore, solar boosting of ageothermal plant based on a steam cycle requirestwo turbines: one for geothermal-only operationand the other for geothermal + solar. Even then,the optimum operating point would be elusivebecause of variable solar incidence and theinability of the plant to optimally track suchvariations. In a supercritical cycle, the turbineinlet temperature and the pressure are not linkedand the solar heat can be added to the cycle fluidon the same pressure line as shown in Figure 7.Supercritical CO 2 Geothermal SiphonThe use of CO 2 as a geothermal heat exchangefluid has been proposed by Brown (2004) andPruess (2006). Gurgenci (2008) and Atrens(2008) and Atrens (2009) expanded the conceptto include the power conversion using asupercritical CO 2 cycle. A supercritical CO 2 cycleachieves higher efficiencies but even then hardlycatches up to the maturity of technology availableto coal- and gas-fired power plants. For example,the supercritical CO 2 Rankine cycle of Figure 6has a thermal efficiency of 20.2%, which is 49% ofits theoretical limit. This is much better than thesecond law efficiency of 33% for the steam cycleof Figure 3 but still below the 60-70% enjoyed bycoal and gas plants as shown in Figure 1.By using a supercritical cycle, the heat exchangerirreversibility is reduced but not eliminated. Theheat exchanger irreversibilities can only beeliminated when we do not use heat exchangers.This is possible if we use the same CO 2 forgeothermal heat exchange in the reservoir andexpand it through the turbine when it comes to thesurface and send it back to the reservoir aftercooling it. The cold CO 2 would sink in theFigure 8. Operation of the supercritical CO2 geothermalsiphonThis is a new concept where supercritical CO 2extracts reservoir heat, rises to the surface anddrives a turbine, and then is cooled and sent backunderground to close the cycle.The concept offers the following intrinsicadvantages over the alternatives:Driven by the buoyancy of the hot fluid, itdoes not need a submersible pump Removing the binary plant heat exchangerincreases efficiency and lowers capital costs Better geothermal heat extraction enableslarger well separation and longer plant lifeAccess to large quantities of CO 2 is essential,first, to start the reservoir and, then, possibly tomake up for underground capture. The cost ofsuch access could be defrayed by the CO 2sequestration benefits.ConclusionsThe Queensland Geothermal Energy Centre ofExcellence (QGECE) of The University ofQueensland is working towards the followingresearch outputs in the next two years:Supercritical CO 2 turbines for high-gradegeothermal resources and solar/geothermalhybrids4232

Australian Geothermal Energy Conference 2009Better dry cooling technologies for geothermaland solar thermal power plants in arid regions Delivery of these outputs will quicken thelarge-scale adoption of HFR geothermalenergy in Australia and around the globe.In this paper, we compare the proposedtechnologies to present alternatives and identifyand quantify the potential benefits from suchresearch.Comparing geothermal power against moremature technologies such as nuclear, coal powerplants, and gas turbines, we first identify a clearpotential to increase geothermal powerconversion efficiencies by at least 50%.Incremental improvements cannot realise such apotential. A fundamentally new approach isneeded. Supercritical cycles offer such afundamentally new alternative.A supercritical CO 2 cycle is the superioralternative at geothermal fluid temperaturesabove 200 o C. These temperatures are too hotfor organic fluids but not hot enough for steamcycles. At 250 o C, for example, we demonstratethat a supercritical cycle would double the poweravailable from conventional technology. For ageothermal plant based on a 500 l/s hot brineresource, this means and additional revenue of$15m per year at an electricity sale price of10¢/kWh.Most of the components in a supercritical CO 2cycle are off-the-shelf technology except for theturbine. To deliver the missing link, QGECE isaiming to demonstrate a 5-kW prototypedemonstrated in the laboratory by mid-2011 anddevelop the funding and the partnership for a 1-MWe demonstration project by mid-2013.Even then, HFR geothermal plants may still beunviable in hot and arid regions without better drycooling technologies. QGECE is pursuingadvances in this area through incrementalresearch and system innovations. Some of thetarget innovations are described in this paper.ReferencesAtrens, A D, Gurgenci, H, Rudolph, V, “CarbonDioxide Thermosiphon Optimisation”, 2008Australian Geothermal Energy Conference,Melbourne.Atrens, A.D., Gurgenci, H., and Rudolph, V.: CO 2Thermosiphon for Competitive GeothermalPower Generation, Energy & Fuels, 23 (2009)553-557.Brown, D.W.: A Hot Dry Rock Geothermal EnergyConcept Utilizing Supercritical CO 2 Instead ofWater, Proceedings, 25th Workshop onGeothermal Reservoir Engineering, StanfordUniversity, Stanford, CA (2000).Bronicki, L.Y.: Advanced Power Cycles forEnhancing Geothermal Sustainability, IEEEPES General meeting, Pittsburgh, PA (2008).Chen, Y., Lundqvist, P., Johansson, A., andPlatell, P.: A comparative study of the carbondioxide transcritical power cycle comparedwith an organic rankine cycle with R123,Applied Thermal Engineering, 26 (2006)2142–2147.Demuth, O.J.: Analysis of Binary ThermodynamicCycles from a Moderately Low-TemperatureGeothermal Resource, Report #TREE-1365,Idaho National Energy Laboratory (July1979).Gurgenci, H., Rudolph, V., Saha, T., and Lu, M.:Challenges for Geothermal Energy Utilisation,Proceedings, 33rd Workshop on GeothermalReservoir Engineering, Stanford University,Stanford, CA (2008).Gurgenci, H.: Electricity Generation Using aSupercritical CO 2 Geothermal Siphon,Proceedings, 34th Workshop on GeothermalReservoir Engineering, Stanford University,Stanford, CA (2009).Larjola, L.: Electricity from Industrial Waste usingHigh-speed Organic Rankine Cycle, Int JProd Economics, 41 (1995) 227-235.Pruess, K.: Enhanced Geothermal Systems(EGS) using CO 2 as Working Fluid – A NovelApproach for Generating Renewable Energywith Simultaneous Sequestration of Carbon ,Geothermics, 35 (2006), 351-367Tester, J.: The Future of Geothermal Energy, MITPress, (2006)Vargas, J.V.C., Ordonez, J.C., and Bejan, A.:Power extraction from a hot stream in thepresence of phase change, Int J of Heat andMass Transfer, 43 (2000) 191-201.Willson, P.: The Nu gas Concept – CombiningNuclear and Gas Power Generation, PBPower,http://www.imeche.org/industries/power/nugas-june-2007.htm (2007).5233

Australian Geothermal Energy Conference 2009An Overview of GRANEX Technology for Geothermal PowerGeneration and Waste Heat RecoveryBehdad Moghtaderi* and Elham DoroodchiPriority Research Centre for Energy, Chemical Engineering, School of EngineeringFaculty of Engineering and Built Environment, The University of Newcastle, Callaghan, NSW 2308, Australia* Corresponding author: Behdad. Moghtaderi@newcastle.edu.auThis paper reports on the recent advancement ofthe GRANEX technology platform developed byour group for power generation from low-gradeheat sources. The technology is particularly suitedto applications involving geothermal powergeneration and waste heat recovery. Bycombining the concepts of heat regeneration andsupercritical Rankine cycle into a unified process,GRANEX improves the thermal efficiency of thecycle and increases the net electrical output whichcan be recovered from a given low-grade heatsource. The regeneration of the thermal energy inGRANEX is achieved through a novel heatregenerator invented and patented by our groupin partnership with Granite Power Limited (GPL).Development of GRANEX dates back to early2006 when a Research and DevelopmentAgreement was established between theUniversity of Newcastle and GPL. In conjunctionwith a program of fundamental studies an appliedprogram of work was undertaken for proof ofconcept and prototype development with theassistance of a REDI grant from AusIndustry(2007-2009). By 2008, a 1 kW prototype had beenbuilt and experimental trials of the system hadbeen completed, demonstrating considerableadvantages over conventional systems in terms ofboth thermal efficiency and power generation(about 40% improvement). This was followed bythe design of a 100 kW pilot-plant in early 2009.The pilot-plant is currently under construction andis due to be commissioned by late November2009.Keywords: Geothermal power, waste heatrecovery, GRANEXIntroductionThe growing world-wide concern about energyconservation and the global impact of greenhousegases have prompted a series of new researchand development activities focusing on renewableenergy sources, particularly solar, wind, biomass,and geothermal energy. By and large thegeothermal energy is an untapped energyresource despite its potential and clearenvironmental advantages (e.g. minimal CO 2emissions) over other sources of energy, such asfossil fuels and nuclear energy. According to anestimate by the IEA (International EnergyAgency), currently only 0.3% of the world’selectricity is generated from geothermal sources(Priddle; 2002). However, geothermal powerproduction is expected to steadily increase at arate of 4.3% per year reaching a share of 0.6% ofthe global electricity production by the year 2030(Priddle; 2002, Barbier; 2002, Bertani; 2005).Although the predicted growth in the geothermalpower production sector should be considered asa positive sign of the worldwide move towardsmore renewable and environmentally friendlyenergy sources, the growth clearly falls short ofexpectations. The contribution of the geothermalenergy to the world’s electricity production by2030 can be potentially one order of magnitudehigher than the IEA’s estimate, should thetechnical problems associated with the use ofgeothermal energy are resolved (Barbier; 2002,Bertani; 2005). Within this context, the study ofgeothermal power cycles is regarded as one ofthe key areas for major technologicalimprovements since many of the problemsassociated with the geothermal power technologyare underpinned by inefficient and oftenunsuitable heat exchange processes within powercycles. That is partly due to the fact that mostpower cycles currently employed in geothermalapplications (with the exception of Kalina powercycle) were originally designed for large-scalepower production from fossil fuels where highertemperature sources are available for heatexchange.In recognition of these shortcomings, the GranitePower Limited (GPL) and the University ofNewcastle initiated a joint R&D program in 2006with the goal of establishing alternative andpotentially more efficient ways of generatingpower from geothermal and other low-grade heatsources, such as industrial waste heat. Reductionof industrial waste heat will undoubtedly lessenthe demand for energy that would otherwise bemet, either directly or indirectly, by primary energyresources such as fossil fuels. Industrial sectorssuch as power generation, aluminium, iron, andsteel manufacturing, petroleum refining, cementproduction, chemical processing, and pulp andpaper manufacturing account for approximately65% of all industrial waste heat.Theoretical ConsiderationsThe fraction of heat that can be converted tomechanical work and/or electrical power is limitedby laws of thermodynamics (Cengel and Boles;2002). This fraction is commonly expressed interms of the so called “grade (or quality)” of thewaste heat although from a thermodynamic pointof view the correct terminology is “exergy” (the1234

Australian Geothermal Energy Conference 2009useful work potential of a system at a given state).Source temperature rather than “quantity” is theprimary consideration in determining the grade ofa waste heat source. For instance no power canbe generated from ambient air even though itcontains huge quantities of thermal energy.Generally, waste heat streams with sourcetemperatures within the range of 600 o C-1700 o Care considered high-grade while those within thetemperature ranges of 250 o C-600 o C and 50 o C-250 o C are deemed medium-grade and low-grade,respectively. Geothermal sources have typicallytemperatures between 150-250 o C and, hence,can be categorised as low-grade.The principles of power generation from low tohigh-grade heat sources are not different and theconstraints that apply to any power generationprocess equally apply to all. Three processesmust be accomplished within the temperaturerange defined by the source (T so ) and sink (T si )temperatures. These are: (i) heat addition fromthe source to power plant driven by thetemperature differential T so = (T so – T H ) where T His the absolute temperature at which energy isintroduced into the plant, (ii) power generation byan expander (i.e. turbine) driven by thetemperature differential T = (T H – T L ) where T L isthe absolute temperature at which heat is rejectedto the sink, and (iii) heat rejection from the powerplant to the sink driven by T si = (T L – T si ). Amongtemperature differentials T is of significantimportance since many key features of the plantdepend on T. For example, the required energyinput per unit power (Q/W) and plant size per unitpower (A/W) can be expressed in terms of Tusing the following equations:(Q/W) = (T H / T) (1)(A/W) = (T H / T 2 ) (2)For low-grade heat sources T is inherently small,hence, for a given power a low-grade heat sourceis required to provide more energy than a highgradesource (Eq 1). The plant size correspondingto the low-grade heat source will be also muchlarger than that of the high-grade one (Eq 2).The other major difficulty with low-grade heatsources is that, if not minimised, T so and T si willtake significant fractions of the possibletemperature drop (i.e. T so -T si ) reducing T and,thereby, the net power output and thermalefficiency of the plant. While the Carnot efficiency( C in Eq 3) defines the upper limit of thermalefficiency the actual efficiency is given by Eq (4): C = (W Max /Q) = (T so - T si ) / T so (3) = (W/Q) = (T H – T L ) / T H = T / T H (4)If T so and T si are minimised (T I - T R ) willapproach (T so -T si ) and, hence, and W movetowards C and W Max , respectively (see Eqs 3 and4). Minimisations of T so and T si are particularlyimportant for real-world finite capacity sources(and sinks) where T so and T si do not necessarilyremain constant during the heat addition and/orrejection processes. Among conventional powercycles the Organic Rankine cycle (ORC) possessthe largest source and sink temperaturedifferentials (T so and T si ) and, thus, suffers themost from problems associated with small T.This is clearly illustrated in Figure 1 where thetemperature entropy (T-S) plots of the ORC,Kalina cycle and Supercritical Rankine cycle(SRC) are shown by the thick solid lines whiledashed lines represent the phase diagram of theworking fluid. As can be seen, there aresignificant temperature differences between thesource and the working fluid in an ORC during theheat addition process because the phase changeof the working fluid takes place at constanttemperature under the saturation dome.Figure 1: T-S plots of ORC, Kalina, and SRC.Kalina cycle reduces the temperature mismatchbetween the source and the working fluid using azeotropic mixture of ammonia and water withvariable temperature phase change (Figure 1).While this approach increases T, and W, itrequires a complex array of absorption anddistillation hardware. The added complexitytogether with the high sensitivity of Kalina cycle topressure and composition of the ammonia-watermixture, limits its application over a wide range ofsource temperatures and significantly adds to thecapital and operating costs (DiPippo; 2005).SRC also avoids the constant temperature phasechange except that the heat addition and/orrejection processes are carried out undersupercritical conditions using a single-componentworking fluid rather than a zeotropic mixture likethat employed in the Kalina cycle (Figure 1). Thisapproach not only results in a simple plant layoutbut a small T so and, hence, higher T, and W.However, the constant pressure lines in thesupercritical region are generally too close and assuch the conventional SRC has a relatively lownet power per unit of enthalpy change. Thus theturbine outlet stream in a conventional SRC maycontain large amount of thermal energy which istypically wasted during the heat rejection processleading to thermal efficiency losses. Moreover,relatively high operating pressures may be2235

Australian Geothermal Energy Conference 2009required to achieve a desired power output undersupercritical conditions. As shown in the nextsection, GRANEX effectively resolves the aboveshortcomings of the conventional SRC in arelatively simple manner.GRANEX TechnologyFigure 2 shows the schematic representation of aGRANEX based power plant. The system isessentially a conventional SRC fitted with a heatregenerator. The inclusion of the regeneratorresolves the issue of low net power per unit ofenthalpy change by utilising the unused thermalenergy of the turbine outlet stream in the heat-upof the cold working fluid exiting the pump. Thisversion of SRC which is also referred to as“Regenerative Supercritical (RGSC) Rankinecycle” has higher thermal efficiencies than theconventional SRC. The issue of potentially highoperating pressures is also overcome by selectingsuitable working fluids with sufficiently low criticalpressures. In addition, the patented design of theregenerator in GRANEX avoids the so-calledmaximum enthalpy points for which the drivingforce for heat transfer is zero. This ensures amuch smoother heat exchange duringsupercritical operation.Figure 2: Schematic of GRANEX system.Power Cycle AnalysisThe performance of the GRANEX cycle wastheoretically assessed by a numerical modeldeveloped using the process simulation softwareHYSYS. For a large selection of working fluidsfirst- and second-law thermodynamic analyses ofthe cycle were carried out to determine the valuesof W (net power), (thermal efficiency), and II(exergy efficiency) under a range of operatingconditions in terms of heat source/sinktemperature (that is 150 o C < T so < 250 o C and15 o C < T si < 35 o C). This was to establish the socalledenvelop of operation for each fluid and rankthem on the basis of thermal and exergeticefficiencies. The interplay between the sinktemperature and condensation properties of theworking fluid will be carefully examined to assessthe impact of ambient conditions on the overallcycle performance. A series of calculations will bealso performed to investigate the impact ofmolecular weight and density on key turbine (i.e.expander) characteristics such as number ofstages, exit area, sonic velocity, and leave loss.As part of these studies, the performance ofGRANEX was compared with several existinggeothermal power plants (Table 1). In each casethe calculations associated with GRANEX werecarried out using a working fluid referred to as“Fluid-6” under source and sink temperaturesidentical to that of the actual plant. The resultshave been summarised in Figures 3 to 5.Table 1: List of case studiesCase Case Description Ref1 Kalina DiPippo; 20052 Otake DiPippo; 20053 Nigorikawa DiPippo; 20054 Heber (SIGC) DiPippo; 20055 Brady (Double Flash) Kanoglu & Cengel, 19996 Single Flash-1 (Nevada, US) Kanoglu & Cengel, 19997 Single Flash-2 (Nevada, US) Kanoglu & Cengel, 19998 Double Flash (Nevada, US) Kanoglu & Cengel, 19999 Binary (Nevada, US) Kanoglu & Cengel, 199910 Combined (Nevada, US) Kanoglu & Cengel, 199911 Pseudo-SC (Nevada, US) Gu & Sato; 2002Figures 3 and 4 illustrate the plots of thermalconversion and exergetic efficiencies as afunction of the temperature difference betweenthe geothermal fluids at the production and rejectwells, T geo . Plots have been drawn using thedata shown in Table 1 for both conventional andRGSC (GRANEX) Rankine cycles.As can be seen, the performance of the RGSCcycle is far superior to that of conventional cycles.For the range of investigated sourcetemperatures, the thermal efficiency variesbetween 10-18% with an average of 16.5% forRGSC cycle whereas for conventional cycles,including Kalina, the thermal efficiency does notchange and plateaus around a nominal valuebetween 11 to 12%.Thermal Efficiency (%)30272421181512963Conventional TechnologiesRGSC (GRANEX)00 25 50 75 100 125 150 175 200T geo( o C)Figure 3: Comparisons of thermal efficiencies of the RGSC(GRANEX) and conventional cycles.3236

Australian Geothermal Energy Conference 2009Exergetic Efficiency (%)504540353025201510500 25 50 75 100 125 150 175 200T geo( o C)ConventionalRGSC (GRANEX)Figure 4: Comparisons of exergetic efficiencies of the RGSC(GRANEX) and conventional cycles.The higher thermal efficiency of the RGSC cycleimplies that more power can be generated fromthis cycle per unit of input energy than from aconventional cycle. This is quite evident fromFigure 5 where the specific power (W spc ) has beenplotted against T geo . The specific power isdefined as:Wspc100 W m. (5)netgeoregenerator module consisting of 4 tube and tubeheat exchangers fitted with our patented heatexchange technology, an electrical heater (i.e.heat source) with a 30 kW rated capacity, a boiler,and a turbine simulation unit fitted with acollection of valves and heat exchangers toreproduce the pressure and temperature drops oftypical expanders. The facility is fully automatic(uses delta VB) and has been equipped with anarray of sensors (T, P, and flow) and safetydevices such as pressure relief valves, gassensors, alarms, an air extraction system.Measurements of pressure, temperature, and flowrate were taken in 20 different points around theplant at a frequency of 10 per minute using asophisticated data acquisition system. For anygiven combination of operating conditions(working fluid, T, P, and flow rate), experimentswere carried out over a 1.5 hours period and wererepeated at least twice to ensure the statisticalintegrity of the results. The aim was to develop anexperimental version of the operational envelopand compare it with that developed fromtheoretical predictions. About 650 individualexperiments were completed over an eightmonths period to achieve the broad objectives ofthe project.W spc(kJ/kg)80604020Conventional TechnologiesRGSC (GRANEX)0 0 25 50 75 100 125 150 175 200T geo( o C)Figure 5: Plots of specific power versus Tgeo.ExperimentalFifteen candidate working fluids were selectedfrom power cycle analysis. The shortlist ofselected fluids was shortened by eliminating fluidswhich in terms of W, and II underperforming areference ORC with iso-pentane as working fluid.The remaining fluids were experimentally studiedover a range of source and sink temperatures(150 o C

Australian Geothermal Energy Conference 2009Net Power (kW)Efficiency Improvement (%)1.210.80.60.40.2Amonia/Water (Kalina)Iso-pentane (ORC)00 1 2 3 4 5 6 7 8 9 101112131415Working FluidFigure 7: Measurements of net power from the 1 kW unit.6040200-20-40-60Granex CycleFluid 1Fluid 2Fluid 3Fluid 4Fluid 5Fluid 6Amonia/WaterKalina CycleFluid 7Fluid 8Fluid 9Fluid 10Fluid 11Fluid 12Fluid 13Reference ORC(Iso-Pentane)Figure 8: Efficiency improvement (%) with respect to areference ORC.Work in ProgressA set of experiments is being carried out using the1 kW POC unit at temperature ranges between80 o C and 150 o C. This lower temperature range isof more relevance to waste heat recoveryapplications. The preliminary findings indicate thatGRANEX can maintain its advantage overconventional systems even at lower sourcetemperatures if a suitable working fluid isemployed.Also, based on theoretical and experimentalresearch conducted since 2006 on GRANEX forgeothermal applications, the design of a 100 kWprototype has just been completed. The prototypewhich is currently under construction is due forcommissioning by the end of Nov 2009. Theprototype will be employed in a comprehensiveseries of pilot-scale experiments in early 2010 todevelop the scale-up rules.ConclusionsThe present document summarises the result of acombined theoretical and experimental study onGRANEX technology. The study is part of a largerproject aimed at developing a technology platformwith thermal efficiency and economics superior toconventional system for power generation fromlow-grade heat sources. GRANEX combines theestablished concepts of supercritical powergeneration and heat regeneration into a unifiedplatform. As shown in this document GRANEX,leads to significantly higher conversionefficiencies than those currently provided byconventional power cycles.Owing to its simplicity, the RGSC cycle also offersa greater degree of flexibility and robustness,which in turn, will translate into much bettereconomic characteristics when compared withconventional power cycles.ReferencesPriddle, R., 2002, Word Energy Outlook 2002,Second Edition, IEA report 2002.Barbier, E., 2002, Geothermal Energy Technologyand Current Status: An Overview, Renewable andSustainable Energy Reviews, 6, p. 3–65.Bertani, R., 2005, World Geothermal PowerGeneration in the Period 2001–2005,Geothermics, 34, p. 651–690.DiPippo, R., 2004, Second Law Assessment ofBinary Plants Generating Power from Low-Temperature Geothermal Fluids, Geothermics,33, p. 565–586.Kanoglu, M., and Cengel, Y., (1999), Retrofitting aGeothermal Power Plant to OptimizePerformance: A case Study, Journal of EnergyResource Technology, 121, no 4, pp. 295-300.Gu, Z., Sato, H., 2002, Performance ofSupercritical Cycles for Geothermal BinaryDesign, Energy Conversion and Management, 43,pp. 961-971.Cengel, Y.A., Boles, M.A., 2002, Thermodynamics:An Engineering Approach”, 4 th Ed,McGraw Hill, NY.5238

Australian Geothermal Energy Conference 2009PureCycle® Product Development and Applications UpdateCraig Morgan 1 , Stephen Byers 21Pacific Heat and Power, Level 14, 500 Collins Street, Melbourne VIC 30002 Pratt & Whitney Power Systems, 400 Main Street, East Hartford, Connecticut, USA* Corresponding Author: craig.morgan@pacificheatandpower.com, +61 3 9013 4425When field trials were first conducted in 2006 thePureCycle® product introduced a new concept inmodular, packaged, quick to market organicrankine cycle power generation systems. Over2008 and 2009 the PureCycle® system wasdeployed in number of applications includingwaste heat capture, both small scale (500kW) andlarge scale (10MW) geothermal power plants. Thesystems have performed exceptionally well withover 98% availability and exceeded expectations.Nevertheless, system improvements continue tobe made.This paper summarises the overall performanceof the systems currently in operation, productfeatures and their performance in the field, andnew technical innovations that are being offeredand considered by Pratt & Whitney PowerSystems.Keywords: PureCycle®, Pratt & Whitney PowerSystems, Pacific Heat and PowerPureCycle® applications to dateThe first field trial for PureCycle® was conductedin 2006 in Chena Springs, Alaska. Since that timestandard water-cooled systems using the nonflammableworking fluid R245fa have beendeployed in numerous applications: 10MW at Raser Technologies’ Utah plant,USA operating on geothermal brine (Fluid -geothermal brine from a hot sedimentaryaquifer; Temperature – 121°C; Flow Rate:approx 19 l/s per unit). The system is watercooled using a common cooling tower.2 units on a greenhouse operation in the USAoperating on geothermal brine (Fluid -geothermal brine from a hot sedimentaryaquifer; Temperature – 108°C; Flow Rate:approx 29 l/s per unit). The system is watercooledusing a common cooling tower.1 unit on waste heat from diesel jacket waterin Guatemala (Fluid – ethylene glycol;Temperature – 99°C; Flow Rate: approx 60 l/sper unit). The system is water cooled using acooling tower.1 unit at the Oregon Institute of technology forthe first geothermal plant in Oregon (Fluid -geothermal brine from a hot sedimentaryaquifer; Temperature – 88°C; Flow Rate: 21.5l/s). The unit is water cooled using a coolingtower.2 units on a waste to energy plant inMassachusetts (Fluid – one on low pressuresteam and one on ethylene glycol;Temperature – 105C; Flow Rate: 4500 kg/hr(steam) & 65 kg/s)1 unit using the thermal energy from an oiland gas well and operating on R134a (Fluid –co-produced fluids from an oil and gas well;Temperature – 85°C; Flow Rate: 54 l/s)The rate of enquiries and equipment orders isincreasing. Based on the existing pipeline ofopportunities we would expect this number tosubstantially increase with the continuedstrengthening of geothermal markets, andincreasing focus on waste heat recovery andenergy efficiency in industrial and oil and gasmarkets.Performance summaryTo date the equipment across all applications isoperating at > 98% availability. Power output hasbeen consistent with the theoretical modelsdeveloped in the UTC Research Centre in EastHartford, Connecticut.Technical innovations on the Model280The product development team continue to makesystem improvements that increase efficiency,broaden the variety of suitable applications, andprovide the ability to operate in with zero water forcooling. Key additions to the product include:Air condenser for use in areas with limitedaccess to water. The refrigerant is condenseddirectly in the air-condenser to maximise heattransfer. Recuperator that improves the cycleefficiency on the air and water cooledsystems. This works by capturing the wasteheat from the turbine exhaust and pre-heatingthe incoming hot liquid prior to the evaporator.Coatings and equipment modifications suchas those necessary for a high H2Senvironment in some international geothermalfields.High pressure evaporators may also beselected on a case by case basis for someapplications.1239

Australian Geothermal Energy Conference 2009Australian and New ZealandapplicationsBased on the previous 12-18 months ofdiscussions with potential customers, the keyapplications for utilising low grade heat inAustralia and New Zealand are: Waste heat from reciprocating enginesoperating on a variety of fuels (diesel, naturalgas, landfill gas, sewage digester gas) Waste heat from biomass plants (sawmillwaste and other mixed wastes) Waste heat from industrial processes andfossil fuel power generation (steel, aluminium,foundries, gas turbines)Low temperature geothermal applicationsAnalysis of the opportunities suggests that thefollowing principles apply:Prices for the major generating plant inAustralia are often more attractive than inNew Zealand due to the relative strength ofthe AUD against the USD and Euro, makingany internationally sourced equipmentcheaper in Australia.High-priced diesel generation is attractive dueto the high cost of fuel and low resource risk(the amount and flow of heat is easilyquantified)The effective revenue gained from generatingpower on-site is higher than selling to thewholesale market Renewable energy certificates (RECs)improve the financial performance of projectsdeveloped in Australia where the waste heatis derived from renewable fuels.Waste heat is easier to quantify and morecertain than geothermal resources, but lessplentiful. There is some resource uncertaintyas the waste heat is only available as long asthe host industry continues to operate.Figure 1 outlines a summary of wherePureCycle® is likely to be most cost effective.Lower riskVery costeffectiveDiesel &industrialheatrecoveryBiomassenergyplantGeothermalHigher riskCost effectiveFigure 1: Cost effective PureCycle® applicationsNevertheless, the future looks bright for Australianand New Zealand geothermal, as well as wasteheat applications.The future and corporate updatePWPS has embraced and enhanced thePureCycle® model 280 since taking over theproduct from its sister company – UTC Power inearly 2009. The PureCycle® sits alongside gasturbines in its industrial power division.For geothermal applications, generation of powerfrom the Next Generation PureCycle® usingresource temperatures at top of hole of up to175°C should be achievable. Target pricing isconfidential, but has been set at a point to ensurecompetitiveness in generating primary utilitygradepower from geothermal power plants. A firmrelease date has not yet been set.ConclusionThere is a wide variety of economic applicationsavailable that suit the current PureCycle® Model280, which continues to prove its reliability in thefield, including waste heat from engines,geothermal, and industrial waste heat. Australia isgenerally a more attractive market than NewZealand due to the lower geothermaltemperatures, better exchange rate, andsupportive policy environment. The range ofsuitable applications is widening as the team atPWPS broaden the product offering and capabilityof the unit with technical innovations.2240

Natural Draft Dry Cooling TowerAustralian Geothermal Energy Conference 2009Clare Murray 1 *1 School of Mechanical and Mining Engineering, The University of Queensland* Corresponding author: clare.murray@uqconnect.edu.auThe location of geothermal power plants in centralAustralia raises the need for a cooling methodthat is not dependent on large volumes of water.The natural draft dry cooling tower is analternative to conventional mechanically driven orevaporative systems. This design is beingcompleted for a geothermal plant located inInnamincka, South Australia. The design of thecooling tower incorporates the arrangement ofheat exchangers and the tower structure itself.This is dependent on the ambient conditions ofthe area and the required heat rejection rates.In a natural draft dry cooling tower air acts as thecooling medium to condense steam that ispumped through heat exchangers. Air is drawn inat the base of the tower and passes through theheat exchangers. This heated air is forced up thetower by the pressure difference created betweenthe warm air and the ambient conditions. The heatexchangers can be placed wither vertically aroundthe perimeter or horizontally within the mouth ofthe tower. This is a suitable alternative as water isnot evaporated to the atmosphere and is reheatedto run through the turbine again. The coolingtower will operate most effectively with a largertemperature difference and a greater towerheight.Keywords: Natural Draft, Dry Cooling, GeothermalEnergy, AustraliaAlternative Cooling MethodsThis system can be considered as an alternativeto mechanically driven systems which incorporatelarge fans to drive the flow of air through thetower. There is an obvious advantage to this asthe flow through the tower can be controlledindependently of the temperature difference whichincreases the reliability of the system to cool. Thismeans the cooling structure can be smallerrequiring lower initial investment. The use of fansdoes require a significant power output ofapproximately 10-15% of the plant’s output. Theyalso require continuous maintenance andgenerate significant amounts of noise (Forgo1979).Another alternative, evaporative cooling is quitesimilar however water sprays are used asopposed to heat exchangers. This does result in amore efficient system as the latent heat of waterremoves more heat, resulting again in a smallertower with a lower initial investment. There issignificant water loss which can be up to 3 millionlitres annually which is not viable for centralAustralia. The run off created by wet coolingtowers creates an environmental hazard due tochemical additives in the water and the wetplumes can be quite corrosive to the towerstructure. Hence a natural draft dry cooling toweris most appropriate for the conditions of thispower plant.Tower StructureThe dimensions of the tower are dictated by theflow requirements for heat rejection at the ambientconditions. The shape and material selection areimportant to ensure the tower is strong againstwind loading, buckling and vibration.To reject the heat from a 23MW power plant at a30°C ambient temperature the followingdimensions listed in Table 1 are required thelocation of which are presented in Figure 1.Table 1: Tower DimensionsOutlet height 200 m H5Inlet height 16 m H3Throat height 170 m HtThroat diameter 136 m D5Inlet diameter 170 m D3Figure 1: Outline of Tower DimensionsThe tower is hyperbolic up to the throat diameterand then extends straight up. The shell of thetower depends on material selection which ismost commonly concrete or steel. This design isslightly different and incorporates a steel framewith square hollow beams that support a materialshroud. The selected material covering must besufficiently strong and stiff to withstand windloading, durable and resistant to UV degradation.Wind loading has been applied with a maximumgust speed of 27.8m/s at a height of 10m. Resultsfrom a static analysis indicate the maximumdeflection would be 2.9m with a stress of375MPa. Based on this the high strength low alloy1241

Australian Geothermal Energy Conference 2009steel A582 (grade 65) has been selected. Thishas a yield strength of 450MPa which is sufficientfor the loading conditions. A possible framedesign has been modelled and loaded in Strand7and is presented in Figure 2.Figure 1: Strand7 model of a cooling tower under windloadingThere are advantages to a steel frame over aconcrete shell. As there is a low possibility ofseismic shocks due to the creation of fracturedrocks underground the the shell must be strongagainst cracking. Steel is more likely to withstandground vibrations without failure. Steel is alsosuitable as this is a dry tower so corrosion is not amajor issue.Heat Exchanger DesignThe design of the heat exchangers requires theselection of the heat exchanger location as wellas the design of the finned tubes within thebundles. The heat exchanger arrangement mustbe designed to minimise the pressure drop in airflow while maximising the heat transfer.The bundles can be located either verticallyaround the circumference of the tower orhorizontally within the mouth of the tower. Someof the common arrangements are presented inFigure 3. The difference in thermal performancebetween the various arrangements is quiteminimal when considering one dimensional flowthrough the tower. It is only when considering theeffect of wind flow around the tower that thedifference in performance is observed (Moore1978).Figure 3: Common Heat Exchanger Arrangements (Kröger2004)For this tower design a vertical arrangement hasbeen chosen as the bundles are self supportedand arrangement is simple to model. The flowlosses through the heat exchangers can becalculated analytically to determine the resistanceto the air flow. A draft equation has beenproposed by Kröger which equates the flowresistances to the pressure drop as the heightincreases.Equations for the resistances have beenproposed and have been calculated iteratively todetermine the mass flow rate through the towerand determine the size of the bundles.Heat Exchanger specifications for this tower arelisted in Table 2.Table 2: Heat Exchanger SpecificationsNumber of Bundles 196Total Number of Tubes per Bundle 1350Rows of Tubes 9Length of Tubes 15.6mNumber of Water Passes 2Outside Diameter of Tube40mmOutside Diameter of Fin80mmNumber of Fins per metre 60/mThe bundles are arranged vertically around thecircumference of the tower at an angle of 60° tothe tower. These results have been compared tothe AspenTech Heat exchanger design programto ensure that the surface area of the finned tubesis sufficient.2242

Australian Geothermal Energy Conference 2009Performance AnalysisThe performance of the natural draft dry coolingtower is quite dependent on the weatherconditions. As the ambient temperature increasesthe cooling capacity and the performance of thepower plant decreases which is the primaryconcern in the use of natural convection. As theambient temperatures will peak in the summermonths when the power usage is often at itsgreatest, this requires some investigation todetermine the viability of this method. There willalso be significant temperature drop during thenight so there will be some variation in theperformance of the tower over a daily and monthlytime frame.Wind acting around the tower will also affect thecooling performance. The direction of air enteringthe tower changes due to the effect of wind as isevident in Figure 4. Ideally, air entersperpendicularly to the face of the heat exchangerto minimise the pressure drop in the flow. Aninvestigation conducted by Moore (1978) todetermine the effect of varying the angle foundthat for angles greater than 75° (fromperpendicular) the flow is negligible. The use ofwind break walls is proposed by Du Preez (et.al.1995) and seems to minimise the effect of thewind.ReferencesBusch, D., Harte, R., Kratzig, W., Montag, U.(2002). "New natural draft cooling tower of 200 mof height." Engineering Structures 24: 12.du Preez, A. F. and Kröger, D. G. (1995). "Theeffect of the heat exchanger arrangement andwind-break walls on the performance of naturaldraft dry-cooling towers subjected to crosswinds."Journal of Wind Engineering andIndustrial Aerodynamics 58(3): 293-303.Forgo, L. (1979). "Dry Cooling for PowerStations." IEEE Trans Power Appar Syst 98(3):1099-1103.Kröger, D. G. (2004). Air-cooled Heat ExchangersAnd Cooling Towers: Thermal-flow PerformanceEvaluation And Design. Oklahoma, PennWellCorporation.Moore, F. K. (1978). Aerodynamics of HeatExchangers and Their Arrangment In Large DryCooling Towers. ASME Thermophysics and HeatTransfer Conference. San Francisco, California,ASME.Singham, J. R. (1983). Natural Draft Towers. HeatExchangers Design Handbook. E. Schlunder.Dusseldorf, Hemisphere Publishing Corporation.3.12.Figure 4: Possible wind streamlines (Moore 1978)SummaryThe natural draft dry cooling tower would providean alternative cooling method when largequantities of water are not available. Investigationis required to determine whether it is suitable for apower plant in South Australia based on theambient conditions of the location. A tower of200m is required to cool the 23MW power plant in30°C ambient conditions. Vertical heatexchangers are arranged around thecircumference to allow for heat transfer.3243

Australian Geothermal Energy Conference 2009Comparing the Tube Fin Heat Exchangers to Metal Foam HeatExchangers for Geothermal ApplicationsOdabaee, M. , Hooman, K. and Gurgenci, H.School of Engineering, the University of Queensland, Brisbane, AustraliaEmail: mostafa.odabaee@uqconnect.edu.au, K.hooman@uq.edu.au, H.gurgenci@uq.edu.auThis paper examines the application of twodifferent heat transfer augmentation techniquesto improve the performance of an air-cooledheat exchanger. The conventional finned-tubedesign is compared with a modern techniquebeing the application of a metal foam heatexchanger applied as a layer to the outersurface of the tube. Both designs improve theheat transfer rate from the condensing fluidflowing in the tube bundle albeit at the expenseof a higher pressure drop compared to the baretube as our reference case. Considering theheat transfer enhancement as the benefit andthe excess pressure drop as the cost, the twocases are compared against each other. In orderto achieve this goal, results from two differentsources have been compared being ANSYS-Fluent and ASPEN B-JAC. A number ofcorrelations are also proposed to predict thecost (excess pressure drop) and the benefit(heat transfer augmentation) of the extendedsurface.IntroductionMost of the geothermal resources of Australiaare located in arid areas where there is notenough water to feed wet cooling towers toabsorb the cycle waste heat. Air-cooledcondensers provide the only economic choice insuch places where the cycle fluid condensesinside the tubes cooled by air. The tubes haveexternal fins to increase the air-side heatexchange surface. Fins improve the heattransfer performance but at the same time leadto higher pressure drop compared to bare tubes.As such, there always is a trade-off betweenthese two opposing effects where the main goalis to remove the waste heat from the condenser.Metal foams, an emerging technology in the fieldof heat exchangers, benefit from suchadvantages as low-density, high area/volumeratio, and high strength structure. Therefore,they have been applied in a variety ofapplications including cryogenics, combustionchambers, cladding on buildings, strain isolation,buffer between a stiff structure and a fluctuatingtemperature field, petroleum reservoirs, compactheat exchangers for airborne equipments, highpower batteries, compact heat sinks for powerelectronics and electronic cooling, heat pipesand sound absorbers (Mahjoob and Vafai 2008).This study explores a comparison betweenthermo-hydraulic performance of finned-tubesand metal foam heat exchangers with specificattention being paid to the price, weight andmanufacturing structure as a basis for futurework.Figure 1: Samples of metal foam heat exchanger and tubefin heat exchangerFinned-Tube Heat ExchangersA finned-tube heat exchanger is designed by thewell-known commercially available engineeringsoftware ASPEN B-JAC for an air-cooled heatexchanger, as indicated by Table 1. This tablepresents a sample of our results for a binarycycle with Isopentane as the working fluid whichis cooled by air in a geothermal power plant.Based on an efficiency of about 15%, 283 MWof heat should be dumped so that 50 MWe canbe generated; see also (Ejlali et al 2008).Further details of the air-cooled heat exchanger,including fin thickness, type, and number densityare presented in Tables 1 and 2 where the tubebundle configuration is illustrated in Figure 2.Metal Foam Heat ExchangersPerformance of a metal foam-covered singletube as a representative, in cross-flow isexamined numerically as illustrated by Figure 3where the geometry and the applied meshsystem is presented. As mentioned earlier, thecommercially available CFD software Fluent isused to solve the full set of governing equationsfor different samples of metal foams (Calmidiand Mahajan 2000).Similar to (Hooman and Gurgenci 2010), thethermo-hydraulic performances of the twodifferent designs, finned-tube and metal foamcoveredheat exchangers, are compared undersimilar conditions.1244

Australian Geothermal Energy Conference 2009Summary and ConclusionIt is expected that metal foams heat exchangershave higher heat transfer rates compared tofinned-tube ones. At the same time, metal foamscan cause higher pressure drop. Interestingly,for a specific case where the same boundaryconditions have been set for a metal foamcovered tube and finned tube (air velocity =3.34m/s, air temperature = 308K, tubetemperature = 320K), according to our numericalresults, the former is associated with 10% higherheat transfer rate at the same pressure drop. Itis expected that an optimization study canfurther increase the heat transfer of metal foamsso that the heat removal form a binary cycle in ageothermal power plant can significantly beimproved with less parasitic losses compared tothe existing technology.ReferencesCalmidi, V. V. and R. L. Mahajan (2000)."Forced convection in high porosity metalfoams." Journal of Heat Transfer 122(3): 557-565.Ejlali, A., Hooman, K., "A comparative study ondry cooling of different working fluids forgeothermal applications," AGEC 2008,Melbourne, Australia.Mahjoob, S. and K. Vafai (2008). "A synthesis offluid and thermal transport models for metalfoam heat exchangers." International Journal ofHeat and Mass Transfer 51(15-16): 3701-3711.Hooman, K. and H. Gurgenci (2010) Differentheat exchanger options for natural draft coolingtowers to be presented in World GeothermalCongress, Bali, Indonesia.2245

Table 1: The result of ASPEN B-JACAustralian Geothermal Energy Conference 20093246

Table 2: Mechanical details of tubes and finsAustralian Geothermal Energy Conference 2009Figure 2: Mechanical details of tube layout31mm50mmFigure 3: The metal foam-covered single tube in 2D and 3D views (the generated mesh in the flow region has not been shownfor the visibility proposes).4247

Australian Geothermal Energy Conference 2009Assessment of Current Costs of Geothermal Power Generation inNew Zealand (2007 Basis)Paul QuinlivanSinclair Knight Merz,12-16 Nicholls Lane, Parnell, Auckland, New Zealandpquinlivan@skm.co.nzSinclair Knight Merz (SKM) has completed astudy for the New Zealand GeothermalAssociation (NZGA) which assesses the cost ofdeveloping typical greenfield New Zealandgeothermal resources in single blocks of either20 or 50MW capacity.Figure 1High temperature geothermal fields in NewZealandThe method used in the study consisted of thedevelopment of a spreadsheet financial modelwhich was then applied to a band, or envelope, ofestimated capital costs based on an assessedrange of resource characteristics. Capital andoperating costs were iterated across a diverserange of New Zealand geothermal industryparticipants until agreement on costs wasobtained while avoiding disclosing confidentialinformation. Using the model, electricity tariffswere derived for geothermal resources in a NewZealand setting from analysis of a total of 32greenfield geothermal development scenarios.Keywords: geothermal resource, capital cost,electricity selling price, greenfield, estimation,geothermal power generationDevelopment ScenariosThe 32 development scenarios derive fromselected combinations of 4 resource variablescritical in any given development: (i) resourcetemperature (3 cases); (ii) development size (2cases); (iii) plant technology (4 cases), and; (iv)well flow rates based on permeability (2 cases).These variables and the rationale for theirassumed values are described. A total of 16cases at a high flow band (150 kg.s -1 ) and 16cases at a low flow band (50 kg.s -1 ) have beenstudied. The cases are realistic in that there isover 50 years of experience in exploration,development and operation of New Zealandgeothermal fields and so good data are availableon which to base the resource performancecharacteristics.A number of resource temperatures for developedand undeveloped geothermal resources, whichmay be available for development, are consideredin the model. For New Zealand fields likely to bedeveloped under the current regulatory andpricing regime, maximum resource temperaturesat depths currently drilled in the natural staterange from 230 to 330°C with an average value ofaround 280°C.Accordingly, four development cases have beenallowed for resource temperatures, welldeliverability and development size. Wells areassumed to self-discharge rather than bepumped. The first development case is for a hightemperature and highly productive resource(Mokai, Rotokawa and Kawerau) with resourcetemperatures in excess of 300°C. In this case,wells have some excess enthalpy, which isassumed to be 10% above the enthalpy of waterat 300°C, and high well head delivery pressuresof typically 20 barA. The development size isassumed to be 50 MWe.The second development case includes mediumtemperature and moderate productivity resources(Wairakei, Ohaaki and Tauhara), and the lowertemperature zone of higher temperature fieldswith resource temperatures averaging 260°C. Inthis case, liquid reservoir conditions prevail withno excess enthalpy, and wells have moderatewellhead delivery pressures of about 5 barA. Thedevelopment size is set at 50 MWe. The thirdcase is the same as the second case, but theassumed development size is set at 20 MWe.1248

Australian Geothermal Energy Conference 2009The fourth case includes lower temperature andmoderate productivity resources such as Ngawhaand outflow zones of higher temperatureresources, with resource temperatures averaging230°C. In this case liquid reservoir conditionsprevail with no excess enthalpy, and wells havelow wellhead delivery pressures of about 3 barA.The development size is limited to 20 MWe.Four classes of plant technology commonly usedin the generation of power from geothermalenergy were selected in order to estimate costsfor this study. These include: (i) Single flashsteam Rankine cycle direct contact condensingplant; (ii) Double flash steam Rankine cycle directcontact condensing plant; (iii) Organic Rankinecycle (ORC) power plant, and; (iv) Hybrid steambinarycycle plant.Historical data indicate that the outputs of NewZealand geothermal wells vary up to a maximumof about 30 MWe per well, with the average valueskewed to a relatively low value of about 4 to 5MWe. This probably reflects that many of thewells were drilled between the 1950’s and 1970’swhen hole depths were typically limited to1,200 m and only rarely to depths greater than2,000 m, and some, such as the early wells atWairakei and Kawerau, were of smaller diameterthan is now considered standard.Outputs of wells drilled subsequent to these earlywells are often higher due to being drilled togreater depth thus benefiting from both shallow(high enthalpy) and deep (liquid) productionzones, and in some cases from having largerdiameter production holes and productioncasings. Future geothermal wells in New Zealandand internationally should prove to be better thanthis past average for the same reasons. Giventhis historical data it is considered reasonable toassume future geothermal wells in New Zealandwill have an average output in the range of 5 to10 MWe, i.e. somewhat greater than wells typicalof the Wairakei and Ohaaki developments, butsignificantly less than the larger output wellsencountered in the higher temperature, centralparts of the Mokai, Rotokawa and Kawerau fields.In each case the specific energy output of thewells was calculated from the flow rate.Methodological ApproachConsidering the range of resource characteristicsdiscussed above and that the developmentoptions to be costed need to include a number ofdifferent power plant cycle types with cycleefficiencies that vary in response to plant inletpressure, and well enthalpies (which dictatesteam and brine flows), it is not very useful forcomparative purposes to assign a single averageMWe rating to wells drilled into the above fourresource scenarios. Instead, the approach takenfollows that of Barnett (2006 and 2007) in whichthe number of production and injection wellsrequired at time 0 was calculated, while ensuringthat those wells at time 0 covered not less than110% of the selected capacity. Well capacitydecline with time was modelled using a harmonicdecline equation. An additional make-upproduction well was added whenever the capacityin a subsequent year would drop below the 10%reserve margin.The method allows for investigation of the costperformance of the various options. Thisperformance varies considerably depending onresource temperature and well flow rate. Totalcapital cost, specific capital cost (SCC) and therequired Year 0 electricity tariff (NZc.kWh -1 ) haveall been estimated for each option and financialmodels developed for each of the 32 cases.The estimated capital costs for each projectscenario are inputs to this model together withoperations and maintenance costs (O&M) andmake-up and replacement wells, assessed overthe operating life of the project which is assumedto be 30 years. Net delivery at the sales point isdetermined on a year-by-year basis, withassumptions made for scheduled andunscheduled outages, semi-annual inspectionshutdowns, and recoverable and unrecoverableperformance degradation.ResultsFull results are presented in Table 1 (Appendix 1).The relative rankings for thermal and financialperformance are summarised below andpresented in Figures 2 to 4:Thermal performance (based on grossgeneration)High temperature:ORC < Single Flash < Hybrid < Double flashLow temperature:Single Flash < Double Flash < ORC < HybridFinancial performanceLow Temperature (20 MWe gross)Specific capital cost:Single flash < Hybrid < ORC < Double FlashElectricity tariff:Single flash < Double flash < Hybrid < ORC[Range 10 to 14.5 NZc/kWh real]High Temperature (50 MWe gross)Specific capital cost:Single flash < Hybrid < Double flash < ORCElectricity tariff:Single flash < Double flash < Hybrid < ORC[Range 7 to 11 NZc/kWh real]The ranking of the power cycle options in terms ofthermal performance (gross) is quite different tothe ranking in terms of financial performance. Theadvantage enjoyed by the binary plant options interms of thermal performance at low temperatureis not able to be translated into a financialadvantage. There are two reasons for this, the2249

Australian Geothermal Energy Conference 2009first being that the binary plant options havesomewhat higher plant parasitic loads whichdecrease their net thermal performance and thustheir respective revenue streams, and althoughthey have similar SCCs to double flash at lowtemperature (based on the cost assumptionsmade in the study), this is not enough to givethem a levellised cost advantage.Nevertheless, the range is quite close andinnovative approaches to equipment marketingand financing may be enough to tip the balance infavour of one technology over the other, as canbe witnessed by the market success of ORC andhybrid plants in New Zealand over the past 15years.Double flash plants have higher specific capitalcosts than the single flash steam or hybrid plantoptions, in spite of double flash plant having goodthermal efficiency at all of the reservoirtemperatures examined. This is due to thegreater complexity and thus cost required withinthe steamfield and power plant to accommodatethe second stage steam flash separators andpiping / instrumentation and the additional cost forfitting out a turbine with two steam inlets. It isthese additional costs which penalise the doubleflash option relative to the single flash and hybridoptions.The analysis undertaken here for the double flashoption is relatively conservative conservativebeing constrained by limiting second stage flashpressure to control silica scaling potential. Amore aggressive approach could be takenthrough reducing the second stage flash pressurefurther to generate a greater steam flow from thesecond stage flash step. This would improve thecost performance of this option, however, thiswould be at the risk of silica super saturation inthe waste brine in excess of 130% with increasedpotential for scale deposition even with chemicaltreatment.The key outputs from the model runs areestimates of the required “electricity tariff” for eachproject development option for a variety offinancial assumptions of which corporate tax rate(30%), depreciation (straight line, 8 years),inflation (0%) and equity content (100%) are themost important. These tariff values are equivalentto the year 0 selling prices required to achieve thefinancial hurdle After Tax Internal Rate of Return(IRR) assumed in the model (10% real).Intermediate model outputs are specific capitalcost (NZ$.kWe(gross) -1 ) and thermal performance(the ratio of thermal power supplied to grosselectrical power generated).The costs developed here (and presented inFigure 2) are in New Zealand dollars. They arebased on 2007 values, and were internallycalibrated against costs being incurred for NewZealand geothermal developments, of which therewere a number in progress at that time, andseveral overseas geothermal projects which werealso in progress at that time.This study did not consider greenfielddevelopments greater than 50 MWe. The mainreason is that a greenfield developer would mostlikely not be able to attract the funds required for alarger development until some experience withthe particular resource was gathered and the risksassociated with a larger development were able tobe well quantified. Furthermore a greenfielddevelopment of over 50 MWe may struggle toobtain resource consents in New Zealand, giventhe conservatism of regulatory authorities andtheir preference for staged developments, for thesame reasons.This contrasts with the current situation in NewZealand where large developments of medium tohigh temperature resources are occurring atbrownfield sites (100 MWe at Kawerau and132 MWe at Nga Awa Purua (Rotokawa)). Beingbrownfield sites, these larger, second stagedevelopments are then appropriate. This impliesthat the anticipated returns on these largerinvestments within the current electricity market inNew Zealand are attractive – and developers areon record as stating that “Geothermal is thelowest cost source of new generation for NewZealand” (Baldwin, 2008).For several years prior to 2007, geothermaldevelopment costs rose steadily in line with globalmarket commodity and equipment price rises.These rises continued until the middle of 2008when the current global financial crisis occurredand commodity prices fell back to 2003 levels. It isnot certain that there is enough market dataavailable yet to determine what is currentlyhappening to geothermal power plant, steamfieldand well costs to be able to compare current(2009) costs with the 2007 estimates used in thisstudy.Applicability to AustraliaThe results of this study should be applied withcaution to Australian geothermal projects.Although we consider the method to be robustand suitable for Australian projects, there are veryreal differences between the two countries whichmake the specific results inapplicable. Quiteapart from the need to escalate costs to 2009, thegeneral tendency will be for the differences tomake New Zealand projects lower cost thatAustralian.Significant differences include:• The volcanic geothermal setting of NewZealand is demonstrably well suited to theoccurrence of exploitable geothermalsystems• With an industry history of 60 years,exploration of New Zealand geothermal3250

Australian Geothermal Energy Conference 2009resource is well advanced, reducing resourcerisks greatly• New Zealand resources are generally hotterand much shallower than in Australia• Some New Zealand wells encounter higherpermeability than will be typical in Australia,and hydro fracturing and stimulation asnecessarily required in the development ofEnhanced Geothermal Systems (EGS) inAustralia are not required in the New Zealandvolcanic setting• Wells in New Zealand do not generally needpumping whereas all Australian geothermalprojects of the EGS and HSA (HotSedimentary Aquifer systems) types, with thepossible exception of some in the GreatArtesian Basin, will require both productionand injection well pumping• There is a highly developed and competitivegeothermal drilling and service industry inNew Zealand• Use of evaporative cooling towers is common(for the non-ORC cases), and• Distances to grid connection points are notgreat.However, the method is equally applicable to theAustralian context as to the New Zealand contextwhen the above differences are taken intoaccount.To assist with transfer of costs, there areassessments of locally-sourced costs versusimported costs. Australian labour and materialscosts can readily be substituted.AcknowledgementThe input to this study of Peter Barnett, previouslyof Sinclair Knight Merz, and currently with HotRock Limited, is gratefully acknowledged.ReferencesBaldwin, D. (2008). Chief Executive’s Review.http://www.contactenergy.co.nz/web/pdf/financial/ar_20080923_chairman_ceo_review.pdfBarnett, P. (2006). Assessment of the CurrentCosts of Geothermal Power Development in NewZealand. Proceedings of 28th New ZealandGeothermal Association Workshop, 2006.http://pangea.stanford.edu/ERE/db/IGAstandard/record_detail.php?id=5119Barnett, P. (2007). Costs of geothermal power inNew Zealand - 2007 Update. Proceedings of 29thNew Zealand Geothermal Association Workshop,2007.http://www.nzgeothermal.org.nz/publications/Reports/Workshop2007/GeothermalCosts2007.pdf4251

Australian Geothermal Energy Conference 2009Figure 2Electricity tariffs required for greenfield geothermal developments in New Zealand (2007 basis)Figure 3Specific capital costs of Greenfield geothermal developments in New Zealand (2007 basis)5252

Australian Geothermal Energy Conference 2009Figure 4Thermal performance of the energy conversion options reviewed in this study6253

Australian Geothermal Energy Conference 2009Appendix 1Table 1Outputs from studyOptionWell CapacityEnvelopeReservoirTemperatureDevelopmentSizePower PlantTechnologyYear 0 Tariff(Real)# High=150kg.s ‐1o C MWe(gross) NZc.kWh ‐1Low=50kg.s ‐1 (2007 basis)Specific CapitalCostNZ$.kWe(gross) ‐1(2007 basis)ThermalPerformancekWthermal.kWe(gross) ‐11 High 300 50 SF 7.3 3400 8.32 High 260 50 SF 7.8 3700 11.93 High 260 20 SF 10.1 4800 11.94 High 230 20 SF 10.5 4800 14.65 High 300 50 DF 7.8 3800 7.36 High 260 50 DF 8.3 4100 10.67 High 260 20 DF 10.8 5300 10.68 High 230 20 DF 10.8 5300 12.99 High 300 50 Hybrid 8.0 3700 7.910 High 260 50 Hybrid 8.4 3900 9.311 High 260 20 Hybrid 11.0 5300 9.312 High 230 20 Hybrid 11.2 5300 11.213 High 300 50 ORC 9.6 4500 9.014 High 260 50 ORC 9.9 4700 10.315 High 260 20 ORC 11.7 5400 10.316 High 230 20 ORC 12.0 5400 12.217 Low 300 50 SF 8.6 400018 Low 260 50 SF 10.1 490019 Low 260 20 SF 12.5 590020 Low 230 20 SF 13.6 630021 Low 300 50 DF 8.8 420022 Low 260 50 DF 10.5 500023 Low 260 20 DF 12.8 600024 Low 230 20 DF 13.9 680025 Low 300 50 Hybrid 9.5 440026 Low 260 50 Hybrid 10.6 500027 Low 260 20 Hybrid 13.3 630028 Low 230 20 Hybrid 14.1 650029 Low 300 50 ORC 11.2 520030 Low 260 50 ORC 12.5 570031 Low 260 20 ORC 14.4 660032 Low 230 20 ORC 15.1 66007254

Australian Geothermal Energy Conference 2009Analysis of Reinjection Tests in a Bedrock Geothermal Reservoir,Tianjin, ChinaZhu Jialing* 1 and Wang Kun 21 Tianjin Geothermal Research & Training Center, Tianjin University, Tianjin, ChinaWeijin Road 92, Nankai District, Tianjin 300072 China2 Geothermal Management Division, Bureau of the City Plan and Land Resource, Tianjin,Email:zhujl@tju.edu.cnBy the end of 2008 there were about 245production wells and 12 reinjection wellsoperating in Tianjin. The annual production rate is25 million m 3 and the reinjection rate is 4.2 millionm 3 . Reinjection is expected to gradually cool thereservoir and so it is important to carefully designand manage the well fields and this involvesestimating the thermal breakthrough time fordifferent well separation distances. This paperdescribes the 2-D mass and heat transfer in theheterogeneous fractured rocks. Equations thatarise for each grid block were linearised andanumerical model of the geothermal system wasdeveloped with TOUGH2. This model was thenused to analyse the reservoir pressures andtemperatures with special emphasis on simulatingbreak-through of cooling at the production well.The tracer test is shown to be important forimproving our understanding of the tracer andheat transport processes and reservoir(channel/fractured/karst) porosity, and forenabling the estimation of future reservoir coolingcaused by fluid reinjection.Keywords: Geothermal reservoir, Simulation, Heatbreak-through, Doublet systemIntroductionTianjin is located at the north-east of the Hua-Beiplane in China, with the Yanshan Mountains at itsnorth and Bohai Bay at its east. The total regionarea is 11305 km 2 . The bedrock outcrop is limitedto the mountain area of the north JI County [1] .In Tianjin, the main productive reservoirs areporous reservoir in the sandstone (two productivezones) and karst/fractured reservoir in bedrock(three productive zones). The top depth of thekarst /fractured reservoir in bedrock is over 950m. The discharge rate of the single well is morethan 100 m 3 /h, the wellhead temperature is 55-100 C. The waters are mainly used in spaceheating, physical therapy, bathing, fish farmingetc.Since 1996, the reinjection test started in thebasement reservoir in Tianjin. Till now there are27 doublet (reinjection/production) geothermalwells, and 10 of them are located in Tianjin urbanarea. These doublet wells are significant for theprotection of the geothermal resource in Tianjin.By the end of 2008, there were about 245production wells (including 27 reinjection wells).The annual production rate is 25 million m 3 andthe reinjection rate is 4.2 million m 3 . The staticwater level is between –35m and –90m, theannual draw down rate is 6-9m.Analysis of the Tests in the BasementGeothermal ReservoirGeological modelling of the doublet systemThe system of WR45 is the second productionreinjectiondoublet well in the basement reservoirof Tianjin, which was drilled in 1995. Productionand reinjection wells were drilled into theWumishan formation of the Jixian series of theProterozoic group.Analysis of the reinjection tests in WR45The productive zone of the doublet WR45 isWumishan formation of the Jixian series inProterozoic group. The main lithologiccharacteristic is the dolomite and limestone. Thekarst fissure is well developed in this area.The first reinjection test was carried out with thepressurization pump in Oct. 1996. Figure 1 showsthe monitoring data for the test. Removing theabnormal data that may cause by someequipment problems, the reinjection flow-rate wasinverse proportional to the re-injective pressureduring the test. When the pump pressure was0.02 MPa, the reinjection rate was 100m 3 /h. Butthe re-injective rate decreased to 86 m 3 /h whenthe pump pressure increased to 0.05 MPa. Duringthe last stage, the pump pressure was 0.09MPa,the re-injective rate settled at 50m 3 /h more orless.Figure1 Relationship between re-injection pressure and flowrate.The doublet well of the WR45 is located at thewell-developed karst fissure area in Wumishanreservoir, which is the porous-fracture medium ofdoubling porosity. At the beginning of thereinjection test, the flow along the fissure takes1255

Australian Geothermal Energy Conference 2009the leading effects. The pump pressure influencesa little on the reinjection rate. The reinjection fluidtransfers the aquifer quickly because of theincreasing of the pressure gradient between thereinjection and production well. As the reinjectiontime extended, the seepage flow in porousmedium took more and more effects. The velocityof reinjection fluids in the reservoir becameslowly, and the re-injective was decreased. As awhole, the pump pressure increased and theinjection rate decreased gradually as thereinjection test continued.During the space-heating period from Nov. 1999till March 2001, the doublet WR45 has been rununder the natural state without pressure pump. Allthe released geothermal water was reinjected intothe reservoir quickly after the heating cycling.Because several geothermal production wellswere used for space heating simultaneouslyaround WR45, the reservoir pressure decreasedfast. It would be of influence to the water level ofthe reinjection well. For the case, it may be easierto reinject. However, the temperature changes ofthe production zone should be monitored so thatthe rate of reinjection can be adjusted. By the2002, the temperature changes have notobserved in surrounding the productiongeothermal wells.Tracer Test in Fractured MediumReservoirThe tracer test is very important to understand thetransport state and channel/space in theproduction/reinjection zone. And it is a veryimportant stage to simulated heat transfer in thereservoir. To investigate the connective channelbetween the reinjection and production well ofdoublet WR45, the tracer tests have been done inthe winter of 1998-1999. 10kg of iodide ofpotassium (KI) is selected for the first stage as thetracer. A series of instruments are installedsurrounding wells to monitor the water quality fora long period. The detailed data is listed in Figure2.Figure 2 Observed concentration breakthrough curves of thetracer test.The monitoring data shows that the tracerconcentration is almost constant in productionwells, in the other hand the observation wellGC45-2 is more sensitive to the iodine. It meansthat the hydro-geological connection between theproduction and reinjection well of doublet WR45 isindirect, and maybe there is a direct or fastmigration channel between the reinjection welland the other geothermal production well, like theproduction well GC45-1, which is about 2.5 kmaway from reinjection well. The test results in thewell of GC45-2 were simulated by themathematics model in order to understand thegeometry structure of the fracture passagebetween GC45-2 and reinjection well (See Figure3 and Table 1).Figure 3 Simulated breakthrough curves compared with theresults of the tracer test.Table 1 Calculated parameter of the tracer testCross sectionarea ADispersionFissure 1 1.50 355.50 20.35Fissure 2 15.74 142.25 38.90Fissure 3 29.51 10.06 10.27Fissure 4 54.68 161.38 21.90LRecoverymass (%)Table 1 shows a comparison of the simulationcurves and calculation data. One simulation curvecompounded by 4 pulse curves is derived fromthe modelling. When the tracer was injected intothe aquifer, it would quickly travel along the mostdirect/fast pathway, which has the smallest crosssection and biggest disparity. Then the tracerwould move to the production well quickly and itsconcentration will reach the maximum value in avery short time. If the reinjection water diffusesinto a large space, only a small fraction of thetracer will be detected and the time reach thepeak value will be longer. The heat breakthroughtime will not be a problem in doublet system if thedistance is more available between the productionand reinjection well.Model and Constitutive EquationsThe main side effect anticipated from reinjection isa cooling of the reservoir [2] . It is necessary to2256

Australian Geothermal Energy Conference 2009estimate the thermal breakthrough time fordifferent injection-production well spacing, i.e. thetime from initial injection until a significant coolingis observed in a production well [3] .The mass conservation equation Sv(1 S l ) F qtttl = liquid phase; v = vapour phase; F = vector ofmass matrix; q = external energy; = density; = porosity; S = vapour saturation.The energy conservation equation (conductivityand convection):Q()V (u uss(1 ))ttFvFl G ( ) P Qu vlS = solid phase; u = internal energy; G = energymatrix; Q = energy; V = volume of reservoir; Q u =external energy.Set of equations (l) and (2) is related to one or twophase filtration in a porous or fractures mediumwhere rock matrix and fluid are considered to bein local thermal equilibrium. For a block of microvolume Vn of the field, the transfer equation ofmass and energy (5) call be interpreted byequations (3) and (4).utsUnN FmA tm1us ( )tmuus (t q)utN1'Anm(GnmunFnm)(QnQn)Vnm1tusus(1) {( ) ( )ts u}uut(1)(2)(3)(4)At present, the main reinjection math model inTianjin has been simulated by a program calledTOUGH2 [4] . The results would be helpful toanalyse changing of the temperature field andpredict the pressure and temperature alterationlater than 10 years in the Wumishan aquifer. Fig 4is a sketch map of another doublet WR82/83.Considering the heat transfer between thereservoir and the other stratum at the top orbottom, a multi-aquifers model is set up to predictthe temperature changes in reservoir during the(5)reinjection test. The parameters used in modellingare listed in Table 2.Fig. 4 The Conceptual Model of WR82/83.Table 2 The parameters in the modellingReservoir temperature 87℃Reservoir thickness900mPermeability of aquifer0.2-200DarcyPorosity of aquifer 0.03-0.5Temperature of aquifer 85℃-90℃Reinjection temperature 30℃Reinjection/production rate 26.78kg/sRock densityHeat capacity of reinjection fluid2550-2770kg/m34100J/kg℃Density of reinjection fluid 995.62kg/m 3Specific enthalpy of reinjection fluidSpecific enthalpy of production fluidReservoir’s average heat capacityRock specific heatRock heat conductivity125.7kJ/kg419.1kJ/kg1200J/kg℃800-999J/kg℃1.9-3.5W/m℃Figure 5 Temperature drawdown curvesThe Figure 5 shows the simulation results. Itappears that locating reinjection wells at adistance of about 100m from production wellshould not cause a thermal break-through in less3257

Australian Geothermal Energy Conference 2009than 10 years. It should be pointed out that thereinjection would only be carried out in wintertimehere. The reinjected water will extract morethermal energy from the rock matrix whengeothermal wells are shut down in summer,resulting in slower cooling rates. However, theresult is highly uncertain because the flowchannel dimensions are unknown. So, moretracer tests are recommended in future research.SummaryAn important process in geothermal energyextraction is the gradual cooling of the reservoirby the reinjection fluid when reinjection isinvolved. The thermal breakthrough time at theproduction well is related to the geologic structure,hydraulic and thermal properties of the reservoir,and the reinjection rate. If the reinjection water isdiluted by a large volume of reservoir fluid thentracer return concentrations will be low andcooling breakthrough is expected to be lessproblematic.The reinjected water will receive more thermalenergy from the rock matrix when geothermalwells are shut down in summer. This will slow thereservoir cooling process somewhat.Interpretations and predictions regarding reservoircooling are difficult to make because thegeometry of the pore space and major flowchannels is the most unknown. Tracer testsprovide the best means of characterising reservoiradvection and dispersion between injection andproduction wells and are recommended forestimating the future cooling trends. It is alsorecommended that long-term monitoring of theTianjin geothermal field be carried out to detectand record temperature changes caused byreinjection.References[1] Somerville, M., Wyborn, D., Chopra, P.,Rahman, S., Estrella, D. and Van der Meulen, T.,1994, Hot Dry Rocks Feasibility Study, EnergyResearch and Development Corporation, Report243, 133pp.[2] Ouyang, J. Wang, K. and Dong, Z. Thereinjection test and its numerical modeling in lowmediumtemperature geothermal field. Dagang,Tianjin: TDE&DI report. 1990. 100pp.[3] Axelsson, G., Bjornsson G., Flovenz, O.G.,Kristmannsdottir H. And Sverrisdottir G., Injectionexperiments in low temperature geothermal areasin Iceland. Proceedings of the World GeothermalCongress 1995, Florence, Italy: May 1995.[4] Zhu Jialing, Wang Kun, Lei Haiyan, Beijing:Studies of the Reinjection Test in the WuqingGeothermal Geothermal Field, Tianjin, China.Transactions of Tianjin University. 2002.2。4258

Australian Geothermal Energy Conference 2009Low and Moderate Enthalpy Geothermal Resources to Desalinate SeaWater and Electricity ProductionHéctor Gutiérrez 1 , Salvador Espíndola 2*1 Comisión Federalde Electricidad, México2 Instituto de Ingenieria, UNAM, México* Corresponding Author: sespindolah@iingen.unam.mxBaja California, on the northwest part of Mexicoand close to the border with the largest economyof the world, has shown a rapid and continuedgrowing of its industrial and touristy activitytriggered for real state demand, since thousandsof retired Canadian and American people aremoving south searching for nice ocean viewplaces and warmer weather along the Mexicancoast. This baby-boomers phenomena isproducing a strong increase of goods andservices in the region but, specifically on the freshwater demand, in a zone where this resource ishighly stressed and not easy to access or supply.On the other hand, this though and arid regionwith extreme temperatures, 0ºC in winter up to50ºC during summer, has been blessed withabundant renewable energy sources. Solar, wind,geothermal, tidal, hydrothermal vents, and otherresources are widely spread along the 1,200miles through the Baja Peninsula. That is why theNational University of Mexico (UNAM) formedthree years ago a professional-multidisciplinaryresearch group –IMPULSA IV- in order to promoteand implemented technological solutions todesalinate sea water through the use ofrenewable energy sources, Alcocer, et al (2008).It is well known that in a traditional thermaldesalination plant, the main component of thecost of the desalinated water comes from steamextracted from a power generating plant or powertaken from the grid. In the case of Baja California,geothermal heat that rises from geological faultshas already increased temperature of water nearto the boiling point. In IMPULSA project acombined analysis of multiple effect distillationplant (MED) and a multi stage flash plant (MSF)was performed in order to be able to desalinatesea water using the hot geothermal fluid insteadof the traditional steam supply from a thermalplant.Keywords: Desalination, Low Enthalpy, MED.Baja California Geothermal ResourcesFor purposes of this paper, we have divided theBaja California Peninsula in three arbitrary zonesin order to present a summary of the principlesites with geothermic potential in the Peninsula(Fig.1). The northern zone is comprised of thearea from the U.S. border on the northern part tothe 30th parallel. The mid zone, comprised of thearea between the 30th and 26th parallel, and thesouthern zone is from the 26th parallel to thesouth end of the Peninsula.Northern Zone, Mexicali ValleyThere are at least 20 sites in the northern part ofthe Baja California Peninsula in which there isgeothermic manifestation. The most well knownand largest are the Cerro Prieto GeothermalFields, in Municipal Mexicali, where the stateowner power company, Comision Federal deElectricidad (CFE) has drilled more that 300 wellsto extract steam necessary for power generation.At Cerro Prieto field it is installed 720 MW ofgeothermal power capacity that means up to 45%of the electric energy consumed in the cities ofMexicali, Tijuana, Tecate and Rosarito.A few kilometers from Cerro Prieto it has beenidentified at least five geothermal sites; allassociated with the Pull-apart system between theImperial and Cerro Prieto faults systems.However, in none of them it has been successfulin obtaining sufficient temperature to be able touse them for power generation, even for example,the Tulecheck Field, where a temperatures of165ºC has been registered, in the Airport field112ºC and in Guadalupe Victoria up to 230ºC in awell 3,100m deep.In the western part of the Cucapah Mountainsthere is a large plain, Laguna Salada (SaltedLagoon) where a multiple geothermal andgeophysical soundings has been found and threedeep exploratory wells where drilled. However,the maximum temperature reported in one ofthem was only 101ºC. To the south of this plain, itis reported agricultural wells with estimatedtemperatures up to 250ºC.EnsenadaIn the western part of the Baja CaliforniaPeninsula, south of the city of Ensenada, severalgeothermal sites have been identified (Alvarez,1993), springs appearing, hot soil, steamescaping, wells and hot norias, where geothermalpotential has been identified from directmeasurements of the natural discharges and inthe wells of the area, particularly in theManeadero Valley, Punta Banda, Santo Tomasand San Carlos, all of them associated with theoccurrence of Agua Blanca Fault, one of theregional structures predominately oriented NW48º.1259

Australian Geothermal Energy Conference 2009Figure 1 Baja California Geothermal Resources. Impulsa, UNAM, showing main geothermal fields Cerro Prieto (720 MW) andLas Tres Vírgenes (10MW) operated by Mexican National Utility, CFE. Also most of places with geothermal features a long of thesea shore.Given that the zone described has beenchanged into a tourist development, the majorpart of the usage of thermal water is utilizeddirectly for use in the tourist areas along thecoast of the Maneadero Valley, there are variousbeaches where at low tide you can see springsof water with boiling temperatures that havebeen measured on the surface, resulting in thestudy of these sites in order to start projects ofdesalination of seawater through the use ofthermal energy. The main locations are:Punta Banda-ManeaderoThis area is characterized by the intensehydrothermal activity, submarine as well as thelength of the coast, showing emanations ofsteam and hot water in the sea bed havingtemperatures of 102ºC to 110ºC at a depth of 30meters, as well as at diverse tourist camps alongthe coast where some norias have been dugthat provide temperatures of 45ºC to 98ºC just atdepths of 1.5 meters and in wells dug in thearea. The most distinctive sites are in the area ofLa Joya, Agua Caliente and the Bufadora.Ejido UruapanOn this area there are a group of springs locatedon the margins of the arroyo that drops into theCañon de la Grulla, located some 3 kilometersNE of the Agua Blanca Fault. One channel ofthis spring has been measured as from 250liters per minute with temperatures of 50ºC to65ºC. This water is used by the residents of thevillage as thermal baths and laundries and theyhave built pools and pits for the purpose.Santo Tomas-AjuscoAlong the length o the Santo Tomas Valley andCanyon, are thermal springs during the rainyseasons. There are reports of springs with2260

Australian Geothermal Energy Conference 2009temperatures of about 47ºC and in one thermalnoria they measured temperatures of 176ºC byusing geothermometers.San Carlos – EnsenadaTo the NE of the Maneadero Valley is the SanCarlos Canyon where there the springs of SanCarlos and Agua Caliente, reportingtemperatures of 47ºC to 50ºC. In the same cityof Ensenada there are springs and norias thathave been used for years in the public baths ofAcapulco, Lourdes and La Providencia.To the Gulf of California or Sea of Cortes, is thevolcanic providence of Puertecitos, where recenttectonic activity and the volcanic and rockactivity of the zone have given rise to variousthermal springs along the coast (Figure 1). Thisdesert zone in the north of the peninsula of BajaCalifornia has been converted into an importanttourist development area, where there areseveral sites along the coast in the upper part ofthe gulf, the majority of which are aimed atrecreation and fishing. The main sites are:San Felipe-Punta EstrellaIn the port of San Felipe, around the Machorrohill area, there are various manifestations ofthermal activity located along the coastline,where there is at least one spring with 50ºC anda noria where a temperature of 30ºC has beenfound at a depth of only 2m. At this site, apartfrom the thermal resources, there have beenseveral studies done for the feasibility ofinstalling a solar power plant, owing to the highdegree of iridescence in the area, for whichmany residents of the area have solar panels forthe energy in their houses. 25 kilometers to thesouth of San Felipe, in Punta Estrella, there is athermal spring that has given readings of 33ºC.Puertecitos-El ColoraditoThe geothermic area of Puertecitos is located onthe east coast of Baja California Peninsula, 76km south of the port of San Felipe. This area isconsidered as a place of geothermic interestowing to the presence of recent volcanic actionin surrounding areas and for the existence ofsprings in the inhabited areas as along the coastas well, registering temperatures in the range of55ºC to 77ºC. An exploratory well has beendrilled on this site but only got to a depth of375m when they started to have problemsdrilling. The maximum temperature registeredthere was 44ºC. To the north of Puertecitos, onthe coast and some 30km inland there is ahydrothermal manifestation in an area known asColoradito, where abundant hydrothermalalteration has been observed in the outlyingrocks around the spring where 56ºC has beenregistered.Central Zone of the PeninsulaTres VirgenesThis geothermic area is located some 33 milesnortheast of Santa Rosalia, Baja California Sur(BCS), in an ample area remarkable for thehydrothermal activity in the middle of the regionof the Tres Virgenes, as the three mainvolcanoes are known, La Virgin, el Azufre andLa Reforma. In this area are numerous thermalzones where small boiling pots are seen, hotsoil, hot water springs, smokers and a largezone of hydrothermal alteration. This area hasbeen widely studied (Lira, 1985) and developedby CFE, the national power company, installingon site a 10 MW power plant, operating on thesteam extracted from the wells drilled in thegeothermal field.Santispac20 kilometres to the south of Mulegé, in thecentral part of the Bahia de Conception, a hotspring has been identified (44ºC) on the beachof the inlet at Santispac, in an area influencedby the fractured region of NW-SE which allowsthe overflow of hot water to mix with the seawater. Through the use of geo thermometers it isestimated that the temperatures of formation canbe on the order of 180ºC. At this site a slim holewas drilled to a depth of 500m where thetemperature was registered at 85ºC maximum.San Nicolás-El VolcánThis is an area of thermal manifestations of65ºC- 70ºC temperatures located 70 km to thenorth of Loreto, BCS, and 9 km southeast of SanNicolás. On this site various hydrothermalactivities have been observed, steaming groundand hot water discharges in the arroyo of SanNicolás. A little further south in the area knownas Puerto Púlpito there have beenmanifestations of steam on the sand of thebeach, the sea invading the area makes itdifficult to measure actual temperature.El Imposible-El CentavitoThere is a hot water well located in the San JuanValley, 30 km northeast of Loreto that averages46ºC. From the chemical analyses of this well,we know that it is a sodium-chlorate composedand a temperature estimated to be between181ºC and 262ºC estimated by geothermometers.Agua Caliente-ComondúIn this area there is a hot spring (59ºC) locatedsome 25 km to the north of Loreto in the ElCaballo Arroyo and 3.5 km from Boca Bataquesbeach. This spring flows through a fractureparallel to the structural system of the zone, andowing to the presence of recent volcanic actionthere is an area of high geothermic interest,however, in a slim hole drilled by CFE it only3261

Australian Geothermal Energy Conference 2009registered 97ºC at 500m depth. Thetemperatures estimated by geo-thermometers atthis site are on the order of 176ºC.Southern zone of the PeninsulaBuena VistaIn front of the Bahia de Las Palmas some 60 kmNE from San José del Cabo BCS, there is theHotel Buena Vista where they found a hot waterwell (58ºC) inside of the property some 200mfrom the beach. This hot well was abandonedbecause they were searching for fresh coldwater well to be use at the Hotel.Agua Caliente-La Paz4 km to the west of the town of Agua Caliente,between the towns of Miraflores and Santiago,in municipal La Paz, there is a hot water spring(50ºC) with water bubbling up over the graniterocks.Los CabosAt the southern extreme of the Peninsula of BajaCalifornia, is one of the major tourist zones inMexico, where an impressive development ofhotels and the service infrastructure has beenbuilt in the last 10 years, increasing drasticallythe need for water and energy in the area. Theoperator of the municipal water system has a200 lt/sec desalination plant fed by beach wells.At the beginning they drilled some wellsregistering temperatures of 35ºC to 72ºC(Lopez, et al, 2006) including an 84ºC well butthey were not able to use that hot water in thereverse osmosis process.Hot water technologicalDevelopmentsIMPULSA project has implemented twoprograms in order to desalinate water. 1) In caseof low temperature of geothermal resource(under 140ºC) we can desalinate sea waterthrough a thermal process (LE-MED). 2) In caseof hot water resources (>140ºC) it can be use togenerate electricity with a PWG system and thenthat power feed a reverse osmosis plant todesalinate sea water.LE-MED (Low Energy-Multi Effect Distillation)The LE-MED system is an original IMPULSAdesign that comes from the technologicalmixture of a MED and a MSF thermaldesalination plants. The operation basics oftraditional MSF and MED plants startedpreheating sea water to its boiling point usingsteam usually extracted from a thermal powergenerator, then the preheated sea water isevaporated and the steam free of salts iscondensate as fresh water. The remaining waterleaves the plant as concentrated brine. The newIMPULSA LE-MED does not use steam in theprocess at all, instead geothermal hot water isuse as an energy source to run the system. Themain idea with this LE-MED system is to avoidthe use of fossil fuels sources in the scheme ofthe desalination process. These would reducesignificantly the desalinated cubic meter cost.We consider this is one of the most relevantthemes in the IMPULSA project. It is a rare casein the world that allows a big savings in energyyielding desalination into a sustainable concept.The price of desalinated cubic meter by thisprocess taking advantage from the geothermalnatural heat will depend strongly on thematerials required and additional sources ofenergy for pumping and vacuum.For the design of the LE-MED IMPULSA plant,several computer programs have beendeveloped in order to assess mass andthermodynamics balance, heat exchange areas,pumping and vacuum power. At this stageIMPULSA project is studying various ways forfuture incorporation of the problems related withscaling. Later on it will comes the constructionof a laboratory prototype to test the wholesystem.The principle benefit of this proposal is to avoidthe use of steam in the thermal desalinationprocess and in its place, use renewableresources (hot geothermal water) abundant inthe Baja California Peninsula. Thereby not usingfuel to generate steam for desalination couldsave up to 30 to 40% of the desalinated cubicmeter cost; this corresponds to the cost of thefuel to produce steam by traditional desalinationmethods (Figure 2).Figure 2 Integrated Cost of a Thermal Desalination Plant.(Semiat, 2000).The continuous economic results of the projectestimate that it can lower the cost up to 30% ofcubic meter desalted with thermal technologiesthrough the use of hot seawater as a source ofenergy for desalination.Geothermal electricity generation, PWG.(Pressure Water Generation).The following project proposes the use of the hotgeothermal water located in abundance in the4262

Australian Geothermal Energy Conference 2009Baja California Peninsula, as part of distributedgeneration for small plants that in many caseswon’t be connected to the grid. Under this planthe IMPULSA project of UNAM has developedexploratory surveys to locate, characterize andestimate the potential of hot sources in thePeninsula. The main idea of this project is togenerate electricity with the PWG plant, theproposal is the generation of electrical energy byheat transference from a geothermal source intoa working compressed liquid (water).The binary geothermal generation technologythat is installed in many parts of the world withorganic fluids which are basically preheated andevaporated through heat exchangers (shell andtube system) is already well known. The maindifference of the proposal with respect to atraditional binary cycle is the elimination of theheat exchange evaporator, proposing a flashsystem so that the fluid vaporization is done bythe pressure lowering, thereby in order to preheat the working fluid its is possible to use aheat plate exchanger that is easier to maintainand operate. Also the turbine proposed for thePWG is a high speed turbine with a reduceddiameter but higher revolutions. This proposalmeets these objectives, having the main goal ofgenerating electricity in a more efficient,sustainable and economically competitive way.The IMPULSA group has developed a newthermodynamic cycle for the efficient use ofgeothermal low enthalpy resources. On thisdesign the secondary fluid is water at highpressure and a temperature. Fist the workingpressurized fluid is pre heated in the heat plateexchanger, then it is flashed into a separationtank, the steam runs the high speed turbine.Finally the exhausted steam from the turbine iscondensate and mixed with the hot water thatdid not flash in the tank, the mixture ispressurized and the cycle starts again.Figure 3 PWG cycle design, (IMPULSA).The conventional systems of binary generationuse great chambers of heat exchange to preheatthe working liquids, which are generally organicfluids such as isopentane and isobutane andother heat exchangers to vaporize the fluid andactivate the turbine, constants stops, arerequired for service and maintenance of theshell and tube heat exchangers.The proposal consists of the installation of platetype heat exchanger that will improve the heattransfer, takes less space and are easymaintenance. The proposed cycle will be waterto-water(pressurized) generating steam by apressure decrease. The IMPULSA turbinedesign will be small diameter (10 to 20 cmdiameter) and high velocity (30,000 rpm)integrating the most advance turbine design.The PWG system could generate energy atprices of 5 to 9 Aus ¢/kWh (4 to 6 US ¢) stronglydepending of the installation equipment’s cost,well drilling and operation and maintenancecosts.Case Study, La Joya, BC.As a demonstration project, IMPULSA isplanning to install two small scale prototypeplants in La Joya, a recreational camp, south ofthe city of Ensenada, BC in order to takeadvantage of the geothermal resources (98ºC)that has been identified on this beach. Drilling ageothermal shallow (150 m) well near the coastit would produce enough thermal output (140ºC)to run a small power generator, then by use thiselectricity install and operated a reverse osmosisplant to desalinate sea water. Main target of thisproject is to assess geothermal reservoir’sresponse at La Joya and at the same time, testand evaluate global performance of both plantsfor a period of on year. General features of thisproject are:Power Generator (PWG)A 7 kW binary plant will be installed at La JoyaCamp, using a geothermal hot water from a welldrilled at this resources to produce electricity bythis way, a levelized power cost of 8 Aus ¢/kWhhas been estimated, which even it is not cheapis lower than electricity tariff on that region 25¢Aus/kWh (20 US¢/kWh).Thermal Desalination (LE-MED)In order to use the power produced on site, a 20m 3 /day desalination plant (LE-MED) is going tobe installed at La Joya Camp.Prototype LE-MED desalination plant has beendesigned and constructed by IMPULSA groupand will be tested and gain some practicalexperience on scaling, heat rate, heatperformance, etc.Final RemarksIntensive use of the cost line geothermalresources in Baja California is one of the bigchallenges for IMPULSA group in Mexico,helping to solve the power and fresh waterscarcity on this region of the county. Since it islocated in a very arid zone but with abundantnatural resources like solar, wind andgeothermic as well.5263

Australian Geothermal Energy Conference 2009At the same time, an enthusiastic and promisingengineering group has been consolidated at theNational University; UNAM committed with theuse of renewal energies meanwhile severalresearch project of IMPULSA allow postgraduated students to finish their Engineeringdegrees.Desalination of sea water by using renewableenergy is the main goal of the IMPULSA teamthat through scientific and technologicalresearch, the group is promoting the use ofclean and environmental friendly energysources, like the PWG and LE-MED prototypedevelopments.ReferencesAlcocer, S. M. and Hiriart L. G. (2008). AnApplied Research Program on WaterDesalination with Renewable Energies.American Journal of Environmental Sciences. 4(3): 190-197. 2008.Alvarez, R. J. (1993). Reconocimientogeotérmico en el área de Ensenada, B.C.Comisión Federal de Electricidad. ResidenciaGeneral de Cerro Prieto. Internal Report.Arango-Galván, C., Flores-Márquez, E.L., Prol-Ledesma, R.M., (2007). “Geoelectrical image ofPunta Banda (Baja California) using CSAMTand ERT data”. Proceedings 13th EuropeanMeeting of Environmental and EngineeringGeophysics of the Near Surface GeoscienceDivision of EAGE (Istanbul, Turkey). 5 pp.Lira, H. H. (1985). Reconocimiento y evaluaciónde focos termales en el estado de BajaCalifornia Sur. Comisión Federal de Electricidad.Gerencia de Proyectos Geotermoeléctricos.Depto. De Exploración. Internal Report.López, S. A., Báncora A. C., Prol LedesmaR.M., Hiriart L.G. (2006). A new geothermalresource in Los Cabos, Baja California Sur,México. Proceedings 28th New ZealandGeothermal Workshop. 2006.Semiat,R. (2000) “Desalination: Present andfuture”. IWRA, Water International, Volume 25,Number 1, March 2000.Torrez, R. V. (2000). Geothermal Chart ofMéxico. Proceedings World GeothermalCongress 2000. Kyushu-tohoku, Japan.6264

Australian Geothermal Energy Conference 2009Direct GeoExchange Cooling for the Australian Square KilometerArray PathfinderDonald J. B. Payne 1,2* , Grant Hampson 3 , Dezso Kiraly 3 , and Evan Davis 31 School of Physics, University of Melbourne, Parkville, VIC, 3010.2Direct Energy Pty. Ltd., 6 Alma Rd, St Kilda, VIC, 3182.3 Australia Telescope National Facility, CSIRO, Corner Vimiera & Pembroke Rd, Marsfield, 2122.* Corresponding author: Donald.Payne@gmail.com; 0423 776 996Direct Geoexhange Heat Pumps (DGHPs)provide chilling via refrigerant-carrying copperloops buried in the ground which act as acondenser and achieve higher efficiency thanequivalent air source heat pumps because of theground’s constant heat capacity. DGHPs areparticularly suited to desert environments withmore extreme ambient temperatures. TheAustralian Square Kilometer Array Pathfinder(ASKAP) radio telescope will be an array of 36 x12-m diameter parabolic dish antennae situated inthe WA desert each requiring 5 – 7 kW th coolingfor computer equipment. A direct geoexchangesystem installed at the CSIRO facility in Marsfield,NSW provides chilling to prototype equipment viaa 160 L water buffer. Preliminary results indicatea Coefficient of Performance (COP) 5 for chillingwater to 15 C. We describe the results from thisprototype in detail.Keywords: Direct Geoexchange, Direct Use,Geothermal Heat PumpDirect GeoexchangeThe emerging geothermal industry in Australia isfocused on producing electricity (“indirect use”)and should begin delivering substantial resultsover the next decade. Direct Use geothermalenergy is more efficiently available as it entailsonly one energy conversion (absorption orradiation of heat), rather than the several thatoccur in electricity generation and usage, witheach step losing a percentage on conversion.Geothermal Heat Pumps (GHPs) are a direct useof geothermal energy which involve circulating afluid (water, brine or refrigerant) through earthloops (poly pipe or copper) a few tens of metresdeep (Fig. 1, Payne et al. 2008).Direct Geoexchange Heat Pumps (DGHPs) whichcirculate refrigerant through copper loops havegreater efficiency than water-loop GHPs because: copper is more thermally conductive thaninsulating plastic; latent heat transfers directly with the groundon evaporation or condensation; and an intermediate water-to-refrigerant heatexchanger between the ground loops andcompressor is not required.DGHPs transfer heat via 30-metre deep, 75-mmdiameter bore holes compared with 100-metredeep, 150-mm diameter bores used for water-loopGHPs. A continuous, closed loop of copperpiping is inserted and sealed with a thermallyconductive grout (cement). Below 5 metres theEarth remains at a stable temperature all-yearround(16-17 o C at Marsfield, NSW). The smallertemperature difference between the heatsource/sink and the building or water to beheated/cooled results in lower head pressure andenergy requirement of the compressor comparedto conventional heating and cooling systems. A“desuperheater” may be employed in chillingapplications to further optimise the performanceand produce hot water or air which can be usedusefully elsewhere.Figure 1: Copper earth loop, liquid & vapour manifold.ASKAPThe Australian Square Kilometer Array Pathfinder(ASKAP) radio telescope will be an array of 36 x12-m diameter parabolic dish antennae situated inBoolardy WA (Fig. 2) with construction due tocommence in early 2010 and is a precursor to theSquare Kilometer Array (SKA) of severalthousand 12-m dishes. A prototype of theElectronics Systems (ES) and Phased Array Feed(PAF) package to be cooled has been installed atthe CSIRO Australian Telescope National Facility(ATNF) headquarters in Marsfield, NSW. Thesetwo components should not exceed 20 - 30 o Cunder all operating and weather conditions andrequire an estimated heat dissipation of 5 – 7kWth. Various cooling methods have beenconsidered and the extreme desert temperaturesand high price of diesel generated power stronglyfavour a DGHP solution. The results of testing ofa DGHP are summarised in this paper.1265

Australian Geothermal Energy Conference 2009across the heat exchanger should not exceed 5 Cand is ideally below 3 C. A minimum flow rate of0.6 L/s (36 L/min) is required to achieve this. Ithas proven important to have large diameter (1.5-inch) water pipe between the evaporator andbuffer tank. An alternative design has arefrigerant coil evaporator dwelling in the buffertank and eliminates the need for a circulationpump – this will be investigated.Figure 1: Location of ASKAPSystem DesignCooling is provided by a 10.5 kWth DGHP whichcirculates refrigerant (R407C) through 4 x 30-mcopper earth loops to a refrigerant-to-water,braised-plate heat exchanger. Water is circulatedthrough this heat exchanger into a 160 L buffertank and is chilled to 7 – 15 o C (the “primary”circuit). Water is circulated from this buffer tank tothe PAF & ES to deliver the required cooling tothe heating load (the “secondary” circuit). Thedesign of the secondary circuit is beyond thescope of this paper – here the performance as afunction of thermal load is explored. A controllerachieves the specified water temperature.Earth Loop InstallationThe 10.5 kW th system requires 4 x 30-m copperearth loops (½-inch vapour and ¼-inch liquid) withPVC insulation on the upper 15-m of the liquid lineto minimise heat transfer between the two andstop flashing of the liquid refrigerant. 75-mmdiameter holes are drilled vertically 30-m deep ina square configuration with at least 3-m spacingbetween them to allow sufficient thermal diffusionthrough the ground. After insertion of the loopsthe holes are filled with a thermally conductive(geothermal) grout (e.g. 111-mix, Therm-Ex, IDP-357, Barotherm) ensuring that there are no airpockets. The liquid & vapour lines from the earthloops are braised to their respective manifolds (½inchliquid & 7/8-inch vapour) using a 15% silverbraising alloy. The lines are insulated with ½-inchnon-corrosive insulation material (e.g. Armaflex,Insul-Lock) and run towards the heat pump(compressor) with a maximum length of 40-m.Figure 3 shows the drilling and site at Marsfield.Buffer Tank, Heat Exchanger & Flow RatesFor chilling in the primary circuit, the braised-plateheat exchanger acts as an evaporator and it iscrucial to have sufficient water flow over it to fullyevaporate the refrigerant else performance will becompromised. The change in water temperatureHeat Pump Design & RefrigerationThe internal design of the heat pump refrigerantsystem is illustrated in Figure 4. The componentsare described in turn.Compressor: A 3-phase Scroll compressor drivesthe heat pump with compression ratio of 4. Itsefficiency is a function of the evaporating andcondensing temperatures (pressures).Active Charge Control (ACC): This:Figure 3: Installation of earth loops at CSIRO Marsfield.prevents liquid refrigerant from reaching thecompressor by acting as a reservoir; evaporates refrigerant to keep the systemproperly charged and to eliminate superheat; improves volumetric efficiency, reducespower draw, and lets compressor run cooler; enables passage of oil entrained inrefrigerant; indicates refrigerant level via 3 sight glasses.Liquid Flow Control (LFC): This is an efficientThermal Expansion Valve (TXV) which: Sets proper refrigerant flow rate based oncondenser (upstream) operating conditions; Ensures zero sub-cooling so condenser isfully active;2266

Australian Geothermal Energy Conference 2009Reduces compressor discharge pressure andlowers power requirement;Prevents vapor from “blowing through”.Oil Separator: Oil lubricates the compressor andthe oil separator acts with the ACC to prevent oilfrom migrating down the earth loops.Dryer: This filters and dries the refrigerant beforeit enters the LFC.Reverse Cycle & Check Valve: This reverses therefrigerant flow between heating & cooling modes.For this specific cooling-only application this isredundant hardware and a specific GHP will bedesigned for the final application.Refrigerant: R407C [HFC azeotrope: R32 (23%)+ R125 (25%) + R134a (52%)]. Future work willexplore other HFC and hydrocarbon refrigerants.Figure 4: Internal components of DGHP.Expected PerformanceThe Air-Conditioning, Heating and RefrigerationInstitute (AHRI) has a well-established standardfor DGHPs: ANSI/ARI Standard 870, 2001. Also,DGHPs are EnergyStar rated and endorsed bythe Environmental Protection Authority (EPA).The DGHP manufacturer, EarthLinked, providesperformance tables which are derived from boththe Scroll compressor’s performance and fieldtrials. For an earth temperature of 16 o C andchilling water to 15 o C, the expected Coefficient ofPerformance (COP = thermal energy removed/electrical energy input) is 5.1. The theoreticalmaximum (Carnot cycle) performance for coolingis given by (Tcond –Tevap)/Tevap where Tcond isthe condensing temperature and Tevap theevaporating temperature (Kelvin) and is 8.4 forTcond = 37 o C and Tevap = 4 o C whichcorrespond to the above conditions.MethodologyTo find the most efficient means of cooling, theCOP is measured as a function of the controllableaspects of the system. The key controllablevariables are:Buffer Set Point (T b-set ): the temperature to whichthe buffer tank is controlled to be chilled – it ismeasured at the primary outlet of the buffer tank.Buffer Maximum (T b-max ): the buffer tanktemperature at which the controller switches onthe chilling DGHP.Cabinet Set Point (T cabinet ): the temperature towhich the cabinet is cooled.Secondary Load (P load ): the thermal power whichis simulated with a set of heaters.Tank Load (P tank ): the element of the tank can beturned on to act as a thermal load to the system.Other input variables include:Ambient Temperature: this includes both the wet(T wet ) and dry (T dry ) bulb temperatures.Environmental Gain (P envt ): the tank & pipes areinsulated but there is still environmental gain.Tank Volume (V tank ): the buffer tank volume.Water Volume (V water ): volume of water in thesystem: tank, primary & secondary pipes.Output variables include:Compressor Electrical Power (P comp ): theelectrical power used by the compressor.Cycle Time (t cycle ): the time between compressorstart-ups.Compressor Time (t comp ): the time thecompressor is on during a cycle.Duty Cycle (D): the percentage of time thecompressor is on (t comp /t cycle ).Earth Loop Temperatures (T 5–30m ): Thetemperatures measured at 5, 10, 15, 20, 25 &30m.Refrigerant liquid & vapour temperature (T liq ,T vap ): the temperatures to and from the earthloopsSuction, Head & Return Pressures (P head , P suc,P ret ): The pressures in & out of the compressorand returning from the earth loops.ResultsThe default input values are: T b-set = 15 o C, T b-max= 17 o C, T cabinet = 23 o C, P load = 5.2 kW th , P tank = 0,3267

Australian Geothermal Energy Conference 2009V tank = 160 L, V water = 201 L. The ambienttemperature varies between 10 and 35 o C duringthe test periods and future results will becalibrated against this. An estimate of theenvironmental gain was determined by cooling thebuffer to 15 o C, leaving the system off andmeasuring the time taken (t envt ) for thetemperature to increase a known amount (T test ).P envt = C pw .V water . w .T test /t envt where C pw = 4.2kJ/(kg.K) is the specific heat of water, w = 1 kg/Lis the density of water. It was found that for T test= 2 K, t envt = 135 min giving P envt = 208 W.Figure 5 shows the temperature and pressureoutputs for the above input conditions. Fromthese results, the COP can be derived. We findt cycle = 1645 sec, t comp = 737.5 sec, giving D =44.83%. There is a temperature overshoot of atleast 0.75 K below T b-set and above T b-max givingT = 3.5 K. The power required to reduce thesystem water temperature is P water =C pw .V water . w .T/t comp = 4.01 kW th .The electricity consumed by the compressor ismeasured over a known number of cycles to giveaverage power consumption. For this run, E =210 MJ is consumed over n cycle = 87.17 cycles(39.8 hr) giving an average power P comp =E/(t comp .n cycle ) = 3.268 kW elec .COP = [P water + (P load + P envt )/D]/P comp = 5.0. Notethat D accounts for the fact that the load andenvironment are constantly delivering heat to thesystem which must be dissipated by the heatpump whilst on.Using this method, the COP is calculated as afunction of load and DGHP configuration. Figure6 shows a summary of average COP values as afunction of secondary thermal load and Figure 7displays COP as a function of the buffer watertemperature.Figure 6: COP vs. Pload.Figure 7: COP vs. Tb-set.Figure 5: Temperature (top) and Pressure (bottom).From top to bottom, the lines are: Tvap, T30-m, T25-m, T20-m,T15-m, T10-m, T5-m, Tliq, spares, Ttank-out, Ttank-in. Phead, Pret,Psuc.It is clear that the system should not be designedto run with a 100% duty cycle. An initialconfiguration of the system had the heat pumpunit 30 m away from the earth loops. Aftermoving the DGHP to within 4 m of the earth loops,the pressure drop across the earth loops was 5 –15 PSI lower. Also, the manifold pit was initiallyexposed for testing and thus about 15 m of thecopper earth loops was exposed to air and thusnot efficiently dissipating heat. Backfilling themanifold pit boosted the performance.Earth Loop TemperatureThe ground temperature is measured every 5 mdown one of the bore holes via thermocouples.As seen in Figure 5, after the compressor starts,the ground temperatures rise asymptoticallytowards saturation at which thermal outputmatches thermal dissipation in the ground. Theno load condition is shown in Figure 8 along withthe maximum load (11 kW th ) with saturatedground temperatures in Figure 9. In Figure 8 notethat the manifold temperatures track the ambienttemperature overnight as the pit was still open atthe time this data was taken. From the no loadgraph it is clear that there are anomalous offsetsin the ground temperatures. The precise4268

Australian Geothermal Energy Conference 2009explanation for these is as-yet undetermined. It issuspected that the thermocouples used areunsuitable for use with the grout. In the absenceof further details, the temperatures are calibratedby these offsets.secondary circuit (which determines the dutycycle) and buffer water temperature. Importantfactors which influence performance include thedistance from earth loops to heat pump and thecoverage of the manifolds.Further results will be obtained for thisconfiguration and additional experiments include:Use of a flooded evaporator within the buffertank to eliminate the primary circulation pump. Use of a desuperheater between thecompressor head and the earth loops. Use of alternative refrigerants.These results are representative of expectedbehaviour in the field site at Boolardy, WA thoughslight variations will result from: An expected ground temperature of 20-21 o Cat Boolardy.Different thermal conductivity of the ground.Different baseline thermal gain to the system.Figure 8: Temperatures for no load condition.Figure 10: Location of desuperheater, compressor &buffer tank.Figure 9: Temperatures for Pload = 11 kWth.Conclusions & Further WorkDGHPs are an efficient solution for heating andcooling and are particularly suitable for cooling ina desert environment with no power infrastructure.It has been shown that a DGHP achieves a COPexceeding 5 when chilling water to 15 o C in theprimary circuit of a cooling system for a pedestalof the ASKAP – the prototype installation is atMarsfield NSW with a ground temperature of 16 -17 o C. Furthermore, it has been demonstratedthat COP decreases as a function of load in theFigure 11: View inside heat pump unit.ReferencesPayne, D. J. B., Ward, M. And King, R. L.,Position Paper: Direct Use GeothermalApplications, Australian Geothermal EnergyAssociation (AGEA), Feb 2008.5269

Australian Geothermal Energy Conference 2009Geothermal extraction from porous rocks - revisitedMichael Swift 1* , Johannes Muhlhaus 2 .1 Applied GeothermEx Pty Ltd PO Box 3001, Norman Park, QLD, 41702 Director, ESSCC The University of Queensland St Lucia, QLD 4072, Australia* Corresponding author: geotherm1@bigpond.comThere are a growing number of studies of heatand temperature distribution in the crust that areindicative of pore fluid movement redistributingenergy. In the subsurface there are incidentalexpressions of pore fluid flow: mineralization,hydrocarbon migration, tilted oil/water contacts,sediment compaction. There has been very littlequantitative work undertaken to understand thelarger heat and mass transfer systems in theshallow crust and subsequent exploitationstrategies. Temperatures within these shallowergeothermal reservoirs may be lower than thedeeper more impermeable granite HDRreservoirs, but higher flow rates and highersustainable fluid temperatures may yet prove aboon for geothermal energy exploitation. Althoughcooler they may offer higher flow rates and moresustainable fluid temperatures. Modelling studiesare targeted to delineate natural geologicalfeatures that will enhance pore fluid flow toovercome fluid extraction loses, diffusivity lossesand injection cooling effects. There is a focus ondeveloping an artificial geysering effect afterdrilling for enhanced production from porousreservoirs as a production model.Keywords: Convection, porous rock, geothermal,geyser.Balancing Heat FlowConservation of energy requirements mean that inany extraction system the total energy will fallunless there is some recharge mechanism. Thisgeothermal extraction of heat reduces the localtemperature. So how can heat flow be utilized tobalance the heat flow anomalies and maintainhigh temperatures ( if at all) ?Geothermal anomalies are generally anyphenomena which perturb the temperature orheat flow from the simply conductive explanation.In general any heat flow variation from theaverage of 87 milliW/m 2 or a shallow crusttemperature gradient far from 25 °C/km isconsidered anomalous and this is generallyascribed an easy explanation; such as heatsources from intrusives, from radioactive decayand less frequently due to pore fluid movement.Generally, heat movement is a sum of threedistinct process; conduction, advective-convectiveand radiation as part of the thermoelectromagneticspectrum. Now in order ofincreasing amount, the approximate numbers are;Q out = 0.087 W/m 2 by body conduction+/- 1400.0 W/m 2 by surface radiation+200000.0 W/m 2 in body advection convectionInterestingly the earth's conductive heat flow is avery low, 87 milliW/m 2 outwards. This is largelyfixed due to the surface of the earth's averagetemperature of about 20 degrees ( above theblack body radiation temperature of -25 degreesto the atmosphere and green house effects) andthe effectively fixed temperature of about 5500degrees at the core. Ultimately, the conductionlevel is defined by the temperature of theboundary ( in Space there is nothing to conductheat), in this case the surface of the earth. Thetemperature of the earth due to the sun is;T E =T S (( (1-α)R S /2D)T E is the Black Body temperature of the earth(250 °K) , T S is the surface temperature of theSun (5778 °K) D is the distance from the Sun1.496 * 10 11 m and α is the earths albedo 0.367and R S is the radius of the sun 6.96 * 10 8 m.Estimates are often based on the solar constant(total insolation power density) rather than thetemperature, size, and distance of the sun. Forexample, using 0.4 for albedo, and an insolationof 1400 Wm -2 , one obtains an effectivetemperature of about 245 K. The point is that allthe radiated heat is lost back to space, hence the+/- sign used above.The conductive losses are converted intoradiation losses, this conversion occurs in the top30 cm of the crust where opacity starts to reduceto zero. The implication is that the heat flow outwill always be about 0.087 W/m 2 in the short tomedium term ( geologically speaking) as theuniversal back ground temperature of -274 °C isstill small relative to the earth's core temperature.This low conductive heat flow defines theminimum state for steady state geothermalextraction, unless of course is in part someredistribution due to advection-convection.It can be seen that 'In body' advection-convectionis the most efficient way to move heat, indeed allgeothermal extraction methods are based on this.Referring to the mathematical development inAppendix 1 and looking at equation (1.1) it can beseen that for the advective-conductive term;Q=ρ*c*V*TSo fluid velocity is very important in heat redistributionbecause these can be quite low andstill give rise to the instance where fluid flow isquicker than heat recharge / discharge via1270

Australian Geothermal Energy Conference 2009conduction. Note that cooling as well as heatingthe country rock will occur by fluid flow.AdvectionAdvection is generally used to describe fluid flowoccurring in one direction, and generally impliesan open system, and generally gravity head is thedriving mechanism. It is a generalization andsimplification of the convection models, whichdeal with circulating systems and have heat asthe driving force. A good way to visualize theeffect of fluid flow is the study the transienteffects of drilling a well. Such as system is quasicirculation as mud is pumped, but consideredadvective here as it is an open system. Thedrilling of wells generally required the circulationof drilling mud to bring the rock cuttings to thesurface. The circulating mud is generally surfaceambient temperature at the top over well and as itis pumped down/up it warms, with acorresponding cooling of the country rock, seeFigure 1 below. The main parameters are thetemperature difference between the mud and thecountry rock and the time of exposure on the rockto the mud.The country rock is cooled and after cessation ofdrilling, given time it will recover to the true predrillformation temperature. Example recoverycurves are shown in Figure 2. The static drillingmud in the hole quickly equilibrates to thedisturbed nearby country rock temperature. It thentakes about 2 to 3 days for the mud/rock torecover. In this example there is a 60 litre/hourrecharge in the well from an aquifer at 1205 feet.The Horner plot shows the theoretical steadystate conductive recovery of about 14 days.Highlighting the efficiency of fluid flow to cool andheat.Figure 2 Restoration of thermal equilibrium and Horner plot.Gretener 1981The surface heat flow of the Exmouth Plateau,offshore North West Australia has been mappedand the results are shown in Figure 3. Theanomaly in this case is the heat flow low in thecentre of the Plateau of 16 milliW/m 2 . Thisanomaly has been explained by deep pore fluidconvection in the sedimentary pile see Figure 4.This conclusion is supported by numericalmodelling of the equations given in Appendix 1.Figure 1 Schematic representation of temperature conditionin bore hole immediately after drilling. Gretener 1981Low Entropy ConvectionThere are many examples of natural pore fluidconvection in the natural world. The first and mostobvious are water wells or springs which areattached to aquifers and so refill with water. Therecharge mechanism is local gravity drive fromthe water table or a confined aquifer. Thesewaters may be hot if the aquifer has reachedgreat depths. There are fewer examples ofconvective systems, some are discussed below.Figure 3 Surface Heat Flow map of Exmouth Plateau, (Swift1991). Dash line is section in Figure 4.The proposed driving mechanisms for pore fluidflow in this instance are horizontal temperaturegradients. These gradients nearly always existdue to horizontal thermal conductivity contrasts,inherent in the basement/sediment architecture ofbasins. Importantly this implies convection withinmost sedimentary basins.Modelling shows these systems to be selfsustaining, that is, the horizontal gradient isactually greater than the conductive onlycomponent, thereby establishing steady stateconvection.2271

Australian Geothermal Energy Conference 2009Figure 4 Subsurface temperature and fluid flow solution forExmouth Plateau, Swift 1991It is possible to characterize the convectivesystem vigour with a modified Rayleigh NumberRa * (Hickox and Gartling, 1981) where;Ra* = gαρck(T hot - T cold )W/μKwhere in this case (T hot - T cold ) is the lateraltemperature difference over the width W. In thiscase there is no critical value that has to beexceeded for convection to occur. There willalways be a driving force able to overcomeresistive forces. It is under the conditions of thismodified Rayleigh Number Ra*, and not theclassic Rayleigh Number Ra (see high entropydiscussion following) that natural convection in thegeological environment readily occurs.Our modelling results in Figure 3 show there areelevated temperatures in the pore fluids, reachingabout 300 degrees Celsius at 5.6 kilometres,approaching a gradient of 53 degrees perkilometre. Darcy velocities are derived from thestream function, which in turn can be used tocalculate the pore fluid velocity, based onassumption regarding the porosity andpermeability. In the example given Darcy velocityas high as 60,000 m/My or approximately 60metres per year in a very low permeabilityenvironment ( 0.01 millli Darcy). There is an orderof magnitude increase in velocity with order ofincrease in permeability. So in permeable sands,of the order of 50 milli Darcy velocities are up to35 metres per hour! With pressure support andreasonable porosities, this is 3.5 tonne over a unitarea.This demonstrates that it is possible to haveextensive and relatively vigorous subsurface porefluid convection cells that are not detectable bysurface heat flow measurements. This is due tothe fact that if the cells are very deep, theperturbations in the temperature field maydiffused out well before the heat flow passesthrough the top boundary, especially if thesesystems are local.High Entropy ConvectionThe analytical solution for high entropy systemsfor the equations governing heat and masstransfer in a porous medium, given in Appendix 1,is based on the classic Rayleigh Number (Ra)analysis. Here only the vertical temperaturegradient is considered. This is seen in thedefinition of the Rayleigh Number Ra as;Ra = gαρ 2 ck∆TH/μKwhere ∆T is the vertical temperature gradient overthe height H (see Notation 1 for the definition ofthe other variables). Natural convection occurswhen the Ra describing the system exceeds Ra Cfor a homogenous medium Ra C = 4π 2 . In thegeological environment the value of k∆TH is moreoften than not too small for Ra > Ra C and sonatural (forced) convection has historically notbeen considered as being a wide spreadphenomena. As demonstrated above, there areconvective systems possible where considerationis given to horizontal temperature gradientsHorowitz et al 2008 report values of Ra C in therange 62 to 186 for the onshore Perth Basin. andimply manifested convection, although notmodelled. It is suspected the Rayleigh criterion aninappropriate approach, however the variation inthe mapped thermal gradient is consistent forpore fluid flow. The underlying inapplicability ofapplying classic convection theory to naturalconvection in the geological environment is that itfails to take any account of horizontal temperaturegradients.Hot water expulsion from geysers derives from ahigh entropy system where the Rayleigh criterionRa C does apply. In this instance the fluid flow iswithin fractures, a schematic is shown in Figure 5below. The mechanisms of geysers arereasonable well understood, see Lu and Watson(2005) for the most recent review. Thefundamental dynamics are; (a) dual water influx,hot and cold. into a reservoir, (b) a heating systemto bring the water mix to the boil, (c) steam to beliberated, (the phase change alters the pressureenvironment to liberate more steam and moreviolent movement in the boiling water). The steamand entrained hot water move up to a lowerpressure environment.In terms of exploitation of geysers, ageneralisation is that it takes about 1 tonne/hr ofvery hot water undergoing flashing to generate1MW of energy.3272

Australian Geothermal Energy Conference 2009Figure 5 Schematic of geyserWater has a specific heat of about 4200 J/kgK . or1.16 w-hr/kgK or 1160 W-hr/tonne C so a turbinetemperature drop of 250 to 90 degrees gives0.162MW-hr for a water system. For a steam flashthe heat content is higher at 2,100,000 j/kgK (500 times higher) or 81 MW-hr per tonne. This iseasily achieved with an efficiency of say 2%.How is it possible to get tonne/hr of hot water togenerate 1MW in a porous system? The keyrequirement is the heating system. Theessentials of the geyser system are seen to existin deep pore fluid convective systems; hot enoughto boil water, a recharge mechanism and fluid flowpaths. Before drilling for these systems furthernumerical modelling is planned to first establishexploration criterion. There are questions on howto find these systems; by surface heat flowmeasurements or is structural configurationsufficient? There are questions on how to exploitthese systems in such a manner that there aresustained high flow rates at sufficiently hightemperature. There are engineering questions,notably on how to complete drilling in such amanner that "geysering" will occur from a singlegeothermal. It is planned that collaborativenumerical modelling be undertaken at the EarthSystems Science Computational Centre of theUniversity of Queensland to answer thesequestions.SummaryIn the geological environment there are low andhigh entropy convective systems within porousmedia. The planned research is to numericallymodel and understand pore fluid systems with aview to establish exploration criterion, drillingmethodology and reservoir engineering of porousrocks for geothermal exploitation. Early resultsindicate that low entropy systems exist at depth,associated with and accentuating horizontaltemperature gradients. The aim is the find andexploit more vigorous systems where rechargerates are very high. It should be reasonable toexpect to discover pore fluid systems that willsupport long term geothermal exploitation.ReferencesGretener, P.E., 1981, Geothermics: Usingtemperature in Hydrocarbon Exploration. AAPGEducation Course Notes Series #17, 170pp.Hickox, C.E. and Gartling, D.K., 1981. Anumerical study of natural convection in ahorizontal porous layer subjected to an end-toendtemperature difference. J. Heat Transfer, 103:797-802.Horowitz, F.G., Regenauer-Lieb, K.,Wellmann,J.F., Chua, H.T., Wang,X. and Poulet, T.2008Evidence for Hydrothermal Convection in thePerth Basin, Australia, in: Gurgenci and Budd(editors),Proceedings of the Sir Mark OliphantInternational Frontiers of Science and TechnologyAustralian Geothermal Energy Conference,Geoscience Australia, Record 2008/18.Xinli Lu and Arnold Watson, 2005, A Review ofProgress in Understanding Geysers, ProceedingsWorld Geothermal Congress 2005 Antalya,Turkey, 24-29 April 2005Swift, M. G., 1991, Heat flow modelling: ageneralized two-dimensional diffusive andconvective numerical model for the ExmouthPlateau, offshore Northwest Australia,Tectonophysics, 194 (1991) 409-426. ElsevierScience Publishers B.V., Amsterdam4273

Australian Geothermal Energy Conference 2009Appendix 1Mathematical developmentThe system of two equations which govern porefluid convection is:Heat Transfer(ρcp )* ∂ t /T= ∂ x (K x ∂ x T) + ∂ z (K z ∂ z T)- ρ f c f u∂ x T- ρ f c f v∂ z T+ S ..............................................(1.1)Fluid Transfer(1 + k x /k z ) ∂ x 2 ψ + (1 + k z /k x ) ∂ z 2 ψ- [∂ x (k z /μ)μ/k z + ∂ x (μ/k z )k z /μ)] ∂ x ψ +- [∂ z (k x /μ)μ/k x ∂ z (μ/kx)k z /μ)] ∂ z ψ= (k x + k z )g/μ ∂ x p ......................................(1.2)These need to be solved simultaneously, with theaid of the following definitions:u= -∂ z ψ= -(k x /μ) ∂ z P .....................................(1.3)v= ∂ x ψ= -(k z /μ) ∂ z P- (k z pg/μ)....................(1.4)ρ = ρo [1 -α(T - To)]................................(1.5)The governing equations are non-linear as thephysical parameters can be temperature andpressure dependent, as well as being functions ofposition and direction (where such a distinction isappropriate). The solutions of these equationshave no analytical expression, and so a solutioncan only be derived numerically.NOTATIONDefinition of variables *Symbol Description Dimensionc specific heat capacity Jkg -1 °K -1g gravitational acceleration vector ms -2k horizontal permeability m 2K thermal conductivity Wm -1 °K -1P pressure PaQ heat flow Wm -2Ra Rayleigh numberRa * Modified Rayleigh numberS internal heat production rate W/m 2t time sT temperature (Kelvin) °K(Celsius) °Cu filtration velocity vector (u, u) ms -1x co-ordinate direction mz ordinate direction mα coefficient of thermal expansionof fluid °K -1K thermal diffusivity m 2 s-Po density of fluid at referencetemperature kgm -3p density of fluid kgm -3Ps density of sediment kgm -3μ (dynamic) viscosity Pa sψ stream function∂ partial derviativeφ porosity(pc) * sediment-fluid compositespecific heat capacity Jkg -1 °K -1* Subscripts: f = fluid, s = sediment, z = vertical direction,5274

Australian Geothermal Energy Conference 2009Radiation associated with Hot Rock geothermal powerDavid L. Battye * , Peter J. AshmanSchool of Chemical Engineering, University of Adelaide, SA 5005.* Corresponding author: david.battye@adelaide.edu.auWater in Hot Rock reservoirs is in contact withgranites containing radioactive elements(radionuclides). The wider community is generallyaware of this fact through publicity by theAustralian geothermal industry. It is less clear tothe public what radiation hazards may exist forHot Rock projects, and how significant they maybe. The aim of this study was to investigate likelyradiation hazards associated with Hot Rockgeothermal power, with a particular emphasis onradon emission. The study consisted of a reviewof literature and quantitative estimates of radonemission and dispersion from a typical Hot Rockreservoir. This information has been used todevelop a fact sheet, published by PrimaryIndustries and Resources South Australia(PIRSA, 2009).Keywords: radiation, radon, radium, uranium, HotRock geothermal.Dissolved radionuclidesThe radionuclides of interest are those with longenough half-lives to travel to the surface from thereservoir, including isotopes of uranium, thorium,radium, and radon.Uranium and thorium in granites are mostly foundin monazite, zircon and allanite mineral phases.These phases are highly insoluble under mostconditions, therefore the controlling mechanismsfor radionuclide release are dissolution at therock-water interface and alpha-recoil (ejectionfrom the rock due to alpha-decay of the parentradionuclide).Uranium solubility is a strong function of theoxidising or reducing nature of the geofluid.Uranium contents in granite groundwaters arefrequently less than the recommended limit fordrinking water (20 g/L), but may exceed 800g/L in oxidising groundwaters (Gascoyne, 1989).Uranium does not emit gamma radiation,therefore it is only hazardous if ingested orinhaled.The solubility of thorium is low since it tends toform the insoluble hydroxide. Thus, thoriumconcentrations in groundwaters rarely exceed 1g/L (Langmuir and Herman, 1980).Radium is released from the rock by alpha-recoil,but is readily scavenged from solution by sorptiononto mineral surfaces. Cations compete withradium for sorption sites, thus the solubility ofradium increases strongly with total dissolvedsolids (TDS), as indicated by groundwater datashown in Figure 1. Where natural waters exist inHot Rock reservoirs, they are typically quite highin dissolved solids, eg. TDS = 100 g/L at Soultz(MIT, 2006) and 21 g/L in the Cooper Basin(Wyborn et al, 2004). The TDS of water in anoperational field will depend on the extent ofdilution of natural water with injected water. AtFenton Hill, substantial dilution was achievedduring open-loop operation (Grigsby et al, 1983).On switching to closed loop operation, the TDSreached a steady value of ~3 g/L. Thus, naturalwater in Hot Rocks may have radium activities atthe upper end of the scale shown in Fig. 1, but theactivity can be reduced to low levels by dilution ofdissolved solids. To gain some perspective onwhat constitutes “low” levels, we note thatgroundwater sources for drinking water maycontain radium at up to or exceeding 0.5 Bq/L(NHMRC, 2004), a level corresponding to TDS 5 g/L according to the trend in Figure 1.Hot Rock reservoirs are at significantly highertemperatures than the groundwaters for whichuranium, radium and thorium data exist. Solubilityis typically enhanced by increasing temperatureand higher concentrations of these radionuclidesthan cited above are therefore possible,depending on the other contributing factors. TheHot Rock geothermal literature reportsmeasurements of radon in solution but not otherradionuclides of interest. Such measurements incurrent and future projects would be of scientificvalue, and would directly address radiationconcerns.Deposition in surface equipmentThe Hot Rock geothermal power concept involvescirculation of water through an artificial reservoirand surface equipment in a closed loop. Coolingand depressurising of water in surface equipmentmay lead to solid deposits in the form of scalesand sludges. There is potential for these depositsto be radioactive due to inclusion of precipitatedradionuclides. This problem is encountered in theoil and gas industry, where highly saline producedwaters with significant dissolved radium arehandled. These waters tend to be saturated withbarium and strontium sulphates, which precipitateas scales and sludges. Dissolved radium readilysubstitutes for barium and strontium in the solids,creating a radioactive waste material which mustbe periodically removed. Workers are exposed togamma radiation, which is able to penetrate pipeand vessel walls. Additionally, inhalation ofradioactive dust is an exposure hazard whenremoving the deposits. Hamlat (2001) providesestimates of radiation doses received by workersin the oil and gas industry which suggest that the1275

Australian Geothermal Energy Conference 2009exposure is low - generally < 1 mSv per year -compared with the Australian occupational doselimit of 20 mSv per year (ARPANSA, 2002),provided that appropriate protective measures aretaken. This level of exposure is less than theaverage background radiation dose in Australia of1.5 mSv per year (ARPANSA, 2009).The levels of dissolved solids, radium, and ofstrontium and barium sulphates are expected tobe lower for Hot Rock waters than generallyencountered in the oil and gas industry. Hence,lesser quantities of radioactive deposits areanticipated, with lower concentrations ofprecipitated radium. The gamma radiation hazardassociated with solid deposits may therefore besmall compared to that managed in the oil andgas industry. The data of Fisher (1995) in Fig. 1 isrepresentative of waters produced from oil andgas fields, which frequently have TDS in excessof 100 g/L. Diluted water circulating in Hot Rocksis expected to have at least 10 times less TDSthan this, and therefore 7 times less radiumactivity according to the trend in Fig. 1. Thesame reduction in radioactivity of the barium andstrontium sulfate deposits can be expected.Considering that the occupational radiationexposure in the oil and gas is already relativelylow, the exposure from Hot Rock geothermalpower plants is therefore likely to be very small.However, the ALARA (As Low As ReasonablyAchievable) principle of radiation protection willstill apply, which calls for monitoring of exposureand protective measures. In particular, workersinvolved with removing solid deposits fromequipment will need to avoid inhaling dusts.RadonRadon is an inert radioactive gas which is formedby the alpha-decay of radium. It is normallypresent at low levels in ambient air. The averageradon level in Australian homes is 10.5 Bq/m3(ARPANSA, 2009). The decay products of radoncan lodge in the lungs if inhaled, exposing them toionizing radiation and increasing the risk of lungcancer. The action limits for radon in air are 200Bq/m3 in dwellings and 1000 Bq/m3 inworkplaces (ARPANSA, 2002).In a geothermal reservoir, radon enters solutionpredominantly by alpha-recoil and remainsdissolved until its decay. The maximum radoncontent is achieved when the rates of solution anddecay are equal This occurs if the residence timeof water in the reservoir exceeds 25 days (222Rnhas a half life of 3.8 days). Radon activity inwater was a maximum of 500 Bq/L at Fenton Hill(Grigsby et al, 1983) and 200 Bq/L atRosemanowes (Richards et al, 1992).Radon emission and dispersionRadon emissions will occur during open-loopcirculation testing of newly created reservoirs,from uncontrolled flows of geothermal water, orfrom venting of light gases from steamcondensers.If the Hot Rock reservoir is assumed to consist ofplanar, parallel fractures with even spacing, theradon emanation rate, R (atoms/s) is given by:R 2FVSwhere F is the radon flux from fracture surfaces(atoms s -1 m -2 ), V the fractured rock volume (m 3 )and S the fracture spacing (m).The radon flux from plane surfaces ofCarnmenellis granite cubes in water wasmeasured at 30 atoms s -1 m -2 by Andrews et al.(1983). The granite had an average uraniumcontent of 13.5 ppm, and we have assumed that asimilar flux value is appropriate for Cooper Basingranites, which typically contain 16 ppm ofuranium (Geoscience Australia, 2008).Kruger (1995) inferred a mean fracture spacing of50 m from circulation tests at the Rosemanowessite.Steady-state emission of radon from a field canbe estimated by assuming that the emission rateat the surface is equal to the emanation rate.Decay of radon in the reservoir is neglected.Assuming the above cited values for fracturespacing and flux in the Cooper Basin, this methodyields an emission rate of 1.2 billion atoms (2520Bq) per second, per cubic kilometer of fracturedrock.Radon is emitted from steam-venting stacksduring circulation testing, therefore downwindradon levels are of interest. A simple Gaussiandispersion model was used to predict themaximum radon activity at ground level downwindof a single emission source with respect toeffective emission height (physical vent heightplus an allowance for plume rise), and windspeed. Results for a 1 km 3 reservoir are shown inFigure 2. Radon levels are generally negligible foremission heights of 10 m or more, except in calmconditions (wind speeds less than 1.8 km/h). Inthe latter case, levels are expected to be less thanthe action limit for dwellings.During an uncontrolled flow of geothermal waterfrom a well, the effective emission height is closeto ground level, eg. 2-5 m. Figure 1 suggests thatfor a 1 cubic kilometre reservoir, downwind radonlevels would be significant but not exceeding theworkplace action limit except under calmconditions. However, it should be rememberedthat Figure 1 is based on a steady-state emissionrate. If the water in the reservoir has been still fora period, its radon content will be higher thanduring circulation. Therefore the initial emissionrate will initially be higher than the steady-statevalue. For example, if still water in the reservoir2276

Australian Geothermal Energy Conference 2009attains a radon level of 500 Bq/L, then a suddenflow of 50 L/s will cause an initial emission rate of25,000 Bq/s, a value 10 times the steady valueassumed for Figure 1 and therefore increasingdownwind radon activities by the same factor.Calm conditions usually occur at night in centralAustralia and may last several hours. Estimatessuggest that during calm periods radon emissionmay be a significant hazard for the area within200 m downwind of an uncontrolled flow.However, the simple Gaussian dispersion modelresults become spurious as wind speedapproaches zero, and more advanced dispersionmodels are required to more accurately predictradon levels in calm periods.AcknowledgementsThis work was commissioned by PrimaryIndustries and Resources SA (PIRSA). We wishto thank Alexandra Long and Michael Malavazosof PIRSA for their guidance throughout theproject.ReferencesAndrews, J.N, 1983, Dissolved radioelements andinert gases in geothermal investigations,Geothermics, v. 12, no. 2/3, p. 67-82.ARPANSA, 2009, Background radiation factsheet,http://www.arpansa.gov.au/pubs/baseline/bg_rad.pdf (retrieved June 2009).ARPANSA, 2002, Radiation Protection Series No.1,http://www.arpansa.gov.au/publications/Codes/rps.cfm (retrieved June 2009).Fisher, R., 1995, Geologic, geochemical andgeographic controls on NORM in produced waterfrom Texas oil, gas and geothermal reservoirs,Final report, US Department of Energy ReportDOE/MT/92011-12.Gascoyne, M., 1989, High levels of uranium andradium in groundwaters at Canada's UndergroundResearch Laboratory, Lac du Bonnet, Manitoba,Canada, Applied Geochemistry, v. 4, p. 577-591.Geoscience Australia, OZCHEM database,http://www.ga.gov.au/gda/ (retrieved October2008)Grigsby, C.O., Tester, J.W, Trujillo, P.E., Counce,D.A., Abbot, J., Holley, C.E., and Blatz, L.A.,1983, Rock-water interactions in hot dry rockgeothermal systems: Field investigations of in situgeochemical behavior, Journal of Volcanologyand Geothermal Research, 15, p. 101-136.Hamlat, M.S., Djeffal, S., Kadi, H., 2001,Assessment of radiation exposures from naturallyoccurring radioactive materials in the oil and gasindustry, Applied Radiation and Isotopes, 55, p.141–146.Kruger, P., 1995. Heat extraction from HDRgeothermal reservoirs. Proceedings of the WorldGeothermal Congress, 1995, Florence, Italy, Vol.4, pp. 2517-2520.Langmuir, D. and Herman, J.S., 1980, Themobility of thorium in natural waters at lowtemperatures, Geochimica et Cosmochimica Acta,44, p. 1753-1766.MIT, 2006, The Future of Geothermal Energy,http://geothermal.inel.gov (retrieved October2008).NHMRC, 2004, Australian Drinking WaterGuidelines,http://www.nhmrc.gov.au/publications/synopses/eh19syn.htm (retrieved June 2009).PIRSA, 2009, Fact Sheet: Radon and NaturallyOccurring Radioactive Materials (NORM)associated with Hot Rock Geothermal Systems,http://www.pir.sa.gov.au/__data/assets/pdf_file/0013/113341/090107_web.pdf (retrieved September2009).Richards, H.G., Savage, D. and Andrews, J.N.,1992, Granite-water reactions in an experimentalHot Dry Rock geothermal reservoir,Rosemanowes test site, Cornwall, U.K., AppliedGeochemistry, v. 7, p. 193-222.Wyborn, D., de Graaf, L., Davidson, S., and Hann,S., 2004, Development of Australia’s first hotfractured rock (HFR) underground heatexchanger, Cooper Basin, South Australia, PESAEastern Australasian Basins Symposium II,Adelaide, p. 423-430.3277

Australian Geothermal Energy Conference 20091000Radium 226 (Bq/L)1001010.10.01Fisher(1995)Gascoyne(1989)Trendline0.0010.1 1 10 100 1000Total dissolved solids (g/L)Figure 1: Radium-226 activity versus total dissolved solids in groundwaters. Fisher (1995): Oil, gas and geopressuredgeothermalwells in Texas. Gascoyne (1989): Granite groundwaters, Whiteshell Research Area, Canada.10000Maximum ground-level radonactivity (Bq/m 3 )10001001010.1Action limit for workplacesAction limit for dwellingsAverage level in Australian homes1015Effective emission height (m) 200 2 4 6 8 10Wind speed (km/h)25Figure 2: Maximum ground-level radon activity directly downwind of a single emission source, with respect to wind speed andeffective emission height. Assumes an emission rate of 2520 Bq/s, based on steady-state emission from 1 km 3 of fractured rock,50 m mean fracture spacing, 30 atoms s -1 m -2 radon flux from fractures, and neglecting decay of radon. To determine radonlevels at another emission rate, E (Bq/s), multiply the radon level in the plot by E/2520.4278

Australian Geothermal Energy Conference 2009Bringing large scale geothermal electricity to the National GridTom R. Butler, Sharon Tissai-Krishna, *Anthony B. MortonSenergy Econnect AustraliaPO Box 16137, Collins St. West, Melbourne, Vic. 8007.*Corresponding author: tony.morton@senergyworld.comThe Australian Greenhouse Accounts report thatthe Australian stationary energy sector is currentlyresponsible for 50% of the country’s total CO 2 -eemissions. In order to mitigate this contribution toreach emissions reductions targets a significantportion of Australia’s electricity generation isexpected to be sourced by renewable energysources in the near future. Although currentlydeveloped as a smaller contribution to electricitygeneration, recent developments in the area ofHot Rock Geothermal Energy have poisedgeothermal electricity generation for large scaledevelopments. In Australia one of the majorimpediments faced by the development of largescale geothermal electricity generation is theability to transfer large quantities of electricalenergy from accessible geothermal resources tothe ‘local’ electricity grid. This abstract outlines thepotential issues of connecting large scale remotegeothermal electricity generators to the ‘local’electricity grid in the context of the NationalElectricity Market (NEM). These are discussedfrom the point of view of a hypothetical case studypresenting large scale generation in the CooperBasin on the border of South Australia andQueensland.Keywords: Geothermal Electricity Generation,HVAC, HVDC, National Grid.Issues to considerIn Australia the remote location of acceptablegeothermal resources for large scale electricitygeneration, such as that found in the CooperBasin, poses some significant issues for thedelivery of electrical energy to the National Grid(Figure 1). Given that large scale generationrequires large scale electricity transmissioncapacity to, and within, the National Grid, aconnection to the closest possible point to agenerator is rarely optimal. Such a connectionmust consider the following technical andregulatory aspects: The optimum connection point to the NationalGrid, considering the location and security ofexisting and proposed transmission networkassets, and the impact of potential constraintson generating capacity (including interregionalpower transfer capacity); The preferred medium of energy transfer(HVAC or HVDC link); Potential transmission capacity sharing withadjacent proposed and existing generators; Voltage and frequency stability issues specificto large scale remote generation; Voltage levels and voltage drop over thedistances involved; Network fault levels both at the point ofconnection to the NEM and generator; and State specific regulatory issues faced by aproposed generator connection.Figure 1: Map of the crustal earth temperatures at 5km inAustralia. Red areas on the map indicate a temperaturerange of 194-319°C while grey lines show the National Grid.Courtesy of the Renewable Energy Atlas:www.environment.gov.au, 12/6/09.Case studyA technical case study is presented here wherebya geothermal electricity generator with a capacityof 2-3GW is assumed to be installed in SouthAustralia’s (SA) remote Cooper Basin region. Theproposed Cooper Basin Power (CBP) generator islocated far from the National Grid and loadcentres, in order to draw out the technical issuesinvolved with the various connection options. Thefollowing outlines the background information,issues and connection options for the hypotheticalCBP project.Proposed GenerationGiven the vast distance between CBP and anypotential points of connection (PoC), multiplelarge scale generation propositions have beenidentified in the ‘vicinity’ of CBP. In suchscenarios, the potential exists for the connectionof these generators to interact with the connectionof the proposed generation or, alternatively,provide a benefit to both projects through ashared connection arrangement. Other generationprojects to consider include:1279

Australian Geothermal Energy Conference 2009Innamincka Geothermal Energy ProjectThe proposed 500MW Innamincka GeothermalPower Station site is situated within 100km of theCBP site. Geodynamics Ltd. is planning to buildthe project in three different stages withcompletion by the year 2013. Faced with similardifficulties to CBP, Geodynamics has identifiedthree connection options for Innamincka:Olympic Dam via a new 275kV circuit;The 275kV network at Robertstown, north ofAdelaide via a HVDC link; andA connection to Braemar in NSW via a HVDC link.Olympic Dam Geothermal Energy ProjectGreen Rock Energy has proposed a largegeothermal generation project with stageddevelopment to a total capacity in excess of400MW near the Olympic Dam mine in SA. Theproposition includes the direct connection of thegenerator to the existing 275/132kV Olympic DamWest Terminal Station (TS) to supply the OlympicDam mine.Paralana Geothermal Energy ProjectPetratherm are proposing a large scalegeothermal generation project with a capacity inexcess of up to 520MW located 370km to the eastof the Olympic Dam mine in SA. Petrathermpropose two separate connection options for theirproject:A 275kV double circuit to connect directly intoDavenport TS; orTwo single 275kV circuits: one direct to Davenportand another to Olympic Dam via Leigh Creek.Silverton Wind FarmEpuron has proposed to install a 1GW wind farmin the Silverton area approximately 25km northwestof Broken Hill. Stage 1 of the project(~400MW) received planning approval in June2009 and is expected to connect directly into the220kV network at Broken Hill TS. Once approvedStage 2 of the project (~600MW) will require anadditional 220kV circuit from Broken Hill to RedCliffs TS or Buronga TS.Mildura Solar ConcentratorSolar Systems is developing a 154MW solarpower plant in Mildura. The project has receivedVictorian and Federal Government grants withproject completion proposed for 2013. However,recent events provided a great deal of uncertaintyin Solar Systems progressing this project.Although unconfirmed, this project is expected toconnect into the NSW 220kV network local toBuronga.Other generatorsIn states adjacent to the proposed generation site,many other renewable generation projects havebeen proposed ranging in scale and technologies.Should any of these proposed projects becommissioned and connected to any CBP PoCidentified here, the existing transmission networkcapacity will be reduced by the amount connectedwhich may impose capacity constrains on CBP.Technical Design IssuesA number of significant challenges are present indelivering the proposed power to the NationalGrid. Not only does the scale of CBP requiresignificant power transfer capacity, but thedistances involved to connect CBP to the gridbring a new set of challenges. Modern electricitytransmission technologies provide two distinctdesign options for the connection.HVACTransmission Network Service Providers are wellversed in the installation, operation andmanagement of HVAC electrical networks. One ofthe key advantages of HVAC is the ability to veryeasily integrate a new connection into the existingnetwork with existing and available componentsand materials. An important disadvantage,however, is the significant cost of reactive plantrequired for voltage support when bulk power istransferred over long distances.HVDCFor long distance transmission HVDC circuitshave numerous advantages over HVAC:HVDC conductors can carry 30-60% more powerthan a similar sized AC conductor, thus requiringsmaller conductors and fewer circuits;HVDC lines typically have lower losses over longdistances;Only two conductors are required thus needingsmaller line easements;Owing to the absence of reactance effects, DClines have a much greater capacity to transferactive power over long distances without riskingvoltage instability; andParticularly for the new voltage-source type ofHVDC systems, there is little or no reactive powercompensation required at AC/DC or DC/ACconversion stations.HVDC experience in AustraliaHVDC provides an efficient method of transmittingelectricity over long distances with cablesdesigned with carrying capacity up to 3GW.HVDC links are already commonly used in theNEM to provide interconnection between statetransmission networks (Error! Reference sourcenot found.).2280

Australian Geothermal Energy Conference 2009Design of HVDC interconnectors varies widelydepending on project specifications as they relateto specified transfer capacities and transmissiondistances.A HVDC transmission link is usually composed ofAC/DC and DC/AC converter stations, located atthe sending and receiving ends with a DCtransmission link connecting the two. As withtraditional AC transmission, DC transmission linksmay be composed of overhead lines. However, asHVDC overcomes the reactive effects found in ACcabling, DC links can also be composed ofoverhead, underground or subsea cables.It is for these reasons that proposed generation ata site such as CBP should fully investigate theuse of HVDC should a PoC be favoured at a greatdistance from the site, in order to provide thegreatest transfer capacity and network reliability.Voltage StabilityHVAC power transfer capability is limited byvoltage stability constraints rather than thermalconstraints.When heavily loaded, long transmission linesabsorb a large amount of reactive power whichcauses voltage along the line to sag and mayresult in voltage collapse. Voltage stability can bemaintained by absorbing reactive power when theline is lightly loaded and exporting reactive powerwhen the line is heavily loaded. Hence, themaximum power transfer capability of HVAC linescan be increased with reactive support such asNameFrom/ToVoltage(kV)DCTransmissionVoltageInstalledCapacityShunt capacitors and/or reactors;Series capacitors and/or reactors;TransferCapacityInterconnectorLength(From/To) kV MW MW* kmDirectLink NSW/QLD 132/110 80 180 80/180 59MurrayLink VIC/SA 220/132 150 220 220/150 180Basslink VIC/TAS 500/220 400 600 480/600 290* A/B, where A implies transfer capacity From/To and B implies transfer capacity To/From.Table 1: Summary table of HVDC interconnectors currentlyoperating in the NEM.Static VAr systems (SVC, STATCOM, etc.); or Synchronous condensers.HVDC transmission on the other hand is muchless constrained by voltage stability limits andrequires little or no additional reactive powercompensation.However, it is not just the transfer of power to thenetwork where issues of voltage stability mayarise. Given the proposed capacity it is expectedthat power will be transferred within the NEM overseveral hundred kilometres from the PoC beforebeing completely used in load centres. Thus, inthe case of CBP, the network surrounding thePoC would likely require the installation ofsignificant reactive support.Following consultation with network operators,detailed power system studies will need to beperformed to determine the extent of this issue forany connection considered here.Fault LevelsNetwork fault levels depend on many factors suchas network configuration, length of lines andgenerator characteristics. In almost all cases, theaddition of new generation increases network faultlevels. Should the increased fault levels exceedthat of the existing protection equipment designratings, anywhere on the network, remedial actionwill be required in order to replace the equipmentwith that of an increased design rating.Assuming that CBP will consist of multiplesynchronous generators, the fault contribution willbe approximately five times the installedgeneration capacity, totalling 15GVA. This couldpotentially have a significant impact on theselection of an appropriate PoC. However, in allcases the extent of this impact is limited by theamount of generation capacity able to connect toany PoC where the fault contribution is five timesthat capacity, not the maximum CBP capacity.In all cases the full extent of fault level issues canonly be determined through extensive powersystem studies and modelling.Existing InfrastructureGiven the remote location of CBP, threeimmediately evident Points of Connection (PoC)‘local’ to CBP have been identified in SA and NewSouth Wales (NSW).The three potential PoCs for CBP are the275/132kV Olympic Dam West TS and the132/33kV Leigh Creek Substation, which are630km and 460km to the south west in SArespectively, along with the 220/22kV Broken HillTS situated 555km to the south in NSW. Theseare shown in Error! Reference source notfound. with (1), (2) and (3) respectively. However,although these connection points appear to beideal none of them offer an immediately optimalsolution as they are all limited in theirtransmission capacity. Considering the worst casesummer conditions published by AEMO, in thecase of (1) the combined 275kV and 132kVnetwork to Olympic Dam along with the presentmine load offer a maximum of 400MW of powertransfer, the 132kV supply to (2) is limited to20MW while (3) has the capacity for 420MW butthis has effectively been allocated to SilvertonWind farm and is troubled with voltage stabilityissues.Hence, the connection of 2-3GW of generationwould ideally be to large load centres such ascities or large industrial loads. Error! Referencesource not found. shows the nearest significantload centres as Melbourne, Adelaide, Brisbane,3281

Australian Geothermal Energy Conference 2009Figure 2: Map showing the major load centres and generators in the south of the NEM along with the location of the CBP projectand the three immediately evident connection options. Background map courtesy of AEMO: www.aemo.com.au, 18/9/09.Canberra, Sydney and the Hunter Valley alllocated a vast distance from CBP. We need tounderstand the network and available capacity ineach state in order to understand the potentialconnection options adjacent to these load centresfor CBP.South AustraliaThe SA transmission system consists of ameshed network operating at 275kV and 132kV.The high capacity 275kV network transportspower from the major generation plants in the PortAugusta region to Adelaide and further south,while the lower capacity 132kV network suppliessmaller regional loads.There are two major interconnections with theVictorian network; the Heywood connection in thesouth east corner of the state and the Murraylinkconnection in the Riverland region.All transmission assets in SA are owned andoperated by ElectraNet, with the exception ofsome 275kV network supplying Olympic Dam.VictoriaThe Victorian transmission system consists of ameshed 500kV, 330kV and 220kV system wherethe 500kV network transports bulk power from themajor generation plants in the La Trobe Valley toMelbourne and then extends further west toPortland and the Heywood–SA interconnection.The 330kV network provides an interconnectionwith the Snowy region in NSW where majorgeneration is placed. The 220kV network suppliesVictoria’s regional areas and the Murraylink SAinterconnector. Further interconnection extendsfrom the La Trobe Valley to Tasmania viaBasslink.The transmission network assets are owned bySP AusNet while VENCorp are responsible fortransmission planning in Victoria. Connection tothis network requires liaison with both utilities.New South WalesThe NSW transmission network operates at500kV, 330kV, 220kV and 132kV and is ownedand managed by TransGrid. This networkprovides transmission capability between largescale generators, distributors and directlyconnected customers and includesinterconnections with QLD and Victoria.In NSW the 500kV and 330kV networks supplybulk power to regional load centres and provideinterconnection to, and between, Victoria andQLD. As a result, any developments at this levelhave an effect on inter-regional power transfercapability. The 220kV and 132kV networks supplythe regional areas around NSW.QueenslandThe 1,700km long QLD transmission network ismainly comprised of a 275kV radial transmissionnetwork from Cairns in the north to Mudgeerabain the south, while the 110kV and 132kV meshedsystem also supplies regional QLD, while backingup the 275kV network. A small amount of 330kVnetwork interconnects the major QLD generationto NSW through the QNI interconnector.4282

Australian Geothermal Energy Conference 2009Figure 3: National Electricity Grid showing the major loadcentres and generators in the NEM along with the location ofthe proposed generation and the five potentially feasibleconnection options identified. Background map courtesy ofAEMO: www.aemo.com.au, 18/9/09.In QLD Powerlink owns, develops, operates andmaintains the HV transmission network underappointment from the State Government as thetransmission network planning body in QLD.Connection OptionsFollowing the initial assessment of theimmediately evident PoCs, Leigh Creek andBroken Hill have been eliminated due to capacityconstraints. Five alternative PoCs have beenidentified as shown in Error! Reference sourcenot found.. All are discussed below.1: Davenport 275kV Terminal StationAccording to AEMO data, Davenport TS bothsupplies the Port Augusta region in SA andprovides access to the National Grid for asignificant amount of generation capacity locatedadjacent to it. Based on maximum demand in theregion the available power transfer capacity atDavenport TS is in excess of 2.2GVA. However,existing generation in the area reduces this to1,120MVA and could potentially reduce further to720MVA should the Olympic Dam GeothermalEnergy Project proceed to its full capacity.From a high level analysis, connection toDavenport TS would require the construction of655km of new transmission circuit from theproposed CBP site to Davenport TS and thepossible expansion of Davenport TS toaccommodate a step down substation or a DC/ACconverter station.A new transmission circuit for this connectioncould also upgrade the Leigh Creek supply,offering a cost saving to the CBP project.Furthermore, the proposed Innamincka andParalana Power Stations would also be positionedadjacent to the new transmission line such thatthe connection cost could be shared to someextent. However, if both of these projects werealso to proceed to their proposed capacity theavailable capacity for CBP would be reduced tozero without major augmentation of the SAtransmission network.In SA the potential exists for regulatory issues toarise owing to the limited capacity available toexport from South Australia to the remainder ofthe NEM under low SA load conditions.Considering that the proposed CBP generation of2-3GW is similar to the total SA 2009 minimumload these constraints become highly likely andare expected to have a significant impact on CBP.Given an installed CBP capacity of 1,120MVAconnecting to Davenport TS the fault contributionwould be 5.6GVA. As there is alreadyconsiderable generation in the Davenport regionnetwork design considers high fault levels and,based on this high level analysis, the only locationwhere fault level mitigation works will be requiredis on the 132kV side of Playford TS.2: Para 275kV Terminal StationPara TS is a major hub in the SA transmissionnetwork supplying power to Adelaide. There areseveral 275kV circuits connecting to Para TSwhich interconnect the north-south power transfercapacity in SA, along with significant 132kVnetwork. In all Para TS has a power transfercapacity of over 5GVA.From a high level analysis, connection to Para TSwould require the construction of 1,000km of newtransmission circuit from the proposed CBP site toPara TS and the possible expansion of Para TS toaccommodate a step down substation or a DC/ACconverter station.The connection of CBP to Para TS would againlikely pass adjacent to the Innamincka andParalana sites. However, in this case there iscapacity at Para to accommodate all threeprojects and it may be possible to achieve somecost saving should the connection be shared.5283

Australian Geothermal Energy Conference 2009As in the case of Davenport, it is highly likely thatSA regulatory issues will constrain the generationcapacity of CBP to some extent under low SAload conditions.Considering the 275kV and 132kV network in thevicinity of Para TS it is apparent that almost all ofthe switchgear design ratings are able to managethe maximum proposed CBP fault level capacityof 15GVA. The only exception being ParafieldWest Gardens TS south of Para TS wheremitigation works will be required.3: Red Cliffs/Buronga 220kV Terminal StationsRed Cliffs and Buronga TS both facilitate a majorjunction between the NSW, Victorian and SAtransmission networks via the Murraylink andVictoria – NSW 220kV interconnectors.Collectively the total capacity available from thetwo stations combined is 1,260MVA whichincludes the 220MVA Murraylink DCinterconnector. However, the planning approvalgiven to Silverton wind farm implies that 800MVAof this will be offset by Silverton’s generationentering and leaving the Red Cliffs / Burongaarea.Thus the total capacity available from thecombined Red Cliffs and Buronga TS is limited tojust 460MVA. A connection to this point in theNational Grid would require approximately 900kmof transmission circuit to accommodate the newgeneration, the reinforcement of the Victoria –NSW interconnector between Buronga and RedCliffs and the probable expansion of both terminalstations. The potential also exists for a jointconnection including Innamincka and the lessprobable Mildura Solar project but, given thelimitations in network capacity imposed bySilverton, significant network augmentation wouldbe required to accommodate either of theseprojects along with CBP.Some network upgrades are proposed for thearea including increasing the existingtransmission network voltage from 220kV to275kV up to Red Cliffs TS from NSW. While thisupgrade would increase the capacity to the area itwould only provide an additional 100MVA to anew total capacity of 560MVA.Although small in comparison to the two previousconnection options an additional 560MVA ofgeneration at this point in the National Grid isexpected to increase the network fault levelsabove switchgear design ratings at at least fiveTerminal Stations requiring significant fault levelmitigation works.4: Bayswater 330kV Terminal StationBayswater TS has a significant total powertransfer capacity of 9.5GW and is interconnectedwith the 330kV NSW transmission network. Theexisting generation capacity connected toBayswater TS is 2.6GW with a further 4.5GW inthe areas surrounding Bayswater TS. Thus, theavailable capacity for the CBP project atBayswater is around 2.4GW. However, thesignificance of this location in the National Gridrequires detailed power system studies todetermine the impact of connecting CBP toBayswater TS.From a high level analysis, connection toBayswater TS would require the construction of1,200km of new transmission circuit from theproposed CBP site to Bayswater TS and thepossible expansion of Bayswater TS toaccommodate a step down substation or a DC/ACconverter station.As the Bayswater TS is located in a very strongarea of the National Grid, adjacent to significantexisting generation, protection equipment is ratedaccordingly with high fault level design ratings.However, the addition of up to 12GVA of faultlevel from the CBP project is expected to exceedthe fault level ratings of protection equipment inthe central NSW and Sydney regions wheremitigation works will be required.5: Tarong 275kV Terminal StationTarong 275kV TS currently supports around 2GWof generation while being heavily interconnectedwithin the QLD 275kV network and Tarong isinstrumental in supplying Brisbane. Just south ofTarong TS, the QNI interconnector connectsQueensland to NSW via Bulli Creek TS adjacentto Tarong TS. Given the level of interconnectionat Tarong TS it has a total power transfercapability of 14.5GW. There is currently around3GW of generation connected to Tarong TS andthe adjacent 275kV network.It is possible that the existing generation in theTarong TS region may impose some constraintson the CBP project, however, given the capacityof the adjacent network this appears to be unlikelyat this early stage. Hence, the available capacityis expected to accommodate the maximum of3GW for the CBP project.From a high level analysis, connection to TarongTS would require the construction of 1,100km ofnew transmission circuit from the proposed CBPsite to Tarong TS, and the possible expansion ofTarong TS to accommodate a step downsubstation or a DC/AC converter station.Powerlink are currently planning for significantupgrade works on the QLD transmission systemin order to accommodate rapidly increasingdemand in the generation poor south east regionsof the state. The proposed upgrades include theinstallation of some 500kV network and largescale generation capacity. Hence, it is expectedthat Powerlink would consider the connection ofCBP to benefit their present network conditions.Considering the existing fault level in the area theaddition of the full CBP capacity at Tarong TS6284

Australian Geothermal Energy Conference 2009would add a further 15GVA. At present much ofthe existing 275kV protection equipment at theterminal stations adjacent to Tarong TS is notrated for this increase. As such it is expected thatthis connection would require significant fault levelmitigation works on the QLD 275kV transmissionnetwork.ConclusionsGiven the information presented it is evident that,while there are many options available for largescale geothermal generation to connect into theNational Grid, few of these are considered to beoptimal as existing transmission system designfocusses around large load centres and existinglarge scale generation. Hence, all of theconnection options considered here are expectedto require significant network upgrades in order toaccept the generation capacities considered in theCBP case study.Based on the CBP case study it is evident thateither northern South Australia or southern QLDpresent the greatest opportunity for theconnection of large scale geothermal electricity,despite the significant transmission distancesinvolved. HVDC transmission is expected to beable to assist here. Correspondingly, theavailability of a shared connection over thedistances considered would be expected tobenefit all parties financially.ReferencesAustralian Gov. Dept. of Climate Change, 2008,“Carbon Pollution Reduction Scheme WhitePaper: Summary”The Australian Greenhouse Information System:Australia’s Greenhouse Accountswww.climatechange.gov.au (10/8/2008)Geodynamics Limited website:www.geodynamics.com.au (12/6/09)Silverton Wind Farm website:www.silvertonwindfarm.com.au (12/6/09)Green Rock Energy website:http://www.greenrock.com.au (12/6/09)ABC, 03/11/2008, “Solar Future for Mildura”:http://www.abc.net.au/local/stories/2008/11/03/2408915.htmThe Age, 26/02/2008, “Mildura power station tohelp cut emission levels”:http://www.theage.com.au/news/national/powerstation-to-help-cut-emissionlevels/2008/02/25/1203788246883.htmlAEMO website:http://www.nemweb.com.au/Reports/Current/Alt_Limits/ (13/6/09)ElectraNet, 2008, “Annual Planning Review 2008-2028”, www.electranet.com.auTransGrid, 2004, “2004 Data Book”,www.transgrid,.com.auTransGrid, 2008, “Annual Planning Report”,www.transgrid.com.auPowerlink, 2009, “Planning a 500kV network tomeet Growth in South East Queensland”,www.powerlink.com.au7285

Australian Geothermal Energy Conference 2009Alternative Energy Carriers for Remote Geothermal SourcesRobert R. Dickinson 1,3 *, David Battye 2 , Valerie Linton 1 , Peter Ashman 2 , and Graham (Gus) Nathan 1Schools of Mechanical Engineering 1 and Chemical Engineering 2 , The University of Adelaide, and Hydricity SA 3The University of Adelaide, Australia, 5005* Corresponding author: robert.dickinson@hydricity.com.auAustralia's geothermal industry will soon be readyto scale up its capacity from pilot-scale projects ofone MW or less, to demonstration plants ofseveral tens of MW. These scales are too smallto justify construction of high-capacity longdistanceelectricity transmission lines connectingto the national grid. As illustrated in Figure 1,Australia’s primary geothermal sources are muchcloser to the national Compressed Natural Gas(CNG) pipeline network than they are to thenational electricity grid. This paper presents anassessment of the prospect of using large-scaleelectrolysis to convert the output of a geothermaldemonstration plant to hydrogen and then tomethane for direct injection into existing CNGtransmission pipelines. The methanation stepinvolves the consumption of carbon dioxide fromCNG processing plants – a byproduct that wouldotherwise be vented to the atmosphere. Asummary of energy flows is given towards the endof this paper, The key advantage of the use ofhydrogen and methane as alternative energycarriers is that it would circumvent the dilemma:“What comes first -- commercially viableelectricity transmission lines or a successfulindustrial scale demonstration plant?”.Keywords: geothermal source, electrolysis,hydrogen, methanation, CNG transmissionpipelinesOutline of assessmentThe assessment that we present here arose fromthe need to quantify and clarify the technical,engineering and economic feasibility of using analternative energy carrier to transport energy froma geothermal source in northern South Australia(SA) to major energy consumers located inOlympic Dam and Adelaide. The outcome andconclusions from our assessment can begeneralised to other regions.For our quantitative assessment, we assumedthat the net power from a geothermaldemonstration plant would be 50 MWe. Thisprovided the basis for estimating the scale of theelectrolysis stack, the maximum rate of feedwaterconsumption, the hydrogen yield, and in turn, themaximum methane flow that would be injectedinto an existing CNG pipeline.The following sections outline the maincomponents of the system that we assessed: thewater that is fed into the electrolysis system, theelectrolysis system and its associated coolingsystem, and the methanation processing plant.Figure 1: Australia's coastal electricity grid (a) is distant fromprimary geothermal sources, but overlaps with the nationalCNG transmission pipeline network (b). [Geothermal dataadapted from AGEC (2009), electricity and gas networksadapted from ACCC ( 2008)]Feedwater productionThe feedwater for the electrolysis process isrequired to be purer than the groundwater that istypically available in central Australia. Figure 2shows a proposed geofluid distillation plant thatcould be used to deliver a sufficient quantity ofdistilled water for input to the electrolysis process.Electrolysis plantThe proposed electrolysis plant is based on anarray of type 5040 electrolysers from StatOilHydro's Hydrogen Technologies (previously NorskHydro) 1 . Each such unit yields an output of 0.1351 We discarded the prospect of hightemperature electrolysis (“HTE”) because commercialsystems are not yet available, and the marginal energy1286

Australian Geothermal Energy Conference 2009Figure 2: Proposed feedwater processing plant flow diagramNm 3 /s (485 Nm 3 /h) of hydrogen, and consumes2330 kW, from a DC power supply of 5150 amps.Waste heat from this electrolysis plant is removedby cooling water, in a water cycle that iscompletely separate from the feedwaterproduction process. This cycle requires a meansof reducing the temperature of the cooling watertemperature by 10 °C. For this, we propose arefrigeration plant. We chose this afterconsidering other more energy-efficient, options,including evaporative cooling (which wouldconsume excessive groundwater) andunderground pipe networks (which would have ahigh capital cost invested in an immovableinfrastructure).In theory, the methanation step shown in Figure 3is optional. In practice it is likely to be the key to asuccessful alternative carrier implementation. Wereached this conclusion based on consideration ofthe prospects for (1) direct use of hydrogen yield,(2) blending the hydrogen yield with CNG fortransmission as HCNG and (3) methanation.Prospects for direct use of hydrogenyieldIn future, there may be opportunities for direct useof the hydrogen yield from an electrolysis plantsuch as the one proposed here. These mayinclude domestic and export markets for 99.9%pure hydrogen. For example, McLellan (2009)presented an assessment of the prospect of largescale domestic consumption of hydrogen in themining sector, but it is unlikely that suchopportunities will arise within the proposed timeframe for implementation of an alternative carrierscheme.Prospects for transmission as HCNGA quantitative assessment of the maximumhydrogen yield from the electrolysis plant relativeto typical CNG flows, led us to consider directinjection of hydrogen for transmission as HCNG ina proportion of 5% H 2 to 95% CNG by volume.conversion efficiency increase is very small for the lowtemperature range of 150-200 ºC at 5km that is typicalof Australia's primary geothermal sources (Balta et al2009).Figure 3: Proposed electrolysis plant layoutOur assessment of the effects of a blend of 5%hydrogen on the physical properties of HCNG fueldid not reveal any major limitations. Standardscompliance would be near the limits of current gaspipeline content requirements, the risk to moderndomestic appliances would be negligible, and therisk to gas engines would be small, while gasturbines would require a stable proportion ofhydrogen. In contrast, our assessment of theeffects of HCNG blends on the structural integrityof the existing CNG pipeline infrastructure led usto conclude that these could be significant limitingfactors.Hydrogen containment engineering is morestringent and challenging than CNG containment.The cost of new hydrogen pipelines of a givendiameter are up to twice those of CNG pipes ofthe same diameter (Ball and Weitschel, 2009).Existing hydrogen pipelines in refineries andchemical plants to date have performed well(Zawierucha and Rana, 2005), but thesepipelines are generally in small diameter,(Thompson and Bernstein, 1977), made from lowstrength steel, (Hayden, 2007) and operate at lowpressures. Experience with such pipelines offerslittle guidance on the potential performance ofhigh-pressure hydrogen transmission pipelines.In contrast to containment of pure hydrogen, therepresumably exists a theoretical proportion ofhydrogen in an HCNG blend below which themarginal increase in engineering stringency isnegligible. Our consideration of such issues asembrittlement, ductility, fracture toughness,fatigue life, fracture propagation, pressure(Haeseldonckx and D’haeseleer, 2007), andexposure duration, led to the conclusion that therewould be a substantial risk that even a 5% blendmight detrimentally affect the CNG pipeline steelin the long term. This risk would have to be takeninto consideration when determining theoperating, inspection and maintenance schedulesfor hydrogen-carrying pipelines.2287

Australian Geothermal Energy Conference 2009MethanationMethanation involves conversion of hydrogenand carbon oxides to methane. The two mainreactions are:CO + 3H 2 CH 4 + H 2 O ∆H = -206 kJ/mol (1)CO 2 + 4H 2 CH 4 + 2H 2 O ∆H = -165 kJ/mol (2)Both reactions are reversible and exothermic andboth require a catalyst.Reaction 1 (using carbon monoxide) is used onan industrial scale to produce synthetic gaseousfuel. A prominent example is the Great PlainsSynfuels Plant in North Dakota, which convertslignite coal to methane at a rate of 1.5 billion Nm 3per year.Reaction 2 was discovered in the early 1900's byPaul Sabatier, and is often cited as the method forremoving astronaut-exhaled CO 2 from space lab“air”. It has not been developed on a largeindustrial scale to date, but researchers in Japanare working towards this end (Hashimoto et al2009). The key advantage of using reaction 2 isthat CO 2 is available in abundance at Moomba'sgas processing facility, as a byproduct gas that isotherwise vented to the atmosphere.Figure 4 shows a flow diagram for implementingreaction 2 in the context of the electrolysis plant.Two or more methanation reactors in series wouldbe required to ensure better than 90% conversionperformance. Alternatively, the separation stepat the bottom of the flow diagram could be used toreduce the delivered hydrogen proportion to anegligible amount.Further work is required to confirm the ways andmeans by which suitably scalable methanationreactors can be built and applied for anelectrolysis plant such as that outlined in Figure 3.The output from a 45 MW electrolysis plant isestimated to yield an amount of methaneequivalent to 2% by volume of the flow of naturalgas from Moomba to Adelaide. This amountcould lead to a net reduction of overall nationalgreenhouse gas emissions, via displacement ofnatural gas from CO 2 -emissions-intensivesources.Summary of energy flowsThe geothermal energy harvesting subsystemgenerates 70 MWe but loses 20 MWe in parasiticlosses. Similarly, of the remaining 50 MWe theelectrolysis plant loses 5 MWe in the coolingsystem. The remaining 45 MWe is converted tohydrogen and then to methane with a netefficiency of 56%. The methane yield (availablefor sale) is about 2.5 Nm 3 /s, or 8.3 TJ/day if theplant is operated at full capacity.Figure 4: Proposed methanation flow diagram.Relative cost assessmentThe capital cost of the installed electrolysis andrefrigeration plant and associated pipework isestimated to be of about 70 million dollars. Thiscompares favourably with the hundreds of millionsof dollars that would be required to construct ahigh-capacity long-distance electricitytransmission line. For example, the cost ofupgrading the SA – Victoria interconnector isexpected to be about 400 million dollars, for adistance of about 300 km. This advantage isgreatest if the geothermal plant is co-located witha CNG pipeline. The cost effectiveness of theelectricity-to-methane process would have to beevaluated in detail on a case-by-case basis foreach new demonstration geothermal plant, andwould be influenced by the accessibility of CO 2stocks as well as distance to electricity andpipeline networks.By way of an example, the break-even electricityproduction cost (amortized capital cost comparedto energy sales) for the 50 MWe electrolysisbasedelectricity consumer, is similar to the breakevenproduction cost of a 400 MW geothermalplant sending electricity down a 400 MW 400 kmelectricity transmission line, despite the electricity3288

Australian Geothermal Energy Conference 2009to methane energy losses and despite thedifference in the value of electricity and methaneper unit of energy. This is because such atransmission line would cost over three times thecost of the electrolysis plant.Summary and conclusionsWe reviewed the prospect of converting electricalenergy from demonstration geothermal plants tohydrogen. We propose a system in which thisenergy would be shared in the ratio of 9:1between an electrolysis plant and a refrigerationplant. An additional methanation step is requiredto avoid the risks posed by adding pure hydrogento the existing CNG infrastructure. Apart from thethe methanation reactor, all of these componentsare available as off-the-shelf items. Only themethanation reactor requires additional detaileddesign and further work to ensure the viability ofthis system. This system appears to offer a costeffectivecircumvention of the geothermalbusiness development dilemma: “What comesfirst -- commercially viable electricity transmissionlines or a successful industrial scaledemonstration plant?”.ReferencesAustralian Geothermal Energy Group (AGEG),Australian Geothermal Implementing AgreementAnnual Report – 2008, 17 July 2009http://www.pir.sa.gov.au/geothermalAustralian Competition and ConsumerCommission, State of the Energy Market 2008,http://www.accc.gov.au/Ball, M., and Wietschel, M., 2009, The future ofhydrogen – opportunities and challenges,International Journal of Hydrogen Energy v. 34,Issue 2, p. 615 – 627.Balta, M.T., Dincer, I., and Hepbasli, A., 2009,Thermodynamic assessment of geothermalenergy use in hydrogen production, InternationalJournal of Hydrogen Energy, v. 34 p. 2925-2939Hayden,L.E., The ASME B31.12 HydrogenPipeline Code. Proceedings of the conferenceTransmission of CO2, H2 and Biogas: ExploringNew Uses for Natural Gas Pipelines. Hilton Hotel,Amsterdam, 30-31 May, 2007.Haeseldonckx, D. and D’haeseleer, W., 2007,The Use of the Natural-Gas Pipeline Infrastructurefor Hydrogen Transport in a Changing MarketStructure. International Journal of HydrogenEnergy v. 32 (2007) p1381 – 1386.Hashimoto, K., Tako, Z., Kumagai, N., andIzumiya, K., 2009, Materials and Technology forSupply of Renewable Energy and Prevention ofGlobal Warming, Journal of Physics: ConferenceSeries 144 (2009) 012009, IOP PublishingMcLellan, B.C., 2009, Potential opportunities andimpacts of a hydrogen economy for the Australianminerals industry, International Journal ofHydrogen Energy, v 34, issue 9, p 3571-3577Thompson, A.W., and Berstein, I.M., 1977,Selection of Structural Materials for HydrogenPipelines and Storage Vessels. InternationalJournal of Hydrogen Energy, v 2, p163-173.Zawierucha, R., Xu, K. and Rana, M., 2005,Hydrogen Pipeline Steels. Proceedings of theMS&T'O5 Conference: Materials Science andtechnology.4289

Australian Geothermal Energy Conference 2009What Contribution Can Geothermal Energy Make to Australia’sRenewable Energy TargetFroome, C.W.School of Chemical Engineering, The University of QueenslandBrisbane, Queensland, 4072, AustraliaPhone: +61 7 3365 1574; Fax: +61 7 3365 4199; Email: c.froome@uq.edu.auGeothermal energy provides the renewableenergy sector with an opportunity to produce baseload power, whilst meeting current governmentobjectives in relation to greenhouse gas emissionand renewable energy portfolio standards. Whilstthe technology is not currently at an advancedstage of commercialisation when compared toother generation technologies utilising renewablesources such as wind or solar, the fact remainsthat it can provide continuous, rather thanintermittent generation. Industry and renewableenergy associations, together with governmentagencies are now including geothermal energywithin their calculations of available generationcapacity by 2020.However, conflicting policy initiatives betweenState and Federal Governments, together withdelays in proving commercial viability of thetechnology may see the sector miss out on manyfunding opportunities. This research looks atwhether the current proposed Federal policies willprovide the incentives needed to drive thedeployment of geothermal energy within the 2020timeframe or whether the current barriers will seedeployment occur much later. This paper will alsoconsider whether the delays may actually beadvantageous given the conflicting policyobjectives.Finally the paper will consider the currentdevelopment sites and whether policy could seedeployment closer to the point of end use. Whilstthe need to develop pilot plants is crucial, theneed to develop sites closer to existing networksis also important given the costs associated withestablishing grid connection, a cost that must beborne by the generator. This may see the need foradditional State based policy measures to driveboth additional development and deployment ofthose identified resources close to existinginfrastructure.For the purpose of illustration any examples willrelate to the State of Queensland.Keywords: Renewable Energy; GovernmentPolicy; TransmissionRenewable Energy in AustraliaAustralia’s renewable energy sector is still in itsinfancy when compared to most other developedcountries. For many European countriesrenewable energy started being deployed in the1980’s to combat energy security concerns. WithAustralia being resource rich, our renewableenergy sector is being developed as a result ofcombating climate change concerns.Current policy is aimed at the period to 2020 withthe target being set at 45,000 GWh of renewableenergy being generated annually at that time. Inaddition most electricity retailers are offering“green” electricity options, with that electricity soldnot counting towards the portfolio standard,increasing the actual target above that required bythe legislation.Wind technology is at an advanced state ofcommercialisation and within Australia has beenthe most widely deployed large-scale renewabletechnology in the past decade. Most recentannouncements on new renewable generationhave also focused on this technology.Whilst all renewable energy resources havebenefited from REC income some renewable orclean energy technologies, such as solar and gas,have received additional financial subsidies at aState level. The deployment of wind has alsooccurred without the need for additional ongoingsubsidies. The wind sector has also benefitedfrom Australia’s population being predominatelylocated on the coast with this generally being thearea of greatest wind potential. This has enabledthe selection of wind farm sites close to existinggrid infrastructure and due to the design of theelectricity market they are able to ensure that allgeneration is dispatched.Many State Governments are also providingadditional incentives, in relation to the deploymentof solar technologies through feed-in tariffs orequipment subsidies. Whilst most of the feed-intariffs adopted are based on the net amount ofelectricity exported to the grid rather than grossgeneration, it has resulted in conjunction withequipment subsidies, a higher than expecteduptake of the technology.Geothermal energy can however provide baseload generation capacity capable of replacingexisting coal-fired plants, unlike their intermittentcounterparts. The only other renewabletechnologies capable of this are hydro andbiomass, however this supply has reached theupper end of possible deployment due to the lackof additional resources.It must not be forgotten that geothermal is not anew energy source for power generation havingbeen around for over a century, with the first1290

Australian Geothermal Energy Conference 2009electricity generation plant constructed inLarderello, Italy in 1904 (Australian Institute ofEnergy, 2004). What is new is the technologysurrounding how the available resource is to beexploited within this country. Whilst many of thecurrent companies are looking at similarproposals, there is still a degree of differentiation.The problems encountered by the geothermalsector are different to the other technologiesnoted above within Australia, due to the areas ofgreatest potential being located at great distancefrom the end point of energy use. However, asthose sites where resources can be easily andeconomically exploited already taken, particularlyin relation to wind, or where solar thermalbecomes an economic option, development ofsites further inland will become an option.Government PolicyThe Government has identified the policymeasures that they believe will drive thedeployment of renewable energy within Australia,being the Carbon Pollution Reduction Scheme(CPRS), a cap and trade system, together withthe Renewable Energy Target (RET), being aportfolio standard.In addition to these schemes, the various Statesare also introducing policy measures of their own,targeting resources where they have an economicadvantage. These policy measures may actuallybenefit the geothermal industry with modellingundertaken to date showing that the increaseddeployment of wind and various small scale solartechnologies will result in a surplus of REC’s inthe early years (particularly due to the multipliereffect to apply to small solar generation), asshown in Figure 1. The RET also includeselectricity displacement options, such as solar hotwater, as an accredited renewable energygenerator.Based upon the current position of technologicaldevelopment, large-scale deployment ofgeothermal is not anticipated until late in the nextdecade, which coincides with the shortfall inrenewable generation. The industry will be in aposition to meet this shortfall with an anticipatedhigher REC price than will be achieved in theearlier years.If we consider PV deployment rates in Europewhen their market was in a similar position ofmaturity, an annual growth rate of 10% is notconsidered unreasonable. Together withproposed wind farms would see a surplus in theREC market until 2017, based on no geothermalcontribution.Figure 1 - National REC Supply v Demand (with banking)Source: (Herd, 2009)In addition to the CPRS and RET discussedabove, the Federal Government has alsoestablished the $50 million Geothermal DrillingProgram as part of the $500 million RenewableEnergy Fund. This program is merit based and iscapped at $7 million per project, with the aim toprovide funding to demonstration proof-of-conceptprojects in a number of locations. It was furtherstated that this program could make small-sizeplants possible, allowing for generation projectswhere sites close to current transmissioninfrastructure have been identified.State Governments have also been active in theirsupport for the geothermal sector, particularly inSouth Australia and Queensland.Current IssuesThere are two major issues currently facing thegeothermal industry effecting their futurecontribution to Australia’s renewable energytarget. The first relates to the development of thetechnology to the point where it can becommercially deployed. Once the technology isproven, there will still be some delay before it canbe deployed to the extent that it can make acontribution to base load generation. Until pilotplants are operational it is still hard to determinewith any pinpoint accuracy this time frame.Major investors in renewable, such as AGL (seewww.agl.com.au) have also focused theirattention on wind farms acquiring the rights to anumber of sites still going through the planningstage. This will enable them meet their corporaterenewable targets based upon existing technologywith a known cost base.The second (and more costly) issue is theconstruction of transmission networks, a costwhich must be borne by the generation company.With existing coal and gas-fired plant, the actualgeneration plant relies upon the fuel beingdelivered to it, with on-site storage generallyavailable. Geothermal, like most renewable2291

Australian Geothermal Energy Conference 2009technologies requires that the generation plant belocated at the site of the resource.Similarly looking at the coal or gas sector, themajority of generation plant is based upon similaror the same technological design. The same maybe true for the above-ground geothermal plant,however there are currently a number of proposedoptions as to how the underground resource canbe best utilised.Geodynamics (Grove-White, 2009) have alreadyidentified that the cost of transmission will be amajor problem and that it may be better to bringthe customers to the source of the generation,rather than vice-versa. Whilst this will allow for thegeneration to be scaled up on-site whilst delayingtransmission infrastructure costs and assist in themeeting of the Federal portfolio standard, it willnot reduce base load generation required fromexisting coal and gas-fired plant, supplying themajor coastal population base, unless thosecustomers are relocating from an existing siterather than establishing additional facilities.The alternative to the construction of newtransmission infrastructure is to locate geothermalpower plants closer to existing infrastructure.The issue of transmission and plant location willbe discussed later in this paper.Industry OutlookA report by MMA (2008) on the capacityexpectations of the industry by 2020 recognisedthat the technology deployed needed to be viable,with this being defined as being cost competitivewith other renewable technologies, including amargin deemed sufficient by providers of capital.A REC market that will be in surplus will result in aREC price that will be much lower than thatcurrently anticipated. This may work to theultimate advantage of the geothermal sector.Figure 2 indicates that the installed geothermalcapacity will start to increase significantly from2015, however due to technical problems withsome pilot plants; it is considered that this will bedelayed by two to three years, which may provideopportunities for the sector.The MMA report (2008) also identified that asubstantial amount of the RET must still beavailable when geothermal projects are at thestage of being ready for deployment. Much of thecurrent State and Federal policy has been aimedat the deployment of existing commercially viabletechnologies, such as solar PV and hot watersystems, through the Federal Solar BonusScheme and various State schemes, focusing onhot water rebates and fees-in tariffs. As notedabove, modelling set out in Figure 1 indicates thatthat this will create a surplus of REC’s anddependent on the uptake of the technology, mayresult in this surplus remaining until 2017. Thedata presented allows for no geothermal energybeing exported to the grid, but does show theshortfall of REC’s that the geothermal sector cantake advantage of.Figure 2 - Cumulative installed capacity and investmentSource: (McLennan Magasanik Associates, 2008)Many electricity retailers also anticipate that windgeneration will pick-up the shortfall, with anadditional 29 wind farm projects currently underconsideration, however, many of these may findthat the wind availability in some of these areasunder investigation is not economically viableparticularly given that the majority are located inSouth Australia and Victoria where there isalready a high presence of this technology.Research has previously indicated (Froome,2009) that existing and proposed Federal policymeasures will not be sufficient by themselves todrive renewable energy deployment to the targetsproposed. With retailers also offering ‘greenenergy’ programs, the actual shortfall will be muchgreater than indicated. Like the solar examplesprovided, additional State measures will berequired, based upon the individual needs of theState in meeting their own economic and socialpolicy objectives.Looking specifically at Queensland the policydecisions being faced may be whether to providesupport through a feed-in tariff to thosegenerators located close to existing infrastructureor subsidise new infrastructure to those areaswhere the resource is more plentiful.TransmissionThe Queensland Government has alreadyreleased 29 sites for tender as shown in Figure 3,with only one site west of Gladstone havingalready been awarded. There are currently afurther 26 tenders under consideration by theDepartment of Mines and Energy. Whilst many ofthese sites are considerably smaller than themajor sites being developed in South Australia,having existing transmission and distributioninfrastructure in close vicinity, together withforecast demand growth for many of the regionssurrounding these sites, the economic return3292

Australian Geothermal Energy Conference 2009required or investment hurdle point will be muchlower.The information shown in Table 1 indicates theincreased interest in geothermal energy, boththrough the number of tenders lodged comparedwith land releases and the number of companiesultimately gaining preferred tender status. Therestill remain two land releases (one from each ofrounds one and two) that no tenders werereceived for.However this will also result in competition for thelimited amount of private funding available toprogress the proposed projects.Rnd 1 Rnd 2 Rnd 3Tender Closing Date 3/06 4/07 2/08Land Released (No.) 6 10 35Tenders Received (No.) 6 11 13Preferred Tenders (No.) 5 9 13No. Of Tendering Company’s 2 3 6Table 1 - Queensland Geothermal TendersSource: (Office Of Clean Energy, 2009a)It is also interesting to note that the land releasedin round three is located furthest from the coastand will therefore incur greater capitalrequirements when considering transmissioninfrastructure costs, but all land releasesprogressed to the preferred tender stage.Also looking at this from a Queenslandperspective, locations that have been identified assuitable for new solar thermal or wind generationare also located near identified geothermalresources. This will provide a number of sharedinfrastructure opportunities.If we consider where the Queensland Office ofClean Energy believes that our renewableresources may come from by 2020, as shown inFigure 4, there will be significant investment inboth of the above technologies.An interesting observation is the extent of thedeployment of solar hot water (being a currentQueensland Government priority) which iselectricity displacement rather than generation,which adds weight to earlier conclusions inrelation to the surplus of REC’s in the early RETprogram.Geothermal, solar thermal and wind are expectedto add approximately 2,000 MW of generatingcapacity, with the majority of generation plant tobe located in areas currently not connected to thetransmission grid.Figure 3 - Queensland's Geothermal SitesSource: (Department of Mines and Energy, 2008)Figure 4 - Queensland's Clean Energy FutureSource: (Office Of Clean Energy, 2009b)It may therefore be more appropriate to look atpolicy measures that fund additional transmissionand distribution infrastructure to bring forward thedeployment of these smaller sites, than looking atpolicy measures that support the final generationoutput.4293

Australian Geothermal Energy Conference 2009SummaryCurrent policy measures would appear to beworking well for the geothermal sector, withfunding being made available for research,exploration and drilling. The deployment of otherrenewable technologies already commercialisedwill be driven by State subsidies and will keep theREC price relatively low in the early years due toanticipated deployment rates, stalling investmentin those marginally economic technologies. Basedupon industry forecasts, much of the plannedgeothermal generation plant will start to come onlinewhen the REC surplus has been expendedand there is short-fall with the price increasingaccordingly, resulting in greater ‘profit’opportunities for this sector.This paper has highlighted the need for furtherresearch looking at the effect that subsidisedtransmission and distribution infrastructure mayhave on the deployment rates of renewabletechnology. As other technologies, particularlywind and solar thermal also look at sitinggeneration plant further from the coastalpopulation bases, the need for a structured planto develop the necessary infrastructurerequirement of the national electricity market as awhole needs to be looked at in much greaterdetail.The renewable energy sector cannot moveforward without considerable support from alllevels of government, but what the sector mustdetermine what form that support should be.ReferencesAustralian Institute of Energy, 2004. Fact Sheet 9:Geothermal Energy.Department of Mines and Energy, 2008.Geothermal Land Released. QueenslandGovernment, Brisbane.Froome, C., 2009. Renewable Energy inAustralia: 20% by 2020 - Can this be achieved? ,Environmental Research Event, Noosa,Queensland.Grove-White, G., 2009. Renewable Energy - Howcan Queensland lead the way, CEDA Forum,Brisbane.Herd, D., 2009. National REC - Supply v Demand,in: Froome, C. (Ed.). People Planet Profit,Brisbane.McLennan Magasanik Associates, 2008. Installedcapacity and generation from geothermal sourcesby 2020. Australian Geothermal EnergyAssociation, South Melbourne.Office Of Clean Energy, 2009a. GeothermalExploration Tenders, in: Energy, D.o.M.a. (Ed.),Brisbane.Office Of Clean Energy, 2009b. Queensland'sClean Energy Future. Queensland Department ofMines and Energy, Brisbane.5294

Australian Geothermal Energy Conference 2009Levelised Unit Cost – A Calculation and Reporting methodologyAlan KnightsExecutive Director, Green Rock Energy Limited, PO Box 1177, West Perth, WA 6005Honorary Secretary, Australian Geothermal Energy Association, PO Box 1048, Flagstaff Hill, SA 5159aknights@greeenrock.com.auTo ensure there is no confusion, contradiction anda fair and meaningful comparison within thegeothermal and investment community in relationto the use of unit generation costs, the adoption ofa standardised methodology for cost calculationsand reporting among different electricitygenerators is a prerequisite. The AustralianGeothermal Energy Association, “AGEA”,proposes to use Levelised Cost as the unit costmeasure to be quoted when companies reportaverage unit generation costs. Levelised Cost isthe methodology used by the electricitygeneration industry and its use enables thecomparison of the generation cost of differentforms of electricity generation (such a coal, gas,wind, wave and geothermal) and of differentprojects using the same form of generation. Themethodology to be adopted by AGEA forcalculating and reporting average unit electricitygeneration costs when developing and/oroperating geothermal power generators has notbeen finalised. This paper describes one methodfor calculating and reporting Levelised Costs. Ithas been prepared to facilitate discussion andconsideration as AGEA moves to agreement on adesired methodology.Keywords: Unit generation costs, Levelised Cost,calculating unit electricity generation costs,geothermal.IntroductionUnit production costs are used for manypurposes, ranging from internal managementcosting through to project evaluation. Themethodology used in calculating the unit cost willdepend upon its use. The Australian GeothermalEnergy Association (“AGEA”) is seeking theadoption of a standardised methodology for thecalculation and reporting of unit electricitygeneration costs to ensure there is no confusion,contradiction and a fair and meaningfulcomparison can be made between alternativeinvestments by the geothermal and investmentcommunity.AGEA proposes the establishment Levelised Costas the unit cost measure to be quoted whencompanies report average unit generation costs.Levelised Cost is the methodology used by theelectricity generation industry and its use enablesthe comparison of the generation cost of differentforms of electricity generation (such a coal, gas,wind, wave and geothermal) and of differentprojects using the same form of generation.This paper describes a methodology forcalculating and reporting average unit electricitygeneration costs by companies developing and/oroperating geothermal power generators. Themethodology is currently open for commentbefore finalisation by AGEA.Calculation of Levelised CostThere are a number of ways of approaching thecalculation of unit production costs. Theelectricity industry uses Levelised Cost whichincorporates the investment in the plant and thefact that not one, but many units of electricity areproduced during the life of the project.The Levelised Cost is the time series of thecapital and operating expenditures divided by thenet power supplied, discounted to their presentvalues.The following sets out the main components ofthe Levelised Cost calculation methodology: Expenditures include all those required todeliver the net power supplied to the stationbusbar, where electricity is fed to the grid orend user. It does not however include thepotential additional costs to the electricitynetwork to cater for the impact of the powerplant on the existing network;The time series covers the life of the powerplant from evaluation through todecommissioning;Capital expenditures include all costs requiredfor the development, commissioning anddecommissioning of the geothermal powergenerator including the site preparation,evaluation, production and reinjection wells,the plant and machinery, administration andpersonnel buildings/accommodation andpower lines and associated costs to connectto the grid or end user.Operating expenditures include all operationand maintenance costs on the wells, powerplants and power lines including make-over oradditional drilling costs to extend the projectlife, plus permit and licence fees,administration, insurances and any royaltiespayable for the extraction of geothermalenergy; Capital and operating expenditures are toexclude income taxes, the benefits associatedwith the generation of renewable energy,1295

Australian Geothermal Energy Conference 2009including Renewable Energy Certificates butare to include any costs associated with thegeneration of greenhouse gases. The costsare to be in constant monetary terms;Net electricity generated and supplied to thegrid, or end user, takes into account the plantavailability and variability due to the plantoperating efficiency factors such as ambienttemperatures, the parasitic power required foroperating the well pumps and plant andmachinery and the impact of thermaldrawdown, if applicable, over the project life;The discount rate is the rate of return thatcould be earned on similar investments on apre-tax basis.The formulae to calculate the Levelised electricitygeneration Cost (LC), for each power plant, is thefollowing:ConclusionThis paper describes a methodology forcalculating and reporting average unit electricitygeneration costs by companies developing and/oroperating geothermal power generators. Themethodology is currently open for commentbefore finalisation by AGEA.Comments should be directed to the author ataknights@greenrock.com.auReferencesMcLennan Magasanik Associates: Installedcapacity and generation from geothermal sourcesby 2020. Report to Australian Geothermal EnergyAssociation, (August 2008).LC = ∑ t [(I t + M t ) (1 + r) -t ] / ∑ t [E t (1+r) -t ]Where:LC = Average lifetime Levelisedelectricity cost per MWhI t = Capital expenditures in year tM t = Operating and maintenanceexpenditures in year tE t = Net electricity generation in yeartr = Discount rate∑ t = The summation over the life ofthe power generator includingevaluation, construction,operation during the economiclifetime and decommissioning ofthe plant.Reporting of Levelised CostWhen reporting of average unit generation costs acompany should clearly state that the unit cost isa Levelised Cost and either $/MWh or c/kWh.The company reporting should be prepared todisclose, as a minimum, the following informationused in the calculation of the Levelised Cost: Total capital expenditure Average annual total operating andmaintenance expenditureAverage annual net electricity generationLife of the power generatorDiscount rate2296

Australian Geothermal Energy Conference 2009Skills Issues and Training in the Geothermal IndustryA New Zealand perspectiveJuliet Newson 1 and Jane Brotheridge 21 Dept of Engineering Science, University of Auckland, Private Bag 92019, Auckland, New Zealand2 NZ Geothermal Association, PO BOX 11-595, Manners St, Wellington 6142, New ZealandGeothermal electricity generation is expandingaround the globe with total global capacityexpected to rise to 11 GW by 2010. Manycountries are investing in research anddevelopment of EGS and low temperatureresources.In New Zealand, 135 MWe geothermal has beenadded to the grid since 2005, with another 155MWe under construction, with a further 120 MWeat the resource consent stage and over 500 MWeplanned or under review. Personnel levels in aprofessional capacity have grown from 350 in2005 to 450 today, with a total of over 600 peoplesolely involved in the geothermal industry basedin NZ. However, there are critical shortages oftrained personnel worldwide.The New Zealand Geothermal Association hasdeveloped a ‘Skills Action Plan’ to address someof these issues.MAKE: Grow professional and trade/technicalskills for new entrants to the industry;FIX: On-the-job up-skilling for those already inthe industry; BUY: Immigration – source skilled labour onthe world market.The aim of this plan is to present a way forward toincrease the level of participation of skilledpersonnel in the industry. It also has the aim ofraising the profile of this energy resource whichoften gets ignored in the bigger discussion onrenewable energy in New Zealand.The Geothermal Institute at University ofAuckland ran a very successful year-longGeothermal Diploma course from 1979 to 2002.This course has been reshaped and revitalisedand is now one-semester PGCert (Post-graduateCertificate), with additional short courses tailormadeto industry needs. From 2010 the Faculty ofEngineering will also offer a Masters Degreecourse in Energy, with a specialisation inGeothermal Energy.The framework already exists to design nonuniversitytrade and technical courses ingeothermal energy topics which can be part of anationally recognised qualification. School andcommunity level education is also required.Keywords: personnel shortages, skills action plan,specialised geothermal training, educationThe Global Geothermal IndustryTrends in the global geothermal industry over thelast several years reflect a strong upswing ininterest in renewable energy which is being drivenby two key factors – a growing recognition of thereality of global warming and the contribution thatfossil fuel generation with high CO 2 emissionsmakes to this problem, and the very high fuelcosts that had prevailed up to 2008. As a result ofthese factors, geothermal energy has become afavoured form of renewable power generation,being suitable for long term sustainable powerwith low CO 2 emissions, typically at a level of lessthan 20 % of that for fossil fuel generation.The New Zealand Geothermal Industry isexperiencing a period of growth which is expectedto continue for the coming 10 years. A number ofdevelopers have built up critical levels of skill andconfidence to be able to make geothermalinvestments as part of a broad portfolio of energyprojects. Additionally, the geothermal industry inAustralia is very buoyant with capital raising,surface exploration, exploration drilling and powerdevelopment planning actively undertaken by anumber of commercial entities.Traditional international markets of the Philippinesand Indonesia have recently undergonerestructuring of the national electricity supplynetworks and of associated state-ownedenterprises coupled with privatisation and assetsales. This has drawn in New Zealand consultants(and potential investors) into due diligence studieson behalf of multiple investors, and subsequentfeasibility studies. Consultants have also providedadvice on maintenance regimes for existingfacilities. Major projects may follow.Other developments that have required and willrequire New Zealand personnel include the Lihirproject in Papua New Guinea, the San Jacintoproject in Nicaragua, and Olkaria in Kenya. Thereare frequent calls on geothermal experience fordue diligence and feasibility studies through partsof South East Asia and in Europe, and morerecently through the Caribbean. Djibouti is one ofthe latest places for prefeasibility studies. There isgrowing interest in Central and South Americandevelopment, including a recent strong drive bythe Chilean government to encouragedevelopment in Chile.1297

Until now there have been almost no inroads intothe US market but that could be about to change.The WGC 2005 country update for the USAshowed there were approximately 725professional personnel involved with geothermalactivities in the US in 2004 compared with 440similarly qualified geothermal professionals inNew Zealand currently.The US DOE has recently announced aninvestment of up to US$350 million targeted atgeothermal demonstration projects; EGS researchand development; innovative explorationtechniques; and a National Geothermal DataSystem, Resource Assessment and ClassificationSystem. One of the expected program outcomesinclude demonstrating the ability to create an EGSreservoir capable of producing 5MW by 2015.Close to US$155 billion was invested in 2008 inrenewable energy companies and projectsworldwide, not including large hydro. Of this,$13.5 billion of new private investment went intocompanies developing or scaling-up newtechnologies alongside $117 billion of investmentin renewable energy projects from geothermaland wind to solar and biofuels. The 2008investment is more than a four-fold increase since2004 according to Global Trends in SustainableEnergy Investment 2009, prepared for the UNEPSustainable Energy Finance Initiative.Geothermal PersonnelThroughout the energy industry worldwide there isa shortage of skilled personnel, an ageingworkforce and a reduction in graduates in relevantdisciplines.In 2005 a skills survey (NZGA 2005) of thegeothermal industry reported a total 350personnel engaged in the NZ geothermal industryas professional engineers, scientists andtechnically qualified plant operators. Four yearson, and with an additional 135 MWe added to thegrid from geothermal, there are almost 450professionals plus over 150 technical and nontechnicalstaff involved solely in the geothermalindustry (NZGA 2009). Several geothermalcompanies in NZ have found a need to attractskilled professionals internationally and thereforemust compete with others in the internationenergy sector.Future development in NZ alone has 155 MWeunder construction, with 120 MWe with resourceconsents. Additional to these, over 500 MW isplanned and under review. In the past 20 yearsmuch of the work NZ consultants (this includeslarge and small companies, individuals, CrownResearch Institutes (CRIs) and universities) havebeen involved with is offshore. The NZ basedwork alone was not enough to sustain them. Yetwith the growth of development in NZ in the lastseveral years, and the growth in personnel, theAustralian Geothermal Energy Conference 2009geothermal industry in NZ is still facing shortages.This has been critical in the drilling sector.The expertise of many NZ geothermal consultantsis being called upon by the recent ‘birth’ of thegeothermal industry in Australia where thisindustry is expected to provide between 1000 and2000 MWe by 2020 (MMA 2008).The MMA 2008 report noted that most of thepersonnel involved in the emerging geothermalindustry in Australia have a strong background inminerals exploration and development, but theyhave less experience in generating and sellingelectricity, with only a few having geothermaldevelopment experience. It is particularly criticalin areas such as drilling and reservoirengineering.With the expansion and investment internationallyin EGS, these areas will be in even higherdemand.Skills Action PlanTo address current and ongoing skill shortages askills action plan is proposed. The Plan wasdeveloped by the New Zealand GeothermalAssociation (NZGA) on behalf of the GeothermalIndustry in NZ. It is based on the ‘Make, Fix, Buy’model developed by the Department of Labourand aligns with the New Zealand Skills Strategy.MAKE Grow professional and trade/technicalskills for new entrants to the industryFIX On-the-job up-skilling for those already inthe industry. BUY Immigration – source skilled labour onthe world marketThe aim of this plan is to present a way forward inincreasing the level of participation of skilledpersonnel in the industry. It is also has the aim inraising the profile of this energy resource whichoften gets ignored in the bigger discussion onrenewable energy in New Zealand. See Table 1 atend of paper.‘MAKE’Education is central to the ‘MAKE’ section of theaction plan. This involves: raising awareness ofgeothermal energy at a community level; schoolprograms in scientific and cultural aspects ofgeothermal energy use; promotion of renewableenergy studies at University; and as a desirablecareer path.Development of a package for use in the schoolscience curriculum is recommended for schools.Environmental awareness and sustainabledevelopment is now part of the school curriculum,and direct use of geothermal energy would fit wellinto this particularly at primary school level. It is astraight forward concept to explain and illustratedwith a multitude of uses.2298

The geothermal industry needs a presence atcommunity events raising awareness, and apackage for static displays suitable, for instance,for libraries and foyers of community buildings.The geothermal industry needs to work with theIndustry Trainings Organisations to develop tradeand technical courses and qualifications to suitindustry requirements. This may involve manyinterested parties, from Technical Institutes andeven Universities for higher level technical skills,to in-house training for school leavers directlyentering the workforce.High level jobs involving tertiary education suchas engineers and geoscientists are critical tocurrent and future geothermal exploration anddevelopment. In the 2005 report on skillscapability in the geothermal industry, the mostcommon complaint from industry was the lack oftraining programs available to maintain asatisfactory inflow of younger staff or for furtherdeveloping experienced staff. It was recommendthat the former Geothermal Institute within theUniversity of Auckland (UoA) be re-establishedbut with tailored training programs to the NZgeothermal operator sector. In particular, focus onresource monitoring and management, steamfield and power plant operational issues wassought.For the long term it is suggested companies mustconsider actively recruiting graduates andmentoring/training them over a 2-4 year period tobuild up necessary experience. However, this isdependent on an increase in school leaversentering these disciplines at university. Programspromoting renewable energy and the greeneconomy as viable career paths need to betargeted at senior school leavers.‘FIX’On-the-job up-skilling is also vital. The benefits ofon-the-job training include higher standards ofsafety, higher productivity, less down time, andemployees feeling valued. Technologicaladvancements require on-going training as wellas the need to extend /expand the knowledge ofworkers moving to new areas of operation and upskilling those moving to supervisory ormanagement roles. Employees report that theyvalue training as long as it is delivered bysomeone experienced and knowledgeable whocan transfer that knowledge in a way that learnerscan relate to, and is timely and that they have theopportunity to learn in group situations.‘BUY’The energy industry as a whole needs to addressthe remuneration issue urgently and considermoves towards pay parity especially with Australiawhich is New Zealand’s major competitor forskilled resources.Australian Geothermal Energy Conference 2009As a proportion of overall demand for skilledemployees, the numbers are smaller and in theshort term can be recruited in the global market.Companies will however have to prepare for alonger lead-in time to source experiencedpersonnel because of the scarcity worldwide or toseek recruits from both traditional and nontraditionalsources.A major consideration for recruiting people fromoverseas is remuneration. Skills scarcity coupledwith escalating demand has had the effect ofadding premiums to wages and salaries for thoseemployed within the sector. The general wagepressure is however wider than the NZ market,evidenced as a continued creep towardsAustralasian rates of pay for some skills and inlimited circumstances, global pay rates forworkers prepared to work in the more lucrativeinternational day-worker market.Current Status of Training in NZBecause education comprises a significantsection of the skills action plan, this section of thepaper discusses the current state of geothermaltraining in New Zealand.In response to perceived demand, and inanticipation of future demand, a new onesemester post graduate course in geothermalscience and engineering is now taught annually atthe University of Auckland. For those who cannotafford the time away from work, specialistprofessional development short courses areoffered.The framework exists for training providers todesign trade and technical courses foraccreditation to a nationally accepted standard.At least one geothermal company has begun towork with Industry Training Organisations (ITO’s)to enable workers to obtain a drilling qualification.However, more needs to be done at a school andcommunity level to promote geothermal energy.Postgraduate Geothermal courses in NZThe Geothermal Institute at University ofAuckland ran a very successful year-longGeothermal Diploma course from 1979 to 2002(Hochstein, 2005). Unfortunately support from theNew Zealand Government for the Diploma coursewas withdrawn at the end of 2002. This wasdespite the growing concern over global warmingand the required development of clean energysources, concern among professionals over theloss of momentum in geothermal research andtraining in New Zealand, and a potential shortageof geothermal professionals (NZGA, 2005).In 2006 Professor Mike O’Sullivan, leader of theGeothermal Reservoir Modelling Group in theDepartment of Engineering Science, andAssociate Professor Stuart Simmons, Director ofthe Geothermal Institute, assembled a group of3299

geothermalists to teach a one-semester PostGraduate Certificate in Geothermal EnergyTechnology (PGCert).The philosophy was to provide through thePGCert the backbone for a comprehensivegeothermal training program involving universitylevel papers, short lecture courses forprofessionals, graduate research degree coursesand academic research programs. With theexception of Assoc Prof Stuart Simmons, thepeople initially involved in organising the coursecame from the Geothermal Reservoir ModellingGroup in the Department of Engineering Science.At the time when the decision to run the coursewas made the University was in the process ofdeveloping a cross-faculty research group calledthe Institute of Earth Sciences and Engineering(IESE). Geothermal energy was considered to bean important part of the research portfolio.However because of its research-only statuswithin the University of Auckland the IESE cannothost University degree programmes and hencethe PGCert course is hosted by the Department ofEngineering Science in the Faculty ofEngineering.Support for the CourseAgainst the background of a small initial numberof enrolments and no special financial supportfrom government bodies, running the courserelied heavily on the goodwill of:the Department of Engineering Science whichprovided lecture rooms, teaching support, andcomputer facilities;the retired staff of the old Geothermal Institute(Manfred Hochstein, Pat Browne, and ArnoldWatson); andthe New Zealand geothermal industry, whoresponded positively and contributed lectures,site visits, and scholarships for the course.A feature of the inherited good will from theGeothermal Institute days has been a closeconnection between industry and geothermalteaching. There has been very strong industrysupport for the PGCert in 2007 and 2008.Contact Energy Ltd has supported the PGCertwith six scholarships over the two years, with atotal value of NZ$120,000, and CenturyResources (now MB Century) has provided twoscholarships with a total value of NZ$40,000.Sinclair Knight Merz (SKM) have donatedfourteen hours of lectures each year, and GNSScience Wairakei have donated 12 hours oflectures and field tuition. In addition, ContactEnergy, MB Century, Tuaropaki Power, and GNSScience, have given access to borefields, powerstations, and geothermal areas, with staffaccompanying groups of students for informaltours, training in taking field measurements,formal lectures, and student project supervision.Australian Geothermal Energy Conference 2009Chevron Geothermal (Indonesia) providedgenerous funding for three aspects of the trainingprogram:the development of one-week short-courseson geothermal geoscience and geothermalengineering;the development of course material for thePGCert; and archiving of course material from theGeothermal Diploma.The success of the PGCert in 2007 and 2008 andthe strong support from the geothermal industrywas sufficient to convince the University ofAuckland to continue support geothermal trainingfor at least the next three years.TeachingGeothermal teaching at the University of Aucklandinvolves four types of courses, all directedtowards post graduate and professional training:the one-semester Post Graduate Certificate inGeothermal Energy Technology;professional short courses taught in NewZealand (one-week or four-weeks). Theseare planned to be part of staff professionaldevelopment schemes;research studies for ME, MSc or PhDdegrees; and professional short courses taught in othercountries (one-week).The University of Auckland is currently planning aone-year taught Masters of Energy degree, with atarget start date of 2011. It will include geothermalenergy as an option but will also allow for otherspecialisations such as wind, solar and bio-fuels.Courses from the PGCert will be available for thisdegree.Post-Graduate Certificate in Geothermal EnergyTechnologyThis one semester course includes lectures andassignments, field visits with data collection andinterpretation, and a short research project. Theminimum entry qualification is a Bachelorsdegree, preferably in Science or Engineering, andthe University of Auckland also has strict Englishlanguage requirements for post graduate courses.Both geothermal geoscience and geothermalengineering topics are covered. All students arerequired to complete the first two lecture courses(papers) which are an introduction to ‘GeothermalResources and their use’, and ‘GeothermalEnergy Technology’. The class then splits:students must chose between a ‘GeothermalExploration’ paper, and a ‘GeothermalEngineering’ paper, where specialist geothermaltopics are covered in more depth. The final five4300

weeks of the course is devoted to a shortresearch project resulting in a ~40 page researchreport. During the course there are two six-daylong field trips to the Taupo Volcanic Zone, whichinvolve lectures from geothermal experts andvisits to power station, natural geothermalfeatures, geological features, and geothermalenergy direct use sites.Professional Short Courses and PGCert PapersOne of the problems of specialist training coursesfor professionals is that many workers cannot take5 months leave to attend a course such as thePGCert. In view of the lack of training coursesworldwide in the last decade, causing an acuteshortage of trained geothermal people, it is verydifficult for those currently working in thegeothermal industry to take training leave forlonger than a few weeks. Our response to thisproblem has been to allow people to attendselected parts of the PGCert course as‘professional short courses’. These students donot attain a University qualification, but are stillable to participate in modules of the course.In 2008 the uptake for these courses was high,with an extra eighteen students attending sectionsof the course. Thus the number of studentsattending part of the PGCert course increasedfrom one in 2007 to 18 in 2008.Geothermal short courses are run according todemand in both in New Zealand and overseas.Some of these short courses were commissionedby companies as part of their staff developmentprograms. For instance, in October 2008 stafffrom the IESE and the Department of EngineeringScience spent two weeks in Indonesia deliveringtwo short courses for Chevron Geothermal – oneweek each on Geothermal Geoscience andGeothermal Engineering attended by a total of 31students. Similar courses were delivered in April2009 in Auckland, and more courses abroad arebeing planned for late 2009.Trade Qualifications and CertificationTrade/Technical skills are catered for in broaddisciplines applicable to the energy industry eg.electricians, fitters etc, but not specific to thegeothermal industry. However, the numbers ofyoung people choosing to enter the trades is lessthan desired.Industry Training Organisations (ITOs) have themandate of the industry that they represent todevelop training standards for their industry and toregister these on the National QualificationsFramework. ITOs are funded by the TertiaryEducation Commission to offer training subsidiesfor their industry. While not directly able to engagein training the ITOs determine which providers willbe accredited to award qualifications for theindustry and who will be recognised as anaccredited assessor.Australian Geothermal Energy Conference 2009When necessary ITOs will respond accordingly ifthe geothermal industry identifies other needs orwill adapt qualifications to meet any specificrequirements. MB Century Ltd has been in talkswith Extractives ITO EXITO to enable their inhousetraining be accredited by New ZealandQualifications Authority NZQA. This newcertificate will take about 6 months for a trainee topass through the various steps in order to obtainthe required credits.ConclusionThe New Zealand geothermal industry has beenexperiencing a shortage of trade, technical, andprofessional staff. The New Zealand GeothermalAssociation has designed an action plan based ona model developed by the Department of Labourfor the New Zealand oil and gas industry, whichinvolves educating people for working in theindustry (MAKE), further training for those alreadyinvolved (FIX), and recruiting from abroad (BUY).The ‘make’ and ‘fix’ components of the planprimarily involve education. Tertiary levelgeothermal training courses have been runannually at the University of Auckland since 2007,comprising the Post Graduate Certificate inGeothermal Energy Technology, and professionaldevelopment courses. From 2010 the Faculty ofEngineering will also offer a Masters degreecourse in Energy, with a specialisation ingeothermal energy.The framework already exists to design nonuniversitytrade and technical courses ingeothermal energy topics which can be part of anationally recognised qualification. One companyis currently developing a drilling qualification butthere is potential for further course developmentin this area. School and community leveleducation is also required.Implementation of aspects of the Action Plan iscurrently under discussion with the NZGA andvarious Stakeholders.ReferencesAkin, J., 2008, Workforce Management. Power,vol 152, No. 4, p 74-78.NZGA Report prepared by SKM 2005, Review ofCurrent and Future Personnel CapabilityRequirements of the NZ Geothermal IndustryNZGA Report prepared by Jane Brotheridge2009, NZ Geothermal Industry Skills Report andAction Plan.McLennan Magasanik Associates Pty Ltd., Aug2008 Installed capacity and generation fromgeothermal sources by 2020.Hochstein M.P. 2005. 25 years GeothermalInstitute, Proceedings, World GeothermalCongress 2005, Antalya, Turkey.5301

Massachusetts Institute of Technology (MIT),2006. The Future of Geothermal Energy. Impactof Enhanced Geothermal Systems (EGS) on theUnited States in the 21st Century. Anassessment by an MIT-led interdisciplinary panel,prepared under Idaho National LaboratorySubcontract No 63 00019 for the US Departmentof EnergyAustralian Geothermal Energy Conference 20096302

Australian Geothermal Energy Conference 2009MAKE General community education and primary to secondary educational level(NERI findings in italics)WhoOutput (note – underlined is output already known to occur orplanned for near future)There appears to be a shortfall in numbers of graduates in geothermal specializations,planning, policy analysis, mining specializations, corrosion sciences, surveying, physics,geology, ICT, human resources, law, resource management and project managementneeded to meet energy industry demand (NERI).A need to ensure that energy education in tertiary institutions includes sufficient focus onissue of strategic national importance (NERI).A need for better understanding of the stimuli external to universities that influence students’selection of courses, degree programmes and employment options (NERI).This appears to be part of a largerproblem that extends over manyengineering and science basedindustries. This requires long-termaction from a range of educational andgovernment organisations. TheGeothermal industry should remainalert to the chance for input intorelevant decisions.Maintain a network of interested people who are in contact withregards this type of promotion – ie PR people in companies plusinterested people at research and teaching organisations plusgovernment departments/agencies.Market to school and tertiary sectors to promote employment opportunities in the sectorCurrently GNS Wairakei and KaikoheSchool.IndustryAssess and collate all existing marketing materialWork alongside other stakeholders to develop relevant material.Some development underway with GNS Wairakei & Kaikohe school.Development of a package for use in school science curriculum - approach schools to assessinterest. Funding needs to sought.University or researchcompany/governmentdepartment/agency.Package developed.Target one school then extend to three schools in 2 years time As above. Identify a pilot school for package. Roll to more schools in futureMAKE Tertiary education (NERI findings in italics) Who OutputIncrease numbers participating in university programmes relevant to the sector (note thatspecialisation would occur in 3rd or 4th year of Bachelor Degree).Industry/NZGA/UniversitiesList of contact people from each University/faculty, who organisecareers presentations.Recruit graduates for the geothermal industry.Company participation in career/recruitment days.To meet current energy industry demand, an increase is needed in the number of universitygraduates from engineering, commerce, science and geography entering employment in theCareer evening presentations hosting the Geothermal Industry as a7303

Australian Geothermal Energy Conference 2009energy sector (NERI).whole.Geothermal research promoted for Postgraduate topics.Development of specific qualifications, specialist papers and projects Universities/Industry/NZGA Courses at the University of Auckland since 2007Build internal expertise by collaborating/developing relationships eg. universities andutilities/developers.A desire by energy stakeholders to have more contact with universities (NERI)Industry/Universities/NZGADevelop a relationship that involves: training using real-world scenarios encouraging students to engage with the industry Student projects Course support Fund researchSupport increased numbers of MSc and PhD projects Industry/Universities Currently Masters and PhD research in geothermal topics at severalinstitutions. Industry is already supportive, can always provide moreresearch topics and funding for projects. ‘Real world’ topics canjustify paying a student to research them.Provide work experience/mentor graduates to build industry experience.IndustryInternship programs.University graduates’ relevant work experience does not appear to be sufficient to meet thework experience demanded by employers in the energy industry (NERI)Already some in the industry do this, needs more coordination withstudents and industryA need for understanding of iwi perspectives on tertiary level energy education (NERI). TPK/Universities Input to Māori Geothermal Seminars, liaise with Māori groups onCampus, for instance UoA SPIES (South Pacific Island EngineeringStudents), liaise with other University groups researching widerMāori Energy Development.There appears to be a need for cross-disciplinary university education relating to energy Universities Currently development of a Masters in Energy course at theUniversity of Auckland starting 2010. Organised in the Faculty ofEngineering but will have the potential for cross-disciplinary study.8304

Australian Geothermal Energy Conference 2009MAKE Trade/Technical Qualifications (NERI findings in italics) Who OutputTrade level roles: Disseminate information to contractors and the community including iwi, toimprove understanding of the current industry training system and how it compares with theformer apprenticeship system.A need for better information about the supply of non-university graduates for employment insuch roles as field technicians and maintenance engineers in the energy industry (NERI).ITO’s/NZGALiaise with the engineering and electrical sectors for joint marketingof the industry as a career optionDevelop a communication strategyDevelop introductory pre-qualification packages for use in secondary schools. ITO’s/NZGA Liaise with school careers advisors, ESITO etc. Establishrelationship between these groups and industry to see what theneeds are, and where the gaps areManage the relationships between schools and industry for work experience through theGateway programmeIndustryAssess what marketing/promotional work needs to be conducted toincrease industry participation in gateway. Work alongside schoolsto identify potential students.Increase the number of apprentices/industry trainees Industry Liaise with industry to encourage the uptake of more traineesFIX General culture of ongoing education Who OutputEmployers in the industry need to ensure ongoing trainingThis is an ongoing obligation for allemployers and for the self-employedRegular widespread attendance at seminars and workshopsEmployees should be continuously adding to their skill baseProvision of suitable courses and topical seminars NZGA, universities, technicalinstitutesRegular targeted seminars and workshops e.g. one day overviewseminars useful for managers and non-technical peopleAssist IESE in developing a business plan for their courses as the basis for a NewZealand/regional geothermal training facilityIndustry, NZGA with someGovernment fundingActive and expanding training programme including input fromexperienced industry professionalsEnsure employees have a minimum of paid hours of training per year Industry Delivery of training9305

Australian Geothermal Energy Conference 2009BUY Preparedness for Expatriate Workers Who OutputIndividual employers should recruit internationally Industry Industry members are currently recruiting internationallyWhere skill shortages are identified by employers, make submissions on behalf of industry toImmigration NZ’s biannual shortage listsNZGA, IndustryShortage lists will address broad gaps, especially intradesUtilising an independent remuneration consultant, promote a collaborative approach tobenchmarking of NZ salaries. Include an assessment of the extent to which NZ geothermalcompensation and benefits are aligned internally and regionally, and with the O & G sector,which are all competitors for skilled NZ geothermal workersIndustry and Government funding of anindependent consultant managed by NZGAReport on bench marked salaries, with repeat reportsshowing a move toward competitive valuesUse Ministerial trade shows and trade fairs and international conferences to publicise theopportunities in the NZ geothermal industryIndustry/NZGA working with GovernmentNZ presence at wide range of events with boothshighlighting opportunitiesTable 1: Geothermal Industry Skills Action Plan10306

Australian Geothermal Energy Conference 2009Power loss evaluations for long distance transmission linesMai Huong Nguyen, Tapan Kumar Saha *Queensland Geothermal Energy Centre of ExcellenceThe University of Queensland, St Lucia, Brisbane - QLD 4072 Australia* Corresponding author: saha@itee.uq.edu.auLong distance power transfer is a major problemfor renewable energy sources located far awayfrom the major load centres. This issue inparticular is more pronounced for the prospectivegeothermal power plants in Australia. Thisproblem involves analysing the cost of investmentand operation and types of interconnection usedfor transmitting the bulk power from a remote areato a major load centre. As the level of powertransfer and the transmission distance increases,the power loss of the transmission line tends toincrease. For these reasons, it is essential tocarefully analyse the impact of interconnection onthe total loss of a power system, subject tochanges in operating conditions and varyingtransmission distances. The typical approach forvery long transmission lines is to use high voltage(HV) based on either DC or AC. In theory, theHVAC line has higher resistance and reactance,therefore, it has a high loss in the line comparedto the HVDC option. On the other hand, theHVDC scheme has a significant proportion of lossin its converter/inverter stations. Up to a certaindistance called the “breakeven distance”, HVAC issuperior in terms of the total cost, loss and thestability margin. Above this distance, HVDC is themost favourable option. The main task in thispaper is determining this “breakeven distance” fora particular electricity system based on staticpower flow analysis. In this paper we apply a fourmachine two area test system implemented in thePSS/E software environment to compare theimpact of high voltage AC and conventional highvoltage DC on total system losses. Furthermethodology will be developed to make thisoutcome more generalised for any electricitynetwork..Keywords: interconnection, HVDC, HVAC, lossevaluation.Long distance transmission linesThe electricity systems from different areas arebeing connected by long transmission lines toachieve an economical benefit and to improvereliability. Such interconnections can connectregions in a country, from a country to anothercountry or cover very large continental areas.They can also be used to transfer the power fromremote renewable sources, such as off-shorewind farms, solar thermal systems or geothermalpower plants in desert areas, etc. to the loadcentre. The advantages of long interconnectionsare the flexibility in deciding locations as well as inbuilding larger and more economical powerplants; creating the possibility of loss reduction byoptimised system operation [1]. In the expansionof the electricity market all over the world, highvoltage transmission lines over a long distancemay offer considerable advantages in technical,economical and environmental aspects. In recentyears, power industries all over the worldsupported many interconnections to enable theexchange of power among areas and transfercheaper electricity over long distance to thecustomers.HVAC and HVDC are the two interconnectionschemes available for long transmission systems.There have been some publications on technicaland economical evaluations for several types ofinterconnections using HVAC or HVDCtechnologies.HVAC has been found to be the better solution fora distance less than the “breakeven distance”,which can vary from 400km to 500km, betweentwo synchronous regions [1-3]. However, for longtransmission lines, HVAC must be facilitated byFlexible AC Transmission System (FACTS)devices for reactive power compensation.Longer than the breakeven distance, HVDCbecomes more preferable either with an overheadtransmission line or an underground cable.Besides, HVDC is also suitable for the submarinecable, interconnections between AC systems ofdifferent or incompatible frequencies and forremote renewable energy resource connection.Paper [4, 5] compared the total system losses dueto the impact of HVAC, Line-CommutatedConverter (LCC) HVDC and Voltage SourceConverter (VSC) based HVDC connected to alarge offshore wind farm (from 100 to 1000 MW)with varying distances up to 200km. Paper [4]concluded that the HVAC solution is superior fordistances up to 70km. LCC HVDC is preferred interms of reduced system losses above thisdistance. The “breakeven distance” for VSCHVDC in a loss point of view is around 200km.According to their results, the combination ofdifferent transmission systems never improves thetotal loss in the system. Paper [5] indicated thatthe HVDC solution is more expensive than theHVAC option with 100MW, 200MW and 500MWwind farms at the connection a distance of 60kmdue to higher investment cost and higher powerloss. However, the HVDC option appears to becheaper than the HVAC option while connected toa 100MW wind farm with a distance greater than90km.1307

Australian Geothermal Energy Conference 2009Nevertheless, these conclusions were based onthe characteristics of HVAC and HVDC lines andon the experimental measurements data. The lossevaluation was carried within the interconnection,not in the whole system. Up to now, very fewtechnical reports are available to compare theimpacts of HVDC and HVAC on large powersystem performance. This paper will focus on theimplementation of HVDC and HVAC options as along transmission line for interconnecting between2 large systems.This paper is organised as follows: the first part ofthis paper introduces the load flow analysis for apower system using HVDC interconnections. Thesecond part summarises loss evaluation andcompares HVDC versus HVAC alternatives. Theimpacts of transmission length, number ofinterconnections, power transfer level and thesending end demand on the “breakeven distance”are also presented in this section.HVDC analytical modelFig. 1 Single diagram of a conventional HVDC link [1, 6].The single line diagram of a HVDC system isdepicted in Fig. 1. The steady state behavior of aAC-DC power system has been described indetails by Arrilaga et.al [6]. The state variables fora HVDC system are: [x] = [V d , I d , a, cos, ] Twhere V d and I d are the direct voltage and current, and are the firing angle and the terminalvoltage angle, respectively. For the inverter side, will be replaced by , which is called theextinction angle.The index r and i represent the parameters at therectifier (converter) and inverter side, respectively.In the PSSE software [7], the relationshipsbetween AC and DC voltages and currents at therectifier side are expressed as:AC-DC voltage:3 2Vdr NrarVtermrcos(1)r 3 23 N rarVtermrcos IdXcr 2RcrId 6NrAC-DC current: Isr I(2)dwhere R cr and X cr are commutation resistance andreactance, a r is the transformer turn ratio, N r is thenumber of bridges connected in series in arectifier station.The DC reactive and active power at the rectifierterminal is determined as follows:Q ( DC) V I a sinPtermrtermrtermrsrr6Nr VtermrIdarsin(3)r( DC) V I a costermrsrrcosrr6Nr VtermrIda(4)r rIn this paper, the commutating resistance andtransformer resistance are neglected, resulting inno active power loss in converter stations.Therefore, the DC active power at the rectifierterminal in equation (4) can be calculated as:P termr (DC) = V dr I dThe equations (1-4) can be applied to calculatethe DC current, voltage and power at the inverterside, with cos and index r replaced by cos andindex i, respectively.The Jacobian matrix for load flow calculation ofthe HVDC system is determined by solving thefollowing system of equations [1, 6]:R ( x,V term) 0 (5)3 2Where: R( 1) V d kaVtermcos3 23R( 2) Vd kaVtermcos IdXcR(3) = f(V d ,I d )R(4) = control equationThe relationship between V d and I d , f(V d ,I d ), in thispaper is: V di = V dr – I d R d (6)where, V dr , V di is the dc voltage at the rectifier andinverter side respectively. R d is the resistance ofDC line.The DC load flow algorithm based on the FastDecoupled Power Flow method [6], which is usedto solve the load flow problem with HVDC isbriefly summarised as follows:P [ B'][] (7)V Q V V Q B”term BB ii AA”VVtermterm RBB” A xWhere:1[ AA"]VtermQ( DC)xterm2308

Australian Geothermal Energy Conference 2009 R[ BB "] V term 1 Qterm(AC)Qterm(DC)[ BB ii] Vterm VtermVtermR[ A] xB’’ and B’’ are susceptance matrix of AC systemLoss evaluationThe test system used in this paper is a 2-areasystem shown in Fig. 2, which comprises of 4generators and 2 large loads [8]. The two areasare connected to each other by twointerconnection lines. In the original system, theinterconnections are two 220km, 230 kV HVAClines in parallel. The line parameters are:R = 0.0529 (Ohms/km)X = 0.529 (Ohms/km)B = 33.1 x 10 -6 (S/km)Fig. 2 System diagram [8]The active and reactive power at system busesare presented in Table 1.BusVM(pu)Vbase(kV)PG(MW)QG(MVAr)PL(MW)QL(MVAr)1 1.03 22 700 0 0 02 1.01 22 700 0 0 03 1.03 22 700 0 0 04 1.01 22 700 0 0 07 1.00 230 0 200 967 1009 1.00 230 0 350 1767 100Table 1. System data bus, including voltage magnitude (VM),base voltage (Vbase), active and reactive power generated(PG, QG) and consumed (PL, QL) at all buses in the systemWe tested the original system with HVACinterconnections replaced by HVDCinterconnections. The load flow results for themodified system are compared to that of theoriginal system. The line resistance for the HVDCsystem is chosen to be the same as that of theHVAC system. In the HVAC case, bus 3 is theslack bus for the whole system; in HVDCinterconnection case, bus 1 is the slack bus forarea 1 and bus 3 is the slack bus for area 2.The HVDC rated voltage is 230kV, the data ofwhich is taken from [3]. The rectifier and invertercommutating reactance are 0.07 and 0.055 pu,based on a rated power of 890MW and a ratedvoltage of 230kV. The tap ratio at the convertertransformer is maintained at 1.0 pu. The inverteris operated in constant extinction angle mode with=22 0 . The maximum and minimum firing angle atthe rectifier side is 12 0 and 8 0 , respectively. Table2 summarises load flow results obtained fromusing PSSE with HVAC and HVDCinterconnection systems.BusHVAC HVDC (constant )VM (pu) Ang. (deg) VM (pu) Ang. (deg)1 1.03 20.98 1.03 24.792 1.01 11.22 1.01 14.93 1.03 -6.8 1.03 -6.84 1.01 -16.93 1.01 -16.825 1.0066 14.51 1.0008 18.276 0.9785 4.43 0.9645 8.017 0.9618 -3.98 0.9367 -0.689 0.9751 -31.33 0.9604 -31.3810 0.987 -22.98 0.9793 -22.9211 1.0114 -12.74 1.0086 -12.7Table 2. Voltage profile of the system, including voltagemagnitude and voltage angle of all buses after solving loadflowThe active power transfer from bus 7 to bus 9 waskept at 400 MW, resulting in 200MW active powertransferred in each line. The load flow results areshown in Table 3 below.HVAC HVDC (constant )P (MW) Q (MVAr) P (MW) Q (MVAr)Gen. 1 700 184.05 635.78 180.19Gen. 2 700 231.94 700 258.28Gen. 3 718.74 164.93 772.30 202.10Gen. 4 700 191.54 700 255.79Total 2818.74 772.46 2808.07 896.36L7 967 100 967 100L9 1767 100 1767 100Loss 84.74 572.46 74.07 696.36Table 3. Power flow data, including active and reactive powergenerated at generator buses and consumed at load buses.See text below for loss calculationTable 3 gives an initial comparison of the twointerconnection options: HVDC and HVAC, with3309

Australian Geothermal Energy Conference 2009the same active power transfer level. Both activeand reactive power losses are calculated bysubtracting the total active/reactive powerconsumed at the loads from the total generatedactive/reactive power. The active power loss isdirectly related to operating cost. The reactivepower loss represents the additional reactivepower the generators have to provide to the gridfor maintaining the system voltage to a desiredlevel. Reactive power generation is an importantancillary service in an electricity power market,and thus, also relates closely to the operatingcost. As can be seen in Table 3, the active powerloss in the HVDC system is smaller than that ofthe HVAC system. However, the HVDC systemrequires more reactive power than the HVACsystem. In the following sections, active/reactivepower loss of the HVDC and HVAC systems arecompared at different power transfer levels andtransmission lengths.Impact of distance on system lossThe length of both interconnections is varied from200 km to 350 km. The HVDC is operated in thepower control mode. The power transferred fromthe rectifier station (bus 7) to the inverter station(bus 9) is kept equal to the power transferred inthe HVAC case. The voltage magnitude and angleof bus 1 in the HVDC system is maintained equalto that in the corresponding HVAC case. Theresult is shown in Fig. 3.The reactive power loss in the HVDC system isslightly decreased with the increase in the lengthof the interconnection line, since the DC line doesnot consume reactive power. Moreover, in theHVDC scheme, the inverter is operated inconstant mode, which keeps voltage at theinverter bus constant at 0.9604 pu (bus 9). As aresult, when the transmission length is increased,the bus voltage at the rectifier bus will beincreased in order to maintain the bus voltage atthe inverter bus due to the relationship in equation(6). The voltage profile of the whole system,therefore, will be improved slightly resulting inlower reactive power loss.When the line length is increased to 350km, tokeep the power transferred on the HVDC lineequal to that on the HVAC case, the HVDC needsto be operated in constant extinction angle mode=23 0 in order to increase the dc voltage (voltageat bus 9 is kept at 0.9581 pu). Therefore, we cansee a slight increase in reactive loss of the HVDCline. When the length goes up to 400km, theextinction angle was kept at 23 0 , thus the reactivepower loss in the HVDC case continues todecrease slightly and becomes smaller than thatin the HVAC case. Therefore, from both activepower and reactive power loss points of view, theHVDC would be superior to HVAC after adistance of 360km.Impact of power transferred in transmissionline on the “breakeven distance”The power transfer level is gradually increasedfrom 150MW to 300MW per line. This is done byvarying the load at the sending end (bus 7), from1067MW to 767MW. Load flows are calculated forboth AC and DC systems at each power transferlevel. The results are presented in Fig. 4.Fig. 3 Total system losses relating to transmission lengthIt can be seen from Fig. 3 that active and reactivepower losses in the HVAC case steadily raise withthe increase of the interconnection length. This isto be expected, as active/reactive loss on theinterconnection line is an important part of thetotal AC system active/reactive loss. On the otherhand, active/reactive loss in the HVDC systemdepends mainly on the losses in converterstations. The active power loss in the HVDCsystem is thus smaller than that in the HVACsystem. Besides, the active power loss in theHVDC case does not increase as steeply as doesthe active power loss in the AC interconnectioncase when the transmission length increases. Thereason is that the voltage profile decreasessignificantly for the HVAC case while the voltageprofile of the HVDC system is slightly improved asthe length of the line increases.Fig. 4 Total system losses relating to power transferred in theinterconnectionThe loss in the HVAC system increasessignificantly as the active power transfer isincreased. On the other hand, the reactive powerloss in the HVDC system remains relativelyunchanged (or even slightly decreases) as thepower transfer is increased. In fact the slightreduction of reactive power loss does not relate tothe DC link in this case. As the load at bus 7 isdecreased, the current on the line 6-7 is reduced,therefore the total reactive power loss in area 1 isreduced slightly.4310

Australian Geothermal Energy Conference 2009The “breakeven distance” for this case occursaround 600MW of power transfer (300MW perline). At this power transfer level, the reactivepower loss in the AC system starts to surpass thereactive loss in the HVDC system. It should benoted that the two shunt capacitors at bus 7 and9 help to reduce the reactive power transfer inboth areas. The total reactive loss in the HVDCsystem could be further improved if one optimisesthe reactive power compensation at the twosending/receiving ends. Overall, reactive powercompensation should be done locally,strategically placing shunt capacitors may help togreatly improve the efficiency of the HVDCsystem.Impact of number interconnection on the“breakeven distance”Load flow analyses are now carried out for thesystem with one interconnection line removed.The length of the transmission line is 200km. TheHVDC is operated at =22 0 . The system loss inthis case was compared to the results of previousparts. Fig.5 illustrates the system losses withrespect to the number of interconnection lines.Fig. 5 Total system losses relating to number ofinterconnectionsAs is shown by Fig. 5, the loss in the HVACsystem is significantly reduced when anotherinterconnection is added. However, the loss in theHVDC system is slightly decreased. Again, onecan see that the line loss in the DC linkconstitutes a very small part in the total systemloss compared to the converter/inverter loss. Itshould be noted that this result is only based onloss evaluation. Adding a new AC line to reducepower loss may not be an overall cost effectivesolution.Impact of receiving end load on the“breakeven distance”The active load at bus 9 is gradually increasedfrom 1667MW to 1967 MW. Active/reactive powerloss for the AC and DC systems are shown in Fig.6.Fig. 6 Total system losses relating to the change in receivingend loadIn this case, bus 3 is chosen as a slack bus,which is in the same area as bus 9. Therefore, theincrease of active load at bus 9 is balanced by theincrease of generating power at generator 3.There is not much difference between how the ACand DC link systems respond to the change inload bus 9. The increase of active/reactive powerloss in Fig. 6 indeed comes from the increase ofactive/reactive power loss in the AC link of area 2.One can conclude that the “breakeven distance”does not depend on the load at the receiving end.ConclusionsThis preliminary work compares the DC and AClink options for a simple power system at varioustransmission lengths, load levels andinterconnection strength.Throughout the case studies, it is observed thatthe active power loss in the DC link constitutes anegligible part of the total system loss.Furthermore, the required reactive power for theHVDC system is quite independent of theinterconnection strength and power transfer level.On the other hand, the AC system losses changeconsiderably with the above parameters.Therefore, as the power transfer level and theinterconnection length increase, the DC linkgradually shows its superior performance. Itshould be noted that strategic placement ofreactive power compensation can greatly improvethe efficiency of a HVDC system. For the studiedsystem in this paper, reactive power locations areobvious as there are only two important loads. Formore complicated power systems, a thoroughstudy of optimal reactive power compensation isessential, as it would strongly affect the outcomeof the AC/DC comparison.In this work, the “breakeven distance” isdetermined by comparing only the reactive/activepower loss, which is closely related to theoperating cost. If one takes into account thecapital cost, the “breakeven distance” would behigher, due to the high cost of building HVDCsystems.One potential advantage of the HVDC system isits capability to enhance the total system dynamicstability. A comparative study of system stabilitywith/without HVDC system is thus needed, andwill be the subject of our future research.5311

Australian Geothermal Energy Conference 2009References[1] W. Breuer, D. Povh, D. Retzmann, and E. T. X.Lei, "Solutions for large Power SystemInterconnections" in CEPSI Shanghai, 2004.[2] N. G. Hingorani and L. Gyugyi, UnderstandingFACTS: IEEE press, 2000.[3] V. K. Sood, HVDC and FACT controllers:Klumer academic, 2004.[4] N. B. Negra, J. Todorovic, and T. Ackermann,"Loss evaluation of HVAC and HVDCtransmission solutions for large offshore windfarms" Electric Power Systems Research, vol. 76,pp. 916-927, 2006.[5] P. Bresesti, W. L. Kling, R. L. Hendriks, and R.Vailati, "HVDC Connection of Offshore WindFarms to the Transmission System" IEEETransaction on Energy Conversion, vol. 22, March2007.[6] J. Arrillaga and B. Smith, AC-DC powersystem analysis: The Institution of ElectricalEngineers, 1998.[7] I. Siemens Power Transmission & Distribution,"PSSE help" in Basic Power Flow ActivityApplications.[8] P. Kundur, Power System Stability andControl: McGraw-Hill, 2006.6312

Australian Geothermal Energy Conference 2009The Western Australian Geothermal Centre of ExcellenceKlaus Regenauer-Lieb, Hui Tong Chua, Xiaolin Wang, Frank Horowitz, Florian Wellmann, FlorianFusseis, Thomas Poulet, Heather Sheldon, Mike Trefry, Klaus Gessner, Paul Wilkes, Thomas Hoskin,Simone Seibert, Peter Cawood, Steve Reddy, Moyra Wilson, Noreen Evans, Nick Timms, Chris Clarke,Geoff Batt, Oliver Gaede, Brent Mc Innes, Sean Webb, James Cleverley, Mehroz Aspandiar, MartinDanisik, Arcady Dyskin, Elena Pasternak, Ali Karrech, David Healy, Neil Prentice, Tim Shannahan,Charlie Thorn, Steve Harvey and Mike McWilliamsWestern Australian Geothermal Centre of Excellence , UWA-CSIRO-CURTINARRC 29, Dick Perry Avenue 6151 Kensington WA, PO Box 1130, Bentley WA 6102In February 2008 the WA Government announcedinvestment into the Western AustralianGeothermal Centre of Excellence with co-fundingfrom CSIRO, UWA and Curtin University. TheCentres mission is to underpin a new era ofenergy development; to provide excellence ingeological understanding and exploitation ofgeothermal fields; to foster a capable work forcefor the geothermal industry by providing worldclass training to students in geothermal energysystems and to promote the development of“geothermal cities”.The Centre establishes capacity for the Australianindustry to lead the exploration and exploitation ofgeothermal heat in a modern society. By exploringfor and utilising low-grade heat in a permeablesedimentary environment the Centre addressesan overlooked opportunity for broadening thefootprint of geothermal energy utilisation. We areparticularly focussing on the geological setting ofsedimentary basins like the Perth Basin, whereexploitable heat is available right where it can beused. We suggest that geothermal groundwater insuch basins provide a unique opportunity for theAustralian geothermal industry. Owing to the highnatural permeability there is no need for artificialhydraulic fracturing.The Centre consists of the constituent institutionsin Perth. Its researchers will provide relevantexpertise in numerical modelling, geophysics,geology, geochemistry and engineering. Thenumerical modelling team will build the Australiancapability for geothermal modelling. It will draw onthe existing expertise of the CSIRO fluid/solidmechanics and reactive flow modelling group.With 25 researchers this group is the largest suchgroup internationally and well respected in thehard rock mining community. However, it iscurrently overlooked in the emerging Australiangeothermal sector. Modellers from this group willparticipate in the Centre and nucleate crossfertilisationbetween the geothermal and miningcommunities.The geophysical aspects of the research consistof a collaborative CSIRO-UWA-CURTIN team.The structural geology/ hydrogeology/microstructure/ geochemistry will be performedthrough an existing Curtin-UWA-CSIROcollaborative team of ten researchers includingpersonnel from the John de Laeter Centre. Thisinterdisciplinary team will be unique in its breadth.The above-ground engineering aspects will beled from the UWA Mechanical EngineeringDepartment in strong collaboration with EarthScientists from the other institutions. Theseresearchers are focussing on novel exploitationtechnologies for low-grade heat. This is anessential step for broadening the utilisationopportunities of geothermal energy in themetropolitan urban environment. We investigatezero emissions Heating Ventilating and AirConditioning (HVAC) technologies andgeothermal desalination. Our abovegroundstrategy is complementary to the Queenslandengineering based State Centre, which focuseson electricity generation and hot rocktechnologies.Keywords: Geothermal Exploration, DeepSedimentary Targets, Modelling and Simulation,Structural geology, Hydrogeology, Geochemistry,HVAC Direct Heat Use, DesalinationGeothermal Basin ExplorationMany of Australia’s major cities are built onsedimentary basins with naturally hot aquifersystems at shallow depth, often less than 3 kmdepth. Permeabilities can be extremely highmaking them an ideal target for geothermalenergy extraction.Classically sedimentary basins are investigatedfor petroleum exploration and a great host ofknowledge exists for this field. In our COE weacknowledge the fact that petroleum geosciencesonly allows us to provide a first cut at geothermalexploration. There are two main reasons for this:1) Economic constraints demand that geothermalexploration must do better than petroleumexploration because geothermal drilling cannotafford a ratio of one successful drillhole out ofseven drilling projects. 2) Geothermal targets aredeep aquifers. In the petroleum geoscience it isnot standard to think of deep aquifers as potentialtargets. Consequently heat transferred throughwater motions in these deep aquifers is generallyneglected. Petroleum geoscience considersophisticated approaches for thermal/sedimentaryevolution modelling of sedimentary basins. In1313

Australian Geothermal Energy Conference 2009these models heat is thought of being transferredonly through conduction or through tectonicmovements of rock masses and little attention ispaid to the possibility of fluid heat transfer.This assumption squarely contradicts currentgeothermal practice where hydrogeology hasbeen used as the science to focus better on theflow in hot aquifers. This approach has been usedsuccessfully in many places for the calculation ofgeothermal extractions for district heating systemssuch as those in the municipalities around Munich(Germany) where a hot aquifer in the MolasseBasin is the target at 3 km depth. Judging fromsuch successful geothermal practicehydrogeological modelling appears to be at firstsight the preferred method for geothermal.However, hydrogeology falls short in the scienceof dealing with geological faults, 3-D complexityand in particular the possibility of geothermallydriven convection.While clearly there is merit in marrying thesciences of petroleum and hydrogeology the basicunderlying assumption of hydrogeology is stilltopography driven flow. In such models waterfollows the underground topography driven by itsbuoyancy defined by heat content and salinity.Hydrogeological software packages therefore arenot designed for dealing with true 3D aspects butthey are excellent for inherently layered aquifersextruded into 3-D. In addition hydrological modelstend to overlook the possibility of thermally drivenconvection. There are a number of numericalcodes that are designed for true 3-D geothermalflows and these would appear to be the preferredtool for assessing geothermal prospects.However, these codes have been mainly used involcanic targets. A present shortcoming is that the3-D complexity of sedimentary basins demandsimplementation on supercomputer systems, whichis not widely available to date.Using the example of the Perth basin weovercome this shortcoming and develop aworkflow for geothermal modelling of geothermalflows in sedimentary basins, which we will lay outin the following subsections. The workflowconsists of a straight coupling between structuralgeological modelling, regional numerical fluid flowmodelling, reservoir scale modelling andgeophysical inversion. Geophysical inversion isused to dispatch the loop of structure and fluidflow modelling for matching geophysical andgeological data. A more detailed description of thefirst part of the workflow can be found in acompanion abstract (Wellman et al., this volume).3-D structural Modelling of the Perth BasinThe Perth Basin is a half-graben system to thewest of the Darling Fault extending into themarine basin to the west. It comprises permeablesedimentary rocks down to 10-15 km depth, andis deeply dissected by normal faults. The structureof the basin is known through seismic and othergeophysical and drillhole data. A 3-D structuralmodel is compiled from these data using softwarepackages such as Geomodeller or Gocad. Thismodel serves as a basis for groundwater flow andconvection modelling. The aim is to incorporatemultiscale observations of sedimentology andstructural characteristics, ranging from microscaleCT scans up to field observations. By wayof example we show a structure model (Figure 1)constructed for the Harvey ridge structure in theSouth Perth Basin built by Thomas Hoskin andFlorian Wellmann. This model is based on adatabase using seismic, borehole, gravity,magnetic and structural data. This structure isclose to the southern industrial precinct developedaround Bunbury and a potential site for a CO 2sequestration.Figure 1 showing the Harvey Ridge structure in the southernpart of the Perth Basin. Basement shown in grey, blue isPermian sediments, above the blue layer is the potentialtarget for CO2 sequestration.3-D Numerical Regional Modelling of FluidFlow and Heat FlowThe Perth basin comprises sediments of highlyvariable permeability ranging over several ordersof magnitude from milli-Darcys to Darcys atseveral km depth. The Yarragadee aquifer is oneof the largest fresh-water aquifers in the world,which is currently used to supply drinking water tometropolitan Perth. At greater than 1 km depth thetemperature is too high for drinking water use(>50°C). The greater depth is the proposed targetfor extracting geothermal heat. The regionalnumerical flow modelling will use numericalmodels to explore the potential for fluid flow drivenby heat, salinity and topography. The aim is toidentify thermal upwellings and downwellings inthe Perth Basin, which may be used forgeothermal heat extraction/injection.3-D Reservoir Scale ModellingThe exploitation of low-grade heat from shallow tointermediate depth aquifers is a new researchfield pioneered by the WA Geothermal Centre ofExcellence. We intend to harness 90°C hot waterfor direct heat use applications, and re-injectwater at ~40-50°C into the aquifer. There is no netwater abstraction. The flow rate required for airconditioning large new housing developments2314

Australian Geothermal Energy Conference 2009(e.g. 10 000 homes ca. 100 MWth base load) canbe substantial and far in excess of 100-200 litresper second that are presently achieved in thewater extraction bores from the aquifer. It willrequire an array of injection and extraction holesinto the permeable Yarragadee aquifer. We willuse reservoir engineering to optimise the layout ofthese wells using a novel approach for which aprovisional patent is filed. This approach goesbeyond the classical geostatistical modelling andwill assimilate the outcomes of the structural,inverse and fluid flow modelling being conductedin the COE.Geophysical Inverse ModellingThe structure of the Perth Basin is complex andnot well constrained, particularly in themetropolitan area where seismic data is lacking. Adetailed knowledge of the structure is required toreduce risk in exploring for geothermal heatresources. The aim of this project is to useinverse modelling techniques to refine thestructural model of the Perth Basin as new databecome available within the COE, e.g. fromdrilling and forward modelling of fluid flow. Asoftware platform will be developed to enablecalculations before drilling, and on-site dataassimilation and inversion while drilling. This is inclose collaboration with the CAGI (computeraidedgeological inversion) initiative of CSIRO,Intrepid, BRGM, GA and UBC built aroundGeomodeller.Deep HeatThis program is aimed at collaboration with thewider Australian industry and research activitiesfocussing on high temperature geothermalactivities, which is not an immediate target for theWestern Australian Geothermal Centre ofExcellence. We offer our leading capacity in solidmechanics, specifically for calculating hightemperature fractures and high strain shearzones. We also supply our leadership in hightemperature fluid dynamics, specificallychemically reactive flows, and contribute theoutstanding geochemical facilities of the StateCentre of Excellence John de Laeter Centre. Weintegrate this work with the Perth Basin by lookingat the potential signature of higher temperature(paleo) systems in the Perth Basin. Extractingheat from these deeper and higher temperaturesystems requires an understanding of rockmechanics in the brittle-ductile transition, which isidentified as the key problem in extraction of heatfrom “hot rock” geothermal systems. The twosubprograms of the Deep Heat initiative are :Identification of deep heat and itsgeochemical fingerprintingThis subprogram uses geochemical tools todefine the thermal history of the Perth Basin. Themineralogy and isotopic signature of authigenicclay minerals within the basin sediments will becombined with low-T thermochronologicalanalysis of basin sediments through (U-Th)/Heand fission track dating of apatite samples toprovide direct constraint of post-depositionalthermal history within the temperature rangerelevant to geothermal circulation. Thiscombination of analyses should be able to identifytemperature variation and excursions of less than30°C, revealing significant detail on the magnitudeand temporal evolution of paleo-geothermalsystems within the basin. Modelling of thisgeochemical data will also allow us to increasethe robustness of the chemical simulation outlinedin the other programs. This work will require theextraction of appropriate borehole samplematerials from sandstone and siltstone unitswhose relationships to basin architecture can bewell constrained through seismic data. 3 He/ 4 Heanalysis of deep fluids extracted from boreholesmay also allow explicit constraint of fluidresidence time in the aquifer.Extraction of deep heatOne of the biggest challenges for the exploitationof deep geothermal power is understanding andenhancing the permeability structure at greatdepth. It was not the lack of heat that causedfailure of the first Hot Dry Rock projects in LosAlamos and Cornwall, but the lack of pervasivepermeability. We have now a lot of observationsof high local permeabilities down to 9 km depth(e.g. the KTB borehole in Germany); however, westill lack understanding of what allows highpermeability to exist at such high temperaturesand pressures.This subprogram targets just this problem fromempirical and computational approaches. Thecomputational approach is based on a recentlydeveloped thermodynamic formulation whichallows for the first time to predict fracturing at hightemperature in the brittle-ductile transition zone(Regenauer-Lieb et al., 2006). The approachpredicts that most high temperature geothermaldrillholes reach a depth where brittle and ductileprocesses are likely to compete. This criticaltemperature depends on rock composition(rheology), the loading rate and thepresence/absence of fluids. For granite the criticaltemperature is of the order of ~270 °C incompression and ~230°C in extension (Figure 2).We will pursue the fracture of hot granite andbenchmark the predicted shear zones on thebasis of available deep drillhole data includingmicrostructural observations.3315

Australian Geothermal Energy Conference 2009Figure 2 Numerical models of an isothermal quartz-feldsparcomposite slab with random thermal perturbations shortenedfrom an initial configuration of 13.2 x 3 km to a finalconfiguration of 3.3 x 12 km.The empirical approach will assess the deeperPerth Basin and its likely basement to provide anassessment of the areas with deep geothermalpotential. Microstructural analysis, utilizingscanning and transmission electron microscopes,X-Ray CT scans and a variety of other methodsare used to examine competing deformationalprocesses in rocks: for example the sliding ofgrains past each other and the formation ofcavities along heterogeneous grain boundaries.The possible coupling of these mechanisms andtheir relation to fluid flow in deforming rocks isinferred from compositional and orientationvariations in mineral grains. To this end weinvestigate these processes using bright X-Raysfrom a synchrotron source. Such sources canidentify and map the 3-D connectivity of microsizedmicroporosity (Figure 3). These studies arehighly relevant to the high temperature shearzones modelled in Figure 2 because themicroporosity under study serves as thenucleating damage for the larger scale hightemperature flow of rock.Above ground TechnologyThe above ground technology investigated in theWestern Australian Geothermal Centre ofExcellence has been the subject of the first AGECpresentation (Regenauer-Lieb et al., 2008) andshall not be repeated here. At present we focuson geothermal desalination (in cooperation withNational Desalination Centre at MurdochUniversity) and geothermal air conditioning andcooling using geothermal fluids harvested in thePerth Basin.Figure 3 Hand specimen (Redbank Shear Zone) exhibiting astrain gradient from top to bottom. Representative sampleseries investigated by synchrotron (1.3 μm resolution) X-raytomography are shown. Red is pore space, blue is mica andfeldspar and quartz are rendered transparent. A dynamicmechanism for pumping of fluids through the shear zonecentre has been identified (Fusseis et al., 2009)SummaryWe have described a tightly integrated researchprogram for investigation of the Perth BasinGeothermal opportunity. We are particularlyexcited by the opportunity of intermediate to lowtemperature geothermal systems to contributetowards a zero emission energy supply.References:Fusseis, F., Regenauer-Lieb, K., Liu, J., Hough,R. and deCarlo, F., 2009. Creep Cavitation canestablish a granular fluid pump through themiddle crust Nature, 459: 974-977.Regenauer-Lieb, K., Chua, H., Wang, X.,Horowitz, F. and Wellmann, F., 2008. Direct-HeatUse for Australia, Australian Geothermal EnergyConference. AGEC.Regenauer-Lieb, K., Weinberg, R. andRosenbaum, G., 2006. The effect of energyfeedbacks on continental strength. Nature, 442:67-70.Wellman, F, Horowitz, F, Regenauer-Lieb, K.,Concept of an Integrated Workflow forGeothermal Exploration in Hot SedimentaryAquifers, (this volume)4316

Australian Geothermal Energy Conference 2009The development, launch and implementation of the AustralianGeothermal Reporting Code and current developmentsMalcolm Ward 1* , Graeme Beardsmore 2 , Anthony Budd 3 , Barry Goldstein 4 , Fiona Holgate 5Graham Jeffress 6 , Adrian Larking 7 , Jim Lawless 8 , Peter Reid 9 and Adrian Williams 101 Geothermal Advisory Pty Ltd, 2 Hot Dry Rocks Pty Ltd, 3 Geoscience Australia, 4 Primary Industry and Resources,South Australia, 5 KUTh Energy Limited, 6 Australian Institute of Geoscientists, 7 Green Rock Energy Limited, 8 SinclairKnight Merz, 9 Petratherm Limited, 10 Geodynamics Limited*Corresponding author: PO Box 275, Orford, Tas, 7190, mward@geothermaladvisory.comA joint committee of the Australian geothermalEnergy Group (AGEG) and the AustralianGeothermal Energy Association (AGEA)developed the world’s first reporting code forgeothermal resources, reserves and explorationresults in 2007-2008. This paper, by theGeothermal Code Committee, outlines thedevelopment of the code, its basic structure andprinciples, implementation since August 2008 anddevelopments since its launch.Keywords: Geothermal reporting code, resources,reserves, exploration results, AGEA, AGEG,geothermal lexicon, ASXHistory and BackgroundThe Australian geothermal sector has expandedrapidly in the past decade, consisting now ofsome 11 stock exchange listed and 30 unlistedcompanies with geothermal exploration ordevelopment tenements. These companies aretargeting Engineered Geothermal Systems (EGS),Hot Sedimentary Aquifer (HSA) and/or ‘DirectUse’ type geothermal plays within Australia andsome are also looking at these and ‘conventional’geothermal plays outside of Australia.Australia has long had an active capital marketsupporting the mining and energy sectors andresources companies account for a significantproportion of the market capitalisation ofcompanies listed on the Australian SecuritiesExchange (ASX). The Listing Rules of the ASXhave developed alongside these traditionalresources sectors to bring about a PublicReporting regime in which investors haveconfidence in the consistency of terminologiesand mechanisms of accountability. This hasgreatly facilitated the raising of both debt andequity by the companies concerned.Specifically, the Listing Rules of the ASXincorporate aspects of the Society of PetroleumEngineers (SPE) regime and, for the miningsector, the entire indigenous Joint Ore ReservesCommittee (JORC) Code, which governs howAustralian publicly listed mining and explorationcompanies may make Public Reports concerningtheir Mineral Resources, Ore Reserves andExploration Results.In 2007 a group was formed comprisingstakeholders from companies, regulators andtechnical agencies to produce a Code to regulatePublic Reporting by geothermal companies inAustralia. This group is now constituted as acommittee under the technical umbrella group theAustralian Geothermal Energy Group and thecompany organisation, the Australian GeothermalEnergy Association.Development of the GeothermalReporting Code and the GeothermalLexiconAfter considering a number of models, the‘Geothermal Code Committee’ chose to base thenew Australian Geothermal Reporting Code onthe JORC mineral code model (Joint OreReserves Committee, 2004), for four mainreasons: It had been developed and revised formore than 20 years and found to be veryrobust;Australian regulators were accepting of it;Mineral sector investors around the worldwere familiar with it and it has beenformally accepted for use in someoverseas jurisdictions; and It was desirable to minimise theintroduction of new terminologies andconcepts.The scope of the new Code was designed toaccommodate all forms of geothermal energy(excluding heat pumps), including ‘conventional’geothermal plays.During 2008 the Geothermal Code Committeemet to resolve many issues arising in theadaptation of a minerals reporting code to thegeothermal environment, whilst preserving thekey terms and principles. One of the keydeterminations was in respect of reportableenergy units, as follows:Thermal energy in place in Petajoules forInferred Resources; The same for Indicated and MeasuredResources, optionally also as recoverablethermal energy in Petajoules. Thesecategories may also be reported asassumed electricity generation and rates1317

Australian Geothermal Energy Conference 2009as MW e for a defined period or GWh intotal; Probable and Proven Reserves arereported as thermal energy in place andrecoverable thermal energy (Petajoules).Electricity generation should be presentedas net electricity output (MW e ) for adefined period or GWh in total.In all cases all key assumptions should be statedalongside the energy totals and in the case ofelectricity generation figures, a statement on thetechnological pathway proposed for the energyextraction/conversion.Another issue that called for additionalconsideration was the definition of the lowestconfidence category, Inferred Resources. Giventhe high cost of drilling test wells into a reservoir,it was decided that, to allow junior companies toreport early stage reservoir definition in acontrolled manner, an Inferred Resource could beestimated and reported without any direct wellpenetration into the reservoir.The Code governs how geothermal resources,reserves and exploration results are publicallyreported, but not the method of computation orestimation. However as the sector is new inAustralia, the committee decided also to compilea Geothermal Lexicon which would describe goodpractice in estimation methodology. The Lexiconis not required to be used under the Code, but ifthe methodologies outlined in it are not broadlyfollowed, then this must be stated in the PublicReport.Implementation of the CodeThe Geothermal Reporting Code 2008 Editionwas launched in August 2008 and was adoptedas mandatory for AGEA members for a six monthtrial. The Geothermal Code Committeeestablished a Compliance sub-committee whichperiodically reviewed Public Reports made byAGEA members and then offered confidentialfeedback to those companies. A number ofPractice Notes were also compiled and circulatedby the Geothermal Code Committee to informAGEA members on ‘best reporting practice’ inrespect of particular aspects of the Code.The main issues that have been identified in theearly application of the Geothermal Code includethe following.Generation and reporting of large InferredResource figures which have the potentialto mislead if the confidence level of theestimation is not understood by thereader. This issue comes about throughthe definition not requiring a directpenetration of the reservoir, allowing theenergy in place of large volumes ofreservoir to be reported and also becauserecovery factors and conversionefficiencies are not required to be made.This issue will likely be mitigated by theeventual requirement to apply a plausiblerecovery and conversion factors to theraw Inferred Resource figure(s). Incombination, these could reduce thereportable figure to as little as 1% of theenergy in place.Lack of understanding by companies ofthe role of the Competent Person in thedrafting and sign-off of various types ofPublic Reports, such as derivativesummaries of reserves and resources asmight appear in Annual or QuarterlyReports. The answer here found in theCode is that each and every report ofdata involving a Competent Person’sestimation of Resources, Reserves orexploration results must be agreed to inwriting by the Competent Person.The amount of technical detail required inPublic Reports; some reports have beenvery brief whilst some companiesreleased the entire original internaltechnical report on the resourceestimation. Ultimately it is up to theCompetent Person to agree to the contentof any Public Report based on their work.A very brief report will likely not containenough information to allow theconfidence on the ‘bottom line’ figure tobe assessed, while a full report is unlikelyto be comprehended by the targetaudience of investors. In early reports, asan education exercise, the GeothermalCode Committee has suggested moreinformation is better than less, and aresources or reserve report of between 10and 20 pages would be adequate, withthe length of report probably decreasingover time.The Geothermal Code has been disseminated toorganisations and experts around the world andfeedback has been constructive and positive. Anumber of comments or queries have come fromtechnical persons concerned with the possibility oftheir technical freedom being restricted or bringingup particular circumstances where there isambiguity with data or interpretation, for instancewhich temperature(s) in and around a reservoirshould be used. In nearly all cases it can beshown that the Geothermal Reporting Code in noway limits any estimation methodology or choiceof data, as long as those choices are clearlystated in the Public Report and can be justified bythe Competent Person, if called upon to do so.The Competent Person must also makejudgments as to the classification of the resourcesand/or reserves. Again, there are no ‘rules’ laidout but check-lists and prompts are given in the2318

Australian Geothermal Energy Conference 2009guidelines and at the end of the day, theexperience of the Competent Person is reliedupon, as is their preparedness to defend theirchoices.In discussing and reporting geothermal reservesand resources, the term ‘estimation’ is preferredover terms such as ‘measurement’ to emphasisethat the computation is not exact.With use, a number of possible improvementswere identified and a Second Edition of the Codewill be launched in November 2009. Following thesuccessful trial, AGEA has begun the process ofhaving the Second Edition formally incorporatedinto the ASX Listing Rules.International applicationIt is hoped that in co-operation with other nationalgeothermal organisations, this Code might formthe basis of a uniform, or at least a harmonisedinternational geothermal reporting code, which willgreatly assist cross-border investment andunderstanding based on recognised heat flowprovinces.Over-view of the GeothermalReporting CodeThe Code seeks to govern how Public Reports ofListed Companies are worded and presented. Itdoes not govern how resources and reserves areestimated, although if methodologies deviatesignificantly from the conventional techniquesoutlined in the Geothermal Lexicon, then thatmust be stated.The governing principles of the Code are:a) Transparency. This requires that the reader ofany Public Report is provided with sufficientinformation, clearly and unambiguouslypresented, to understand the report and not bemisled;b) Materiality. This requires that a Public Reportcontains all the relevant information whichinvestors and their professional advisors wouldreasonably require, and reasonably expect to findin the report, for the purpose of making areasoned and balanced judgment regarding thematerial being reported; andc) Competence. This requires that the PublicReport be based on work that is the responsibilityof suitably qualified and experienced persons whoare members of recognised, relevant professionalorganisations and subject to accountability and aprofessional Code of Ethics.Under the Code, the writer or compiler of atechnical report on either geothermal explorationresults, or the estimation of geothermal resourcesor reserves must be a ‘Competent Person’ (CP),who is defined as having at least five years ofrelevant experience in the type of geothermal playunder consideration. If a company then wishes tomake a Public Report based on that work, the CPconcerned must be satisfied as to the form andcontent of the Public Report and then mustconsent in writing to be personally identified assuch in the report. This places a dual onus on thereporting company and the CP to produce aPublic Report that is transparent, material,competent and defendable.The categorisation of resources and reservesunder the Code is illustrated as follows.Figure 1 Structure of the Geothermal Reporting CodeWith increasing levels of technical knowledge andconfidence, geothermal resources progress fromInferred to Indicated to Measured. There is noclaim or implication of the ability to economicallyextract any of the estimated resources at the timeof reporting (i.e. for electricity production or ‘directuse’), however there should be some expectationthat reported resources may be economic underplausible circumstances in the future.If studies into energy recovery and conversion,economic, marketing, legal and other factors areundertaken, so as to demonstrate energyextraction at a profit, then Indicated Resourcesmay be converted into Probable Reserves andMeasured Resources may be converted intoProved Reserves. The level of knowledgeregarding Inferred Resources is always such thatthey may never convert directly into reserves.Reserves may fall back to resource status if theeconomics of the project decline.Current developments (late 2009)The 2008 Edition of the Code was reviewedduring 2009 via appraisal of its performance,effectiveness and the technical outcomesresulting from its implementation and viaextensive consultation with industry. The majoroutcome from this review will be enshrined in aSecond Edition of the Code, to be launched at theNovember 2009 Brisbane Conference. The majoreffect was to change the definition of Resourcesand Reserves from thermal energy in place torecoverable thermal energy; units remain as PJ thor MW th -years. All estimates must quote arecoverable figure and state assumptions such as3319

Australian Geothermal Energy Conference 2009recovery factor(s), base and cut-off temperaturesand other key inputs. An estimate of the resourceor reserve in terms of total electrical generation (inPJ e or MW e -years) or electrical generation over aperiod (X MW e for y years) may also be quotedbut only in addition to the recoverable thermalenergy figure. Again, conversion factors andmajor assumptions must be stated.The requirements for Competent Personstatements and sign-offs did not change in theSecond Edition of the Code, but were made moreexplicit.Discussions are continuing with the ASXregarding having the Geothermal Reporting Codeincorporated into the ASX listing rules, therebybringing in mandatory use of the Code for ASXlisted geothermal companies via the force offederal law.The Canadian Geothermal Association, CanGEAhave released a draft Geothermal Reporting Codefor Canada, which is based on the AustralianReporting Code.The authors thank the AGEG and AGEA for theirencouragement in developing the AustralianGeothermal Reporting Code and for permission topresent this paper.ReferenceJoint Ore Reserves Committee, 2004,Australasian Code for Reporting of ExplorationResults, Mineral Resources and Ore Reserves;The JORC Code 2004 The Australasian Instituteof Mining and Metallurgy, the Australian Instituteof Geoscientists and the Minerals Council ofAustralia.4320