Western Australian Oil and Gas Review 2005 - Department of Mines ...

Western Australian 

oil and gas review 

2005 

Department of 


Industry and Resources 

Industry and Resources

CONTENTS 

Foreword 

Western Australian Oil and Gas 2004 

3 

The year in review 4 

Review of 2004 Upstream Petroleum Activity in Western Australia 10 

Implications of High Oil Prices in Western Australia 13 

Outlook for Western Australian Oil and Gas 16 

North West Shelf Project – A Continuing Progression 18 

The Gorgon Development – Key Assessment and Approvals Processes 20 

Map 1: Significant hydrocarbon discoveries in Western Australia 23 

Map 2: North West Shelf Oil and Gas 24 

Oil and Gas Projects (Index) 25 

Operating Projects 27 

Airlie Island 27 

Athena 28 

Barrow Island 29 

Beharra Springs 31 

Blina–Boundary–Lloyd–Sundown–West Terrace 33 

Buffalo 35 

Dongara–Mondarra–Yardarino–Xyris–Apium–Elegans 36 

East Spar 38 

Griffin–Chinook–Scindian 39 

Harriet area fields 40 

Hovea–Eremia–Centella 45 

Jingemia 47 

Laminaria–Corallina 48 

Legendre 50 

Mount Horner 51 

North West Shelf Gas Project 52 

Stag 56 

Thevenard Island 57 

Tubridgi 59 

Wandoo 60 

Woodada 61 

Woollybutt 62 

Projects under consideration 63 

Blacktip 63 

Cliff Head 63 

Coniston 64 

Enfield 65 

Gorgon 65 

Ichthys 68 

Jansz 69 

John Brookes 69 

Macedon 70 

Mutineer–Exeter 70 

Ravensworth–Crosby–Stickle–Harrison 71 

Scarborough 72 

Scott Reef–Brecknock–Brecknock South 73 

Stybarrow 73 

Tern–Petrel 74 

Whicher Range 74 

Western Australian petroleum fact sheet 76 

Abbreviations, permits and conversions 80 

Western Australian Oil and Gas Review 2005 

1

The Ocean Epoch at work on the North West Shelf

FOREWORD 

I am pleased to be able to release the 2005 edition of the Western Australian Oil and 

Gas Review. As in previous years, this publication is a useful reference document, 

containing a comprehensive and detailed summary of oil and gas projects currently 

in production or under consideration within Western Australia. It also contains key 

information about major petroleum discoveries and prospects. 

Fifty years ago, Western Australia had its fi rst oil discovery, at Rough Range on the 

Exmouth Peninsula. Since then, the petroleum industry – oil, gas and condensate – has 

emerged as Western Australia’s largest resources industry and an important part of 

the State’s economy. 

Western Australia is now the nation’s premier petroleum producer, accounting for 

approximately 64 per cent of national crude oil and condensate production and 

65 per cent of natural gas production. The State is a major supplier of LNG with 

export contracts and competitively priced energy particularly prominent in the rapidly 

expanding Asian market. Growth in LNG demand has also emphasised the State’s role 

as a world-class supplier of high quality, competitively priced and environmentally 

friendly energy. In total, during 2004, the value of Western Australia’s petroleum output 

amounted to $10.4 billion, or 37 per cent of the total value of the State’s mineral and 

petroleum sales. 

Growth in Western Australia’s oil and gas industry has been encouraged by strong 

global demand for crude oil and LNG with subsequent price increases. It is diffi cult to 

attribute levels of exploration expenditure directly to the increase in oil price because 

of the lead-time required to undertake exploration programs. However, it would be 

fair to assume that in the coming years, exploration expenditure will increase in 

response to high oil prices if these prices are sustained. In particular, the established 

cornerstone hydrocarbon regions of Western Australia – the North West Shelf and 

the northern Perth Basin – will continue to grow. However, it is hoped that into this 

mix, exploration dollars are directed towards some true greenfi eld areas of Western 

Australia, both onshore and offshore, where the potential exists for huge discoveries. 

The increase in oil prices and new openings in foreign LNG markets has also pushed 

the development of discoveries as soon as possible. This sets the stage for a State oil 

and gas industry, which is only at the beginning of a continuing evolution that will see 

Western Australia achieve global status in the oil and gas industry. There are currently 

$22 billion worth of proposed oil and gas projects in Western Australia. These include 

Gorgon, a fi fth LNG train, Enfi eld, Scarborough, Blacktip and a variety of other smaller 

projects. Combined with this is a continued acreage release and growing reserves. 

I commend this year’s Western Australian Oil and Gas Review to you with confi dence 

that the petroleum industry will continue to provide a foundation for strong economic 

growth in Western Australia. 

The Honourable 

Alan Carpenter, MLA 

Minister for State Development 

Government of Western Australia 


3


4 

World oil prices in 2004 averaged 

US$40.25/bbl (combination of Brent, 

Tapis and West Texas). This represented 

a 34 per cent increase above the 

equivalent average price in 2003. Locally, 

this increase was ameliorated because in 

2004 the average value of the Australian 

dollar appreciated against the US dollar 

by 13 per cent. This meant that in local 

currency terms, local producers faced 

world oil prices which were almost 

19 per cent higher on average in 2004 

compared with the previous year. 

Key factors supporting oil prices have 

been strong demand, supply disruptions 

and geopolitical disturbances. On the 

demand side, the US economic recovery 

and rapid growth in oil consumption of 

newly industrialised countries, 

particularly China, have supported strong 

growth in oil requirements. Further 

upward pressure on oil prices has 

emanated from production cuts by OPEC 

producers, strikes in Venezuela and 

Nigeria, continuing sabotage of Iraq’s oil 

supply infrastructure, natural disasters 

and other geopolitical risks. These 

conditions have generated considerable 

concerns about disruptions to oil supply 

and served to encourage speculative 

activity in the market. 

In 2004, the total value of Western 

Australian petroleum sales amounted to 

$10.385 million. This represented an 

increase of more than seven per cent and 

15% 

10% 

5% 

0% 

-5% 

-10% 

-15% 

Condensate Crude Oil LNG LPG Natural Gas Petroleum 

Sales Value 

Sales Volume 

Night operator 

WESTERN AUSTRALIAN OIL AND GAS 2004 

THE YEAR IN REVIEW 

Figure 1 Comparison of Western Australia’s Petroleum Sales 

in 2003 and 2004 (Source: DoIR) 

reversed the declining trend of the past 

two years. The strength of oil prices in 

2004 and an 11 per cent increase in 

liquefi ed natural gas (LNG) shipments 

were the key factors responsible for the 

increase, as the sales quantities of crude 

oil and condensate declined. Reduced 

volumes from mature fi elds meant that in 

volume terms, crude oil sales fell by 

more than 13 per cent and the volume 

of condensate sales dropped by 

seven per cent. 

Crude oil was the principal contributor 

to total petroleum sales, accounting for 

41 per cent of total petroleum sales value, 

followed by LNG (30 per cent) and 

condensate (19 per cent). Together 

these commodities account for about 

90 per cent of the State’s petroleum 

sales. The rest was accounted for by 

natural gas (six per cent) and liquid 

petroleum fuels (LPG - propane 

and butane).

CRUDE OIL 

In 2004, the value of crude oil sales 

reached $4.24 billion which compared 

with 2003, was $207 million or fi ve per 

cent higher. The reason for the increased 

value of sales was higher global oil prices 

which on average, increased by more 

than a third during the course of 2004. 

This increase in international oil prices 

was of suffi cient magnitude to counteract 

the appreciation of the Australian dollar 

in the same year which resulted in local 

oil prices in Australian dollars increasing 

by 19 per cent. 

Strong growth in oil prices also 

counteracted a drop in the volume of 

crude oil sales from Western Australia. 

In 2004, Western Australia produced 

76.8 million barrels (MMbbl) of crude oil, 

down 13 per cent on the previous year. 

Total gross reduction (which does not 

take into account output increases in 

some fi elds) in oil output was 14.8 MMbbl. 

The production decrease was due to 

several mature fi elds experiencing 

depleting reserves, namely Stag, Griffi n, 

Harriet area, Cossack, Lambert, 

Legendre, Wandoo and Wanaea. Together, 

these fi elds accounted for almost all of 

the drop in output in 2004. 

Falls in oil production levels were 

partially ameliorated by output increases 

from a number of new fi elds such as 

Hermes, Hovea, Woollybutt, Jingemia, 

Buffalo and Saladin. Total increase in oil 

output was 2.9 MMbbl. The Hermes, 

Hovea and Woollybutt fi elds were the 

most important contributors to the 

additional output. In 2004, combined 

production from these three fi elds 

increased by 15 per cent. These three 

fi elds accounted for 75 per cent of total 

additional output. Nevertheless, output 

increases were not suffi cient to offset 

production falls, resulting in a net oil 

production decrease of 12 MMbbl. 

Although a number of signifi cant oil 

discoveries have been made, it is 

anticipated that oil production in the short 

term will continue to decline. This decline 

will continue until new oil fi elds come 

online alleviating the fall in production 

from mature oil fi elds. New oil fi elds 

expected to boost output from Western 

Australia include Santos’ Mutineer– 

Exeter oil fi eld development, 

Nickel 11% 

Iron Ore 22% 

Gold 10% 

Alumina 11% 

Gigalitres 

Gigalitres 

Others 9% 

45 

40 

35 

30 

25 

20 

15 

10 

5 

Petroleum 37% 

Figure 2 SALES BY COMMODITY (Source: DoIR) 

0 

1965 1970 1975 1980 1985 1990 1995 2000 

5.8 

5.6 

5.4 

5.2 

5.0 

4.8 

4.6 

4.4 

4.2 

4.0 

Western Australia 

Rest of Australia 

Figure 3 Crude Oil and Condensate Quantity (Source: DoIR and ABARE) 

Mar-03 

Value 

Quantity 

Sep-03 Dec-03 

Jun-04 

Figure 4 Crude Oil and Condensate Quantity and Value by Quarter 

(Source: DoIR and ABARE) 

Crude Oil 41% 

LPG - Butane 2% 

LNG 30% 

LPG - Propane 2% 

Condensate 19% 

Natural Gas 6% 

2,000 

1,750 

1,500 

1,250 

1,000 

750 

500 

250 

0 

$ million 


5


6 

USA18% 

New Zealand 4% 

China 23% 

Singapore 23% 

South Africa 2% 

New Zealand 5% 

China 20% 

USA 11% 

Thailand 15% 

Figure 5 CRUDE OIL EXPORTS 

Total Value $3.52 Billion (Source: DoIR) 

Figure 6 CONDENSATE EXPORTS 

Total Value $1.6 Billion (Source: DoIR) 

Japan 7% 

South Korea 2% 

Thailand 23% 

Japan 10% 

South Korea 4% 

Singapore 33% 

located in the Carnarvon Basin, 

which was expected to commence 

production in mid-2005. Also expected 

to come on-stream, but later in 2006 

is Woodside’s Enfi eld oil fi eld in the 

offshore Carnarvon Basin. 

About half of Western Australia’s crude 

oil is exported, with Japan the largest 

overseas market for the State’s crude oil. 

Other major export destinations include 

the USA, Singapore, South Korea, 

Indonesia, China and Thailand. 

CONDENSATE 

The volume of condensate sales in 

Western Australia fell by seven per cent 

to 37.4 MMbbl in 2004. This was largely 

due to production decreases in the 

Goodwyn and Perseus–Athena fi elds. 

The production of condensate in the two 

fi elds fell by 19 per cent and 38 per cent 

respectively in 2004. The combined 

reduction in production from Goodwyn 

and Perseus–Athena was 3.5 MMbbl, 

accounting for about 95 per cent of the 

State’s total gross fall in condensate 

production. 

However, the lower sale volumes were 

insuffi cient to counteract stronger oil 

prices which translated to the overall 

sale values of condensate in Western 

Australia increasing by 14 per cent to 

$2 billion in 2004. 

Condensate is a by-product from offshore 

gas fi elds. Woodside Energy Ltd. is 

Western Australia’s largest condensate 

producer. The top-three condensate fi elds 

operated by Woodside, namely Goodwyn, 

Echo–Yodel and Perseus–Athena, 

produced 32.01 MMbbl of condensate in 

2004, accounting for 84 per cent of the 

State’s total. New fi elds, which 

commenced condensate production in 

2004, include Linda, Xyris, Gudrun and 

Monet. Although Goodwyn remains 

Western Australia’s largest producer of 

condensate, generating 12.1 MMbbl in 

2004, production levels have signifi cantly 

decreased, dropping by 22 per cent 

compared with the previous year. 

Almost all of Western Australia’s total 

condensate sales in 2004 were exported. 

The major destinations for the State’s 

condensate exports were Singapore, 

South Korea, Japan and the USA.

Looking into the short- to medium-term, 

the outlook for Western Australia’s liquid 

hydrocarbon production, based on current 

production fi elds, is forecast to fall. This 

is due to natural decline from mature 

fi elds. However, it is expected to be 

counterbalanced by a number of new 

liquid hydrocarbon developments 

projected to come on-stream within the 

next fi ve years. 

The decline of Western Australia’s oil 

fi elds is an issue with national 

implications. Western Australia currently 

produces over half of Australia’s crude oil 

and together with condensate production, 

in 2004 accounted for over 70 per cent of 

Australia’s total output. This needs to be 

placed in context whereby the eastern 

Australian fi elds are in a more advanced 

state of decline. In addition, the Northern 

Territory’s fi elds are not forecast to make 

up the future shortfalls in production. 

LIQUEFIED NATURAL GAS (LNG) 

LNG is Western Australia’s second most 

valuable petroleum product after crude 

oil, accounting for 30 per cent of the 

State’s total petroleum sales in 2004. 

In contrast to crude oil and condensate, 

the volume of LNG sales increased, by 

11 per cent to 8.7 million tonnes (Mt). 

All of Western Australia’s LNG is 

exported. In 2004, the value of LNG sales 

was $2.78 billion and represented a 

10 per cent increase compared with the 

previous year. Japan remains the 

dominant overseas market for LNG, 

accounting for about 95 per cent of the 

State’s total LNG exports. Other LNG 

export destinations have included South 

Korea, the US and Spain. 

LNG is produced by the North West Shelf 

Venture (NWSV) gas project. Based on 

extensive gas and condensate reserves 

discovered in the early 1970s just over 

130 km off the Pilbara coast of Western 

Australia, the NWSV project began LNG 

exports to Japan in 1989 under a longterm 

contract. Japanese power utilities 

have been the principal purchasers. In 

July 2003, the NWSV project reached a 

key milestone by delivering its 1500th 

LNG cargo to customers Osaka Gas and 

Kansai Electric Power. The NWSV also 

began supplying LNG to South Korea 

under a mid-term, seven-year contract 

bbl/d 

600,000 

500,000 

400,000 

300,000 

200,000 

100,000 

0 

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 

% 

100 

80 

60 

40 

20 

0 

Figure 7 WA Hydrocarbon Forecast DoIR Projections (Source: DoIR) 

Cossack 

Hermes 

Woollybutt 

Legendre North 

East Spar 

North Rankin 

Perseus- 

Athena 

Echo-Yodel 

East Spar 

Echo-Yodel 

North Rankin 

Perseus- 

Athena 

Wanaea Goodwyn Goodwyn 

Oil Condensate Gas 

Figure 8 Top Five Oil, Condensate and Gas Fields in WA in 2004 (Source: DoIR) 

Stybarrow 

Pyrenees Terrace 

Skiddaw 

Mutineer 

Enfield–Laverda 

Spar 

West Tryal Rocks 

Gorgon 

Egret 

Angel 

Cliff Head 

Linda–Rose 

Current Production 


7

Goodwyn A Gas Platform at work on the North West Shelf 


8 

that started in late 2003. In addition to 

contract sales, ‘spot’ cargo sales have 

also taken place around the world. 

2004 marked 15 years of LNG supply from 

Western Australia. Formalising a heads 

of agreement signed in September 2003, 

a new LNG sale and purchase agreement 

was signed in July 2004 between the 

NWSV LNG sellers and Kansai Electric 

Power, which is Japan’s second-largest 

power company and one of the original 

customers when LNG shipments began in 

1989. The agreement is for the supply and 

purchase of 0.5 Mt/a of LNG between 

2009 and 2014 and 0.925 Mt/a of LNG 

between 2015 and 2023. 

The $2.7-billion expansion of the NWSV’s 

gas-processing facilities, which 

commenced in 2001, was largely 

completed in 2004 with the new fourth 

LNG train which successfully commenced 

production in September 2004. The new 

fourth train was expected to reach full 

capacity of 4.2 Mt/a of LNG by early 2005 

in addition to the existing annual 7.5 Mt 

of production. 

Contingent on future market conditions, 

the NWSV may consider constructing a 

fi fth LNG train to meet growing Asian 

energy markets. Preliminary site works 

for Train-5 have been completed and a 

decision to proceed with the $1.6-billion 

fi fth train was expected in 2005. A fi fth 

LNG train would lift total LNG capacity 

above 14 Mt/a. 

Whilst the NWSV gas project is currently 

the only LNG project in Western Australia, 

an additional LNG facility is being 

considered in the form of the Gorgon gas 

project. This centres on the development 

of an LNG facility on Barrow Island, 

which will supply LNG for distribution to 

markets abroad. In September 2003, the 

State Government granted in-principle 

approval for the restricted use of Barrow 

Island as part of the $11-billion Gorgon 

gas project, conditional on the Gorgon 

partners meeting State and 

Commonwealth environmental 

safeguards. This agreement is a major 

milestone in Western Australia’s 

economic development. 

The Gorgon Joint Venture, comprising 

ChevronTexaco (4/7th interest), Shell 

(2/7th interest) and ExxonMobil (1/7th 

interest), plans to build an initial 5 Mt/a 

LNG plant on Barrow Island at an upfront 

cost of $6 billion. Natural gas feedstock 

for the LNG facility would initially be 

supplied from North Gorgon via a 26-inch, 

70-km subsea trunkline. Feedstock for 

future liquefaction expansions or 

domestic sales may be supplied from the 

Chrysaor, Dionysus, West Tryal Rocks and 

Spar fi elds. 

A development decision regarding the 

Gorgon LNG project is subject to market 

commitments. The Gorgon Joint Venture 

is targeting markets in China, South 

Korea and North America. Massive new 

demand for diversifi ed and clean energy 

in South Korea, China and the US has 

presented new opportunities for Western 

Australian LNG producers. In October 

2003, the Gorgon Joint Venture 

Participants and China National Offshore 

Oil Corporation (CNOOC) signed a 

non-binding agreement based on CNOOC 

acquiring a 12.5 per cent stake in the 

fi eld’s reserves while contracting the 

delivery of up to 100 Mt of LNG over 

25 years.

Australian Gas Reserves 

NATURAL GAS 

Outside of gas used as feedstock for LNG 

production, all remaining natural gas 

produced in Western Australia is for 

domestic industrial and household 

consumption. In 2004, natural gas sales 

for domestic purposes accounted for 

six per cent of the State’s total petroleum 

sales. Natural gas sales increased by 

13 per cent in 2004 to 9.2 billion cubic 

metres (Bcm), worth $648 million. 

As at the end of 2004, the gas reserves for 

Australia were: 

• Bonaparte Basin 21.6 trillion cubic 

feet (Tcf) (Western Australian portion 

2.34 Tcf, Northern Territory portion 

19.26 Tcf) 

• Browse Basin 26.5 Tcf 

• Carnarvon Basin 83.9 Tcf 

• Perth Basin 0.05 Tcf 

• Otway Basin 0.03 Tcf 

CARNARVON 

BASIN 

• Bass Basin 1.3 Tcf (in place) 

• Gippsland Basin 4.2 Tcf 

83.9 Tcf 

0.05 Tcf 

PERTH 

BASIN 

Karratha 

• Cooper–Eromanga Basin 3.5 Tcf. 

BROWSE 

BASIN 


Perth 

26.5 Tcf 

Broome 

BONAPARTE 

BASIN 

21.6 Tcf 

Darwin 

Northern Territory Queensland 

COOPER- 

EROMANGA 

3.5 Tcf BASIN 

South Australia 

Adelaide 

Using the data above, Western Australia 

holds 80 per cent of the nation’s total gas 

reserves. In addition, according to data 

sourced from ABARE’s Australian Mineral 

Statistics quarterlies, Western Australia 

produces 65 per cent of the nation’s 

natural gas. 

Reserves for Western Australia are 

calculated on the basis of a 50 per cent 

probability of recovery level. Reserve 

fi gures for the rest of Australia have 

been sourced from other State 

Authorities and producers. 

New South Wales 

Brisbane 

Sydney 

OTWAY 

BASIN 

Victoria 

GIPPSLAND 

4.2 Tcf BASIN 

Melbourne 

BASS 

BASIN 

1.3 Tcf (in place) 

0.03 Tcf Tasmania Hobart 

LIQUIFIED PETROLEUM GAS 

(LPG) 

In 2004, sales volumes of LPG (including 

butane and propane) fell by three per cent 

to 722 000 tonnes (t). Despite the lower 

sale volume and appreciating Australian 

currency, the total sale values of LPG was 

up by fi ve per cent on the previous year to 

$340 million. 

The majority of LPG produced in the State 

is for export and the primary destination 

for Western Australia’s LPG is Japan. 


9


10 

REVIEW OF 2004 UPSTREAM PETROLEUM ACTIVITY 

IN WESTERN AUSTRALIA 

Global demand for crude oil and gas and 

subsequent price rises in these 

commodities has encouraged the growth 

of petroleum exploration and production 

in Western Australia. Much of this 

exploration has occurred in the offshore 

Barrow and Exmouth Sub-basins and in 

the onshore northern Perth Basin. 

Successful ‘farm-outs’ in the Canning 

and Perth Basins also indicate renewed 

frontier exploration activity in the 

medium term for these areas. 

In 2004, 76 wells were drilled, 

representing a one per cent decrease on 

the previous year’s total of 77. Signifi cant 

discoveries were made in the Northern 

Carnarvon, Browse and Perth Basins. 

Successful new developments in the 

offshore Exmouth Sub-basin and offshore 

$ million 

1,200 

1,000 

800 

600 

400 

200 

0 


Rest of Australia 

New generation LNG carrier. 

Figure 9 Petroleum Exploration Expenditure (Source: ABS) 

Perth Basin and the acquisition of 3D 

seismic data in the onshore northern 

Perth Basin, also led to increased drilling. 

Exploration expenditure during 2004 for 

Western Australia saw a slump during the 

March quarter to $106.9 million, which 

rebounded strongly in the June quarter 

only to slump back in the third and fourth 

quarters to $113.1 million. 

It is diffi cult to attribute levels of 

exploration expenditure directly to the 

increase in oil price because of the leadtime 

required to undertake exploration 

programs. As such it is fair to assume 

that in the coming years, exploration 

expenditure should increase in response 

to the high oil prices if these prices are 

sustained. 

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Energy supply issues in Perth have 

encouraged junior explorers such as ARC 

Energy to undertake an aggressive 

onshore exploration program in the 

northern Perth Basin. The company is 

targeting gas discoveries within its L1/L2 

permit that can be rapidly tied into spare 

pipeline capacity. During 2004, ARC 

discovered the Xyris and Xyris South gas 

fi elds, which are now in production, in 

addition to the Apium gas fi eld that is 

currently undergoing feasibility studies. 

ARC also drilled two development wells 

in their 100 per cent owned Dongara gas 

fi eld targeting ‘attic’ gas that had not 

been previously accessed by the fi eld’s 

production facilities. Also, the ARC 

Energy and Origin Energy joint venture 

discovered oil during their gas exploration 

program at the Centella-1 exploration 

well. Assessment of this new oil fi eld is 

underway and plans for its development 

were expected in 2005. 

Exploration drilling along the North West 

Shelf yielded a new gas discovery for 

ChevronTexaco Australia Pty Ltd 

(ChevronTexaco) in excess of 56 Gm 3 

(2 Tcf) at Wheatstone-1. ChevronTexaco is 

currently undertaking the Wheatstone 3D 

seismic survey to further assess this new 

fi eld. BHP Billiton Petroleum (Australia) 

Pty Ltd (BHP Billiton) were also 

successful with exploration near their 

2003 Ravensworth discovery yielding 

further oil discoveries in the Harrison-1 

and Stickle-1 wells. 

In 2004, the fi rst coal seam methane 

exploration program in Western Australia 

commenced in the southern Perth Basin 

with a zone of interest in the Redgate and 

Rosabrook Coal Measures being 

identifi ed. Target seams with a combined 

thickness in excess of 20 m were 

identifi ed and appraisal drilling is 

expected in early 2005. 

With the increase in oil prices and 

a number of new openings in foreign 

LNG markets, there has also been a push 

to develop discoveries as soon as possible. 

The most extreme example of this was 

Apache Energy’s Monet discovery early 

in 2004, which involved an oil fi eld of 

approximately 600 000 barrels (bbl) in the 

Barrow Sub-basin and was put into 

production within two months of 

discovery through spare capacity in the 

nearby Simpson Platform. 

In other developments, drilling for 

Santos’ Mutineer–Exeter oil fi eld 

commenced in the second half of 2004 

and despite some disappointing results 

which lowered the upside potential of the 

oil fi eld, the project was ahead of 

schedule by about four months with 

production due to start in the latter half of 

2005. Meanwhile, appraisal drilling 

around the Eni-operated Woollybutt oil 

fi eld yielded excellent results with an 

estimated extra 1.6 gigalitres (Gl) (10 

MMbbl) of oil added to the reserves of the 

fi eld. As part of this, the Scalybutt 

horizontal well into the Woollybutt fi eld 

commenced production in early 2005. 

Perhaps the most interesting 

development project for 2004 occurred 

late in the year when BHP Billiton 

Petroleum recommenced appraisal 

drilling of the giant Scarborough gas 

fi eld. Indications are that gas from 

Scarborough could form a supply 

cornerstone of a gas-to-liquids plant in 

the Pilbara and an LNG receival terminal 

in California if the company can obtain 

the required approvals. 

Sustained high prices for oil and an 

increase in demand from gas and LNG 

markets over the next year will see the 

established hydrocarbon regions of 

Western Australia – the North West Shelf 

and the northern Perth Basin – continue 

to grow. However, it is hoped that into this 

mix, exploration dollars are directed 

towards some true greenfi eld areas of 

Western Australia, both onshore and 

offshore, where the potential exists for 

huge discoveries. 


11


12 

ACTIVITY BY BASIN 

Bonaparte Basin 

Activity in the Bonaparte Basin during 

2004 was confi ned to drilling the Polkadot 

Prospect in WA-313-P, held 50:50 by 

Woodside Energy Ltd. (Operator) and Eni 

Australia. The well is located 300 km 

southwest of Darwin in 65 m of water. The 

well appraised the Hyland Bay and 

Keyling Formations, with a 4-m gascolumn 

in the Hyland Bay Formation 

indicated from wireline logging and two 

gas-bearing zones identifi ed in the 

Keyling Formation. A production test in 

the Keyling Formation failed to fl ow 

hydrocarbons 

to surface. 

Browse Basin 

2004 saw the completion of Inpex’s 

exploration and appraisal drilling 

program over the Ichthys gas fi eld, 

with the Ichthys-2 well drilled in their 

100 per cent owned permit, WA-285-P. 

The well penetrated thick zones of gas, 

proving up a signifi cant gas and 

condensate resource within the 

permit area. 

Antrim Energy also spudded their South 

Galapagos-1 well in WA-306-P. The well 

reached a total depth of 3636 m with no 

signifi cant oil or gas recorded. 

Canning Basin 

Drilling recommenced in the Canning 

Basin after a few years hiatus with the 

spudding of Sally May-1 (formerly known 

as the Cetus Prospect) in EP/429. 

The well encountered encouraging shows 

of oil and reached a total depth of 1700 m. 

Northern Carnarvon Basin 

During 2004, a total of 19 exploration and 

38 appraisal/development wells were 

drilled in the Northern Carnarvon Basin. 

A number of oil and gas discoveries were 

made, with the most signifi cant of these 

being Harrison, Monet, Wheatstone and 

Stickle. Development and appraisal 

drilling were also undertaken in a 

number of fi elds in the Carnarvon Basin 

as several substantial hydrocarbon 

projects in the region commenced 

development. These included a number 

of wells for Santos’ Mutineer–Exeter 

development, infi ll drilling in the Bambra, 

Stag, Wanaea and Lambert fi elds and 

appraisal drilling on the Stybarrow, 

Ravensworth, Woollybutt and 

Scarborough fi elds. 

MONET-1 

The Monet oil fi eld was discovered in 

April 2004 in TL/1, near Varanus Island in 

the Barrow Sub-basin. Monet-1 

intersected 17 m of oil in a structure at 

the Flag Sandstone level and Monet-2H 

was drilled two months later and 

commenced production of the fi eld at 

a rate of 10 500 bbl/d. 

STICKLE-1 

Stickle-1 was drilled in BHP Billiton’s 

WA-12-R permit and encountered oil in 

the Cretaceous Pyrenees Member of the 

Barrow Group. The well is located 2.7 km 

east of the Crosby oil fi eld and 5 km east 

of the Ravensworth oil fi eld, both 

discovered in 2003. 

HARRISON-1 

After drilling in a water depth of 193 m 

and intersecting a 7-m oil-column, in the 

Pyrenees Member of the Lower Barrow 

Group, BHP Billiton spudded its WA-12-R 

wildcat well Harrison-1 in May 2004. 

WHEATSTONE-1 

Wheatstone is located in the 

ChevronTexaco-operated permit WA-12-R 

in a water depth of 215 m. The well 

penetrated three separate gas reservoirs 

and went to a total depth of 3384 m. 

The fi eld is estimated to contain close to 

73.6 Mm3 (2.6 Tcf) of gas. Preliminary gas 

analysis indicates the gas is a very clean, 

dry gas with low levels of nitrogen and 

carbon dioxide. 

Perth Basin 

The Perth Basin continued to be an 

exploration and development ‘hotspot’, 

with ten exploration/stratigraphic wells 

and seven appraisal/development wells 

drilled during 2004, with all except one of 

these wells drilled in the northern portion 

of the basin. Of the exploration wells, fi ve 

intersected signifi cant gas columns: 

Apium-1, Redback-1, Tarantula-1, Xyris-1 

and Xyris South-1. Another, Centella-1, 

drilled on L1, intersected an oil column in 

the Dongara Sandstone. 

Development wells were drilled in the 

Hovea, Eremia, Jingemia and Whicher 

Range fi elds. Three new wells were 

drilled in the Hovea–Eremia fi elds 

including a water injector well. One 

development well was drilled at 

Jingemia. Two development wells were 

drilled in the Dongara gas fi eld targeting 

by-passed gas in the Aranoo Member of 

the Kockatea Shale. Both wells 

penetrated the Aranoo sands and fl owed 

at approximately 170 km 3 /d (6 MMcf/d) 

during test fl ow. 

XYRIS-1 

Xyris-1 was drilled on a gas prospect 

located 6.5 km east of the Hovea 

production facility and 1.2 km northwest 

of the Mondarra gas fi eld. The well 

intersected a large gas column. 

TARANTULA-1 

Origin Energy’s Tarantula-1 well targeted 

a fault block roughly 6 km north of the 

Beharra Springs gas facility. The well 

penetrated a gas column and further 

appraisal was expected during 2005. 

CENTELLA-1 

Centella-1 is located on the L1 licence, 

6.5 km east of the Hovea Production 

Facility and 1.3 km north of the Mondarra 

gas fi eld. The well intersected an oil 

column and early indications were 

that the fi eld is of economic size. 

Further studies were to be undertaken 

during 2005. 

APIUM-1 

The Apium-1 well was drilled 3 km to the 

east of the Hovea oil fi eld and intersected 

a 10-m gas-column. Apium-1 is currently 

suspended as a future gas producer.

IMPLICATIONS OF HIGH OIL PRICES 

IN WESTERN AUSTRALIA 

Price per barrel 

A$ Price per barrel 

70 

60 

50 

40 

30 

20 

10 

A BRIEF HISTORY OF OIL PRICES 

Oil prices have increased substantially 

over the past two years, with the Tapis 

crude oil price exceeding US$50/bbl in 

October 2004 compared with around 

US$28/bbl in late 2002. While the extent 

of this increase partly relates to weakness 

in the US dollar (growth in currencyneutral 

SDR terms has been somewhat 

lower), spot prices in most currencies are 

currently at historically high levels. 

In the case of Australia, the domestic 

currency price of crude oil has also 

reached record levels. However, the oil 

0 

1991 1992 1993 

US$ 

A$ 

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 

Figure 10 TAPIS CRUDE OIL PRICE 

Current Prices, Calendar Month Average 

120 

100 

80 

60 

40 

20 

Oil 

embargo 

Nominal A$ 

Real A$ 

(Source: Thomson Finance) 

Iranian 

revolution Iraq invades 

Kuwait 

0 

1970 1974 1978 1982 1986 1990 1994 1998 2002 

Figure 11 CRUDE OIL PRICES 

World Trade-Weighted Prices, Quarterly Average 

(Source: ABARE) 

Start of 

Iraq war 

price in Australian dollar terms has been 

high for some time (see fi gure 10). This is 

because a strong increase in oil prices in 

1999 was accompanied by a sharp 

depreciation in the Australian dollar, 

which resulted in a three-fold increase 

in Australian dollar oil prices over an 

18-month period. 

While prices remain close to record levels 

in nominal terms, the real price of oil 

(adjusted for infl ation) is still below the 

peak in the 1970s. In today’s Australian 

dollars, the world trade-weighted price of 

crude oil rose above $100/bbl in the wake 

of the second OPEC oil shock in 1979. 

This compares to an average of around 

A$50 (in trade-weighted terms) in the 

September quarter 2004. Nevertheless, 

the Australian dollar price in real terms 

now exceeds that observed following the 

fi rst oil shock in 1973 and the Gulf Warinduced 

spike in 1990. 

The increase in the price of oil in recent 

years partly refl ects solid growth in 

international demand (particularly from 

China), as well as concerns relating to 

short-term supply. However, according to 

the Australian Bureau of Agricultural and 

Resource Economics’ (ABARE’s) oilforecasting 

model, the equilibrium price 

of West Texas Intermediate (WTI) oil (the 

benchmark frequently referred to in the 

fi nancial press) is now around US$30/bbl 

based on current demand and supply 

fundamentals. This is signifi cantly higher 

than the average of the past decade, 

but still much less than the current 

price level. 

The difference between the current price 

of oil and estimates of the equilibrium 

price can be interpreted as representing 

‘risk premium’ relating to concerns about 

the short-term supply of oil. In particular, 

these concerns stem from interruptions 

to production in Iraq, political tensions in 

Nigeria and Venezuela, and fi nancial 

diffi culties experienced by Russia’s 

largest oil producer, Yukos. 

Current estimates of the risk premium 

range between US$10 and US$15/bbl. 

Although the size of this premium is 

generally expected to diminish over 

time, the speed and extent to which 

this will occur is subject to a large 

degree of uncertainty. 

Note: 1 Tapis crude oil is the common feedstock for refiners in the Singapore region and is the most relevant crude oil reference for Australian consumers. 

Other oil prices referred to in this article are the West Texas Intermediate price, which is a commonly quoted price (but for a specific grade of oil), and 

the World Trade-weighted price, which is an average price of oils of different grades. 

2 The SDR (Special Drawing Right) is a unit of account used by the International Monetary Fund. Its value is based on a basket of key international currencies. 


13


14 

Fuel Excise 88% 

Petroleum 

royalties 4% 

Petrol resource 

rent tax 8% 

Per cent 

1.2 

1.0 

0.8 

0.6 

0.4 

0.2 

0.0 

-0.2 

ECONOMIC IMPACTS OF HIGH 

OIL PRICES 

Macroeconomic Impacts 

The oil shocks of the 1970s had very 

signifi cant adverse effects on infl ation 

and global economic growth. However, 

as the Reserve Bank of Australia (RBA) 

recently noted, the current period of high 

oil prices may have less serious 

implications for global economic growth. 

Not only is the real price of crude oil still 

lower than the second peak of the 1970s 

(which saw a more rapid and pronounced 

increase than the recent price rise), 

but the energy intensity of world output 

has also fallen noticeably over the past 

few decades. 

Australia Western Australia Rest of Australia 

Figure 12 Potential Long Run Impact of Higher Energy Prices and 

Increased Gas Production GDP/GSP Per Capita 

(Source: Department of Treasury and Finance) 

Figure 13 COMMONWEALTH GOVERNMENT PETROLEUM REVENUES 2003-04 

(Source: DoIR) 

FUEL EXCISE DUTIES 

Petrol 48% 

Crude oil 14% 

Other 1% 

Diesel 37% 

Importantly, the recent increase in oil 

prices has also been partly driven by 

demand factors. This is unlike the 

price-spikes in the 1970s, which arose 

solely as a result of supply shocks and 

therefore had more severe implications 

for output growth. Another signifi cant 

contrast with the oil shocks of the 1970s 

is that infl ationary expectations are now 

well contained, which means that there 

is arguably more scope for a temporary 

rise in prices without severe secondround 

infl ationary impacts. 

The International Energy Agency (in 

collaboration with the OECD and the IMF) 

recently estimated that a US$10/bbl 

increase in the crude oil price from 

US$25/bbl to US$35/bbl would reduce 

global gross domestic product by around 

0.5 per cent in the fi rst and second years 

of higher prices. The impact of high oil 

prices has been modelled using the 

MMRF computable general eqilibrium 

model developed by the Centre of Policy 

Studies at Monash University. The effect 

of higher oil prices on individual 

economies, however, will vary according 

to the oil intensity of production and 

consumption and the extent to which 

economies are reliant on oil imports. 

As Western Australia is a large net 

exporter of oil and a growing net exporter 

of natural gas (the price of which is 

related to oil), any adverse impact on the 

State’s economy is likely to be less than 

for most other industrial countries. 

This is because an increase in energy 

prices will tend to boost Western 

Australia’s terms of trade (the ratio of 

export prices to import prices), resulting 

in a net transfer of income into the State. 

Preliminary analysis by the Department 

of Treasury and Finance supports the 

view that high oil prices may affect 

Western Australia to a lesser extent than 

many other industrialised countries. 

In the short term, the State’s gross state 

product (GSP) is likely to contract 

marginally and less than the rest of 

Australia. In the long run, Western 

Australia may be in a position to benefi t 

from higher energy prices. If strong 

prices are combined with a strong rise in 

gas production (corresponding to the 

fourth LNG train on the North West Shelf 

project), this could potentially offset the 

adverse impact on Western Australia of 

high-energy prices on global growth and 

hence external demand for the State’s 

goods and services.

IMPACT ON GOVERNMENT 

FINANCES 

Commonwealth Government 

The Commonwealth collects the bulk 

of Australian petroleum revenues. 

In 2003–04, Commonwealth Government 

revenues from petroleum totalled 

$15 billion of which the excise on fuel 

products accounted for around 88 per 

cent ($13 billion) of the total. These 

revenues are largely unresponsive to 

crude oil prices, since nearly all the fuel 

excise is levied on a volumetric basis 

(i.e. a fi xed number of cents per litre). 

The Commonwealth also collects 

petroleum royalties and the petroleum 

resource rent tax (PRRT) on taxable 

profi ts in relation to offshore projects 

(excluding the North West Shelf). 

The PRRT revenue only rises to the 

extent that higher prices translate into 

increased profi tability of projects. 


Western Australia only collects 

$509 million, or less than 4 per cent of 

the Commonwealth fi gure, in petroleum 

revenues — from two sources. 

Firstly, it collects petroleum royalties 

paid by oil companies for the right to 

extract the publicly owned resource. Most 

royalty revenue accrues under a special 

arrangement with the Commonwealth. 

Under this arrangement, Western 

Australia receives a share of petroleum 

royalties from the North West Shelf 

project. Ordinarily, Western Australia 

would not be entitled to these payments 

as the High Court has effectively deemed 

that offshore projects fall under the 

domain of the Commonwealth. In 2003– 

04, these royalties amounted to 

$363 million, whereas, non-North West 

Shelf petroleum royalties only amounted 

to $53 million. 

Notably, while these revenues benefi t 

from higher oil prices (as they are 

calculated according to the value of 

production), around 90 per cent of 

Western Australia’s royalties are 

redistributed to other States and 

Territories in the medium term under 

the Commonwealth Grants Commission 

process. 

Secondly, Western Australia receives a 

share of the Commonwealth’s Goods and 

Services Tax (GST). All GST revenues 

collected by the Commonwealth are 

distributed in the form of grants to the 

States and Territories. It is estimated that 

the State received around $112 million 

in 2003–04 from the GST on petrol. 

However, the sensitivity of GST revenue 

to oil prices is quite low. This is because 

a large share of the pre-GST price of 

petrol relates to the Commonwealth’s 

petrol excise, which does not change with 

movements in the crude oil price (fi xed 

at 38 cents per litre). 

Overall, while the sensitivity of Western 

Australia’s revenues to higher oil prices 

can be substantial in the short term, 

the sensitivity is quite low over the longer 

Cossack Pioneer: riser 

term. Each US$1/bbl increase in the price 

of oil boosts petroleum royalties by 

around $15 million over a full year. 

However, as noted above, around 

90 per cent of this benefi t is offset by 

Grants Commission redistributions in 

later years. Taking into account the effect 

of the Commonwealth Grants 

Commission process, every US$10 

increase in the price of crude oil will lead 

to an increase in State revenue of around 

A$20 million per annum over the medium 

term (assuming a constant Australian 

dollar). To put this into context, total 

revenue in Western Australia was around 

$13 billion in 2003–04. 

SUMMARY 

Global economic growth could be 

adversely impacted upon if oil prices 

continue to rise over the medium term 

(contrary to general expectations). 

However, any impact is likely to be less 

severe than that experienced in the 

1970s, because the real price of oil is 

still lower than this period, oil intensity 

of output has fallen signifi cantly and 

infl ationary expectations are well 

contained. The adverse impact on 

Western Australia would be contained 

because the State is a large net exporter 

of energy. Overall, it is likely that the 

Western Australian economy would 

benefi t from a sustained increase in the 

price of oil to the extent it provides a fi llip 

to the State’s oil and gas industry, and its 

export earnings. 


15


16 

OUTLOOK FOR WESTERN AUSTRALIAN 

OIL AND GAS 

Total number wells 

50 

45 

40 

35 

30 

25 

20 

15 

10 

5 

0 

Other NFW 

Significant Discoveries 

Success Rate 

EXPLORATION 

Currently there is a high level of oil and 

gas activity in both exploration and 

development in Western Australia. The 

question is where does the industry go 

from here? 

Western Australia has been attracting 

high levels of petroleum exploration, $500 

to $600 million per year or 60 per cent to 

70 per cent of Australia’s total petroleum 

exploration for the past seven years. 

On average, 40 exploration wells have 

been drilled each year with an average 

commercial success rate during the past 

seven years of about 20 per cent. 

Despite high oil and gas prices and highretained 

earnings, many companies have 

been taking a conservative approach and 

have been primarily exploring in proven 

basins. Given this environment, it is 

surprising that Western Australian 

exploration expenditures reached a 

record high in 2003 of $709 million and a 

respectable $547 million in 2004. 

Worldwide, not only have there been 

embarrassingly high levels of retained 

earnings, but also many companies have 

not replaced produced reserves (Shell for 

example had a 45 per cent reserve 

replacement last year). Furthermore, 

acquisition costs for reserves in the 

ground have continued to increase to a 

point where companies are widely 

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 

100 

Figure 14 New Field Wildcats (NFW) and Significant Discoveries WA 1993–2004 

(Source: DoIR) 

90 

80 

70 

60 

50 

40 

30 

20 

10 

0 

Success Rate % 

expected to now focus on investing in 

higher levels of exploration in order to 

discover, rather than acquire, oil and gas 

reserves to expand or even maintain 

their inventories. 

This was the topical issue at the recent 

North American Prospect Expo (NAPE) 

in late January 2005 in Houston. 

Indications from NAPE were that there 

will be a large increase in worldwide 

exploration. It was estimated that 

companies can develop reserves through 

the ‘drill bit’ (i.e. exploration) at an 

average of about US$3.00 per barrel of oil 

equivalent (boe) versus acquisition of 

reserves at US$8.00 per boe. 

Early indications from companies 

exploring in Western Australia show a 

large increase in exploration this year. 

Examples are: 

• Apache plans 40 exploration wells in 

2005 versus 11 in 2004 with total 

exploration expenditure (Apache 

Share) rising from US$31 million to 

US$102 million; and 

• The Woodside budget for Australian 

exploration is up by 60 per cent for 

2005 with more than a doubling of the 

number of wells to thirteen. 

Another indicator of the outlook for 

exploration is the total amount of 

exploration obligations (offshore and 

onshore) accrued through work program 

commitments. These work programs 

occur during the term of the exploration 

permits and are scheduled to be carried 

out over the next six years. Total 

exploration commitments show that 

although there has been some decline in 

total commitments, they are still at a 

healthy level. Current total exploration 

commitments (2004–05 to 2010–11) 

amount to $1.31 billion and 162 

exploration wells. Industry is committed 

to drilling an average of over 35 

exploration wells per year for the next 

four years.

TOTAL WA EXPLORATION COMMITMENTS 

Year Commitment 

($ billion) 

Number 

of Wells 

2004 $1.31 162 

2003 $1.44 173 

2002 $1.58 207 

2001 $1.27 171 

2000 $1.64 210 

1999 $1.59 254 

Yet another indicator is the industry 

response to gazettals or offers for 

exploration acreage. Recent gazettal 

response has been very high both 

onshore and offshore. A recent Western 

Australian gazettal had applications for 

all areas offered. Work commitments 

proposed have also increased. 

The exploration outlook for Western 

Australia is extremely good. Industry has 

indicated an interest not only in the more 

mature areas of the Carnarvon and Perth 

Basins, but also frontier areas. 

The Western Australian Government and 

the Department of Industry and 

Resources (DoIR) have been 

endeavouring to facilitate exploration 

through a number of initiatives. For 

example, DoIR has been assembling 

more pre-competitive information prior 

to gazetting acreage and facilitating 

exploration. This has involved: 

• The Government funding the 

gathering of pre-competitive 

geoscience information in the more 

frontier onshore sedimentary basins, 

including the Perth, Southern 

Carnarvon, Canning and Offi cer 

Basins at $3.6 million per year. 

• DoIR re-processing and reinterpreting 

seismic data, identifi ed 

prospects and leads, in addition to the 

development of other information 

(such as economic modelling and 

Native Title representative group 

contacts) for inclusion in CDs for 

distribution to industry. 

• DoIR has participated in a number of 

conferences and exhibits in Australia 

and overseas to assist in raising the 

profi le of Western Australia’s onshore 

and State waters exploration 

opportunities. 

In facilitating exploration, DoIR has 

observed that many explorers are in a 

hurry to begin exploration and prefer not 

to go through the application and bidding 

process for areas in addition to the Native 

Title processes. Often, smaller local 

companies that have gone through these 

processes require investment capital. 

However, there is a mechanism for 

participating in existing Exploration 

Permits, which is referred to as ‘farmout’. 

A farm-out can allow investors to 

be on the ground and exploring in a very 

short timeframe. DoIR has therefore 

endeavoured to bring together investors 

and holders of titles through an annual 

publication called ‘Western Australian 

Petroleum Opportunities’ (or sometimes 

referred to as the ‘farm-out booklet’). 

Copies are widely distributed both in 

Australia and overseas and are of much 

interest to potential investors. 

The Western Australian Government is 

also in the process of implementing 

recommendations of a review to 

streamline approval processes (Keating 

Review) in order to improve the effi ciency 

of exploration (and development) 

operations in the State. 

DoIR has also made petroleum data more 

accessible. An upgrade has been 

completed on DoIR’s Western Australian 

Petroleum Information Management 

System (WAPIMS) database to create 

a more robust platform that allows the 

interrogation of open fi le petroleum data 

through a spatial web-based system. 

This database contains information on 

petroleum permits, wells, geophysical 

surveys and other exploration reports 

submitted to the DoIR by petroleum 

explorers. It means that a geologist in 

Houston, Texas for example, can look at 

well logs from Western Australia on 

the Internet. 

DEVELOPMENT 

With regard to petroleum development, 

commercialisation of the huge gas 

resources off the Western Australia coast 

(more than 100 Tcf of uncommitted gas) 

will be key to major growth and a number 

of upstream projects that are at various 

stages of evaluation and development. 

There are also crude oil developments at 

various stages of evaluation and 

development. These will offset the 

decline in Australia’s self-suffi ciency in 

liquids production and provide additional 

security of supply. Also, a number of 

pipeline projects are being developed. 

In addition to projects already under way 

which include the expansion of offshore 

North West Shelf gas production 

facilities; Enfi eld, Mutineer–Exeter, 

Jingemia and Eremia oil projects; and the 

John Brookes gas project, evaluation and 

planning is under way for other gas and 

oil projects including: 

• Potential LNG projects: Gorgon, 

Scarborough and Scott Reef– 

Brecknock; 

• Three oil projects: Stybarrow, 

Macedon–Pyrenees and smaller 

Apache projects; 

• Gas supply projects: Tern–Petrel, 

Blacktip, Angel and Perth Basin 

projects; and 

• The Pyrenees gas-gathering pipeline. 

These projects are estimated to have 

a capital investment value of 

$13 billion, more than has ever been 

experienced in Western Australia’s oil and 

gas history. 

The projects will benefi t Western 

Australians through: 

• increased direct employment with 

additional further indirect 

employment when considering the 

economic multiplier effect; 

• regional development; 

• increased infrastructure 

development; and 

• increased benefi t to the Western 

Australian community through 

revenues to government for provision 

of schools, hospitals and other 

services. 

Altogether, the outlook for oil and gas 

exploration and development in Western 

Australia is very positive. 


17


18 

NORTH WEST SHELF PROJECT – 

A CONTINUING PROGRESSION 

The North West Shelf (NWS) Project is 

generally regarded as Australia’s largest 

single resource project. In terms of 

physical size and expenditure, the scale 

of the project is huge and has special 

signifi cance, even in an industry where 

large projects and associated high 

numbers are not unusual. 

From its inception the project has 

provided signifi cant physical and 

engineering challenges that have 

required innovation and determination 

to overcome. For example, in the 

development of the onshore plant, more 

than 6Mt of rock and other material had 

to be moved and much of this had to be 

drilled and blasted – before the complex 

process of construction could begin. 

In addition, at the time although much of 

the technology had been tried and tested 

elsewhere in the world, it had never been 

applied in Western Australia. As an 

illustration 

of this, the North Rankin-A platform, 

apart from being the largest capacity 

gas-production platform in the world at 

the time, was also the fi rst built offshore 

from Western Australia. 

Consistent with overcoming engineering 

challenges in the various construction 

phases, the project has also demonstrated 

ongoing achievements in the operations 

area. For a project of such signifi cance, 

notable achievements in any yearly 

statement of progress would therefore not 

be unexpected. However, the year 2004 may 

be regarded as one of the more notable in 

the project’s history, because of the number 

of signifi cant highlights, including: 

• completion of the second trunkline 

connecting the offshore gas and 

condensate fi elds with the onshore 

gas-processing plant on the 

Burrup Peninsula; 

• completion of the 4.2 Mt/a capacity 

fourth LNG train, lifting processing 

capacity of the gas plant by 56 per 

cent to 11.7 Mt/a; 

• record annual LNG production of 

9.3 Mt/a (an increase of 14.2 per cent 

on 2003); 

• a 15-year milestone of reliable LNG 

supply, inclusive of over 1600 cargoes 

delivered since 1989 without missing 

a single delivery; 

• a total of 156 LNG cargoes delivered; 

• formalisation of agreements to 

provide China with at least 3.3 Mt of 

LNG each year for 25 years; 

• commissioning of a ninth LNG ship 

(Northwest Swan) to service North 

West Shelf LNG shipping; 

• a 20-year milestone of North West 

Shelf domestic gas supply to Western 

Australia; and 

• signing of an agreement with Western 

Power Corporation for additional 

domestic gas sales (up to 700 PJ). 

A project of the size of the NWS cannot 

stand still. It must maintain momentum 

both through ongoing development of 

new projects and through upgrading and 

replacement of existing facilities. 

Production reliability, especially for 

domestic gas and LNG, where long-term 

contractual commitments must be 

honoured, is therefore critical to 

continued project success. 

The historical cost of investment to date 

in the project’s onshore, offshore and 

shipping facilities is approximately 

A$14.3 billion. To ensure continuation of 

the reliability of supply, for which the 

project has an enviable record, the NWSV 

participants last year commenced a 

program consisting of a number of 

separate developments. Expenditure on 

these developments since the middle of 

last year and continuing over the next 

four to fi ve years will, when completed, 

increase the total investment cost by 

some 30 per cent. 

For instance, in December 2004, Woodside 

Energy Ltd. (Woodside), in its capacity as 

project operator, submitted a proposal on 

behalf of the NWSV participants to the 

State Government for an expansion 

of the LNG facilities at the onshore plant. 

The expansion is aimed at meeting a 

portion of the 8 per cent per year forecast 

LNG demand growth (from 90 to 182 Mt/a) 

in the Asia–Pacifi c region from 2004 to 

2015, with an expected large shortfall in 

global LNG supplies in mid-2008. 

The proposal, termed the LNG-5 

Expansion Project, comprises a fi fth LNG 

processing train, supporting infrastructure 

consisting of a third fractionation train, 

a third LNG boil-off gas compressor, an 

acid gas removal unit, upgrades to utilities 

and general structures including the 

addition of a new fuel gas booster 

compressor, additional power generation 

capacity and a new second LNG berth as 

a spur off the existing jetty. Total 

development cost of the expansion is 

estimated to be $2 billion. 

Under the proposal, the fi fth LNG train 

would have a capacity of 4.2 Mt/a. Initial 

design work for Train-5 has been 

undertaken. Train-5 is based on a copy 

of Train-4, which came into operation in 

September 2004. When operational, 

towards the end of 2008, the fi fth train 

would lift total LNG production capacity 

of the onshore plant to 15.9 Mt/a. 

In public statements, Woodside has 

highlighted the advantages of pursuing 

growth through brownfi eld expansion of 

the LNG hub on the Burrup Peninsula. 

One signifi cant benefi t is the ability to 

provide additional capacity at low 

incremental operating cost. Thus, when 

completed, Train-5 will increase the LNG 

production capacity by 42 per cent, but 

gas system operating cost will rise by 

only 14 per cent. 

Subject to receiving government approvals 

and successful marketing efforts, a 

fi nancial investment decision by the NWSV 

participants to proceed with the expansion 

is expected in the fi rst half of 2005. 

Last year, the NWSV submitted a bid for 

a contract for long-term supply (20 to 25 

years) of LNG to the Korea Gas 

Corporation (KOGAS) commencing in 2008. 

Capturing one of the three potential 

contracts (in total up to 6 Mt/a of LNG) 

would have helped an early decision on 

development of the LNG-5 Expansion 

Project. Although the NWSV was not 

successful in gaining a contract, Woodside 

has indicated that this would have no 

impact on the development timing for the 

expansion. The NWSV participants have 

targeted the predicted large shortfall in 

global LNG supplies in 2008 on the basis 

that existing and emerging markets in 

Japan, China and India could fi ll the 

additional capacity available. 

In addition to the proposed LNG 

Expansion Project, the NWSV participants 

will undertake a number of initiatives, 

in the next fi ve years, with two main 

objectives: 

• upgrading of existing, and location of 

new, resources and reserves of oil 

and gas; and

LNG carrier docking in the North West Shelf 

• ensuring that production activities 

are maintained and increased 

as required. 

The foundation for this work lies in the 

acquisition of data from a 3D seismic 

survey that was carried out from April 

2003 to February 2004. The survey, 

covering 3590 km2 (over most of the NWSV 

acreage) was the second-largest survey 

of its kind in Australia. Processing and 

interpretation of the high resolution data 

during the remainder of 2004 has been 

undertaken with the objective of defi ning 

prospects for drilling, commencing in 

2005. The total cost of work to the end 

of 2004 is $60 million. 

In the current production projection, 

the NWSV participants are undertaking 

and working towards development 

of four projects with a total estimated 

capital expenditure of approximately 

A$1.8 billion. 

In the fi rst of these developments, 

upgrading of reserves for the Wanaea– 

Cossack and Lambert–Hermes (WCLH) 

fi elds has been a priority. During 2004, 

production of oil from the fi elds was 

enhanced by drilling and tie-in of two 

infi ll wells (Wanaea-8 and Lambert-6). 

At year-end, the expected ultimate 

recovery of the WCLH fi elds had 

increased by 10.8 per cent compared to 

that at the end of 2003. 

With the additional production capacity of 

LNG Train-4 now available to meet 

increased gas demand, recycling to extract 

liquids and re-inject surplus gas back into 

the Goodwyn reservoir is no longer 

needed. Accordingly, the Goodwyn-A 

low-pressure train development has been 

implemented to meet increased gas 

deliverability from Goodwyn-A required by 

the fourth quarter of 2005. This is to be 

achieved by lowering the operating 

pressure of one of the Goodwyn-A’s two 

process trains. 

The change to a low-pressure operation 

involves a new export compressor and 

modifi cations to platform utility systems. 

An 11-day shut-down for the Goodwyn-A 

platform in conjunction with a 33-day 

shut-down for the processing train was 

undertaken in October 2004 as part of 

the ongoing low-pressure train project. 

The project was about 75 per cent 

complete at year-end. Due to operational 

constraints, the scheduled work plan has 

been revised and start-up is now 

expected in the fi rst quarter of 2006. 

The ‘Perseus over Goodwyn’ project (PoG) 

will bring the Perseus gas fi eld into 

production to fully utilise Goodwyn-A 

spare production capacity as it becomes 

available. The project received fi nal 

investment approval in December 2004 

and the development comprises a fourwell 

subsea tieback to Goodwyn-A. 

Current plans incorporate development 

of the liquids-rich Searipple reservoir 

with tieback to Goodwyn-A via the Perseus 

subsea pipeline. The PoG project is 

scheduled for start-up in the fi rst quarter 

of 2007. 

Development of the Angel gas and 

condensate fi eld, which lies some 50 km 

east of North Rankin-A, will involve the 

installation of the NWSV’s third fi xed gas 

production facility. The Angel fi eld will 

signifi cantly boost the NWS offshore 

production capabilities and ensure 

continuation of reliable long-term gas 

supplies to domestic and international 

customers. Woodside recently announced 

that the front-end engineering design 

contract for development of the fi eld had 

been awarded to the Eos Joint Venture. 

The current design concept for Angel 

comprises a three-well subsea tieback to 

a platform with a new pipeline connecting 

into the existing trunkline. The project 

has been referred for environmental 

impact assessment and remains subject 

to government approvals. A fi nal 

investment decision to proceed with the 

project is expected in the second half of 

2005 with start-up scheduled for the 

fourth quarter of 2008. 

In addition to the above, the NWSV 

participants will undertake refurbishment 

of existing facilities between 2005 and 

2010, which will require further 

expenditure of over $500 million. About 

$160 million of this will be spent offshore, 

on refurbishment of the North Rankin 

platform and $360 million will be spent 

onshore, to refurbish LNG Trains 1 to 3. 

All of the above illustrates the continuing 

progression of the NWS project – a focus 

on maximising production from existing 

assets whilst continuing to invest in 

development and exploration 

opportunities. This progression provides 

benefi ts – in the form of strong growth 

and future wealth, not only for the 

participants and their shareholders, but 

also for Western Australia and the nation. 


19


20 

THE GORGON DEVELOPMENT – 

KEY ASSESSMENT AND APPROVALS PROCESSES 

INTRODUCTION 

The proposed $11-billion Gorgon 

Development has the potential to be 

Australia’s largest oil and gas 

development. Exploration drilling in the 

Greater Gorgon area commenced in 1973 

with the discovery of the West Tryal 

Rocks gas fi eld, located approximately 

130 km off the northwest coast of 

Western Australia. However, it was not 

until 1980 that the Gorgon fi eld was 

discovered, highlighting the area as a 

world-class gas province. Subsequent 

exploration programs resulted in 

additional gas discoveries with a 

combined estimated gas resource in the 

Greater Gorgon Area of over 40 Tcf. 

The Greater Gorgon Area constitutes 

Australia’s largest undeveloped natural 

gas resource. 

In 2001, the Gorgon Joint Venture (GJV), 

comprising ChevronTexaco, Shell and 

ExxonMobil, approached the Western 

Australian Government with a proposal to 

develop the Gorgon fi elds through the 

development of a gas-processing facility 

located on Barrow Island. It was identifi ed 

as the only viable commercial site for the 

location of the gas-processing facilities 

following an extensive study and 

evaluation of alternative development 

options. 

The Gorgon development will require a 

range of infrastructure to extract and 

transport natural gas from the Greater 

Gorgon Area to Barrow Island for 

processing and delivery (see Figure 15). 

The initial development proposal includes 

the installation of: 

• Subsea gathering systems; 

• Subsea pipelines from the gas fi elds 

to Barrow Island; 

• A gas-processing facility located 

on the central-east coast of Barrow 

Island; 

• Carbon dioxide (CO ) injection 

2 

facilities; 

• Liquefi ed Natural Gas (LNG) shipping 

facilities to transport products to 

international markets; 

• Accommodation and ancillary 

supporting infrastructure; and 

• A pipeline to deliver domestic gas 

to the mainland. 

It is proposed that development of gasprocessing 

facilities on the island would 

occur via a staged approach, based on 

market demand. 

BENEFITS AND CHALLENGES 

The proposed Gorgon Development offers 

signifi cant national and Western 

Australian benefi ts, including: 

• Provision of energy security by 

securing a new gas supply hub for 

Western Australia; 

• Job creation, estimated at 6000 jobs 

of which 1700 will be based in 

Western Australia; 

• Payment of $17 billion in taxes and 

royalties to the government; and 

• Development of new skills and 

technologies with benchmarks being 

established in the areas of subsea 

development and geosequestration. 

However, the proposed Gorgon 

Development is challenging for two 

key reasons: 

1. The proposed site for locating the 

processing facility is on Barrow Island, 

an A-Class nature reserve, declared in 

1910 for high biodiversity conservation 

values. Co-locating petroleum 

development on the island is not 

unique, as Barrow Island has been 

an active oil producing fi eld since 

the 1960s. 

2. The gas from the Gorgon fi eld 

contains CO 2 , which must be removed 

from the gas stream prior 

to processing into LNG. This reservoir 

CO 2 is traditionally vented to the 

atmosphere and adds signifi cantly 

to a development’s greenhouse gas 

emissions. However, the GJV has 

undertaken to reduce these 

emissions by the disposal of reservoir 

CO 2 through injection into the 

subsurface – a technique often 

referred to as geosequestration. 

The Gorgon development has the 

potential to be the world’s largest CO 2 

geosequestration operation when it 

comes online.

Subsea tie-backs 

to Barrow Island 

Jansz Field 

Figure 15 Greater Gorgon Development Concept 

ASSESSMENT AND APPROVALS 

PROCESSES 

This summary outlines the assessment 

and approvals processes of the Gorgon 

development at a Commonwealth, State 

and Local Government level. This outline 

of the assessment and approvals process 

is not an exhaustive list, rather it captures 

key approvals processes associated with 

the Gorgon development. Whilst CO2 disposal is part of the Gorgon proposal, 

it is covered separately to highlight the 

developments in that area. 

DEVELOPMENT PROPOSAL 

The challenges associated with the 

Gorgon project were recognised at the 

outset of the proposed development. 

There were no existing processes in 

Western Australia to evaluate, at a 

strategic level, the benefi ts of allowing 

the GJV access to an A-Class nature 

reserve. In 2002, the Western Australian 

Government initiated a strategic review of 

environment, social and economic (ESE) 

aspects associated with the proposed 

Gorgon Field 

Gas Supply 

to mainland 

2 x 5 - Mt/a LNG trains 

& CO 2 Injection on 

Barrow Island 

Gorgon development. This unique review, 

established to advise the State 

Government on the implications of 

locating the processing plant on Barrow 

Island, resulted in the State Cabinet 

consenting to in-principle support for the 

proposal in September 2003. Importantly, 

in-principle support does not constitute 

or imply environmental acceptance of the 

proposal, hence formal environmental 

assessment under relevant State and 

Commonwealth environmental legislation 

is still required. (Additional information 

on the ESE process was covered in Oil 

and Gas Review 2004). 

In-principle support for the Gorgon 

proposal was formalised with the assent 

of the Barrow Island Bill and Gorgon Gas 

Processing and Infrastructure Project 

Agreement in November 2003. The Barrow 

Island Act 2003 (WA) authorises the 

implementation of a comprehensive 

agreement between the Western 

Australian Government and the GJV for 

developing the Greater Gorgon Area gas 

fi elds. The Act has a number of features 

that contribute to reducing environmental 

0 

N 

kilometres 

50 

impact and managing environmental 

outcomes of the proposal by: 

• limiting the total footprint of the project 

on Barrow Island to a maximum of 

300 ha; 

• establishing a $40 million fund, 

solely for the purpose of implementing 

a net conservation benefi t concept 

or program within a specifi ed region or 

area; and 

• including provisions which allows 

the Minister to approve and regulate 

CO disposal by injection into the 

2 

subsurface. 

In November 2003, the GJV initiated the 

State and Commonwealth Environmental 

Impact Assessment (EIA) process. 

The highest level of assessment was set 

in both jurisdictions, i.e. an environmental 

impact statement (EIS) under the 

Environmental Protection and Biodiversity 

Conservation Act 1999 (Cwlth) and an 

environmental review and management 

program (ERMP) under the Environmental 

Protection Act 1986 (WA). This led to the 

State and Federal governments agreeing 

to a parallel EIA process. If approved, the 


21


22 

outcome of the EIS/ERMP process is likely 

to be Ministerial conditions for aspects of 

the development. It is anticipated that 

Gorgon’s Draft EIS/ERMP will be released 

for public comment in mid-2005. 

The State environmental agency’s 

involvement does not cease following the 

EIA process. GJV will still require 

environmental approvals under Part V of 

the Environmental Protection Act 1986 (WA), 

specifi cally a Works Approval for 

construction and an Environmental 

Licence for operating the facility. 

Following the EIS/ERMP process and 

subject to approval, it is anticipated that 

GJV will require permits, licences and 

approvals administered by the Department 

of Industry and Resources (DoIR). This 

process requires the preparation and 

submission of applications, fi eld 

development plans, safety cases, 

environment plans etc. to meet the 

requirements of the: 

• Explosives and Dangerous Goods Act 

1961 (WA) 

• Petroleum Act 1967 (WA) 

• Petroleum Pipelines Act 1969 (WA) 

• Petroleum (Submerged Lands) Act 1967 

(Cwth) 

• Petroleum (Submerged Lands) Act 1982 

(WA) 

Local government also has a role in the 

approvals process, as planning approvals 

under the Shire of Ashburton’s Town 

Planning Scheme No. 7 are required for 

the project. 

CARBON DIOXIDE INJECTION 

The CO 2 content in the gas from the 

Gorgon fi eld is considered moderate (~14%). 

Carbon dioxide from the raw gas is captured 

and separated in the production of LNG. 

Rather than venting this reservoir CO 2 into 

the atmosphere, the GJV has proposed 

injecting the separated CO 2 into a geological 

formation located some 2.5 km beneath 

Barrow Island. This will reduce emissions 

from the Gorgon Project by between 2.6 and 

3.1 Mt/a of CO 2 equivalents. 

Currently, no generic legislation 

(international, national and State) exists 

for regulating geosequestration. A national 

group was established to address this gap 

by developing a regulatory framework for 

geosequestration. The Western Australian 

Government, through DoIR, is highly 

involved in this process. It is the intention 

of the State to apply the outcomes of the 

National Regulatory Group to the Gorgon 

development, where applicable. 

At the time of drafting the Barrow Island 

Act 2003 (WA), it was recognised that the 

absence of a regulatory instrument for CO 2 

disposal could unnecessarily delay the 

project. Consequently, the Act has 

provisions that allow the Minister 

responsible for the Barrow Island Act to 

approve CO 2 disposal on Barrow Island. 

Specifi cally, Section 13 of the Act: 

• requires the GJV to seek approval 

of the Minister responsible for the 

Barrow Island Act to dispose of CO2 on Barrow Island; 

• requires the GJV to submit an 

application detailing the proposed CO2 disposal; and 

• allows the Minister responsible for the 

Barrow Island Act to grant approval 

and place conditions on the operations. 

It should be noted that approval under the 

Barrow Island Act 2003 (WA) is subject to 

environmental approval under the 

Environmental Protection Act 1986 (WA). 

The CO2 disposal component along with all 

other aspects of the Gorgon development 

must also comply with any imposed 

Ministerial conditions. 

As a means of fully understanding the 

process and the associated risks, 

the Western Australian Government, 

through DoIR, engaged independent 

consultants to appraise the feasibility of 

geosequestering Gorgon gas beneath 

Barrow Island. To date, the fi rst two 

phases of the study have been concluded 

and it is anticipated that the third phase 

will be completed later in 2005. 

MORE INFORMATION 

Additional information on the Gorgon 

Project can be obtained from the following 

website: www.gorgon.com.au. 

The contact at the Department of Industry 

and Resources is: 

Beverley Bower 

Project Manager – Gorgon Development 

Offi ce of Major Projects 

Department of Industry and Resources 

Email: beverley.bower@doir.wa.gov.au

MAP 1: SIGNIFICANT HYDROCARBON DISCOVERIES IN WESTERN AUSTRALIA 


23


24 

MAP 2: NORTH WEST SHELF OIL AND GAS 

VARANUS AREA MAP 

John Brookes 

Montgomery 

Maitland 

BARROW 

ISLAND 

MONTE BELLO 

Wonnich 

THEVENARD AREA MAP 

Griffin 

Nimrod 

Corowa 

Ridley 

ISLANDS 

Peck 

Sinbad 

Commonwealth Jurisdiction 

State Jurisdiction 

Campbell 

Endymion 

Doric 

Bambra 

Linda 

Harriet Lee 

B 

Rose 

A C 

Rosette 

Monty 

Varanus I 

North Gipsy 

Monet Josephine-Baker 

Agincourt 

Gipsy 

Gibson-South Plato 

Simpson-Tanami 

Little Sandy-Pedirka 

Double Island Victoria 

Chinook-Scindian 

Rosily 

State Jurisdiction 

Commonwealth Jurisdiction 

Australind 

Crest 

A 

Thevenard I 

B Saladin 

Yammaderry C 

Cowle 

Roller C 

B 

A 

Coaster 

Tubridgi 

Skate 

Airlie I 

ONSLOW 

Topaz 

Chervil 

Cadell 

South Pepper 

North Herald 

Nasutus 

Oryx 

0 5 

km 

10 

0 5 

km 

10 

Tusk 

Chamois

Oil and Gas Projects and Fields 2004 

Projects are listed either under their name or under the processing facility details 

Agincourt 41 

Airlie Island 27 

Alkimos 41 

Angel 77 

Antiope 24 

Apium 37 

Arrowsmith 23 

Athena 28 

Australind 58 

Baker 43 

Bambra 44 

Bambra East 44 

Bandar 24 

Barrow Island 29 

Beharra Springs 31 

Beharra Springs North 31 

Blacktip 63 

Blencathra 78 

Blina 33 

Boundary 34 

Brecknock 73 

Brecknock South 73 

Buffalo 35 

Cadell 27 

Campbell 41 

Cape Range 24 

Capella 24 

Caretta 24 

Caribou 56 

Carnie 24 

Centella 45 

Chamois 79 

Chervil 27 

Chinook-Scindian 39 

Chrysaor 66 

Cliff Head 63 

Coaster 58 

Coniston 64 

Corallina 48 

Corowa 24 

Cornea 23 

Corvus 77 

Corybas 36 

Cossack 55 

Cowle 58 

Crest 58 

Crosby 71 

Dionysus 66 

Dixon 78 

Dockrell 78 

Dongara 36 

Doric 44 

Double Island 42 

Eaglehawk 79 

East Spar 38 

Echo-Yodel 53 

Egret 78 

Egret Deep 78 

Elegans 37 

Endymion 42 

Enfield 65 

Eremia 45 

Erregulla 23 

Eskdale 78 

Eurythion 78 

Exeter 70 

Flinders Shoal 78 

Gaea 78 

Geryon 67 

Gibson 42 

Gingin 23 

Gipsy 42 

Goodwyn 53 

Gorgon 65 

Griffin 39 

Gudrun 42 

Gungurru 78 

Gwydion 79 

Hakia 23 

Harriet 40 

Harrison 71 

Hermes 55 

Hoover 42 

Hovea 45 

Iago 67 

Ichthys 68 

Io 66 

Io South 66 

Ishmael 79 

Jansz 69 

Jingemia 47 

John Brookes 69 

Josephine 44 

Jupiter 72 

Keast 78 

Lambert 55 

Lambert Deep 55 

Laminaria 48 

Laverda 77 

Leatherback 79 

Lee 44 

Legendre 50 

Legendre North 50 

Legendre South 50 

Linda 42 

Little Sandy 42 

Lloyd 34 

Looma 23 

Macedon 70 

Maenad 66 

Maitland 78 

Mardie 79 

Mondarra 37 

Monet 42 

Montague 79 

Montgomery 24 

Monty 44 

Mount Horner 51 

Mutineer 70 

Narvik 44 


25


26 

Oil and Gas Projects and Fields 2004 

Projects are listed either under their name or under the processing facility details 

Nasutus 79 

Nimrod 79 

Norfolk 70 

North Alkimos 44 

North Erregulla 23 

North Gipsy 42 

North Gorgon 65 

North Herald 27 

North Pedirka 42 

North Rankin 52 

North West Shelf 52 

North Yardarino 36 

Novara 77 

Orthrus 66 

Oryx 78 

Outtrim 78 

Parrot Hill 24 

Pasco 24 

Peck 24 

Pedirka 43 

Penguin 78 

Perseus 53 

Petrel 74 

Phantom 24 

Pictor 23 

Pitcairn 70 

Point Torment 23 

Polkadot 23 

Prometheus 78 

Pyrenees 64 

Ravensworth 71 

Redback 23 

Reindeer 56 

Ridley 24 

Rivoli 24 

Roller 58 

Rose 44 

Rosette 43 

Rosily 24 

Rough Range 29 

Rubicon 78 

Sage 77 

Saladin 57 

Saratoga 23 

Scafell 78 

Scalybutt 7 

Scarborough 72 

Scott Reef 73 

Sculptor 78 

Searipple 77 

Simpson 43 

Sinbad 43 

Skate 58 

Skiddaw 77 

South Chervil 27 

South Pepper 27 

South Plato 43 

South Pueblo 78 

Spar 38 

Stag 56 

Stickle 71 

Stybarrow 73 

Sundown 33 

Talisman 24 

Tanami 43 

Tarantula 32 

Taunton 78 

Tern 74 

Thevenard Island 57 

Thringa 24 

Tidepole 78 

Topaz 24 

Tubridgi 59 

Turtle 78 

Tusk 78 

Ulidia 44 

Urania 66 

Varanus Island 38 

Victoria 43 

Vincent 64 

Wanaea 55 

Wandoo 60 

Warro 23 

West Dixon 78 

West Erregulla 23 

West Terrace 34 

West Tryal Rocks 65 

Wheatstone 67 

Whicher Range 74 

Wilcox 79 

Withnell 24 

Wonnich 43 

Woodada 61 

Woollybutt 62 

Xyris 37 

Xyris South 37 

Yammaderry 58 

Yardarino 37 

Yardie East 24 

Yulleroo 34

Airlie Island provided the base for the 

processing and storage of oil produced 

from the Chervil fi eld. It also served as 

the base for production from the North 

Herald and South Pepper fi elds before 

they were decommissioned in December 

1997. The island infrastructure includes 

oil-processing and water-separation 

facilities, two 150 000 bbl storage tanks, 

pipelines, a power generation plant and 

a fl are tower. 

CHERVIL 

Chervil was discovered in August 1983 

and commenced production in August 

1989 using a two-well monopod platform. 

The fi eld is currently shut-in but may 

be revived with a Chervil-7 well if new 

discoveries are tied into Airlie Island. 

It had one operating well, Chervil-6, 

which commenced production in August 

1997. The oil (44° API gravity) was 

transported to processing facilities on 

Airlie Island through a 150-mm, 7-km 

pipeline. It was then pumped via a 

508-mm, 2-km pipeline to an offshore 

tanker-loading facility and shipped to the 

BP refi nery in Kwinana for processing. 

Chervil-6 ceased production in March 

2002. The joint venture may consider 

drilling Chervil-7 to further improve the 

recovery from the fi eld. 

POTENTIAL DEVELOPMENTS 

The joint venture is continuing to examine 

potential developments within the permit 

area with the aim of extending production 

operations on Airlie Island. The Airlie 

facilities may also have an ongoing value 

as a storage facility for other oil and 

gas projects. 

CADELL 

The Cadell-1 well, located 7 km from 

Airlie Island in TP/7, intersected a 75-m 

gas-column in November 1999. The joint 

venture estimates that the fi eld contains 

gas reserves of 0.5–1 Bcm (20–40 Bcf). 

Subject to further detailed analysis, 

Cadell is unlikely to be economic for 

a stand-alone development. 

SOUTH CHERVIL 

In November 1983, the South Chervil- 

1 well intersected a 3.5-m oil-column 

overlain by a 10-m gas-cap and tested 

a separate structure to Chervil. Around 

one-third of the fi eld lies in TL/2 with the 

remainder in TP/7. South Chervil may be 

developed using a single well, similar to 

the approach undertaken with Chervil-6, 

and tied back to production facilities on 

Airlie Island. 

Location 

35 km north of Onslow 

Basin 

Carnarvon, offshore 

OPERATING PROJECTS 

Permit/Licence 

TP/7, TL/2 

Ownership TL/2 TP/7(Pts 1–3) TP/7 (Pt 4) 

Apache Oil Australia Pty Ltd (Operator) 51.834% 39.658% 64.658% 

Pan Pacifi c Petroleum (South Australia) 

Pty Ltd 23.166% 4.157% 4.157% 

Santos (BOL) Pty Ltd 15.000% 43.711% 18.711% 

Tap (Shelfal) Pty Ltd 10.000% 12.474% 12.474% 

Contact 

Apache Energy Limited 

Level 3, 256 St Georges Terrace 

PERTH WA 6000 

Tel: +61 8 9422 7222 Fax: +61 8 9422 7447 

Web: www.apache-energy.com.au 

Average oil production (bbl/d) 

7,000 

6,000 

5,000 

4,000 

3,000 

2,000 

1,000 

0 

Jan 94 

Jan 95 

Jan 96 

Jan 97 

Chervil, North Herald and South Pepper 

TAUNTON 

Taunton-2 was drilled in December 2002. 

It discovered 5.7-m and 1.4-m gross 

oil-columns (4.9 m and 1.3 m net) within 

the P. burgeri (Birdrong Sandstone) 

and upper Barrow Group respectively. 

Taunton-2 L1 horizontal sidetrack tested 

49 o API oil at rates up to 2783 bbl/d 

accompanied by 251 bbl/d of water and 

2.05 TJ/d of gas. Taunton-3, drilled in 

August 2003, encountered 6.1-m gross 

(5.8-m net) oil-pay in the Birdrong 

Sandstone and sidetrack well, 

Taunton-3 L1, encountered 4.6-m gross 

and net oil-pay, also in the Birdrong 

Sandstone. 

Taunton-4 was drilled in 2004 on the 

south-western fl ank of the fi eld and 

Jan 98 

Jan 99 

Airlie Island Oil 

Jan 00 

Jan 01 

Jan 02 

found the shallowest part of the structure 

at both Top P. burgeri sandstone and Top 

Barrow Sandstone. The well established 

that the Barrow Sandstone and P. burgeri 

sandstone reservoirs are separated by an 

effective sealing shale. 

One further well, Blackthorn-1, was also 

drilled in 2004 on the southern fl ank of 

the fi eld to test a potential extension 

of the fi eld outside the mapped time 

closure. The well penetrated a thin 

section of P. burgeri sandstone and 

identifi ed for the fi rst time an OWC for 

the P. burgeri reservoir. The Barrow 

Sandstone was water-saturated. 

Economic and technical studies are being 

carried out to assess the viability of the fi eld. 

project details 


27



28 


Athena Gas and Condensate 

Location 

134 km northwest of Dampier 

Basin 



WA-17-L 

Ownership 

Mobil Australia Resources Company Pty Ltd (Operator) 50% 

Phillips Oil Company Australia 50% 

Contact 

ExxonMobil Australia Pty Ltd 

12 Riverside Quay 

SOUTHBANK VIC 3006 

Tel: +61 3 9270 3333 Fax: +61 3 9270 3493 

Web: www.exxonmobil.com 

The Athena fi eld was discovered in 

October 1997 and is an extension of the 

North West Shelf Gas project’s Perseus 

gas fi eld. The Athena-1 well was drilled 

in a water depth of 120 m and reached a 

total depth of 3364 m. The well was tested 

over four zones and achieved a combined 

fl ow rate of 1340 kcm/d (47.4 MMcf/d) of 

gas and 2133 bbl/d of condensate. 

A production licence over the Athena fi eld 

was awarded in January 1999. 

In early March 2001, Mobil Australia 

Resources Company Pty Ltd and Phillips 

Australia Gas Holdings Pty Ltd signed 

an agreement with the North West Shelf 

Venture participants in relation to the 

development of the Perseus–Athena gas 

fi eld. Under the agreement, Woodside 

Energy Ltd. as operator of the North West 

Shelf Venture, is producing gas from the 

WA-17-L permit on behalf of the permit 

holders. Production is through the North 

Rankin A production facility and the 

term of the contract is for the life of the 

Perseus fi eld. 

The Athena fi eld commenced production 

in late 2001.

The Barrow Island oil fi eld was discovered 

in July 1964 beneath the 233 km 2 island 

and is the largest oil fi eld discovered 

in Western Australia. Production 

commenced in April 1967 and peaked at 

50 000 bbl/d in 1971. Barrow Island was 

originally envisaged to have a 30-year life, 

but as a result of careful management of 

the reservoirs using more than 800 oil- 

and water-injection wells, the life of the 

fi eld has been extended until 2019. 

The joint venture estimates that the fi eld 

will have produced 330 MMbbl of oil by 

2019, approximately a third of the known 

oil-in-place. At midnight on 20 October 

2003, the 300-millionth barrel was loaded 

onto the ship Olympic Symphony. This was 

a signifi cant milestone for the Barrow 

Island operations. 

In February 2000, Chevron Australia 

assumed the operatorship of Barrow 

Island from West Australian Petroleum 

Pty Ltd (WAPET) and in 2001, Shell 

Development (Australia) Pty Ltd 

completed the sale process of its Barrow 

exploration and production assets to 

Santos Offshore Pty Ltd. In October 2001, 

Chevron and Texaco merged to form 

ChevronTexaco Corporation. 

In December 2003, ChevronTexaco 

celebrated the 50th anniversary of 

Australia’s fi rst signifi cant oil discovery. 

On 4 December 1953, Standard 

Oil Company of California (SOCAL) 

announced Australia’s fi rst signifi cant oil 

discovery by WAPET at Rough Range near 

Exmouth. 

WAPET was owned 80 per cent by Caltex 

(itself jointly owned by Texaco and SOCAL, 

later to become Chevron) and 20 per cent 

by AMPOL Petroleum. The Rough Range 

discovery launched a major exploration 

campaign by WAPET across northern 

Western Australia, leading to the 

discovery of oil at Barrow Island in 1964. 

In 2000, prior to its merger with Texaco in 

2001, Chevron assumed responsibility for 

WAPET’s operations in Australia. 

PRODUCTION FACILITIES 

Barrow Island currently consists of 

454 oil-production wells (mostly in the 

Windalia reservoir), 268 water-injection 

wells, and a number of gas-producer 

and water-disposal wells. In the majority 

of producing wells, oil is pumped to the 

surface using beam pumps (nodding 

Location 

88 km north of Onslow 

Basin 

Carnarvon, onshore and offshore 


L1H, WA-7-L, L10, TL/3, TPL/9 

EP 61, EP 62, TP/2 

Ownership 

ChevronTexaco Australia Pty Ltd (Operator) 28.57% 

Texaco Australia Pty Ltd 28.57% 

Santos Offshore Pty Ltd 28.57% 

Mobil Australia Resources Company Pty Ltd 14.29% 

Contact 


Level 24, QV1 Building 

250 St Georges Terrace 

PERTH WA 6000 

Tel: +61 8 9216 4000 Fax: +61 8 9216 4444 

Web: www.chevrontexaco.com 

Production 2003 2004 

Oil (bbl) 3 306 611 3 001 612 


16,000 

14,000 

12,000 

10,000 

8000 

6000 

4000 

2000 

0 

Jan 94 

Jan 95 

Barrow Island 

Jan 96 

Jan 97 

Jan 98 

donkeys). The remaining producing wells 

use gas-lift or are on natural fl ow. 

The fl uids produced from each well are 

piped to one of ten separator stations, 

each capable of handling up to 60 wells. 

A typical separator station has an oil 


Jan 99 

Barrow Island Oil 

Jan 00 

Jan 01 

Jan 02 

Jan 03 

Jan 04 

storage tank and a tank in which 

produced water settles before being 

piped to a deepwater disposal facility 

for re-injection into reservoirs. Clean 

oil is pumped from the stations to the 

main oil storage facility, comprising fi ve 



29


30 


Barrow Island Oil 

Aerial view of Barrow Island 

200 000 bbl oil tanks. At present, only 

three of the tanks are in service. The oil 

(37.7 o API gravity) is then transported via 

a 508-mm, 10.4-km submarine pipeline 

to an offshore mooring system, where 

tankers are berthed for loading. 

In February 1999, the joint venture 

announced that the facilities on Barrow 

Island could be utilised by third parties 

for processing oil and gas production 

from nearby operations. 

RESERVOIRS 

Barrow Island contains at least 30 

different reservoirs of oil and gas. 

Currently there are eight oil-producing 

Formations, with the Windalia reservoir 

containing 95 per cent of known reserves. 

All producing reservoirs are continuously 

assessed as part of the Barrow Island 

Development Plan, a multi-disciplinary 

study aimed at optimising well production 

performance and increasing the mature 

fi eld’s reserves. The ongoing study 

includes re-completions, additional 

infi ll and extension drilling, workovers, 

refracture stimulation, artifi cial lift 

optimisation and facility expansion. 

Production from the Windalia reservoir 

is by way of secondary recovery 

conditions known as ‘water-fl ooding’. 

Water is injected into 268 wells to 

displace oil towards producing wells. 

The joint venture estimates that there 

are signifi cant amounts of oil remaining 

in the ground, and while some will be 

recovered with the existing water-fl ood 

technique, it presents a major challenge 

to develop innovative tertiary recovery 

techniques. Non-water-fl ood reserve 

potential is also under review and 

includes the Windalia extension areas 

around the fl anks of the fi eld, as well 

as the development potential in other 

reservoirs under Barrow Island. 

DEVELOPMENT AND EXPLORATION 

DRILLING 

Since 1995, a total of 76 infi ll wells 

have been drilled in Windalia reservoir 

on Barrow Island, and water-injection 

volumes increased from less than 

50 000 bbl/d to in excess of 90 000 bbl/d. 

These strategies are designed to increase 

the fi eld life and enhance oil recovery 

from the reservoir.

The Beharra Springs fi eld was discovered 

in April 1990 and commenced production 

in January 1991 using a temporary 

production facility. The fi eld operates with 

three producing wells. 


A $9.4-million permanent gas-processing 

plant, with a capacity of 15 TJ/d, was 

commissioned in May 1992 and replaced 

the temporary facility. Plant capacity 

was increased to 25 TJ/d following the 

completion of a $2.2-million expansion in 

November 1993. Compression facilities 

were commissioned in 1996 at a cost of 

$8 million. Production rates in excess of 

30 TJ/d have been achieved through the 

more effi cient use of existing equipment. 

The gas-processing plant features low 

temperature separation for the removal 

of condensate and water from the 

natural gas. In addition, semi-permeable 

membranes purify the gas for sale by 

removing carbon dioxide and hydrogen 

sulphide. Treated gas is pumped via a 

168-mm, 1.6-km pipeline lateral into 

the Parmelia pipeline and is delivered to 

customers at that point. Condensate 

(62° API gravity) is stored in a 600-bbl 

tank and is then trucked to the BP 

refi nery in Kwinana for processing. 

GAS SALES CONTRACT 

An initial gas sales contract with Alcoa 

was signed in 1990 for the supply of up 

to 39.5 PJ of gas at rates of up to 15 TJ/d 

from January 1991 to January 2002. 

A second contract with Alcoa was signed 

in April 1991 for additional gas supplies 

of up to 40.5 PJ from January 1996. It was 

also agreed that Alcoa could accelerate 

its gas offtake up to 25 TJ/d over the 

initial period. As a result, total gas sales 

far exceeded the contractual take-or-pay 

requirement since mid-1992. In 1998, 

Alcoa chose to cut its offtake to 8 TJ/d. 

Following a re-negotiation of the Gas 

Sales contract in late 1999, this offtake 

increased and was maintained at 17.5 TJ/d 

for most of 2000. This contract expired in 

January 2002. A later arrangement with 

Alcoa commenced in May 2002 to supply 

gas at rates up to 8 TJ/d . 

Currently the fi eld deliverability is fully 

contracted with supply to customers in 

the Perth region and further south. 


Beharra Springs Gas and Condensate 

Location 

350 km north of Perth 

Basin 

Perth, onshore 


EP320, L11, PL/18 

Ownership 

Origin Energy Developments Pty Ltd* (Operator) 67% 

ARC (Beharra Springs) Pty Ltd** 33% 

* a wholly owned subsidiary of Origin Energy Limited 

** a wholly owned subsidiary of ARC Energy Limited 

Contact 

Origin Energy Developments Pty Ltd 

34 Colin Street 

WEST PERTH WA 6005 

Tel: +61 8 9324 6111 Fax: +61 8 9321 5457 

Web: www.originenergy.com.au 


Gas (kcm) 108 286 85 180 

Condensate (bbl) 6 305 5 461 

Average condensate production (bbl/d) 

120 

100 

80 

60 

40 

20 

0 

Jan 94 

Jan 95 

Jan 96 

Gas 

Condensate 

Beharra Springs 

Jan 97 

Jan 98 

Jan 99 

Jan 00 

Jan 01 

Jan 02 

Jan 03 

Jan 04 

1,200 

1,000 

800 

600 

400 

200 

0 

Average gas production (kcm/d) 



31


32 


Beharra Springs Gas and Condensate 

Beharra Springs 

EXPLORATION DRILLING 

The Mungenooka-1 well, located 

10 km northeast of Beharra Springs, 

was drilled in June 1998 and intersected 

a tight gas-column. The well was plugged 

and suspended for possible re-entry, 

however a re-evaluation of well results 

concluded that the commercial potential 

was minimal. The well was plugged and 

abandoned in July 2000. 

A 3D seismic survey covering the L11 

licence area and parts of the surrounding 

EP320 permit was completed in August 

1999. On the basis of this data Beharra 

Springs North-1 and South-1 were drilled 

in the second half of 2001. Beharra 

Springs North-1 intersected a gross 

gas-column of 28 m. Subsequent testing 

of the well produced gas fl ow rates of up 

to 30 MMcf/d. 

Beharra Springs South-1 was plugged 

and abandoned. Beharra Springs North- 

1 commenced production in August 2002. 

The gas exploration well, Tarantula-1, 

commenced drilling in late May 2004. 

The well reached the primary target of 

the Wagina Formation in early June 2004. 

On penetration of the target a signifi cant 

increase in rate of penetration and a 

gas peak was observed. Preparation 

was then made to pull out of the hole to 

commence coring. During this procedure 

the well commenced to fl ow gas to 

surface and the well was not able to be 

secured. All personnel were evacuated 

and perimeters secured. 

The well was brought under control in 

late June 2004 and operations to secure 

and suspend the well commenced. 

A sidetrack from the Tarantula-1 well bore 

is being planned with commencement 

expected in fi rst quarter 2005. 

Early in 2004 Redback-1 was drilled to 

the east of the Beharra Springs Field 

on the downthrown side of the main 

fi eld-bounding fault. While fractured, low 

matrix porosity was encountered in the 

target zone of the Wagina Formation and 

the well was plugged and suspended for 

possible future re-entry.

Kimberley Oil took over as operators and 

interests in the exploration and 

production licences covering the Blina– 

Boundary–Lloyd–Sundown–West Terrace 

fi elds from Capital Energy in March 1999. 

Kimberley Oil also took over the direct 

management of the operations from 

Gearhart Australia Ltd in December 1999. 


The Blina fi eld produces into the Blina 

Battery where the oil and water are 

separated, and the oil is stored in two 

tanks. It is then transported via a 

114-mm, 29-km underground pipeline to 

the Erskine truck-loading terminal on the 

Great Northern Highway for storage in 

two tanks. The other fi elds produce oil via 

well fl owlines into the Meda Battery, 

which consists of four storage tanks. 

Oil (30–38° API gravity) from the Erskine 

Terminal and Meda Battery is transported 

by trucks 220 km to Broome where it is 

stored in a 120 000 bbl tank. 

PRODUCING FIELDS 

Kimberley Oil considers that the areas in 

and around the existing fi elds present 

opportunities for further commercial 

accumulations. As a result, work is 

continuing to delineate potential 

prospects for drilling in 2004. 

Infrastructure is in place, which will allow 

any new discovery to be brought onstream 

quickly and economically. 

Blina 

The Blina fi eld, located 105 km southeast 

of Derby, was discovered in May 1981 and 

commenced production in September 

1983. Eight wells have been drilled in the 

fi eld, three of which are currently 

producing. 

Sundown 

The Sundown fi eld, located 26 km 

northwest of Blina, was discovered in 

November 1982 and commenced 

production in July 1984. Sundown is 

currently producing from one well only, 

Sundown-3H. 


Blina–Boundary–Lloyd–Sundown–West Terrace Oil 

Location 

80 km east of Derby 

Basin 

Canning, onshore 


EP129, L6, L8, PL/7 

Ownership 

Producing Fields 

Kimberley Oil NL 100% 

Deep Rights Area 

Kimberley Oil NL 100% 

Contacts 

Kimberley Oil NL 

Suite 12B, 573 Canning Hwy 

ALFRED COVE WA 6154 

Tel: +61 8 9330 8876 Fax: +61 8 9330 8896 

Email: ko@iinet.net.au 

Production – Oil (bbl) 

Field 2003 2004 

Blina 12 286 9 624 

Boundary 2 679 2 197 

Lloyd 2 009 1 564 

Sundown 2 182 2 062 

West Terrace 11 466 9 231 

TOTAL 30 622 24 678 


450 

400 

350 

300 

250 

200 

150 

100 

50 

0 

Jan 94 

Jan 95 

Jan 96 

Jan 97 

Jan 98 

Blina, Boundary, Lloyd, Sundown and West Terrace 

Jan 99 

Jan 00 

Jan 01 

Jan 02 

Jan 03 

Jan 04 



33


34 


Blina–Boundary–Lloyd–Sundown–West Terrace Oil 

West Terrace 

Located 8 km north of Sundown, the West 

Terrace fi eld commenced production in 

June 1985 from one well. A second well 

was drilled and produced oil for a short 

time in 1987 before being abandoned 

because of what was considered then to 

be excessive water cut. The well was 

brought back on production in 2001 and is 

now out-producing West Terrace-1. 

Lloyd 

The Lloyd fi eld, located 30 km from Blina, 

was discovered in July 1987 and 

commenced production a month later 

from one well. A second well, Lloyd-3, 

was put on an extended test in August 

1998 and signifi cantly increased the 

output from the fi eld. Lloyd-3 has now 

ceased production. 

Boundary 

Located 2.2 km south of Lloyd, the 

Boundary fi eld was discovered in August 

1990 and commenced production in 

December 1990 from one well. 

OTHER PROSPECTS 

Kimberley Oil has concluded a farm-in 

agreement with Golden Dynasty 

Resources, a Canadian-listed company, 

to drill Boundary Southeast-1 over an 

anticlinal closure to the southeast of 

Boundary-1 with potential for discovery of 

oil in the Grant and Anderson Formations. 

This well is scheduled to be drilled during 

the 2005 dry season. 

Outside of the EP129/L6/L8 area, but also 

within the Canning Basin, the company is 

endeavouring to farm-out its Yulleroo and 

Ungani Prospects in EP371 where there is 

potential for the discovery of large gas– 

condensate accumulations. A farm-out of 

the Pictor horizontal drilling opportunity is 

also being offered. The Pictor Anticline 

occurs in EP431 which was granted in 

December 2004. Successful oil and gas 

recovery has been achieved from this 

structure in previous exploration wells and 

the company is of the opinion that the 

Pictor Anticline has strong potential to yield 

economic oil recoveries in horizontal wells. 

Oil-in-place is estimated at 164 MMbbl. 

The Company has also accepted the offer 

of Release Area L04-5 in the northern 

Perth Basin and this area will be formally 

granted upon the Company reaching 

agreement with the native title claimants 

within the area. The Release Area 

contains the Walyering Deep Coal Seam 

Methane Prospect where gas-in-place is 

estimated at 300 Bcf. The gas is 

reservoired in coal seams of the 

Cattamarra Coal Measures adjacent to 

the Parmelia Pipeline.

The Buffalo oil fi eld, located 9 km 

southeast of Laminaria in the Timor 

Sea, was discovered in October 1996 and 

commenced production in December 

1999. The fi eld contained proved oil 

reserves of approximately 21 MMbbl. 

Buffalo crude is a light oil (53.3° API 

gravity) with a gas-oil ratio of 3.4 m 3 /bbl 

(120 cf/bbl). 

The fi eld reached its economic limit in the 

fourth quarter of 2004. The FPSO was 

demobilised from Buffalo on 9 December 

2004. The remaining infrastructure 

including the WHP and fi xed pipelines 

will be removed in fi rst quarter 2005. 

Nexen Petroleum Australia Pty Limited 

(formerly Canadian Petroleum Australia 

(Operations) Pty Ltd) is the 100 per cent 

owner and operator of the fi eld effective 

from 1 July 2001. 


Location 

560 km northwest of Darwin 

Basin 

Bonaparte, offshore 


WA-19-L, WA-21-L 

Ownership 

Nexen Petroleum Australia Pty Limited 100% 

Contact 

Nexen Inc 

801, 7th Avenue S.W. 

Calgary, Alberta 

Canada T2P3P7 

Tel: +1 403 699 4000 Fax: +1 403 699 5800 

email: nexenaustralia@nexeninc.com 

Web: www.nexeninc.com 



50,000 

40,000 

30,000 

20,000 

10,000 

0 

Jan 00 

Jul 00 

Buffalo 

Jan 01 

Jul 01 

Jan 02 


Jul 02 

Jan 03 

Jul 03 

Buffalo Oil 

Jan 04 

Jul 04 



35



36 


Dongara–Mondarra–Yardarino–Xyris–Apium–Elegans 

Gas, Oil and Condensate 

Location 


Basin 



L/1, L/2, PL/1, PL/2 

Ownership 

Production Licences 

Dongara–Yardarino–Elegans 

ARC Energy Limited (Operator) 100% 

Xyris–Apium 


Origin Energy Developments Pty Limited 50% 

Contact 

ARC Energy Limited 

Level 4, 679 Murray Street 


Tel: +61 8 9486 7333 Fax: +61 8 9486 7322 

Email: arc@arcenergy.com.au 

Web: www.arcenergy.com.au 

Ownership/Contact 

Pipeline Licences, Gas-processing Facilities, Mondarra Storage Facility 

Australian Pipeline Trust (Operator) 100% 

8 Marchesi Street 

KEWDALE WA 6105 

Tel: +61 8 9353 7500 Fax: +61 8 9353 2452 

Email: acmswa@cmsenergy.com.au 

Web: www.cmsenergy.com.au 



Oil (bbl) 2 965 2 488 


Average oil and condensate production (bbl/d) 

100 

80 

60 

40 

20 

0 

Jan 94 

Jan 95 

Jan 96 

Jan 97 


Oil and Condensate 

Jan 98 

Dongara–Mondarra–Yardarino 

Jan 99 

Jan 00 

Jan 01 

Jan 02 

Jan 03 

Jan 04 

600 

500 

400 

300 

200 

100 

0 


FIELD HISTORIES 

The Yardarino fi eld was the fi rst fi eld 

discovered in the north Perth Basin in 

May 1964 and was followed by discoveries 

at Dongara in June 1966 and 

Mondarra in 1968. First gas deliveries 

from the Dongara fi eld commenced in 

October 1971 via the Parmelia Pipeline. 

The Mondarra fi eld commenced 

deliveries in April 1972 and ceased 

production in July 1994. The Yardarino 

fi eld came on-stream in October 1978 and 

ceased production in April 1989. 

Subsequently gas discoveries have been 

made at Xyris and Xyris South and 

Corybas (Elegans Pool). 

THE DONGARA FIELD 

The Dongara fi eld lies 360 km north of 

Perth. ARC owns 100 per cent of the fi eld 

which was discovered in 1966 by WAPET. 

It is a world-class fi eld with original 

reserves in excess of 480 PJ of 

recoverable gas and some 100 MMbbl of 

oil-in-place. 

Dongara Sandstone Pool 

The Dongara Sandstone is the principal 

producing reservoir in the fi eld and has 

produced the majority of the reserves in 

the fi eld to date. The current production 

is some 3 to 5 TJ/d of gas from the 

Dongara Sandstone Pool. 

Arranoo Pool 

The Arranoo reservoir is a unit of thinly 

bedded sandstones and siltstones with an 

overall thickness of 80 m in the upper 

part of the Kockatea Shale. It has been 

recognised as an oil and gas reservoir 

since the early development of the 

Dongara fi eld. Two wells, Dongara-9 and 

Dongara-24A, have produced a total of 

3.5 Bcf of gas and 40 000 bbl of oil. 

Permeabilities in the reservoir are 

generally low and two new development 

wells, Dongara-31 and Dongara-32, were 

designed to intersect the reservoir at 60 o 

and have had an additional lateral added 

to the well bore. Current production is 

approximately 5 TJ/d from the Arranoo 

Sandstone Pool. 

DONGARA OIL LEG 

The original in-place reserves of the 

Dongara fi eld were estimated to be in 

excess of 60 MMbbl of oil and some 

500 Bcf of gas.

Due to the fact that the existence of the 

oil leg was not recognised until a 

commitment to produce the gas had been 

made, the production technique used to 

produce the fi eld has “smeared” the oil 

through the reservoir and made a large 

amount of it unrecoverable. 

Due to the low oil recoveries, this form of 

production would not be either allowable 

or economically sensible in the modern 

regulatory and technical environment. 

The possibility of oil recovery from the 

Dongara oil leg will also be reviewed in light 

of the experience gained with production at 

the Hovea and Eremia fi elds. 

DONGARA GAS RESERVES 

A further reserves review has not been 

carried out during the year as the wells 

continue to produce in accordance with 

the predictions of the last reserves report 

as at 1 July 2002. At this stage of the 

fi eld’s life ultimate economically 

recoverable reserves estimates are 

strongly infl uenced by engineering 

considerations such as well lift 

performance, availability of wellhead 

compression, compressor and pipeline 

inlet pressures, etc. These parameters 

may be infl uenced by further gas 

developments in the Licences and a 

further reserves estimate will be 

undertaken when more of these 

parameters have been fi nalised. 

PRODUCTION AND 

TRANSPORTATION FACILITIES 

Twenty-nine wells have been drilled on, 

or near, the Dongara fi eld of which four 

are currently in production. Gas from 

these wells is transported by fl owlines 

to gas-processing facilities and, after 

treatment to remove liquids, is 

compressed and transported down the 

Parmelia Pipeline. 

Australian Pipeline Trust (APT) owns and 

operates the gas-processing facilities and 

is responsible for transportation of the 

processed gas to sales outlets via the 

Parmelia Pipeline. ARC Energy owns the 

Dongara fi eld (L/1 and L/2) and has an 

agreement with APT for it to process and 

transport its gas at an agreed toll fee. 

The gas-processing plant includes 

three-stage gas compression, primary 

fl uid separation and glycol dehydration, 

a water treatment and disposal plant, 

an oil-condensate storage and loading 

plant, and well-testing equipment. 

The 350-mm, 420-km high-pressure 

Parmelia Pipeline, which extends from 

Dongara to Pinjarra, has a design gas 

capacity of around 124 TJ/d and currently 

transports about 30 TJ/d. 

ARC Energy installed a wellhead 

compressor on the Dongara-18 well 

during 2002 to assist in ultimate reserve 

recovery and installed another one on 

Dongara-23 during 2004. 

GAS SALES CONTRACTS 

ARC Energy currently supplies gas to 

Midland Brick and other industrial 

companies in Perth. 

Sale of gas continued to exceed 

expectations during the year with backup 

gas continuing to be purchased to 

ensure that current demand is met. 

The commencement of production from 

the Xyris fi eld means all ARC’s contracts 

are now supplied from its fi elds. 

YARDARINO GAS FIELD 

The Yardarino gas fi eld is a separate 

gas and oil accumulation lying to the 

northeast of Dongara. It has produced 

some 5 Bcf of gas and is currently shut-in 

pending acquisition of additional 3D 

seismic data over this structure. 

ELEGANS GAS FIELD 

The Elegans gas fi eld was discovered by 

the deepening of the existing Yardarino-1 

well in 1999. This well produces at rates 

of up to 0.5 TJ/d of gas. The fi eld contains 

over 400 Bcf of gas in place in relatively 

tight sandstones of the Caryinginia and 

Irwin River Formations. The recent 

Corybas well has demonstrated the 

commercial potential of this resource 

having fl owed gas on test at up to 

4 MMcf/d. 

XYRIS AND APIUM GAS FIELDS 

In March 2004, the Xyris-1 well was 

drilled and intersected a signifi cant gascolumn, 

which subsequently fl owed at 

rates of up to 15.5 MMcf/d. The following 

well, Apium-1 also intersected a gascolumn 

and tested at a rate of 1.9 MMcf/d 

through a 20/64ths choke. The Xyris 

discovery has since been brought into 

production at up to 10 TJ/d of sales gas 

through a simple gas-processing system. 

The development of the other gas 

reserves in the area including Xyris 

South, Apium, Hovea-2 and Hovea 


associated gas will be undertaken in early 

2005 with the Xyris area gas-gathering 

System (XAGGS) project. 

Production – Xyris 2004 

Gas (kcm) 9 748 

Condensate (bbl) 541 


The Company has a continuous drilling 

program for wells which over the past 

year is as follows: 

Of the total 12 wells drilled there were 4 

development and 8 exploration with an 

overall success rate of 5 in 8. In the 3D 

gas area, the success rate was 5 out of 6. 

WELL RESULT 

Eremia-2 Oil Development 

Kingia-1 Exploration - Dry 

Redback-1 Exploration - gas shows 

Xyris-1 Exploration Gas Discovery 

Jingemia-4 Oil Development 

Apium-1 Exploration Gas Discovery 

Tarantula-1 Exploration Gas Discovery 

Agonis-1 Exploration - gas shows 

Centella-1 Exploration Oil Discovery 

Hovea-11 Oil Development 

Xyris South-1 Gas Discovery 

Dongara-31 Gas and Oil Appraisal 

MONDARRA GAS STORAGE FACILITY 

The depleted Mondarra fi eld was retained 

by APT at the time of the sale of the 

Dongara and Yardarino fi elds to ARC 

Energy, in order for it to be developed as 

the Mondarra gas-storage facility. 

APT is continuing to evaluate the 

commercial and technical feasibility 

of developing the depleted Mondarra 

fi eld into a natural gas-storage facility 

for service in the Western Australian 

natural gas industry. The Mondarra 

fi eld is considered well suited as 

a gas-storage facility due to its close 

proximity to both the Dampier to Bunbury 

Natural Gas Pipeline (DBNGP) and the 

Parmelia Pipeline. 


37



38 


East Spar Gas and Condensate 

Location 

40 km west-northwest of Barrow Island 

Basin 



WA-214-P, WA-13-L, WA-5-PL, TPL/12, TPL/13, PL/29, PL/30, PL/42 

Ownership 

Apache Oil Australia Pty Ltd (Operator) 25% 

Apache East Spar Pty Ltd 25% 

Apache Kersail Pty Ltd 5% 

Santos (BOL) Pty Ltd 45% 

Contact 

Apache Energy Ltd 


PERTH WA 6000 

Tel: +61 8 9422 7222 Fax: +61 8 9422 7447 

Web: www.apachecorp.com 



Condensate (bbl) 1 909 232 1 560 832 


8,000 

7,000 

6,000 

5,000 

4,000 

3,000 

2,000 

1,000 

0 

Jan 97 

Jan 98 


Condensate 

East Spar 

Jan 99 

Jan 00 

The East Spar fi eld was discovered in 

April 1993 and commenced production in 

November 1996. Total capital cost of the 

development was $250 million. 


East Spar comprises Australia’s fi rst 

fully-automated all-subsea production 

and gathering system operated via an 

unmanned navigation control and 

Jan 01 

Jan 02 

Jan 03 

Jan 04 

4,000 

3,500 

3,000 

2,500 

2,000 

1,500 

1,000 

500 


communication (NCC) buoy. Controlling 

an entire subsea facility via an unmanned 

NCC buoy was a world-fi rst. Electrohydraulic 

umbilicals connect the buoy to 

all control and monitoring devices on the 

subsea components. A telemetry 

communication system, with radio and 

satellite links, allows the remote control 

of the offshore facilities from a 

0 

computerised master control system on 

Varanus Island. The buoy also includes 

chemical storage for corrosion and 

hydrate inhibitors, which are injected via 

umbilicals into the wellheads. 

Gas and condensate are currently 

produced from two wells, which, after 

cooling in heat exchangers are conveyed 

to a manifold via 1.8-km, 150-mm fl exible 

fl owlines. Provision for the tie-in of two 

further wells and a future pipeline from 

another fi eld is included in the manifold 

design. The combined wet gas production 

fl uid is transported from the manifold via 

a 356-mm, 63-km carbon-steel pipeline 

to processing facilities on Varanus Island. 

VARANUS ISLAND PROCESSING 

FACILITIES 

In November 1996, two 120 TJ/d gasprocessing 

trains were commissioned 

on Varanus Island adjacent to the two 

existing 60 TJ/d trains and the recently 

commissioned single 120 TJ/d train 

used by the Harriet Joint Venture. 

The processing trains remove 

condensate, water and other minor 

impurities from the gas, conditioning it 

to pipeline specifi cations. Sales gas is 

then transported to the mainland through 

either of two 100-km sales-gas pipelines 

(324 or 406 mm) connecting with the 

DBNGP and Goldfi elds gas transmission 

(GGT) pipeline at Compressor Station 

No.1. The 406-mm gas-pipeline, 

with a capacity in excess of 300 TJ/d, 

was commissioned by the East Spar 

(70 per cent) and Harriet (30 per cent) 

joint ventures in July 1999. Condensate 

(58° API gravity) is stored in existing tanks 

on Varanus Island and exported via tanker. 

The East Spar and Harriet joint ventures 

entered into an infrastructure-sharing 

agreement in January 1997 whereby the 

Harriet gas transportation and liquids 

storage facilities on Varanus Island could 

be utilised by the East Spar joint venture. 

In addition, the two joint ventures agreed 

to share the cost of all operating 

resources and contract services such 

as supply boats and helicopters. This was 

the fi rst infrastructure-sharing 

agreement made in the North West Shelf 

gas province.

The Griffi n oil and associated gas 

development comprises the Griffi n and 

Chinook–Scindian fi elds which were 

discovered in 1989–90. First oil production 

from Griffi n commenced in January 1994, 

with production from Chinook–Scindian 

starting in March 1994. 

Initial recoverable oil reserves were 

estimated at 115–130 MMbbl, however in 

2003, production exceeded 150 MMbbl. 

Total capital cost of the development was 

A$720 million. 


The Griffi n development utilises the 

100 000 dwt double-hulled Griffi n 

Venture FPSO facility, which comprises 

a disconnectable mooring riser and 

production system. All production is from 

subsea-well completions linked back to 

the centrally located FPSO via fl exible 

fl owlines. The vessel and its mooring riser 

system are confi gured to accommodate 

a total of 11 production wells. The FPSO 

stores up to 820 000 bbl of oil, which is 

then pumped to stern-moored offtake 

tankers through a fl oating hose system 

at a rate of 25 000 bbl/h. Cargoes of the 

light Griffi n crude (55° API gravity) are 

sold to markets in Australia, Singapore 

and Japan. 

GAS-PROCESSING FACILITIES 

The Griffi n Venture also has gas-processing 

facilities on board which makes commercial 

use of the associated gas produced with the 

oil. This gas is sold into the domestic gas 

pipeline system, used as gas-lift or used 

as fuel on the FPSO, except when safety 

dictates that fl aring is necessary. 

Gas is transported from the FPSO to 

shore via a 200-mm, 68-km pipeline. 

Up until January 2001, Griffi n Gas was 

processed at the Griffi n Gas Treatment 

Plant. Located about 30 km southwest 

of Onslow, the plant commenced full 

operations in November 1994. It processed 

the gas-to-sales-specifi cation standards 

by removing unwanted inert gases, such 

as nitrogen and carbon dioxide, and other 

contaminants. The LPG component (up to 

68 t/d) was separated and transported to 

a loading terminal at Onslow via a 50-mm, 

24-km pipeline and it was then sold by 

Wesfarmers Kleenheat Gas Pty Ltd into 

the domestic market. In 2000, the Griffi n 

Joint Venture entered into a blending 

arrangement with Epic Energy (operator 

of the DBNGP) to blend Griffi n Gas into 

the DBNGP without the need to process 

the gas. Accordingly, from February 2001 

onwards, the majority of the Griffi n Gas 

Treatment Plant has been bypassed and the 

facility decommissioned and mothballed. 

Location 

68 km northwest of Onslow 

Basin 



WA-210-P, WA-10-L, WA-3-PL, TPL/10, PL/20 


Ownership 

BHP Billiton Petroleum (Australia) Pty Ltd 45% 

Mobil Exploration & Producing Australia Pty Ltd 35% 

Inpex Alpha Ltd 20% 

Operator 

BHP Billiton Petroleum Pty Ltd 

Contact 


Level 42, Central Park 

152–158 St Georges Terrace 

PERTH WA 6000 

Tel: +61 8 9278 4888 Fax: +61 8 9278 4899 

Web: www.bhpbilliton.com 


Production 

Griffi n–Chinook–Scindian Oil and Gas 

Field Oil (bbl) Gas (kcm) 

2003 2004 2003 2004 

Griffi n 3 645 414 2 581 279 44 169 30 577 

Chinook–Scindian 2 848 579 1 593 716 246 839 183 654 

TOTAL 6 493 993 4 174 995 291 009 214 231 

90,000 

80,000 

70,000 

60,000 

50,000 

40,000 

30,000 

20,000 

10,000 

0 

Jan 94 

Jan 95 



Jan 96 

Jan 97 

Jan 98 

Griffin–Chinook–Scindian 

The LPG agreement with Wesfarmers 

Kleenheat Gas Pty Ltd has been terminated 

and the LPGs will remain within the gas 

stream. Wesfarmers will extract the LPGs 

at Kwinana. 

Jan 99 

Jan 00 

Jan 01 

Jan 02 

Jan 03 

Jan 04 

1,600 

1,400 

1,200 

1,000 

800 

600 

400 

200 

Up to 40 TJ/d of sales gas can be metered 

and sold to the Tubridgi joint venture. It is 

then delivered into the DBNGP via a 250mm, 

90-km pipeline and on-sold into the 

domestic gas market. 

0 




39



40 


Harriet area fi elds Gas, Oil and Condensate 

Location 

120 km west of Dampier 

Basin 



TL/1, TL/5, TL/6, TL/8, TL/9, TP/8, TPL/1, TPL/2, TPL/5, TPL/8, TPL/13, PL/12, PL/17, PL/42 

Ownership 

Apache Northwest Pty Ltd (Operator) 68.5000% 

Kufpec Australia Pty Ltd 19.2771% 

Tap (Harriet) Pty Ltd 12.2229% 

Contact 



PERTH WA 6000 

Tel: +61 8 9422 7222 Fax: +61 8 9422 7447 


Production 

Field Gas (kcm) Oil (bbl) Condensate (bbl) 

2003 2004 2003 2004 2003 2004 

Agincourt 2 753 1 798 118 539 86 175 1 434 1 003 

Campbell 138 012 33 923 - - 119 111 21 177 

Double Island 17 626 6 949 2 202 709 1 026 980 12 365 4 621 

Endymion 210 341 132 159 - - 199 016 108 027 

Gibson 553 - 2 916 - 138 - 

Gipsy 3 246 6 503 158 111 165 847 18 566 

Gudrun - 4 180 - 478 582 - 359 

Harriet 10 714 12 749 392 787 382 925 46 1 176 

Hoover 2 040 1 435 199 926 113 018 1 292 926 

Linda - 565 349 - - - 998 610 

Little Sandy 2 414 705 269 575 58 834 1 800 333 

Monet - 5 337 - 909 388 - 2 629 

North Pedirka 595 831 66 606 50 924 363 329 

Pedirka 6 305 3 186 977 815 271 562 4 486 1 841 

Simpson 16 201 10 138 687 628 515 042 11 610 5 722 

South Plato 13 923 - 1 625 780 809 021 2 328 988 

Tanami 5 377 2 324 230 221 140 400 3 539 1 555 

Victoria 1 774 103 152 341 3 273 1 276 79 

Wonnich 576 391 320 765 - - 378 596 182 427 

TOTAL 1 008 265 1 108 434 7 084 954 5 011 971 737 418 1 332 368

Average oil/condensate production (bbl/d) 

35,000 

30,000 

25,000 

20,000 

15,000 

10,000 

5,000 

0 

Jan 94 

Jan 95 

Jan 96 

Harriet area fields 

Jan 97 



Jan 98 

Varanus Island provides the base for the 

Harriet gas-gathering and oil export 

projects, which currently involve 

production from the Agincourt, Campbell, 

Double Island, Endymion, Gibson, Gipsy, 

Gudrun, Harriet, Hoover, Linda, Little 

Sandy, Monet, North Pedirka, Pedirka, 

Simpson, South Plato, Tanami, Victoria 

and Wonnich fi elds. The island 

infrastructure includes the following 

Harriet Joint Venture processing 

facilities: 

• oil-processing plant 

• three 250 000-bbl oil tanks and tanker 

export facilities 

• a three-train, low-temperature 

separation gas plant comprising 

of 100 000 Bcf/d-3-phase (gas/oil/ 

water) separation facilities and 

two x 25 MMcf/d gas lift compressors 

• condensate stabilization facilities 

• water treatment and injection 

facilities 

• two sales gas pipelines and 

• 7 MW power station. 

In November 1996, two 120 TJ/d gasprocessing 

trains were commissioned on 

the island as part of the East Spar gas 

development. 

The total gas-processing capacity on 

Varanus Island is 480 TJ/d. 

In January 1997, the Harriet joint venture 

entered into an infrastructure sharing 

agreement with the East Spar joint 

Jan 99 

Jan 00 

Jan 01 

Jan 02 

Jan 03 

Jan 04 

4,000 

3,500 

3,000 

2,500 

2,000 

1,500 

1,000 

500 


venture. Under the agreement, the 

Harriet joint venture will provide gas 

transportation and liquids storage 

services for the East Spar gas fi eld 

utilising existing Harriet facilities on 

Varanus Island. In addition, the two joint 

ventures agreed to share the cost 

of all operating resources and contract 

services such as supply boats and 

helicopters. 

PRODUCTION OPERATIONS 

The oil project commenced in January 

1986 and currently involves the transport 

of oil and condensate from the Agincourt, 

Double Island, Gipsy, Gudrun, Harriet, 

Hoover, Little Sandy, Monet, North 

Pedirka, Pedirka, Simpson, South Plato, 

Tanami and Victoria, as well as 

condensate from the gas fi elds, to 

Varanus Island where it is processed and 

stored. A 762-mm, 3.5-km subsea 

pipeline then transfers the commingled 

crude to offshore tankers berthed at an 

eight-point spread mooring system. 

The crude (38–48° API gravity) is sold to 

refi neries in Australia and overseas. 

The $150-million Harriet gas-gathering 

project was commissioned in July 1992 

and was Western Australia’s fi rst offshore 

gas project to tap associated gas, which is 

produced during the oil recovery process. 

The project currently involves the 

transport of gas from the Campbell, 

Linda, Sinbad and Wonnich fi elds, as well 

as associated gas from the oil fi elds, 

to Varanus Island. 

0 


The separation gas plant removes water 

and natural gas liquids from the gathered 

gas, conditioning it to pipeline 

specifi cations. Separated liquids are then 

commingled with the crude oil. Sales gas 

is transported through either of two 

100-km pipelines (324 or 406 mm) 

connecting with the DBNGP and GGT 

pipeline at Compressor Station No. 1. 

The 406-mm gas pipeline, with a capacity 

in excess of 300 TJ/d, was commissioned 

by the Harriet (30 per cent) and East Spar 

(70 per cent) joint ventures in July 1999. 

Agincourt 

Agincourt was discovered in June 1996 

and commenced production in August 

1997 at a total cost of around $33 million. 

The joint venture estimates that the fi eld 

contains around 4 MMbbl of recoverable 

oil reserves and is expected to have an 

operating life of around 7–10 years. 

Current production is from one horizontal 

well linked to an unmanned offshore 

monopod. The platform has been 

designed to support up to three wells. 

A 150-mm, 6.5-km pipeline transports 

oil, condensate and gas to facilities on 

Varanus Island. Gas is compressed for 

access to the separation gas plant. It is 

also used for Agincourt lift gas, which is 

transported back to the monopod via 

a 100-mm, 6.5-km gas-lift pipeline. 

No fl aring of the associated gas occurs 

unless required for an emergency. 

Alkimos 

The Alkimos-1 deviated well was drilled 

from Varanus Island in August 1994 and 

was completed as an oil producer a 

month later. In November 1995, Alkimos 

was re-completed as a gas producer and 

produced almost 120 000 kcm until being 

shut down in March 1997. The well is now 

used as a water disposal well. 

Campbell 

Located 25 km north-northeast of the 

Harriet-A platform, the Campbell gas 

fi eld was discovered in 1979 and 

commenced production in October 1992. 

The fi eld currently produces from 

Campbell-5, which is linked to an 

offshore fi xed monopod, situated in 

40 m of water. 


41


42 



Double Island 

The Double Island fi eld was discovered in 

January 2002 by Double Island-1, which 

encountered a 16.9-m gross oil-column in 

sandstones informally referred to as the 

Double Island Sandstone Member of the 

Flag Sandstone Formation. 

Reservoir properties within the Double 

Island Sandstone Member are excellent 

and similar to that of other Flag 

Sandstone discoveries to the north. 

The Double Island fi eld is located about 

8.8 km southwest of the South Plato and 

Gibson oil development and contains 

under-saturated oil similar to that found 

in the Gibson, Simpson and South Plato 

fi elds. The fi eld came on production in 

February 2003 and is being drained by 

one horizontal well. 

Endymion 

The Endymion fi eld was discovered in 

October 2002 by Endymion-1, which 

encountered a 20.6-m gross gas-column 

in the Flag Sandstone Formation with an 

average porosity of 20.7 per cent, a netto-gross 

of 90.4 per cent and water 

saturation of 11.6 per cent. The Endymion 

gas fi eld lies about 2 km to the south of 

the Sinbad platform. Production 

commenced in mid-November 2002 with 

an initial well deliverability of 35 MMcf/d. 

Gibson 

The Gibson fi eld was discovered in March 

2001 by Gibson-1, which encountered a 

12.6-m gross oil-column. The fi eld is 

located about 2 km south of the Tanami-4 

well and contains under-saturated oil 

similar to that found in the Simpson fi eld. 

The fi eld commenced production from 

Gibson-1 in June 2002 at a monthly 

average oil rate of 2500 bbl/d and watercut 

of 40 per cent. An additional 

development well (Gibson-2H) was drilled 

in February 2003. The fi eld ceased 

production in April 2003. 

Gipsy–North Gipsy 

The Gipsy oil and North Gipsy oil–gas 

fi elds are part of the Rose–Lee–Gipsy– 

North Gipsy group of fi elds. They have 

hydrocarbon reservoirs in up to four 

separate units — the North Rankin 

Formation, the Brigadier Formation and 

the Mungaroo A and B units. The 

reservoirs are highly faulted and the gas– 

water and oil–water contacts vary 

signifi cantly between the fi elds. The fi elds 

were developed using subsea horizontal 

wells and they came on production in 

February 2001. North Gipsy fi eld was 

abandoned in August 2003. 

Gudrun 

Gudrun-1, drilled in October 2001, 

discovered a 5.5-m gross (and net) oilcolumn 

in the Flag Sandstone. The fi eld 

was developed by a single deviated well 

drilled from the Harriet–Alpha platform. 

Initial oil rate was about 1500 bbl/d. 

Harriet 

Harriet was discovered in November 1983 

and became the fi rst offshore oil 

producer in Western Australia when 

production commenced in January 1986. 

The wells are linked to a fi xed platform 

(Harriet A) and two offshore fi xed 

monopods (Harriet B and C). Crude oil 

fl ows from the Harriet A platform through 

a 219-mm, 6.5-km subsea pipeline to 

Varanus Island while associated gas is 

transported via a 168-mm, 6.5-km subsea 

gas pipeline. 

In July 1999, the North Harriet-1 well 

intersected an 8.7-m net hydrocarboncolumn 

including 6 m of oil. The well 

confi rmed the existence of oil in the 

northern area of the Harriet fi eld. This 

oil is now being developed by the Harriet 

B-5H well which commenced production 

in September 1999. 

Currently oil is being produced from the 

main central area by wells A-3, A-8H, 

A-9H, C-1, C-2 and C-4 and from the 

northern area by B-5H. 

Hoover 

The Hoover fi eld was discovered in April 

2002 by Hoover-1, which encountered a 

6.0-m gross oil-column within the 

Valanginian Flag Sandstone. The Hoover 

fi eld is located about 2.8 km east of the 

Victoria oil development and contains 

under-saturated oil similar to that 

found in the Gibson, Simpson and 

South Plato fi elds. 

Hoover-1 has been abandoned. 

The Hoover-2H development well was 

drilled from the Victoria platform in 

August 2003 and commenced production 

in September 2003. 

Linda 

Linda was discovered in 2000 when the 

Linda-1 well encountered gas-saturated 

Biggada-A sand between 2629 m and 

2720 m. A drillstem test fl owed gas at 

rates up to 895 km 3 /d (31.6 MMcf/d) 

accompanied by 1457 bbl/d of 

condensate. An appraisal well, Linda-2 

was drilled in April 2001 and confi rmed a 

gas-column and established a gas–water 

contact at 2721 m. 

The fi eld was developed with a platform 

installation and tieback to Varanus Island 

through the existing Campbell–Sinbad 

pipeline. First gas fl owed in April 2004. 

Little Sandy 

The Little Sandy fi eld was discovered in 

March 2002 by Little Sandy-1, which 

encountered a 20.3-m gross oil-column 

within the Valanginian Flag Sandstone. 

The Little Sandy fi eld is located about 

5 km south of the South Plato and Gibson 

oil development and contains undersaturated 

oil, similar to that found in the 

Gibson, Simpson and South Plato fi elds. 

Little Sandy-1 commenced production in 

November 2002. 

Monet 

The Monet Oil Field was discovered in 

April 2004 with the drilling of Monet-1 in 

Permit area TL/1 some 3.6 km northeast 

of the Simpson-B platform in 17 m water 

depth. The well intersected a 20-m gross 

(18.2-m net) oil-column at the top Flag 

level. An oil–water contact was 

intersected in the well at 1851.7 m TVD. 

The fi eld covers an area of about 0.2 km 2 . 

The fi eld was developed in June 2004 with 

the drilling of Monet-2H well from the 

Simpson-B platform. Initial oil rate was 

over 10 000 bbl/d with no water-cut. 

North Pedirka 

The North Pedirka fi eld was discovered in 

August 2003 by North Pedirka-1, which 


within the Flag Sandstone. 

The North Pedirka fi eld is located about 

4.6 km south of the South Plato – Gibson 

oil development and contains 

undersaturated oil, similar to that found 

in the Gibson, Simpson and South Plato 

fi elds. The fi eld commenced production 

in September 2003.

Pedirka 

The Pedirka fi eld was discovered in 

February 2002 by Pedirka-2, which 


within the Valanginian Flag Sandstone. 

The Pedirka fi eld is located about 4.6 km 

south of the South Plato and Gibson oil 

development and contains undersaturated 

oil, similar to that found in the 

Gibson, Simpson and South Plato fi elds. 

The fi eld commenced production at the 

end of November 2002. 

Rosette 

The original Rosette well was 

directionally drilled to the west from 

Varanus Island in 1987. The fi eld 

commenced a production test as an oil 

fi eld in April 1988 but ceased production 

in September 1988 after producing 

6900 bbl of oil. Rosette recommenced 

production as a gas fi eld in July 1992. 

A workover was successfully conducted 

on the Rosette well during 1999 that 

substantially increased production from 

the fi eld. The Rosette fi eld watered out in 

November 2002. Rosette-1 has been 

converted into a water disposal well. 

Simpson 

The Simpson oil fi eld was discovered in 

June 2000 by Tanami-4 well, which was 

intended to be an exploration/appraisal 

well in the nearby Tanami fi eld. Tanami-4 


and is quite clearly located in a separate 

accumulation from the main Tanami fi eld. 

The Simpson-1 appraisal well was drilled 

in February 2001 and encountered a 

33.5-m gross oil-column. Simpson-1 and 

Tanami-4 are located in the same oil 

accumulation, which has been named the 

Simpson fi eld. Both wells have been 

completed as production wells. Simpson- 

2 appraisal well was drilled in March 2001 

and encountered an oil–water contact 

similar to Simpson-1 well. The well 

increased the proven bulk rock value 

considerably from that established by 

Tanami-4 and Simpson-1 wells. 

The Simpson fi eld was developed in 

November 2001 utilising Tanami-4 

and Simpson-1 plus one 500-m long 

horizontal well, Simpson-3H, located 

southwest of Simpson-1 with the toe of 

the well located near the Simpson-2 pilot 

hole location. Simpson-3H watered out in 

July 2002 and was followed by the drilling 

and completion of Simpson-4H and South 

Simpson-1 wells. Simpson-7 and West 

Simpson-1 wells were drilled and 

completed in April 2003. 

Additional appraisal wells, Simpson-6, 

Simpson-8 and South Simpson-2 were 

drilled in November and December 2003. 

The successful Simpson-6 and South 

Simpson-2 wells were put on production. 

Sinbad 

The Sinbad gas fi eld, located 16 km 

northeast of Harriet-A, was discovered in 


November 1992. Currently, the fi eld only 

operates intermittently from Sinbad-1 

well, which is linked to an offshore 

fi xed monopod. 

Gas and condensate from the Campbell 

and Sinbad fi elds are transported to 

Varanus Island via 324-mm, 30-km 

gas-gathering pipelines. 

South Plato 

Plato-1, located some 2.8 km north of 

South Plato-1 was drilled in 1986 and was 

dry. The South Plato fi eld was discovered 

in February 2001 by South Plato-1 and 

encountered a 27.4-m gross oil-column. 

The South Plato fi eld is located 2 km 

southwest of Gibson-1 and 4 km 

southwest of the Tanami-4 well. The oil 

fi eld contains under-saturated oil, similar 

to that found in the Simpson fi eld. South 

Plato-2 appraisal well was drilled in 

October 2001 between South Plato-1 

and Plato-1 and encountered a 3.8-m net 

oil-column, thereby confi rming the 

northern extent of the South Plato fi eld. 

South Plato-3H well was drilled in 

February 2003. 

Tanami 

The Tanami-1 well was directionally 

drilled from Varanus Island in July 1991 

and commenced production under an 

extended test in October 1991. Production 

facilities were installed in December 

1993. Tanami-6 was drilled and 

completed in October 2002 as the second 

drainage point. 

Victoria 

The Victoria fi eld was discovered in 

February 2002 by Victoria-1 which 

encountered a 33-m gross oil-column 

primarily in sandstones, above the main 

massive Flag Sandstone, which are 


interpreted as being the feather edge of 

the younger, Double Island Sandstone 

Member. Victoria-2 was drilled in 

September 2002. Upside reserves were 

tested by Victoria-2 well in the second 

half of 2002 and have led to a downward 

revision in reserves. The Victoria fi eld is 

located about 5 km south of the South 

Plato and Gibson oil development and 

contains slightly under-saturated oil. 

Victoria-1 commenced production in 

November 2002. 

Wonnich 

Wonnich was discovered in August 1995 

and commenced production in July 1999 

utilising one well linked to an unmanned 

monopod. The platform lies in 30 m of 

water and has been designed to support 

up to four wells. The fi eld can produce 

gas at a rate of up to 80 TJ/d. Gas and 

condensate are transported 33 km to 

the separation gas plant on Varanus 

Island via two 200-mm pipelines. 

Total capital cost of the development 

was about $60 million. 

The joint venture estimates proven and 

probable reserves to be 186 PJ of gas 

and 3.5 MMbbl of condensate, which is 

expected to provide a fi eld life of around 

20 years. 


The joint venture has made a number of 

oil and gas discoveries in close proximity 

to the existing facilities on Varanus 

Island. These discoveries may be 

developed in the future to maintain/ 

increase production and to secure 

new gas contracts. 

Baker 

The Baker-1 well was drilled to a total 

depth of 2512 m in January 2000. 

The well intersected a 31.5-m gross 

hydrocarbon-column in three separate 

reservoirs in which both gas and 

condensate were recorded. Baker-1 was 

subsequently plugged and abandoned 

as a gas discovery. 


43


44 



Bambra 

Discovered in 1983, the development of 

the Bambra fi eld was deferred early in 

the planning phase of the gas-gathering 

scheme because suffi cient gas reserves 

were available from the Sinbad, Rosette 

and Campbell gas fi elds. 

In December 1997, the Bambra-4 well 

successfully appraised the southern 

extension of the existing gas fi eld 

indicating an oil fi eld. The well 

encountered a hydrocarbon column 

interpreted to comprise 9 m of gross gas 

and 5 m of net oil, overlaying a residual 

oil leg of approximately 2 m. 

The optimum method of developing 

Bambra is to drill two multi-lateral 

horizontal wells, near the crest of the 

structure. The gas cap can then be blown 

down, and the oil will be swept upwards 

towards the horizontal well-bores by 

water infl ux from the aquifer. The mean 

ultimate recovery from the Bambra fi eld 

is estimated to be 7.5 MMbbl of oil, 

17.7 Bcf of gas and 0.2 MMbbl 

of condensate. 

The Bambra fi eld is located very close to 

the Harriet fi eld, and its development and 

operation should be relatively easy and at 

moderate cost. The gas will be sold into 

existing gas contracts. 

In July and August 2004, Bambra-5H 

development well was drilled as a dual 

horizontal well from a surface location 

some 2.3 km from the Harriet Bravo 

platform. A second well, Bambra-6H was 

drilled in August–September 2004 as an 

interceptor well from the Harriet Bravo 

platform and although it was successful 

in locating the Bambra-5H wellbore, 

it was unable to successfully penetrate 

the wellbore and thus make a hydraulic 

connection. It is now planned to drill a 

new development well from the Harriet 

Bravo platform using a higher capacity 

drilling rig in the second quarter of 2005. 

Doric 

The Doric fi eld was discovered in 

November 1992 by Ulidia-1, which 

encountered a 6.7-m gross gas-column in 

the Flag Sandstone Formation. Doric-1, 

drilled in 1996, confi rmed the fi eld to the 

southwest of Ulidia-1 with a common 

gas–water contact (GWC). The fi eld has 

been remapped following the drilling of 

Dawn-1, which was drilled in December 

2002 into a deeper Biggada target. 

The fi eld will be drained by one or two 

crestal wells drilled in conjunction with 

the proposed platform development of 

the Linda gas fi eld. The Doric reserves 

are considered to be undeveloped as of 

31 December 2004. 

Gipsy–Rose–Lee trend 

In 1998, the joint venture confi rmed a new 

hydrocarbon trend in the Gipsy–Rose–Lee 

series of complex fault blocks to the east 

of the Harriet fi eld. It is the fi rst major 

trend in the deeper and older Jurassic- 

and Triassic-aged reservoirs within the 

Carnarvon Basin, outside the deepwater 

Rankin trend. The majority of the Harriet 

area wells in the Carnarvon Basin only 

intersected the lower Cretaceous-age 

Formations. 

Gipsy and North Gipsy have been 

developed with Rose and Lee awaiting 

a gas market. 

Rose–Lee 

In July 1998, the Rose-1 well was drilled 

to a total depth of 2643 m and identifi ed 

a gross hydrocarbon-column of up to 

245 m. The well fl ow tested at a combined 

rate of 2520 m 3 /d (89 MMcf/d) of gas and 

3100 bbl/d of condensate over three 

separate intervals. The Rose-2 well was 

drilled in November 1998 but did not 

encounter hydrocarbons. Rose-3 was 

subsequently drilled and intersected the 

same three intervals as Rose-1. 

Lee-1 was drilled in January 1999 to test 

a separate fault compartment to the 

north of the Rose structure. The well 

intersected a 112-m gross hydrocarboncolumn 

within the same three intervals 

intersected by the Rose wells and a 

deeper fourth interval containing oil. 

In May 1999, Lee-2 intersected 

hydrocarbons at the same four intervals 

as Lee-1, thereby proving the northern 

extent of the fi eld. 

The joint venture considers that the Rose 

and Lee fi elds are commercial and Rose 

development is scheduled for 2005 when 

additional gas deliverability is required. 

Josephine 

In January 2000, the Josephine-1 well 

was drilled to a total depth of 2678 m and 

intersected a 43.5-m gross hydrocarboncolumn 

in three separate reservoirs 

containing both gas and condensate. 

Josephine-1 was subsequently plugged 

and abandoned as a gas discovery. 

Monty 

Monty-1 was drilled to a total depth of 

2492 m in December 1999 and 

intersected a 38.5-m gross hydrocarboncolumn 

in four separate reservoirs 

containing both gas and condensate. 

Monty-2 was subsequently drilled to 

evaluate the discovery but it did not 

encounter hydrocarbons. The well 

determined that the gas accumulation 

intersected in Monty-1 did not extend 

down to the Monty-2 location. 

Consequently, the joint venture has 

evaluated the Monty structure as 

containing a small volume of gas. 

Narvik 

Located 25 km southeast of the Harriet 

fi eld in TP/8, the Narvik-1 well was 

drilled to a total depth of 820 m in 

November 1999. The well identifi ed a 

31-m gross gas-column, of which 10.7 m 

is interpreted to be a productive reservoir. 

Narvik-1 was subsequently plugged and 

abandoned as a gas discovery. Reserves 

are yet to be established for the fi eld. 

North Alkimos 

The North Alkimos fi eld was discovered 

in June 2000 with the drilling of North 

Alkimos-1 exploration well. The well 

intersected a 5.6-m gas-column overlying 

a 6.5-m oil-column with an oil–water 

contact at 1937.6 m true vertical-depth 

subsurface. 

Plans are advanced to develop the fi eld 

with a long reach well from Harriet-Alpha 

platform in 2005. 

The fi eld was undeveloped as of 

31 December 2004.

The Hovea Field was discovered by the 

Hovea-1 well which was drilled in October 

2001 some 6 km south of the Dongara 

fi eld and discovered oil in the Dongara 

Sandstone Formation. After acquiring 

a 3D seismic survey over the discovery 

in early 2002, the joint venture drilled 

a series of appraisal and development 

wells which provided the confi dence and 

the production capability to move to full 

scale production and in October 2002 

the joint venture announced that it had 

committed to the full scale development 

of the fi eld. The fi elds have produced in 

excess of 4 MMbbl since being brought 

into production. 

DEVELOPMENT PROCESS 

The stated development philosophy for 

the Hovea fi eld was “to implement a 

phased development of the fi eld with 

the earliest practical start-up date and 

production level increases, in accordance 

with the appropriate regulations and 

consistent with safe, environmentally 

sound, and prudent operating practices”. 

The basis for development which was 

adopted was to: 

• centralise wells and equipment at the 

Hovea Production Facility (HPF) to the 

extent operationally practicable; 

• minimise the number of development 

wells by using directional wells with 

horizontal sections as warranted; 

• recycle produced water into the 

producing Formation; 

• utilise the off-gas either onsite or 

for sale; 

• optimise the oil transport system to 

reduce the number of trucks required. 

The project was undertaken in three 

phases: 

Phase 1 (which was completed in October 

2002) was to: 

• Drill the fi rst appraisal wells – Hovea- 

1,-2,-3 and 3S/T1 wells; 

• Production test Hovea-1 and establish 

initial production from Hovea-3. 

Phase 2 (which was completed in March 

2003) was to: 

• Production test Hovea-3, drill Hovea-4 

and –5; 

• Implement reservoir pressure 

support; 

Location 

69 km south of Geraldton 

Basin 



L/1 

Ownership 


Origin Energy Developments Pty Ltd 50% 

Contact 




Tel: +61 8 9486 7333 Fax: +61 8 9486 7322 



Production – Oil (bbl) 2003 2004 

Hovea 1 395 557 2 101 394 

Eremia 128 589 126 575 


8000 

6000 

4000 

2000 

0 

Jan 02 

Apr 02 

Jul 02 

Hovea–Eremia 

Oct 02 

• Install permanent production 

facilities; 

• Undertake engineering studies to 

establish full fi eld production. 

Phase 3 (which is currently in progress) 

is to: 

• Establish pressure support and 

commence a reservoir waterfl ood 

(completed); 


Hovea–Eremia–Centella Oil 

Jan 03 

Apr 03 

Jul 03 

Oct 03 

Jan 04 

Apr 04 

Jul 04 

Oct 04 

• Install a produced water-handling 

system (completed); 

• Add additional drainage points to 

fully drain the reservoir (Hovea-11 

– completed); 

• Install a gas utilisation and disposal 

system including a gas-lift system 

(completed). 



45


46 


Hovea–Eremia–Centella Oil 

Hovea plant at dusk 

DEVELOPMENT DRILLING 

The appraisal and development of 

the Hovea and Eremia oil discoveries 

continued with the successful drilling 

of the Hovea-8 development well and 

Hovea-9 appraisal/Hovea-10 waterinjection 

wells. Hovea-8 successfully 

intersected the Dongara Sandstone 

reservoir approximately 20 m above 

the original oil–water contact and 

produced at initial rates of 1200 bbl/d in 

October 2003. Following Hovea-8, the 

company then successfully drilled the 

Hovea-9 appraisal well which confi rmed 

the southern extent of the Hovea 

fi eld. Hovea-9 was then successfully 

sidetracked as the Hovea-10 waterinjection 

well, to be used as the main 

water-injection well and provide pressure 

support to the Hovea fi eld. Hovea-11 

was subsequently drilled to provide an 

additional drainage point in the central 

area of the fi eld. 

PRODUCTION AND RESERVES 

The fi eld commenced full production in 

March 2003 and is currently producing 

at over 6000 bbl/d of oil. The current 

development plan and budget calls for 

production at this rate or higher during 

the 2004–05 fi nancial year period. ARC’s 

net share of oil from the Hovea facility 

was 15 170 bbl in 2001–02, 350 508 bbl in 

2002–03 and 1.1 MMbbl in 2003–04. The 

fi eld has produced over 4 MMbbl of oil. 

A reserves review of the fi eld was carried 

out in October 2002 by RISC. It was of the 

opinion at that time that fi eld reserves 

were some 9.4 MMbbl recoverable at 

the 2P level and 5.2 MMbbl at the 1P 

level. Subsequent to that review, RISC 

undertook another review of the 1P 

reserves for the fi eld for Rothschild which 

confi rmed their previous 1P estimate. 

EREMIA FIELD 

The Eremia-1 exploration well was drilled 

in March 2003 and was completed as 

an oil discovery after encountering an 

oil-column of up to 18 m in thickness 

in excellent quality Dongara Sandstone 

reservoir and conclusively demonstrated 

the prospectivity of the northern Perth 

Basin. The Eremia fi eld is located some 

2.5 km to the west of the HPF. 

The Eremia-1 well was placed on 

production through test facilities only 

six weeks after the rig was released and 

has subsequently produced over 

100 000 bbl of oil. A second development 

well was subsequently completed and a 

fl owline back to the HPF, together with 

a gas-lift line from Hovea to Eremia, has 

been installed combined with the gas-lift 

system, this has allowed the production 

from Eremia to be substantially 

increased. 

The Eremia-2 development was drilled 

in November 2003 and after some initial 

problems with a stuck drill string, the 

well was plugged back and sidetracked, 

then drilled as a high-angle production 

well that was completed on 7 January 

2004. The well intersected an oilcolumn 

of approximately 18 m in the 

Dongara Sandstone and subsequent to 

year-end was completed for production. 

Subsequently the Eremia 3 well was 

drilled to delineate the southern extent 

of the Eremia fi eld. The well intersected 

the oil–water contact of the fi eld and 

was plugged back and sidetracked (with 

the sidetrack designated Eremia-4) to 

a total depth of 2273 m with a bottom 

hole location approximately 90 m to 

the northeast of the original reservoir 

intersection. 

Both well bores intersected the Dongara 

Sandstone reservoir at or just below the 

Eremia oil–water contact and Eremia-4 

was completed as a water injector to 

provide pressure support to the main 

Eremia fi eld pool. 

CENTELLA FIELD 

The Centella fi eld was discovered by the 

Centella-1 well drilled in September 

2004. The Centella-1 well is located 6.5 

km east of the HPF and 1.3 km northwest 

of the Mondarra gas fi eld. It encountered 

an 18.5-m oil-column in the Dongara 

Sandstone. A clean-up fl ow resulted in 

an infl ux of approximately 1500 m of oil 

in the tubing. There was no associated 

gas and the oil gravity was estimated at 

39 o API. The lack of gas and the regional 

reservoir pressure means the well is 

unlikely to fl ow to the surface but is likely 

to be able to be produced on pump. 

Further tests are planned to establish the 

productivity of the well, and to aid in the 

estimation of reserves.

The Jingemia fi eld was discovered in 

October 2002 and commenced production 

testing in May 2003. Jingemia is currently 

continuing an extended production test 

pending issuing of a production licence 

covering the fi eld. 


Oil from the Jingemia-1 and -4 wellheads 

fl ow through a choke manifold and is 

processed in a horizontal 3-phase 

production separator where the gas is 

separated from the crude oil. The gas is 

fl ared via a smokeless vertical fl are, the 

water is transferred to the produced 

water treatment and re-injection system, 

and the oil is transferred to a 940-bbl 

segregation tank and three 940-bbl oilstorage 

tanks. The oil is then pumped 

into road tankers via a fully automated 

tanker loadout facility, and then 

transported to BP in Kwinana for refi ning. 

Produced water is injected into Jingemia- 

3 well via a high-pressure plunger pump 

to maintain pressure support. 

SALES CONTRACTS 

All oil production is currently trucked and 

sold to the BP refi nery in Kwinana. 


The Jingemia prospect was tested by the 

exploration well Jingemia-1 in October of 

2002 and intersected up to 33 m of net oil 

pay in the Dongara Sandstone and Wagina 

Formation. Maximum free fl ow rates of 

up to 2000 bbl/d (317.8 kl/d) have been 

recorded from the well on production 

test. The Jingemia-1 discovery well was 

completed as a future oil producer. 

Subsequent appraisal and development 

activities saw Jingemia-2 spudded in late 

August of 2003 to test the downdip extent 

of the fi eld. Upon reaching the Dongara 

Sandstone reservoir, a thinned interval 

was encountered below the fi eld oil– 

water contact, the well was plugged back 

and sidetracked. The sidetracked well, 

Jingemia-3, was drilled intersecting good 

quality Dongara Sandstone updip from 

Jingemia-2 and was completed as 

a water-injection well. 

Jingemia-4 was spudded in late 

April 2004 and reached a total depth of 

2522 m RT in early May. The well 

intersected the Dongara Sandstone 

approximately 12 m updip of Jingemia-1. 

Within the Dongara Sandstone, 28.3 m 

of net pay, with excellent reservoir 

characteristics, was intersected. 

The underlying Wagina Formation was 

Location 

24 km south of Dongara 

Basin 



EP413, L14 


Ownership 

Origin Energy Developments Pty Ltd* (Operator) 49.189% 

ARC Energy Limited 33.141% 

Voyager (PB) Limited 11.000% 

Victoria Petroleum Offshore Pty Ltd 5.000% 

Norwest Energy NL 1.278% 

Roc Oil (WA) Pty Ltd 0.250% 

J. K. Geary 0.142% 

* a wholly owned subsidiary of Origin Energy Limited 

Contact 

Origin Energy Developments Pty Ltd 



Tel: +61 8 9324 6111 Fax: +61 8 9321 5457 





3500 

3000 

2500 

2000 

1500 

1000 

500 

0 

Jan 03 

Jingemia 

Sep 03 

Dec 03 

found to contain only minor fl uorescence 

and low permeability. Three 27-m cores 

were cut through the Dongara Sandstone 

and Wagina Formation interval with 

100 per cent recovery. 

A permanent completion string was 

set and rig released in mid-May 2004. 

The well was subsequently perforated 

and fl owed oil to surface. During the 

81-minute clean-up fl ow period, a total of 

Mar 04 

Jun 04 

Jingemia Oil 

Sep 04 

31 000 l of completion brine and oil was 

recovered. 

Further exploration is planned in L14 

commencing with a 3D seismic survey 

over the northern portion in 2004; this is 

likely to aid development of the Jingemia 

oil fi eld and delineate further drillable 

prospects. The acquisition of the Denison 

3D commenced in January 2005 and is 

expected to be completed by April 2005. 



47



48 


Laminaria–Corallina Oil and Condensate 

Location 

550 km northwest of Darwin 

Basin 



AC/P8, AC/L5, WA-18-L 

Equity Holding 

Laminaria-Corallina/Northern Endeavour 

Woodside Energy Ltd. (Operator) 66.67% 

Paladin Oil & Gas (Aust.) Pty Ltd 33.33% 

Feild Splits AC/L5 AC/P8 WA-18-L 

Woodside Energy Ltd. 59.9% 66.67% 0 

Paladin Oil & Gas (Aust.) Pty Ltd 40.1% 33.33% 0 

BHP Billiton Petroleum (NWS) Pty Ltd 0 0 100% 

Contact 

Woodside Energy Ltd. 


PERTH WA 6000 

Tel: +61 8 9348 4000 Fax: +61 8 9325 8178 

Web: www.woodside.com.au 


Laminaria East (WA portion only) 



Average oil and condensate production (bbl/d) 

(Western Australian proportion only) 

10,000 

8,000 

6,000 

4,000 

2,000 

0 

Jan 01 

Jul 01 

Jan 02 


Laminaria–Corallina 

Jul 02 

Jan 03 

Jul 03 

Jan 04 

Jul 04 

The Laminaria fi eld was discovered in 

October 1994 within the Territory of 

Ashmore and Cartier Islands area in 

permit AC/P8. 

A separate fi eld, Corallina, was 

discovered in December 1995 within 

AC/L5. Laminaria and Corallina are 

administered by the Northern Territory 

Department of Mines and Energy on 

behalf of the Commonwealth of Australia. 

A unitisation agreement was concluded 

in July 1998 between the AC/L5 and 

WA-18-L participants which allowed the 

entire Laminaria fi eld to be developed. 

The agreement concluded that 

89.85 per cent of the Laminaria fi eld is 

situated in AC/L5. 

The Joint Venture estimates that the 

Laminaria and Corallina fi elds have 

an expected production life of about 

14 years. On the basis of a greater than 

50 per cent probability of recovery, 

the remaining proven oil reserves (WA 

proportion only) as at the end of 2004 was 

16.8 MMbbl. Production in the Laminaria 

fi eld commenced in November 1999 and 

was among the fi rst developments in this 

part of the Timor Sea, following Elang– 

Kakatua which are located in the zone 

of cooperation. 


Development of the Laminaria and 

Corallina fi elds utilises the FPSO, 

the Northern Endeavour, which is 

permanently moored between the fi elds 

by means of an internal turret-mooring 

system. It is moored in a water depth 

of 390 m. 

The Northern Endeavour comprises 

hydrocarbon separation, stabilisation 

and testing facilities which are designed 

to handle a maximum oil production rate 

of 170 000 bbl/d. Facilities have been 

provided for produced water treatment, 

gas compression, gas-lift, power 

generation, cooling water and fi scal 

metering. In addition, a stabilisation 

column reduces LPG content and 

improves crude value. 

The two fi elds produce from diver-less 

subsea facilities consisting of eight 

production wells (six in Laminaria and 

two in Corallina), two manifolds and a 

network of subsea fl owlines and dynamic 

risers which are connected to the FPSO.

“The Northern Endeavour FPSO (fl oating production storage and offl oading vessel), 

Northern Australia. 

Surplus gas is re-injected through a 

dedicated gas disposal well. The internal 

turret system includes provisions for 

future risers and riser tubes, as well as 

future piping arrangements, thereby 

allowing the tie-in of additional 

Laminaria–Corallina wells and further 

discoveries in the area. 

Stabilised oil (58 o API gravity) is stored 

onboard the FPSO, which has a storage 

capacity of 1.4 MMbbl, and is then 

transferred via an offtake loading hose 

to an export tanker moored astern 

of the FPSO. 

Total capital cost of the original 

Laminaria–Corallina development 

was $1.37 billion. 

To deal with the rapid decline in 

production from the Laminaria fi eld, 

the $123-million Laminaria Phase II 

development was completed in June 

2002. The development consists of two 

vertical infi ll wells tied-back to the 

Northern Endeavour FPSO. 



49



50 


Legendre Oil and Gas 


Location 

100 km north of Dampier 

Basin 



WA-20-L, WA-1-P 

Ownership 


Apache Northwest Pty Ltd 31.50% 

Santos Limited 22.56% 

Contact 



PERTH WA 6000 

Tel: +61 8 9348 4000 Fax: +61 8 9325 8178 





50,000 

40,000 

30,000 

20,000 

10,000 

0 0 

Jan 01 



Jul 01 

Legendre 

Jan 02 

Jul 02 

Jan 03 

Jul 03 

Jan 04 

Jul 04 

1,250 

1,000 

750 

500 

250 

Average gas production (kcml/d) 

The Legendre North and Legendre South 

oil fi elds are located 35 km southeast 

of the Wanaea–Cossack fi elds in water 

depths of 45–60 m in Production Licence 

WA-20-L. Legendre North was discovered 

in 1968 with the drilling of Legendre-1, 

however, it was considered uneconomic 

to develop at that time. In 1997, Jaubert- 

1 confi rmed the potential of the fi eld. 

In April 1998, Legendre South-1 proved 

to be a separate accumulation with the 

intersection of a 21 m oil-column, 3.5 km 

southwest of Jaubert-1. 

FIELD DEVELOPMENT 

In October 1999, the joint venture 

formally approved the development of the 

Legendre oil fi elds at an estimated cost 

of $110 million. The initial development 

comprised four horizontal production 

wells (three in Legendre North and one in 

Legendre South) and one gas re-injection 

well. The development wells produce via 

the Ocean Legend Production Facility 

connected via a subsea pipeline and 

Catenary Anchored Loading Buoy to the 

Karratha Spirit Oil Storage and Offl oading 

tanker. Both the Ocean Legend and 

Karratha Spirit are leased facilities and 

operate under service agreements. 

First oil was achieved in mid-May 

2001 after the completion of the fi rst 

production well. In mid-June, the fi rst 

cargo of approximately 630 000 bbl of 

Legendre crude oil was shipped. By early 

July 2001, four production wells and a 

single gas re-injection well had been 

completed and commissioning of the gas 

re-injection facilities commenced. 

Legendre crude oil is a 43° API gravity, 

light, sweet crude oil. The attractive 

qualities of this crude have enabled 

the crude to be sold on a spot basis in 

markets in Australia, South Korea, China, 

Thailand, New Zealand and Indonesia. 

In June 2003, the Legendre North-4H 

infi ll well was completed and came 

into production. This, coupled with gas 

compression optimisation work and a 

work over of the Legendre North-3H well, 

led to the achievement of record facility 

production rates. In June 2004, a sixth 

producer was added through realisation 

of the Legendre North-5H infi ll well. 

In line with expectations, production from 

Legendre is now in natural decline.

The L7 permit lies immediately to the 

north of L1/L2. It contains signifi cant 

exploration potential and an exploration 

program will be undertaken in 

conjunction with that on the surrounding 

permits. 

It also contains the Mount Horner oil 

fi eld, which was discovered in 1965 but 

did not commence production until 

May 1984. The fi eld is currently at a 

mature stage of its life and is producing 

some 75 bbl/d of oil. 

On 10 February 2004, ARC Energy 

acquired 100 per cent of the Licence 

from the previous holder, PetroEnergy 

Pty Ltd. ARC operates a number of other 

facilities in the area and this is expected 

to assist in the further development of the 

fi eld. ARC will undertake a review of the 

fi eld and the wells and the exploration 

potential of the area over the next year. 

PRODUCTION 

Current production is some 75 bbl/d of 

oil at 98 per cent water cut. Eight wells 

are currently completed for production, 

all of which are on artifi cial lift by 

electrically driven beam pumps. The 

process facilities, which were installed 

in December 2000, comply with stringent 

safety case requirements set by the 

Department of Industry and Resources 

and are capable of production of up to 

800 bbl/d of oil. The crude oil (37.6° API 

gravity) is stored onsite in heated tanks 

and then trucked to the Kwinana refi nery 

south of Perth. 

Location 


Basin 



L7 

Ownership 

ARC Energy Limited 100% 

Contact 




Tel: +61 8 9486 7333 Fax: +61 8 9486 7322 






The Mount Horner oil production facility near Dongara. 

Mount Horner Oil 



51



52 


North West Shelf Gas Project Oil, Gas and Condensate 


Location 

130 km northwest of Karratha 

Basin 



WA-28-P, WA-1 to 6-L, WA-9-L, WA-11-L, WA-16-L, WA-1-PL, WA-2-PL 

Ownership 

Domestic gas 


BP Developments Australia Ltd 16.67% 

ChevronTexaco Australia Pty Ltd 16.67% 

BHP Billiton Petroleum (NWS) Pty Limited 8.33% 

Shell Development (Australia) Pty Ltd 8.33% 

LNG, Oil, LPG, Gas recycling 




BHP Billiton Petroleum (NWS) Pty Limited 16.67% 


Japan Australia LNG (MIMI) Pty Ltd 16.67% 

Contact 



PERTH WA 6000 

Tel: +61 8 9348 4000 Fax: +61 8 9325 8178 



Domestic Gas (kcm) 5 416 424 5 337 322 

LNG (t) 8 131 241 9 300 000 


Condensate (bbl) 39 587 473 35 097 084 

LPG (t) 765 746 759 791 

160,000 

140,000 

120,000 

100,000 

80,000 

60,000 

40,000 

20,000 

0 

Jan 95 

Jan 96 

Jan 97 

Perseus, Goodwyn and North Rankin 

NWS Condensate 

Jan 98 

Jan 99 

Jan 00 

Jan 01 

Jan 02 

Jan 03 

Jan 04 

The North West Shelf Venture (NWSV) 

is Australia’s largest natural resource 

development. 

It produces gas for Western Australia’s 

domestic market and gas, condensate 

and oil for export from its vast offshore 

gas and oil fi elds and is located about 

130 km north of Karratha in northwestern 

Australia. 

Gas and condensate are produced from 

the North Rankin, Goodwyn, Perseus 

and Echo–Yodel fi elds on board the 

Goodwyn-A and North Rankin-A 

production platforms. 

The gas is transported by two subsea 

pipelines to the NWSV onshore gas plant 

at Withnell Bay on the Burrup Peninsula 

20 km north of Karratha. The plant 

currently produces LNG, natural gas, 

LPG and condensate. 

The NWSV celebrated major milestones 

in 2004, achieving 20 years of domestic 

gas production and 15 years of LNG 

production, as well as completion of a 

major LNG expansion project. 

The NWSV also produces crude oil from 

its Wanaea, Cossack, Lambert and 

Hermes fi elds. The oil is processed on 

board the Cossack Pioneer FPSO before 

being loaded on to crude-oil tankers for 

transport to customers. 

OFFSHORE GAS FIELDS 

North Rankin 

Discovered in 1971, the North Rankin gas 

and condensate fi eld is 130 km offshore 

from Karratha in approximately 125 m 

of water. 

Following installation and commissioning 

of the North Rankin-A platform (NRA), 

production commenced in July 1984 with 

initial deliveries of gas to the market one 

month later. 

The NRA was originally designed to drill a 

maximum of 34 production wells up to a 

vertical depth of 3.4 km, deviated up to 

60°. The drilling facilities were upgraded 

in 1990 to extend the rig’s drilling 

capability to drill wells up to 70° deviation 

and up to 6.2 km along-hole depth. 

In 2000, a rig refurbishment campaign 

enabled the drilling of production 

wells into the eastern fl ank of the 

Perseus fi eld.

Recently completed LNG Train 4. 

Perseus 

Discovered in 1996, the Perseus gas fi eld 

is about 135 km northwest of Karratha 

in 131 m of water and started production 

in 2001. 

Goodwyn 

The Goodwyn gas fi eld was discovered 

in 1972, 23 km southwest of North 

Rankin fi eld. 

The Goodwyn-A platform (GWA) was 

designed for 30 wells and started 

production in February 1995. 

The initial drilling program of 13 wells, 

included four horizontal, world-class, longreach 

wells producing from up to 

8.3 km from the platform. The second 

phase of drilling, included four long-reach, 

horizontal and deviated wells and was 

completed during 1999. The third phase of 

two wells was completed in 2001. 

Debottlenecking of the GWA, in support of 

NWSV expansion activities, was also 

undertaken in 2001 and the Production 

Licences over the fi eld were extended for 

a further 21 years. 

During 2004, a total of 7.75 Gm 3 (0.27 Tcf) 

of gross gas and 1.93 Gl (12.13 MMbbl) of 

condensate were produced from the 

Goodwyn fi eld. 

Echo–Yodel (gas and condensate) 

The Echo fi eld was discovered in 1988 and 

Yodel in 1990, 25 km southwest of the 

GWA in 140 m of water. 

In 2001, Production Licences were 

granted over the fi eld and two subsea 

horizontal wells were completed and tied 

back to GWA. 

In 2004, a total of 2.33 Gm 3 (0.08 Tcf) of 

gross gas and 1.73 Gl (10.86 MMbbl) of 

condensate were produced from the 

Echo–Yodel fi eld. 

DOMESTIC GAS PRODUCTION 

The onshore gas treatment plant on the 

Burrup Peninsula was commissioned in 

August 1984 to process gas and 

condensate piped from NRA. 

The plant currently consists of two 

parallel processing trains with the main 

components of each train being the 

dehydration units, which separate water 

from the gas, and the extraction unit, 

which removes the heavier hydrocarbons. 

After processing, the bulk of the gas is 

compressed and metered for delivery to 

customers in the Pilbara and the 

southwest of Western Australia. 

Sales of domestic gas are mostly under 

long-term take or pay contracts with the 


NWSV supplying up to 65 per cent of 

Western Australia’s annual domestic 

gas requirements. 

LNG PRODUCTION 

The LNG plant was commissioned in July 

1989 and currently consists of four 

liquefaction trains with a total capacity 

of 11.7 Mt/a of LNG, four 65 000-m 3 

storage tanks and a jetty dedicated to the 

loading of LNG. 

Key elements of each LNG train include: 

• the acid gas removal units, which 

remove carbon dioxide from the gas; 

• dehydration units for removal of 

water; 

• a mercury removal unit; 

• a scrub column, which removes the 

heavier gases; 

• a liquefaction unit which reduces the 

temperature of the gas from minus 

35°C to minus 138°C; and 

• two end-fl ash vessels, where a 

reduction to atmospheric pressure 

leads to further cooling, achieving the 

cold temperature boiling point for 

methane of minus 161°C. At this 

point, the gas condenses to a liquid at 

1/600th of its gaseous volume. 


53


54 


North West Shelf Gas Project Oil, Gas and Condensate 


160,000 

140,000 

120,000 

100,000 

80,000 

60,000 

40,000 

20,000 

0 

Jan 95 

Jan 96 

NWS Oil 

Jan 97 

Jan 98 

The LNG is stored before being piped to 

the LNG jetty for offl oading onto purposebuilt 

LNG ships for transport to Japan, 

South Korea and other international 

markets. 

The expansion of the NWSV’s gasprocessing 

facilities was a major focus in 

2004, with the completion of a fourth LNG 

processing train, a subsea trunkline and 

associated second slugcatcher, and 

delivery of the NWSV’s ninth LNG ship, 

the Northwest Swan. 

The expansion project positions the 

NWSV to satisfy growth in future 

contractual commitments. Train 4 has a 

capacity to process 4.2 Mt/a of LNG. 

Jan 99 

Wanaea, Cossack, Hermes and Lambert 

As part of China’s Guangdong LNG 

project, the NWSV participants and China 

National Offshore Oil Corporation 

(CNOOC) Limited fi nalised agreements in 

December 2004 that provide for CNOOC 

to acquire an approximate 5.3 per cent 

interest in the NWS titles and to secure 

rights to use NWS infrastructure to 

process gas and associated liquids. 

CNOOC holds a 25 per cent interest in the 

new joint venture that has been 

established within the overall NWS 

project to supply the Guangdong LNG 

project, with each of the existing NWSV 

participants having a 12.5 per cent share. 

Jan 00 

Jan 01 

Jan 02 

Jan 03 

Jan 04 

CNOOC paid each of the current NWSV 

participants about US$58 million for 

interests in the NWSV titles. CNOOC will 

also pay a tariff to use NWS infrastructure 

to produce and process gas and 

associated liquids from its acquired gas 

resources. 

Sales contracts 

LNG is sold to eight Japanese gas and 

electricity utilities under 20-year 

contracts, which started in 1989, as well 

as to the spot market when deliveries 

are available. 

The fi rst shipment to Japan left the 

Burrup Peninsula for Japan on 28 July 

1989 on board the Northwest Sanderling. 

In recent years, the NWSV has 

progressively signed further long-term 

LNG supply contracts with fi ve existing 

and two new Japanese customers, as 

well as with customers in South Korea 

and China. 

In 2004, 156 LNG cargoes were delivered. 

CONDENSATE PRODUCTION 

Since 1984, the NWSV has produced 

condensate, a light oil which is used as 

a feedstock to manufacture automotive 

and aviation fuels and for chemical plants 

and is a by-product from the offshore 

gas fi elds. 

The onshore gas-processing plant 

separates condensate from the dry gas 

via two slugcatchers, the second 

commissioned in February 2004. 

The liquid moves through fi ve stabilisation 

units, each capable of processing 2750 t/d 

of condensate. Water and remaining gas 

are removed before the condensate is 

stored in two 73 000-m 3 and two 90 000-m 3 

tanks for shipment to oil refi neries around 

the world. 

Total condensate production for 2004 

was 35.1 MMbbl, an 11 per cent decrease 

on 2003. 

LPG PRODUCTION 

The onshore LPG plant on the Burrup 

Peninsula was commissioned in 

November 1995 and extracts propane and 

butane from the gas originating from the 

NWSV’s offshore gas fi elds. 

The facilities include a 52 000-m 3 liquid 

propane storage tank, a 65 000 m 3 liquid 

butane storage tank, a 450-m-long 

load-out jetty with berthing facilities for 

both LPG and condensate tankers and a 

chiller plant to reliquefy boil-off gases. 

System capacity of the plant is 2500 t/d. 

LPG production in 2004 averaged 

2081.6 t/d, a decrease on 2003 in line with 

the recovery of LPG from decreased 

condensate production.

Oil Production (MMbbl) 

Field 2001 2002 2003 2004 

Wanaea 27.23 28.73 26.35 23.43 

Cossack 6.92 6.39 5.17 3.62 

Hermes 5.50 5.60 5.08 5.70 

Lambert 3.21 3.03 2.70 0.97 

TOTAL 42.86 43.75 39.30 33.72 

Sales contracts 

The owners of the NWSV make sales 

arrangements of LPG on an individual 

basis. In 2004, the operator, Woodside 

Energy Ltd., sold its entire LPG 

entitlement in Japan under a contract 

which started in January 2001 and was 

extended to the end of 2004. 

CRUDE OIL PRODUCTION 

First oil production from the NWSV 

started in November 1995 and currently 

comprises production from the Wanaea, 

Cossack, Lambert and Hermes fi elds. 

The oil development utilises an FPSO 

vessel, the Cossack Pioneer, which is 

moored by its bow to a disconnectable 

riser turret over the Wanaea fi eld. It is 

capable of producing up to 140 000 bbl/d 

of oil and 3700 kcm/d (118 MMcf/d) 

of gas. 

Fluids from the four fi elds are 

transported to the Cossack Pioneer where 

processing facilities separate the oil, 

water and gas. Stabilised oil is stored in 

the FPSO’s tanks, which have a capacity 

to hold up to 1.15 MMbbl. The oil (49° API 

gravity) is offl oaded by fl exible hose to 

shuttle tankers moored astern 

of the FPSO. 

Associated gas from the separation 

process is partly used to fuel power 

generation to service the FPSO vessel. 

The remainder is exported via a 

300-mm, 33-km subsea pipeline 

to the main trunkline connected to the 

onshore gas treatment plant. 

After its $196-million maintenance and 

upgrade in 1999, operational 

performance of the Cossack Pioneer 

continued to exceed expectations. 

OFFSHORE OIL FIELDS 

Wanaea and Cossack 

Discovered in June 1989, Wanaea is 

located 30 km east of the North Rankin 

fi eld in 80 m of water and was followed 

in 1990 with the discovery of the 

Cossack fi eld. 

Production started in November 1995 

and there are now six deviated wells 

producing from Wanaea and one 

horizontal well from Cossack. 

Oil production from the Wanaea fi eld in 

2004 was 3.73 Gl (23.43 MMbbl) while 

production from the Cossack fi eld was 

0.58 Gl (3.62 MMbbl). 


Lambert and Hermes 

The Lambert and Hermes are two 

separate oil accumulations in 125 m 

of water, 15 km north of the Wanaea 

and Cossack fi elds and 145 km north 

of Karratha. 

Lambert was discovered in 1973 and 

Hermes in February 1996 and both have 

been developed as subsea satellites to 

the Cossack Pioneer FPSO. 

Additional wells tied back to Cossack 

Pioneer and commencing production 

during 2004 were Lambert-6 

and Wanaea-8. 

Oil production for the Lambert and 

Hermes fi elds in 2004 was 0.15 Gl 

(0.97 MMbbl) and 0.91 Gl (5.70 MMbbl) 

respectively. 


55



56 


Stag Oil 

Location 


Basin 



WA-209-P, WA-15-L 

Ownership 

WA-15-L 



WA-209-P 

Apache Northwest Pty Ltd (Operator) 55% 

Santos Offshore Pty Ltd 45% 

Contact 



PERTH WA 6000 

Tel: +61 8 9422 7222 Fax: +61 8 9422 7447 





30,000 

25,000 

20,000 

15,000 

10,000 

5,000 

0 

Jan 98 

Stag 

Jan 99 

Jan 00 

The Stag fi eld was discovered in June 


May 1998. The joint venture identifi ed 

initial proven and probable oil reserves 

of around 44 MMbbl, giving the fi eld a 

minimum life of 13 years. Total capital 

cost of the development was around 

$200 million. 

Jan 01 

Jan 02 

Jan 03 

Jan 04 


The development utilises a central 

processing facility (CPF), which 

comprises a fi xed production platform 

consisting of a six-leg piled substructure, 

topsides and processing facilities. 

The platform is able to accommodate up 

to 12 wells and has 50 000 bbl/d liquid 

processing capacity, including 

40 000 bbl/d of water-injection. 

Stag crude has an API gravity of 19 o with 

low-wax and low-pour-point properties. 

Artifi cial lift with electric submersible 

pumps is therefore required to lift the 

oil to the surface at commercial rates. 

The oil is processed on the CPF and 

then exported through a 200-mm, 2-km 

subsea fl owline to a CALM buoy. The buoy 

forms a mooring for a fl oating storage 

and offl oading (FSO) facility, the Dampier 

Spirit, which has a storage capacity of 

700 000 bbl. 

In 2000, one new production well and one 

re-drilled well were placed onstream. 

In 2001, Stag-23 was drilled and Stag-10 

was sidetracked. Stag-24 was added 

in 2002, Stag-25 in June 2003 and 

Stag-26, -27 and -28 in 2004. The fi eld is 

now operating with 11 producing wells 

and three water-injection wells while 

producing at an 8000 bbl/d rate. 

REINDEER 

The Reindeer fi eld, located 32 km north of 

Stag in permit WA-209-P, was discovered 

in October 1997 when the Reindeer-1 well 

encountered a 65-m gas-column. Located 

3.2 km south of Reindeer, the Caribou-1 

well intersected a 19-m gas-column 

in April 1998 and confi rmed the southern 

extension of the Reindeer fi eld. 

Caribou-1 tested at a combined 

1470 kcm/d (51.9 MMcf/d) gas rate and 

850 bbl/d of condensate from two zones. 

The joint venture estimates that Reindeer 

could contain gas reserves of around 

11 Bcm (400 Bcf). 

Roebuck-1 was drilled in February 2000, 

but was plugged and abandoned as a 

dry hole. Development options, such as 

the supply of gas to nearby offshore oil 

developments for use in fi eld operations, 

will also be investigated.

Thevenard Island provides the base for 

the processing and storage of 

hydrocarbons produced from the Saladin, 

Roller, Skate, Yammaderry and Cowle 

fi elds. The island infrastructure includes 

facilities capable of handling up to 

120 000 bbl/d of mixed oil–water 

production, three 350 000 bbl oil tanks, 

water treatment and disposal facilities, 

pipelines, three gas turbine generators, 

a gas treatment plant, a 55 m 3 capacity 

slugcatcher/separator vessel and gas 

compression units. The joint venture 

announced in February 1999 that the 

facilities could be utilised by third parties 

for processing oil and gas production 

from nearby operations. 

In February 2000, Chevron Australia Pty 

Ltd assumed the operatorship of 

Thevenard Island from WAPET and in 

2001 Shell Development (Australia) Pty 

Ltd sold its interests in the Thevenard 

Island area production and exploration 

assets to Santos Offshore Pty Ltd. 

PRODUCTION OPERATIONS 

Fluid produced from the fi ve fi elds is 

piped to Thevenard Island where it is 

separated into oil, water and gas. 

The water is re-injected into the 

reservoirs while the oil is processed and 

blended together before being stored 

in tanks. It is then transported via a 

610-mm, 7-km pipeline to offshore 

tankers berthed at a 10-point spread 

mooring system. The crude (48 o API 

gravity) is sold to refi neries in Australia 

and overseas. 

Gas is conditioned and compressed 

before being transported via a 

150-mm, 44-km export line extending 

from Thevenard Island to the mainland 

via each of the Roller and Skate 

monopods, and then overland to the 

Tubridgi facilities at a maximum rate 

of 20 TJ/d. The bulk of the gas is then 

transported via the onshore Tubridgi 

pipeline and the DBNGP to the 

Mondarra gas fi eld in the Perth Basin. 

The $20-million gas-gathering system 

was commissioned in November 1994. 

SALADIN 

The Saladin fi eld was discovered in June 


November 1989. Currently, two wells are 

producing from the Barrow Group 

reservoir and twelve wells are producing 

from the Mardie Greensand reservoir. 

Location 


Basin 

Carnarvon, onshore and offshore 



EP 357, TL/7, TL/4, TR/4, L12, L13, TPL/6, TPL/1, PL/15 and PL/21 

Ownership 





Contact 




PERTH WA 6000 

Tel: +61 8 9216 4000 Fax: +61 8 9216 4444 


Production 

Thevenard Island Oil and Gas 

Field Oil (bbl) Gas (kcm) 

2003 2004 2003 2004 

Saladin 813 181 699 991 22 066 18 361 

Roller 1 058 195 794 672 25 032 22 481 

Skate 0 0 1 521 139 

Yammaderry 29 564 21 222 1 169 1 323 

Cowle 53 842 39 072 649 2 236 

Crest 27 519 14 586 6 265 3 197 

TOTAL 1 982 301 1 569 543 56 702 47 737 


80,000 

70,000 

60,000 

50,000 

40,000 

30,000 

20,000 

10,000 

0 

Jan 95 

Jul 96 



Jan 97 

Jul 98 

Thevenard Island fields 

Jan 99 

Jul 00 

Jan 01 

Jul 02 

Jul 03 

Jul 04 

800 

700 

600 

500 

400 

300 

200 

100 

0 

Average gas production (bbl/d) 



57


58 


Thevenard Island Oil and Gas 

Seven wells are located offshore on three 

fi xed mini-platforms and seven wells are 

located on Thevenard Island. Fluid 

produced from each offshore platform 

and onshore well is transported through 

either 150-mm or 200-mm pipelines to 

separation facilities on Thevenard Island. 

The Mardie Greensand Formation is a 

secondary producing horizon in the 

Saladin fi eld to the main Flacourt 

Formation of the Barrow Group reservoir. 

However, with the original completions in 

the Flacourt Formation continuing to 

water-out and with several new wells 

drilled in the Mardie Greensand, it is now 

the dominant producing Formation. 

The joint venture estimates that the 

Mardie Greensand Formation contains 

oil-in-place of 55 MMbbl, with potential 

recoverable oil of 26 MMbbl. 

Gas injection through three wells is 

currently used to support pressure 

in the Mardie Greensand Formation. 

In addition, one horizontal producer 

has been converted to a water-injection 

service, following the installation of 

a water fi ltration system and a waterinjection 

pump. 

ROLLER AND SKATE 

The offshore Roller fi eld was discovered 

in January 1990 and commenced 

production in May 1994. The fi eld consists 

of four production wells and one gas 

injection well which are linked to three 

unmanned monopods. Discovered in 

October 1991, the offshore Skate fi eld 

commenced production in July 1994. 

A 508-mm, 27-km three-phase 

production pipeline transports 

commingled oil from the two fi elds, 

together with associated gas and 

water, to separation facilities on 

Thevenard Island. 

Total capital cost of the Roller and Skate 


YAMMADERRY AND COWLE 

Yammaderry and Cowle were each 

developed as single-well fi elds linked to 

separate offshore-unmanned monopods 

at a total capital cost of $30 million. 

Discovered in July 1988, the Yammaderry 

fi eld commenced production in March 

1991. After being shut-in throughout 

1998, the fi eld produced intermittently 

during 1999 following a workover of the 

Yammaderry-2 well. Production 

continues from this well, at a very low 

rate. Fluid is transported to Thevenard 

Island via a 150-mm, 2-km fl owline that 

is connected to the Saladin C platform for 

processing with Saladin crude. 

The Cowle fi eld was discovered in 

December 1989 and commenced 

production in May 1991. The Cowle-4 well 

was completed in the Mardie Greensand 

as an oil producer in May 1999 and 

resulted in a four-fold increase in 

production for the year. Following the 

success of Cowle-4, Cowle-5 was also 

drilled into the Mardie Greensand, 

although with less encouraging results. 

A 200-mm, 10-km fl owline transports 

fl uid directly to Thevenard Island. 

CREST 

The onshore Crest fi eld was discovered in 

February 1994 when the deviated Crest-1 

well encountered hydrocarbons under 

Thevenard Island. The well was placed on 

an extended production test in June 1994. 

In 1998, Crest-1 was abandoned and 

Crest-6 was drilled horizontally into the 

overlaying Mardie Greensand reservoir. 

Crest-6 produced at low oil rates and was 

shut-in in October 1998 pending the 

applications for a production licence. 

A production licence application over the 

Crest fi eld (EP65) triggered the Native 

Title Act 1993 and the Right to Negotiate 

provisions. Extensive negotiations 

occurred with the Thalanyii people since 

November 1998. The matter ended in a 

determination in WAPET’s favour. 

Legal discussions were fi nalised in 2002 

and two production licences were granted 

over Thevenard Island (Production 

Licences L12 and L13). Production 

recommenced in December 2002 from 

the Mardie Greensand horizontal well 

Crest-6. 


The joint venture is continuing to evaluate 

potential developments within the permit 

areas that could be tied into existing 

production facilities on Thevenard Island. 

Australind 

Additional hydrocarbons were discovered 

in permit TP/3 (Pt 1) with the successful 

drilling of the offshore Australind-1 well 

in September 1993. Located about 5 km 

northeast of Thevenard Island, the well 

was drilled to a total depth of 1310 m in 

the Barrow Group Formation and 

encountered a 12-m gas-column 

associated with a minor oil-column. 

Australind-1 was abandoned. 

The development of this fi eld remains 

marginal. The fi eld is now covered by 

retention lease TR/4. 

Coaster 

In January 2000, the offshore Coaster-1 

well intersected an 11-m net oil-column 

(30 o API gravity) in the Barrow Group 

Formation after reaching a total depth of 

1112 m. Located 5 km from Roller, 

the well was suspended as a potential 

oil producer.

The Tubridgi gas fi eld was discovered in 

June 1981 and commenced production in 

September 1991. The project incorporates 

gas production and transportation 

operations, as well as re-injection and 

storage facilities. 


There are now four producing wells 

in the fi eld. Gas is piped from the 

producing wells via 30 km of fl owlines to 

a central processing plant, consisting of 

dehydration, separation and compression 

facilities, located on the Tubridgi fi eld. 

The processed gas may be transported 

via a 150-mm, 90-km gas-pipeline, with a 

capacity of 30 TJ/d, to Compressor Station 

No. 2 on the DBNGP or via the Griffi n 

pipeline. 

In 1997, the Tubridgi hub was connected 

to the adjacent Griffi n gas plant so that 

Tubridgi sales gas could be processed 

or blended to meet normal sales gas 

specifi cations for the DBNGP. 

GAS SALES CONTRACT 

Gas is currently supplied to Alcoa, Alinta 

and Western Power. 

GAS TRANSPORTATION FACILITIES 

The Tubridgi project was expanded in 

1994 to act as a transportation and 

storage facility for associated gas from 

the Griffi n and Thevenard Island fi elds. 

The strategic location of the gasgathering 

facilities and the substantial 

spare pipeline capacity, may assist in 

the transport of gas from other offshore 

oil and gas fi elds in the southern area of 

the Carnarvon Basin. The facilities are 

capable of delivering around 120 TJ/d of 

gas and further increases are possible 

with additional compression. 

GRIFFIN 

Associated gas from the Griffi n Venture 

FPSO is transported via a 200-mm, 

68-km offshore pipeline to the Griffi n 

onshore gas treatment plant, adjacent 

to the Tubridgi facilities. The gas is then 

transferred via a 250-mm, 90-km onshore 

pipeline lateral into the DBNGP. 

The onshore pipeline, with a capacity 

of more than 90 TJ/d, was built by the 

Tubridgi joint venture and parallels its 

150-mm pipeline. 

The Tubridgi joint venture can purchase 

up to 40 TJ/d of the Griffi n gas for resale 

into the domestic gas market. 

Location 

25 km southwest of Onslow 

Basin 

Carnarvon, onshore 


L9, PL/16, PL/19 


Ownership 

SAGASCO Southeast Inc.* (Operator) 51.15% 

Pan Pacifi c Petroleum NL 43.00% 

Origin Energy Petroleum Pty Ltd 2.80% 

Origin Energy Amadeus NL 2.70% 

Tubridgi Petroleum Pty Ltd 0.35% 

*a wholly-owned subsidiary of Origin Energy Limited 

Contact 

Origin Energy Resources Ltd 



Tel: +61 8 9324 6111 Fax: +61 8 9321 5457 





800 

700 

600 

500 

400 

300 

200 

100 

0 

Jan 94 

Jan 95 

Tubridgi 

Jan 96 

Jan 97 

Jan 98 

Jan 99 

Jan 00 

Jan 01 

Jan 02 

Tubridgi Gas 

Jan 03 

Jan 04 



59



60 


Wandoo Oil 

Location 

75 km northwest of Karratha 

Basin 



WA-14-L 

Ownership 

Mobil Legendre Pty Ltd (Operator) 60% 

Wandoo Petroleum Pty Ltd 40% 

Contact 




Tel: +61 3 9270 3333 Fax: +61 3 9270 3493 





50,000 

40,000 

30,000 

20,000 

10,000 

0 

Jan 94 

Jan 95 

Wandoo 

Jan 96 

Jan 97 

Jan 98 

The Wandoo oil fi eld was discovered in 

June 1991 in a water depth of 55 m. 

Production commenced in October 1993 

under an extended production test using 

the Wandoo-A platform. First oil 

production from the Wandoo-B platform 

commenced in March 1997 and full fi eld 

development was completed in June 

1997. Total capital cost of the full 


Jan 99 

Jan 00 

Jan 01 

Jan 02 

Jan 03 

Jan 04 

There were three further horizontal wells 

drilled in late 2000, two on Wandoo-A and 

one on Wandoo-B. 

Initial recoverable oil reserves were 

estimated at 75 MMbbl, giving the fi eld a 

production life of around 20 years. The 

Wandoo crude has an API gravity of 19° 

with low-wax and low-pour-point 

properties, but high viscosity. 


Wandoo-A is a single column, monopod 

wellhead platform, which supports a deck 

and fi ve production wells. Fluid produced 

from the wells is piped to the Wandoo-B 

platform, located to the northeast. 

Wandoo-B consists of a concrete gravity 

substructure (CGS) which supports steel 

topsides and provides storage capacity for 

400 000 bbl of crude oil. 

The 81 000-tonne CGS was constructed at 

a casting basin in the Port of Bunbury 

inner harbour. The completed CGS was 

fl oated out of Bunbury Harbour, towed 

1760 km to the Wandoo fi eld and then 

sunk into position on the seabed in 

October 1996. It was the fi rst concrete 

seabed storage facility to be installed 

in Australia. 

In January 1997, the topsides were 

installed on the CGS using the fl oat-over 

method for the fi rst time in Australian 

waters. The topsides support processing 

facilities, ten horizontal oil production 

wells, one gas injection well and an 

accommodation module. The processing 

facilities, which can handle more than 140 

000 bbl/d of total fl uid, separate and 

process the fl uids produced from both 

platforms. Typical production rates are 22 

000 bbl/d of oil, 132 000 bbl/d of water 

and 500 kcm/d (18 MMcf/d) of gas. 

The water is treated and discharged into 

the ocean. Gas is used for reservoir 

gas-lift and for fuel. 

Oil is stored in the CGS and then 

offl oaded through two 348-mm fl exible 

pipelines to a loading buoy located 

1.2 km north of Wandoo-B. A fl oating 

hose is used to transfer the oil to export 

tankers at a mooring facility. Markets for 

the oil are mainly Japan and South Korea 

with a small amount also being shipped 

to the Altona refi nery in Victoria.

Located 13 km northwest of the township 

of Eneabba, the Woodada fi eld was 

discovered in May 1980 and commenced 

production in May 1982. Production is 

expected to continue for at least another 

six years. 


Processing facilities at Woodada include 

separation and compression units, a gas 

drying and sweetening unit, evaporation 

ponds and a condensate storage tank. 

A total of 18 wells have been drilled in the 

fi eld, eight of which are currently 

producing. Gas and condensate from 

the producing wells are collected by a 

150-mm gas-gathering system. Following 

separation dehydration and compression 

at the processing plant, the gas is 

transported via the Parmelia pipeline, 

located 11 km northeast of the fi eld to 

Perth. Condensate (53.6 o API gravity) 

is piped to a storage tank and is then 

transported by truck to the BP refi nery in 

Kwinana for processing. 

GAS SALES CONTRACTS 

Woodada currently supplies gas to 

Tiwest and Midland Brick under 

long-term contracts. 

Location 


Basin 


Permit 

L4, L5, PL/6 

Ownership 

ARC Energy Limited 100% 

Contact 




Tel: +61 8 9486 7333 Fax: +61 8 9486 7322 




12 

10 

8 

6 

4 

2 

0 

Jan 94 

Jan 95 

Woodada 

Jan 96 


Condensate 

Jan 97 

Jan 98 

Jan 99 


Woodada Gas and Condensate 



Condensate (bbl) 1 214 916 

Jan 00 

Jan 01 

Jan 02 

Jan 03 

Jan 04 

180 

150 

120 

90 

60 

30 

0 




61



62 


Woollybutt Oil 

Location 

44 km west of Barrow Island 

Basin 

Carnarvon, offshore (Barrow Sub-basin) 

Permit 

WA-25-L 

Ownership 

Eni Australia Limited (Operator) 65% 

Mobil Exploration & Producing Australia Pty Ltd 20% 

Tap Oil NL 15% 

Contact 

Eni Australia Limited 

Level 3, 40 Kings Park Road 


PO Box 1265 


Tel: +61 8 9320 1111 Fax: +61 8 9320 1100 

Email: info@eniaustralia.com.au 




45,000 

40,000 

35,000 

30,000 

25,000 

20,000 

15,000 

10,000 

5,000 

0 

Apr 03 

Jul 03 

Woollybutt 

Oct 03 

The Woollybutt fi eld was discovered in 

April 1997 when the Woollybutt-1 well 

intersected a 1.8-m net oil-column in 

the basal Mardie Greensand and an 

11.5-m net oil-column in the Upper 

Barrow Group. The well fl ow tested 7600 

bbl/d of 49 o API gravity oil, confi rming the 

potential of the fi eld. This was followed 

by the drilling of Woollybutt-2 in 1997 

and Woollybutt-3 in 1999. Woollybutt-3 

encountered an oil–water contact 3 m 

Jan 04 

Apr 04 

Jul 04 

Oct 04 

high to the Woollybutt-1 and Woollybutt-2 

wells, indicating that the southern and 

northern lobes are not in communication. 

Further appraisal drilling was undertaken 

in 2004–05 with the drilling of Scalybutt-1 

on the western fl ank of the Woollybutt 

North Field and Woollybutt-4 on the 

northwestern fl ank of the Woollybutt 

South Field. Two additional wells are 

planned to access reserves in the central 

and southern lobes of the Woollybutt 

South Field, namely Woollybutt-5 and 

Woollybutt-6. The Yarri prospect, located 

5 km east of the Woollybutt South Field, 

is under evaluation by the Joint Venture. 

DEVELOPMENT 

A development plan for the fi eld was 

approved by the joint venture partners 

in the fourth quarter of 2001. The plan 

comprised tie-back of two subsea 

production wells to a leased FPSO 

facility. A contract with Vanguard SPC 

was executed in November 2001 for 

provision of the FPSO. The Woollybutt- 

1 and Woollybutt-2 exploration and 

appraisal wells were re-entered in 2002 

and sidetracked horizontally prior to 

completion as production wells. 

The FPSO Four Vanguard has been 

installed in the fi eld and production 

started on 29 April 2003 from the two 

wells. The ship exhibits a double hull, 

with an internal turret and a quickly 

disconnectable mooring system. 

The production rate declined from 

35 000 bbl/d in January 2004 to 

24 000 bbl/d in December 2004, while 

the fi eld water-cut increased from 19 

per cent to 52 per cent. Production was 

disrupted for 10 days in early March 2004 

due to cyclone avoidance and from 20 

March until 5 May for the planned swivel 

replacement job at a Singapore shipyard. 

A total of 8.7 MMbbl, 49.4 o API oil was 

produced in 2004. Some 24 offl oading 

operations to export tankers were 

performed during 2004. A development 

plan for the Woollybutt South Field is 

under study and may involve the drilling 

of 2 to 4 development wells.

Blacktip Gas 

Location 

50 m of water 

approximately 250 km southwest of 

Darwin and 110 km northwest of Wadeye. 

Basin 

Joseph Bonaparte Basin 

Permit 

WA-279-P 

Ownership 


Eni Australia BV 46.15% 

Contact 



PERTH WA 6000 

Tel: +61 8 9348 4000 

Fax: +61 8 9325 8178 


Cliff Head Oil 

Location 

20 km southwest of Dongara 

Basin 

Perth, offshore 

Permit 

Location No. 2SL/03-4 within WA-286-P 

Ownership 

Roc Oil (WA) Pty Limited (Operator) 37.5% 

AWE Oil (Western Australia) Pty Ltd 27.5% 

Wandoo Petroleum Pty Ltd 24.0% 

Voyager (PB) Limited 6.0% 

CIECO Exploration and Production 

(Australia) Pty Ltd 5.0% 

Contact 

Roc Oil (WA) Pty Limited 

Level 14, 1 Market Street 

SYDNEY NSW 2000 

Tel: +61 2 8356 2000 

Fax: +61 2 9380 2066 

Web: www.rocoil.com.au 

PROJECTS UNDER CONSIDERATION 

The Blacktip gas fi eld (permit WA-279-P) was discovered in 2001 and contains 

reserves of approximately 930 Bcf of gas and 1.7 MMbbl of condensate. 

In November 2004, the Blacktip Joint Venture (JV) participants signed a Gas 

Sales Agreement with Alcan Gove Pty Ltd to supply up to 44 PJ/a of natural gas 

for up to 20 years to Alcan’s aluminium and bauxite operations at Gove. 

The Blacktip Project commenced Front End Engineering and Design (FEED) 

studies in May 2004. The studies were completed in December 2004. Key 

government approvals such as the EIS and the Production Licence are 

progressing. 

A land access agreement for the Blacktip onshore facilities is being negotiated 

with the Northern Land Council which is acting on behalf of the Aboriginal 

traditional owners. 

The Blacktip Joint Venture participants are planning to make a fi nal investment 

decision in mid-2005. 

The Blacktip JV is working with Alcan to progress the transportation of Blacktip 

gas by pipeline from its onshore location at Wadeye to the Gove operation in the 

Northern Territory. This component of the project is referred to as the Trans- 

Territory Pipeline (TTP). It is expected that the fi nal investment decision for the 

TTP will also be made in mid-2005. 

First gas is expected to be delivered at the end of 2007. 

Cliff Head was discovered in December 2001 with the drilling of Cliff Head-1 and 

subsequent appraisal with Cliff Head-2. The Cliff Head Field is in a water depth 

of approximately 16 m, 11 km offshore, and is located southwest of Dongara. 

Cliff Head-1 intersected a 5-m oil column within the Irwin River Coal Measures. 

Cliff Head-2 intersected a 36-m oil column also within the Irwin River Coal 

Measures. No production testing was undertaken in either well and they were 

plugged and abandoned. 

Further appraisal of the Cliff Head Field was undertaken with a small 2D 

seismic survey in October 2002 and in January 2003 with the drilling of Cliff 

Head-3, 2.4 km northwest of the Cliff Head-2 well, followed by Cliff Head-4, 1 

km south of Cliff Head-3, in March 2003. The oil–water contact encountered 

in Cliff Head-3 and Cliff Head-4 is the same as that for Cliff Head-1 and -2. 

Production testing was undertaken in Cliff Head-3 over 27 m of the reservoir for 

a period of three days. The maximum fl ow rate was 3000 bbl/d on a downhole 

pump through an 11-mm choke. 

A 3D seismic survey was acquired over the Cliff Head Field in November 

2003 designed to support development planning, in particular optimisation of 

development well design. In August 2004, a location (2SL/03-4) was declared 

over the Cliff Head fi eld for a period of two years. FEED and work on reservoir 

engineering and geological modelling were completed in October 2004, 

and incorporated into a Cliff Head Pre-development Field Report and Field 

Development Plan. 


63


64 


Cliff Head cont. 

Coniston Oil 

Location 

50 km north of Exmouth 

Basin 



WA-255-P 

Ownership 

BHP Billiton Petroleum (Australia) Pty Ltd 50% 

Woodside Energy Ltd 50% 

Operator 


Contact 



152-158 St Georges Terrace 

PERTH WA 6000 

Tel: +61 8 9278 4888 

Fax: +61 8 9278 4899 


In February 2005, Cliff Head-5 was drilled in the southeastern part of the fi eld (about 

1 km southeast of the Cliff Head-1 discovery well) as a vertical “pathfi nder” appraisal 

well to assist in the planning of horizontal development drilling, but was a dry hole, 

coming in low to prediction due to a seismic velocity anomaly. 

The Cliff Head-6 deviated early development well was drilled in February-March 2005 

on the main horst of the fi eld, about 1.6 km north of the Cliff Head-1 discovery well, 

and was suspended as a future oil producer. 

Final Investment Decision was made in March 2005. First oil is expected to fl ow late 

2005 – early 2006 at an initial rate in excess of 10 000 bbl/d through facilities with 

15 000 bbl/d capacity. Proven and probable fi eld reserves, in the fully appraised part of 

the Cliff Head structure, are currently estimated to be about 14 MMbbl. There is upside 

reserve potential in areas adjacent to the fi eld which are currently undrilled but which 

will be accessible from the production platform. The total development cost is expected 

to be A$227 million. Cliff Head will be the fi rst oil fi eld to be developed in the offshore 

Perth Basin. 

In February 2000, the Coniston-1 well was drilled in a water depth of 389.5 m and 

reached a total depth of 1350 m. A production test achieved a maximum unassisted 

oil fl ow rate of 2119 bbl/d. 

Coniston-1 is located 25 km north of the BHP Billiton-operated Macedon–Pyrenees 

fi eld and 10 km north of the Vincent–Enfi eld oil fi elds, operated by Woodside 

Energy Ltd. 

Following initial assessment of this relatively heavy oil discovery (15 o API), it is not 

considered commercial as an independent development at this time.

Enfi eld Oil 

Location 

40 km offshore, north-west of Australia’s 

North West Cape 

Basin 


Permit 

Production Licence WA-28-L 

Ownership 

Woodside Energy Ltd. (Operator) 60% 

Mitsui E&P 40% 

Contact 



PERTH WA 6000 

Tel: +61 8 9348 4000 

Fax: +61 8 9325 8178 


Gorgon Area Gas 

 

 

 

 

 

 

 

 

 

 

 

 

 


The Enfi eld oil project is situated within Production Licence Area, WA-28-L and lies 

close to a number of environmentally sensitive areas including the Ningaloo Reef and 

associated Marine Park. The area is subject to tropical cyclones during a nominal 

November to April cyclone season. The water depth across the licence area varies 

from 400 m in the east to more than 550 m in the west. 

Enfi eld reserves will be extracted using subsea wells with fl owlines back to a doublehull 

type FPSO, the Nganhurra, with a disconnectable mooring, located about 2 km to 

the east of Enfi eld fi eld in approximately 396 m water depth. 

There are various other fi elds within WA-271-P and adjacent permits that may be 

developed in the future, subject to successful appraisal and evaluation. To provide 

fl exibility to tie-in other fi elds, the Enfi eld FPSO will have a number of unallocated 

slots for the installation of additional risers and the swivel will be designed to 

accommodate additional fl uid paths. However, no facilities capacity beyond that 

required to produce Enfi eld will be provided. It is expected that production from future 

fi elds will be accommodated by system ullage, debottlenecking, or upgrade of existing 

facilities, whichever is most advantageous. 

The Enfi eld reserves will be extracted through gas-lifted wells. Water-injection 

wells will be used for the disposal of produced water, supplemented by injection 

of seawater to provide reservoir pressure support. Excess gas will be re-injected into 

the Enfi eld reservoir. 

The Enfi eld FPSO is based on a Suezmax tanker design, of double-hulled construction, 

with a storage capacity of approximately 900 000 bbl. It will be equipped with a 

disconnectable mooring and its own propulsion system to allow evasion of cyclones. 

The Enfi eld reservoir contains a medium crude, with an API gravity of approximately 

22° (SG 0.92). The well-stream fl uid will be stabilised on the FPSO to produce export 

quality crude oil, which will be stored in the FPSO’s tanks and periodically exported 

through an offl oading hose to tandem-moored offtake tankers. Export cargoes will be 

of about 80 000 t (about 550 000 bbl). 

The Final Investment Decision was made in March 2004 and fi rst oil is planned for the 

fourth quarter 2006. Production is expected to extend over a period of about 

12 years, however the facilities will be designed for 20 years’ operation. The FPSO 

will be designed to remain on-station for the entire design life without recourse to dry 

docking for maintenance or survey. 

 

 

 

 

 

 

 

 

 

 

The ChevronTexaco-operated joint ventures are currently 

planning the development of the large natural gas 

reserves of the Greater Gorgon fi elds to support a major 

LNG and domestic gas project. Recent exploration 

success in deepwater acreage west of Gorgon has 

increased the gas reserve base signifi cantly. 

The Greater Gorgon Area contains an estimated gas 

resource, at the P50 confi dence level, in excess of 40 Tcf 

and is made up of two groupings of fi elds: the Gorgon 

area gas fi elds in the shallower water; and the deeper 

water fi elds which include the Io–Jansz fi elds located 

further offshore. 

The Gorgon Area contains certifi ed gas reserves of 12.9 

Tcf and includes the Gorgon, West Tryal Rocks, Spar, 

Chrysaor and Dionysus fi elds. 

The Gorgon gas fi eld is the largest fi eld in this group, and 

one of the largest ever discovered in Australia. 


65


66 


Gorgon Area cont. 

Location 

200 km west of Dampier 

Basin 


Permit 

WA-205-P, WA-253-P, WA-268-P, WA-2-R to 5-R, 

WA-14-R to WA-26-R 

Ownership 

WA-2-R to 5-R, WA-14-R, WA-16-R 



Shell Development (Australia) Pty Limited 28.57% 


WA-253-P, WA-15-R, WA-17-R, WA-19-R to WA-21-R 

ChevronTexaco Australia Pty Ltd (Operator) 50% 

Texaco Australia Pty Ltd 50% 

WA-22-R to WA-26-R 

ChevronTexaco Australia Pty Ltd (Operator) 25% 


Mobil Australia Resources Company Pty Ltd 25% 


BP Exploration (Alpha) Ltd 12.5% 

WA-18-R 

Mobil Exploration & Producing Australia 

Pty Ltd (Operator) 50% 


WA-268-P 

Texaco Australia Pty Ltd (Operator) 100% 

WA-205-P 




Contact 




PERTH WA 6000 

Tel: +61 8 9216 4000 

Fax: +61 8 9216 4444 


EXPLORATION AND APPRAISAL DRILLING 

West Tryal Rocks was the fi rst of the Greater Gorgon gas fi elds to be discovered 

in 1973 and this was followed by Spar in 1976. Up to 1999, a total of 14 exploration 

and appraisal wells had been drilled in the Greater Gorgon fi elds, comprising 

Gorgon (8), West Tryal Rocks (3), Chrysaor (1), Dionysus (1) and Spar (1). 

Guaranteed work commitments in exploration permits WA-205-P, WA-25-P 

and WA-267-P since 1999 have increased the number of wells in this area 

signifi cantly. This recent exploration phase was extremely successful with six 

new gas discoveries in the Greater Gorgon area. These were Geryon, Orthrus, 

Maenad, Urania and Io in WA-267-P and Iago in WA-25-P–WA 253-P. In 2004, 

further exploration success saw the discovery of the Wheatstone gas fi eld within 

WA-17-R, WA-16-R and WA-253-P. 

In 2002 and 2003, the Mobil-operated Jansz gas fi eld has been further delineated 

with the drilling of Jansz-2 and -3. Jansz-2 was cored and Jansz-3 underwent 

production testing. 

In 2004, a large 3D seismic program was acquired over the Io–Jansz gas fi eld 

to further appraise the fi eld in preparation of fi eld development. In early 2005, a 

signifi cant 3D seismic program will be undertaken over the Wheatstone and Iago 

fi elds again to further appraise the resource prior to development planning. 

Gorgon 

The Gorgon fi eld was discovered in 1980 with the drilling of the Gorgon-1 well 

and was initially appraised with the drilling of North Gorgon-1 in 1982 and 

Central Gorgon-1 in 1983. 

In July 1994, the North Gorgon-2 appraisal well was drilled to obtain a more 

accurate defi nition of the Gorgon reserves. The well fl owed gas at a maximum 

rate of 1764 kcm/d (62 MMcf/d) during drillstem tests (DSTs). The North Gorgon- 

2 well confi rmed the northern extension of the Gorgon fi eld (within the main 

horst) and the existence of gas-bearing sands previously inferred from 3D 

seismic data. 

To delineate further reserves and to aid in the selection of development options 

and sites within the North Gorgon fi eld, two appraisal wells were drilled in 1995– 

96. The North Gorgon-3 vertical appraisal well was drilled to a total depth of 

4628 m in December 1995 and intersected a gas-column. The well helped defi ne 

the northern extension of the Gorgon fi eld (further north of the main horst). 

The North Gorgon-4 vertical appraisal well was drilled to a total depth of 

4170 m in February 1996. The well fl owed gas at a maximum rate of 1050 kcm/d 

(37 MMcf/d) during DSTs. The results of the tests indicated the presence of gasbearing 

sands in a previously undrilled North Gorgon fault block (west of the 

main horst block). 

In October 1998, the Gorgon-3 appraisal well was drilled to provide critical data 

on well productivity and fl uid compositions. The well encountered over 398 m 

of permeable gas sands and fl owed gas at a maximum rate of 1790 kcm/d (63.2 

MMcf/d) during testing of two separate intervals. The high fl ow rates confi rmed 

the enormous delivery of the Gorgon reservoirs. 

North Gorgon-6, the fi nal appraisal well in the Gorgon fi eld, was drilled to a total 

depth of 4290 m in November 1998. The well encountered a total net gas pay of 

157 m and confi rmed the continuity of the reservoir. 

Chrysaor 

Located 19 km northeast of the North Gorgon fi eld in 806 m of water, the 

Chrysaor-1 exploration well was drilled to a total depth of 3597 m in December 

1994. The well fl owed gas at a maximum rate of 1798 kcm/d (63.5 MMcf/d) during 

production testing. Although the well was drilled within permit WA-205-P, the 

majority of the Chrysaor structure extends into adjoining permit WA-253-P. 

Two retention leases have been granted over the entire fi eld, WA-14-R (from 

WA-205-P) and WA-15-R (from WA-253-P).


Dionysus 

The Dionysus-1 well was spudded in 1100 m of water in June 1996 and was drilled to a 

total depth of 4417 m. The well fl owed gas during two DSTs at a maximum rate of 

1804 kcm/d (63.7 MMcf/d). Dionysus-1 intersected separate gas accumulations from 

those encountered in the Chrysaor fi eld and established the presence of a second 

major gas fi eld in permit WA-253-P. A retention lease (WA-15-R) was awarded over the 

Dionysus fi eld on 20 April 2000. 

Geryon, Orthrus-Maenad, Urania and Io 

In August 1999, the joint venture commenced a signifi cant deepwater drilling program 

involving six commitment wells in permit WA-267-P, located to the west of the 

Greater Gorgon fi elds. Drilling to date has resulted in fi ve signifi cant gas discoveries, 

Geryon-1, Orthrus-1, Urania-1, Maenad-1 and Io-1. The exploration success rate for 

this permit’s drilling program was 83 per cent. 

Geryon-1 was drilled in 1232 m of water and reached a total depth of 3515 m in 

September 1999. The well encountered a total net gas-pay of 113 m in three highquality 

reservoir zones. Located 28 km southwest of Geryon in 1200 m of water, 

the Orthrus-well was drilled to a total depth of 3570 m in October 1999. The well 

encountered a total net gas-pay of 53 m in a high-quality reservoir zone. 

In February 2000, 21 km northeast of Geryon, Urania-1 was drilled in 1200 m of water, 

reaching a total depth of 4010 m and encountering two high-quality reservoir zones with 

54.5 m of total net gas-pay. Maenad-1, located 50 km southwest of Urania in 1220 m 

of water was drilled in March 2000. The well was drilled to a total depth of 2690 m and 

encountered two high-quality reservoir zones with a total net gas-pay of 20 m. 

In January 2001, 2.5 km south-southeast of Geryon, Callirhoe-1 was drilled. While 

an unsuccessful exploration test of deeper reservoirs, it successfully appraised the 

Geryon gas accumulation. 

The latest gas discovery, Io-1, was made in January 2001. Located 40 km northwest 

of Maenad in 1350 m of water, Io reached a total depth of 3020 m and encountered a 

single gas-bearing zone. 

Retention leases were awarded over all of the gas fi elds during 2003 and are named 

WA-19-R through to WA-26-R. Subsequent to the award of the gas retention leases, 

the remaining graticular blocks of WA-267-P were relinquished. 

Iago and Wheatstone 

In December 2000, the joint venture fulfi lled the WA-25-P permit obligations by drilling 

Iago-1. Situated 6.4 km north of North Tryal Rocks-1, Iago-1 was drilled in 118 m of 

water, reaching a total depth of 3354.5 m. A single reservoir with 20 m of net gas pay 

was encountered. Retention Leases WA-16-R (from WA-25-P) and WA-17-R (from 

WA-253-P) were granted in 2002 over the Iago fi eld. The WA-25-P permit has since 

been relinquished. 

In July 2004, ChevronTexaco at 100 per cent drilled the Wheatstone-1 wildcat targeting the 

Triassic AA sands of the Mungaroo Formation. Situated 12 km west of the Iago-1 discovery 

well, Wheatstone was drilled in 215 m water and reached a total depth of 3410 m. The well 

encountered 126 m of hydrocarbon column within the Tithonian and Triassic Mungaroo AA 

sands. A 50.5 m conventional core was cut and a DST was undertaken over the lower AA 

sands. Gas fl owed at a rig-constrained rate of 54 MMcf/d. 

THE GORGON AREA GAS RESERVES 

In January 1999, international petroleum consultants Netherland, Sewell and 

Associates, Inc. (NSAI) of Dallas Texas independently certifi ed that proven hydrocarbon 

reserves for the Gorgon area fi elds were 360 Bcm (12.9 Tcf), including 270 Bcm 

(9.6 Tcf) for the Gorgon fi eld itself. Proven and probable reserves exceed 500 Bcm 

(17.6 Tcf) and possible reserves extend the total to 608 Bcm (21.5 Tcf). The raw gas 

from these fi elds contains 12–15 per cent carbon dioxide. 

In September 2003, NSAI independently certifi ed additional proven hydrocarbon 

reserves of 3.2 Tcf for the Deepwater Fields of Geryon, Eurytion, Maenad, Orthrus 

and Urania. Proven and probable reserves for these fi elds are 4.4 Tcf and possible 

reserves extend the total to 6.1 Tcf of gas. The raw gas from these fi elds contains 


67


68 


Gorgon Area cont. 

Ichthys Gas and Condensate 

Location 

440 km north of Broome 

Basin 

Browse, Offshore 

Permit 

WA-285-P 

Ownership 

INPEX Browse Ltd (Operator) 100% 

Contact 

INPEX Browse Ltd 

2 The Esplanade 

Perth WA 6000 

Tel: +61 8 9223 8433 

Fax: +61 8 9223 8455 

Web: www.inpex.co.jp/english/ 

around 3 per cent inert gases, including carbon dioxide. Wheatstone reserves were 

certifi ed during the year. These will be reviewed once the 3D seismic data have been 

evaluated. 

The joint venture considers that the reserves are suffi cient to support a major LNG 

development as well as providing gas to the domestic market. For comparison, the 

North Rankin fi eld was developed by the Northwest Shelf Gas joint venture based on 

proven gas reserves of around 200 Bcm (7 Tcf), with around 3 per cent carbon dioxide. 

LNG DEVELOPMENT 

Securing LNG market commitments for a two-train LNG project, and progressing domestic 

gas supply opportunities, will continue to be core focus areas for the Gorgon Development. 

Contractor selection for FEED work progressed throughout 2004 and the contracts 

for the FEED/EPCM (Engineering Procurement Construction Management) work will 

be executed on approval by the Gorgon Joint Venture to enter the FEED phase. The 

downstream FEED/EPCM contract will include the LNG facility on Barrow Island and 

the domestic gas pipeline to shore, with the Upstream contract covering all subsea 

facilities associated with transporting the gas to Barrow Island. 

The Gorgon Development will continue to progress environmental approvals with the 

public release of the EIS/ERMP (Environmental Risk Management Plan) expected later 

in the year, to be followed by a 10-week public comment period. 

DOMESTIC GAS DEVELOPMENT 

Since August 1999, the joint venture has been actively marketing domestic gas aimed 

at supplying Greater Gorgon gas to industrial users in the northwest region of 

Western Australia. This initiative complements the joint venture’s continuing LNG 

development plans. 

ChevronTexaco acts as the domestic gas-marketing agent on behalf of the joint venture. 

The marketing effort is seeking to attract new industrial gas users to Western Australia 

such as methanol, gas-to-liquids and ammonia–urea projects, as well as meeting 

growth in the existing industrial gas market. Gorgon would require about 300 to 500 TJ/d 

of gas demand to justify the infrastructure needed to bring the Gorgon gas to shore 

for processing. 

The Ichthys fi eld was fi rst indicated by the Brewster-1A exploration well drilled by 

Woodside in 1980. INPEX acquired a 100 per cent interest in WA-285-P in August 1998 

and conducted a 2D seismic survey in the same year. In 2000 and early 2001, INPEX 

drilled three exploration wells and tested gas and condensate from all three wells. 

WesternGeco acquired 3D seismic data as Multiclient survey in this region in 2001 

and INPEX purchased and reprocessed a part of these data for evaluation. In 2003 and 

early 2004, INPEX drilled three exploration and appraisal wells and confi rmed gas and 

condensate from all three wells. 

Reserve estimates for the Ichthys fi eld is approximately 6 Tcf of gas and 230 MMbbl 

of condensate.

Jansz Gas 

Location 


Basin 


Permit 

WA-18-R 

Ownership 

Mobil Exploration & Producing 

Australia Pty Ltd (Operator) 50% 


Contact 




Tel: +61 3 9270 3333 

Fax: +61 3 9270 3493 


John Brookes Gas and Condensate 

Location 

60 km northwest of Varanus Island 

Basin 


Permit 

WA-214-P 

Ownership 


Santos (BOL) Pty Ltd 45.00% 

Contact 

Apache Energy Limited 


PERTH WA 6000 

Tel: +61 8 9422 7222 

Fax: +61 8 9422 7447 



The Jansz gas fi eld is located in Retention Lease WA-18-R on the western fl ank of the 

Kangaroo Syncline in the Carnarvon Basin, 70 km northwest of the Gorgon gas fi eld. 

The Jansz-1 discovery well was drilled in April 2000 and intersected 29 m of net gas-pay. 

A second well Io-1 (18 km from Jansz-1) was drilled in January 2001 on the adjacent 

permit WA-267-P and intersected the same sandstone reservoir with a total of 44 m of 

net gas pay. 

In November 2002, the Jansz-2 appraisal well was drilled to determine the extent of 

the initial discovery. Jansz-2 was drilled in 1350 m of water to a depth of approximately 

3300 m below sea level confi rming the western extension of the Jansz gas fi eld. The 

Geryon-1 exploration well drilled in the adjacent permit WA-267-P in August 1999 

intersected gas in two sandstones defi ning the Geryon gas fi eld. Subsequent analysis 

of pressure data determined the sandstones to be in communication with the Jansz 

sandstone reservoir. This observation combined with the results of Jansz-2 confi rmed 

the Jansz gas fi eld covers an area in excess of 2000 km 2 and has an interpreted 400-m 

gross gas-column. Including an extension into the adjacent WA-25-R and WA-26-R 

licences (former WA-267-P), it is estimated that the fi eld contains approximately 

20 Tcf of recoverable sales gas, believed to be the largest gas discovery ever to have 

been made in Australian waters. 

In June 2003, the Jansz-3 appraisal well was drilled in 1340 m of water to a depth of 

approximately 2900 m below sea level. Jansz-3 confi rmed the high, reservoir-quality 

continuity with a successful well test fl owing at a maximum rate of 2056 kcm/d 

(72.6 MMcf/d) of gas. The successful production test demonstrates that it can be 

produced at rates that will allow a range of commercial developments. 

In early 2004, a 2800 km 2 3D seismic survey was acquired over WA-18-R and 

surrounding retention leases to further appraise the Jansz gas fi eld. 

Development 

The joint venture is now conducting a study to assess a range of options to 

commercialise this substantial gas resource. 

In November 1998, the John Brookes-1 well was drilled to a total depth of 3741 m in 

a water depth of 20 m and intersected an 80-m gross hydrocarbon-column. The well 

was tested over two separate zones and achieved a combined fl ow rate of 1510 kcm/d 

(53.4 MMcf/d) of gas and 460 bbl/d of 46 o API condensate. 

The joint venture estimates that the John Brookes fi eld could contain recoverable gas 

reserves of more than 28 Bcm (1 Tcf). The proximity to existing infrastructure provides 

the potential for an early development. 

A second well in the permit, Moon-1, was drilled to a total depth of 3035 m in 

October 1999, but was plugged and abandoned as a dry hole. 

The appraisal well, Thomas Bright-1 drilled in March 2003 and Thomas Bright-2 

drilled in late 2004 confi rmed economic viability of the fi eld. 

A fi eld development is currently in progress via an unmanned, six-slot wellhead 

platform; an initial 2–3 production wells will be drilled in the second quarter of 2005; 

a single, three-phase 18-inch pipeline linking the wellhead platform to the Varanus 

Island gas treatment facilities is being laid; and debottlenecking of the East Spar 

gas plant to handle gas from the John Brookes fi eld is also taking place in the fi rst 

half of 2005. 

First gas is scheduled for July 2005. 


69


70 


Macedon Gas 

Location 


Basin 



WA-12-R 

Ownership 

BHP Billiton Petroleum 


Apache Energy Limited 28.57% 

Operator 


Contact 




PERTH WA 6000 

Tel: +61 8 9278 4888 

Fax: +61 8 9278 4899 


Mutineer–Exeter Oil 

Location 

150 km north of Dampier 

Basin 

Carnarvon, offshore, Dampier Sub-basin 

Permit 

WA-26-L, WA-27-L 

Ownership 

Santos Ltd Group (Operator) 33.3977% 

Kufpec Australia Pty Ltd 33.4023% 

Nippon Oil Exploration 

(Dampier) Ltd 25.0000% 

Woodside Energy Ltd. 8.2000% 

Contact 

Santos Limited 

Level 28, Forrest Centre 


PERTH WA 6000 

Tel: +61 8 9460 8900 

Fax: +61 8 9460 8971 

Web: www.santos.com.au 

The Macedon fi eld was discovered in November 1992 by the West Muiron-3 well which 

encountered a gas column in excess of 81 m, but did not establish a hydrocarbon– 

water contact. The well was subsequently plugged and abandoned as a gas discovery 

after being drilled to a total depth of 1200 m. In May 1993, the West Muiron-4 well was 

drilled to a total depth of 1550 m and was suspended as a potential gas producer. 

In November 1994, the joint venture successfully completed a fi ve-well appraisaldrilling 

program in the Macedon fi eld. The wells confi rmed the structural 

interpretation, gas-water contact, reservoir distribution and production of the fi eld. 

All the wells were plugged and abandoned, as programmed, with the exception of 

Macedon-4, which was suspended as a potential gas producer. 

GAS MARKETING AND DEVELOPMENT 

The joint venture estimates that Macedon contains a gas resource of up to 1.2 Tcf. 

Gas recovered to date is dry containing no condensate or LPG. The resource size 

and composition suggest development as either industrial gas feedstock for power 

generation or for commodity chemicals such as methanol or ammonia–urea. 

BHP Billiton is continuing to investigate gas market opportunities for Macedon. 

MUTINEER 

The Mutineer fi eld is located in permit WA-26-L, WA-27-L, in the northern part of the 

Carnarvon Basin, 150 km north of Dampier and 40 km north of the existing Wanaea– 

Cossack production facility (Cossack Pioneer FPSO). Water depth is 150 m. 

The discovery well (Pitcairn-1), drilled in 1997 intersected 2.7 m of oil in the uppermost 

J40 sandstone of the Late Jurassic Angel Formation, with an oil–water contact (OWC) 

of 3128 m subsea interpreted from wireline logs and pressure data. A deeper 

2.5 m oil-column was also intersected in the J35 sequence of the Angel Formation. 

Mutineer-1B was drilled in August 1998 following mapping of the Mutiny 3D seismic 

shot in 1997 over most of the permit. Mutineer-1B encountered an 8-m oil-column 

with no OWC. Results from Mutineer-1B indicated a stratigraphic trap combining the 

Mutineer and Pitcairn oil discoveries. 

Norfolk-1 was drilled in March 2002, intersecting a 14.9-m oil-column in the primary 

target sand (J40). Norfolk-2 was drilled as a down-dip sidetrack and encountered 

8.6 m of oil, with no OWC. Mutineer-2 was drilled in May 2002, and Mutineer-3 drilled 

in November 2002, the latter intersecting an 8-m oil-column with OWC at 3128 m 

subsea. Mutineer-3 was production tested, at rates up to 1048 m 3 /d (6600 bbl/d), 

fl owing 43 o API oil with a gas-to-oil ratio of only 1.78 m 3 /m 3 (10 scf/bbl). 

Bounty-2 was drilled to test a separate culmination to the southeast of the Mutineer 

fi eld. The primary objective Upper Angel Formation J40 reservoir was wet, but within 

a secondary objective, a total of 37 m of oil was also encountered in three separate 

zones within the Lower Angel and Legendre Formations. Bounty-2 was sidetracked up 

dip to appraise the deeper oil columns with the Bounty-3 well. This well encountered a 

thin sub-commercial net oil-column and was plugged and abandoned. 

Three appraisal wells were drilled in the Mutineer fi eld during 2004, Mutineer-7, 

-8 and -9. The results of these appraisal wells were used to better defi ne the fi eld and 

to plan and optimise the development well locations. The appraisal results were mostly

Ravensworth–Crosby–Stickle–Harrison Oil 

Location 


Basin 



WA-155-P(1) 

Ownership 




Inpex Alpha Ltd 28.500% 


disappointing with the reservoir being intersected low to prognosis and thinner. 

The development drilling campaign for Mutineer commenced in 2004 with three 

horizontal production wells successfully drilled, tested and completed (Mutineer-4H, 

-5H and -9H). Additional appraisal and development drilling is planned in 2005. 

EXETER 

The Exeter fi eld is located approximately 10 km south of Mutineer within permit WA-26-L 

and WA-27-L. It was discovered in April 2002 when the Exeter-1 well encountered a 

23-m oil-column with no OWC. Exeter-2 was drilled 40 m down-dip of Exeter-1, in May 

2002, and encountered a 12-m oil-column with OWC at 3136 m subsea. Exeter 3 was 

drilled in December 2002, on the downthrown side of the Exeter Fault, encountering the 

J40 sand 38 m high to prognosis, but entirely water-bearing. Exeter-3 also encountered 

a 9-m oil-column in the Lower Angel Formation, with an OWC at 3432.6 m subsea. 

The Carteret-1 near fi eld exploration well was drilled in July 2003, in permit WA-4-L 

(Woodside Energy Ltd. operator) adjacent and to the south of WA-191-P, and encountered 

a probable thin oil-column in the J40. However the OWC is shallower than that encountered 

in Exeter-2, so the Carteret discovery is separate to the Exeter fi eld. 

During 2004, Exeter-4AH horizontal development well was successfully drilled and 

tested at 10 220 bbl/d. Exeter-5ST1 appraisal well was drilled in the southern part of the 

fi eld and encountered a thin oil-column that was insuffi cient to justify a completion. 

The Exeter-6 appraisal well was drilled in an area between Exeter-4AH and Exeter-5ST1 

and intersected a 14.5-m oil-column in the J40 reservoir. It is likely that a development 

well will be drilled in the Exeter-6 area during 2005. 

DEVELOPMENT PLAN 

In October 2003, the joint venture submitted a fi eld development plan to develop 

the fi elds using subsea wells tied back, via a subsea manifold at each fi eld, to an 

FPSO with an oil process capacity of 100 000 bbl/d and liquid process capacity of 

140 000 bbl/d. Given the low GOR oil, the wells will use dual electric submersible pumps, 

and each fi eld will use a multiphase seabed booster pump located at a subsea manifold, 

all powered from the FPSO. There is provision for up to nine wells at Mutineer and fi ve 

wells at Exeter. Field life is estimated at between 5 and 12 years, depending on reservoir 

performance. 

First oil is expected in early 2005, only 17 months after the fi nal investment decision, from 

initially three wells at Mutineer and one at Exeter. Additional development, appraisal and 

exploration drilling within WA-191-P is planned to commence around mid-2005. 

There is potential to use water injection to supplement natural reservoir energy in either 

or both fi elds, but this decision will depend mainly on initial reservoir performance. Preinvestment 

has been made in topsides for up to 150 000 bbl/d of water injection capacity. 

In addition, provision has been made for tie-back of near-fi eld discoveries, and the joint 

venture has identifi ed several candidates for future development. 

In July 2003, the semi-submersible SEDCO 703 drilled Ravensworth-1 on the 

WA-155-P (1)–WA-12-R boundary, encountering 7 m of gross gas and a 39-m gross 

oil-column in the Pyrenees Member of the Lower Barrow Group Sandstones. Crosby-1, 

Located in WA-12 -R was then drilled in October 2003 intersecting a 35-m gross oilcolumn 

in the target Pyrenees Member Sandstones. 

Exploration activity during 2004 by the operator BHP Billiton in WA-155-P(1) and 

WA-12-R focused on a drilling program by the SEDCO 703 to appraise the Ravensworth 

and Crosby oil discoveries and test adjacent fault blocks. The fi rst well in this program, 

Stickle-1, intersected a 27.3-m gross oil-column while the second, Harrsion-1, 

intersected 7 m of gross oil-pay, both within the Pyrenees Member Sandstones. 

On completion of these wells, the rig moved to appraise the Ravensworth and 

Crosby discoveries. 


71


72 


Ravensworth–Crosby–Stickle–Harrison cont. 

Operator 



WA-12-R 

Ownership 




Operator 


Contact 




PERTH WA 6000 

Tel: +61 8 9278 4888 

Fax: +61 8 9278 4899 


Scarborough Gas 

Location 


Basin 



WA-1-R 

Ownership 


(Australia) Pty Ltd (Operator) 50% 

Esso Australia Resources Pty Ltd 50% 

Contact 




Tel: +61 3 9270 3333 

Fax: +61 3 9270 3493 



WA-346-P 

Ownership 



Contact 




PERTH WA 6000 

Tel: +61 8 9278 4888 

Fax: +61 8 9278 4899 


The Crosby-2 appraisal well, located 2.7 km northeast of Crosby-1, was drilled in 

June 2004 and encountered a 25-m gross oil-column in the Pyrenees Sandstone. 

After bypass coring operations, the rig moved to drill an appraisal well on the 

Ravensworth fi eld. Ravensworth-2, located 2.1 km northeast of Ravensworth-1, 

intersected a 29-m gross oil-column within the Pyrenees Sandstone. Both Crosby-2 

and Ravensworth-2 were successful in defi ning the northern extension of each of the 

oil accumulations in these fi elds. 

From July to August 2004, the Stickle-2 and Stickle-3 appraisal wells were drilled in 

WA-12-R using the deepwater, semi-submersible rig, the Atwood Eagle. Stickle-2, 

located approximately 2.5 km northeast of Stickle-1, intersected a gross oil-column of 

23 m. The subsequent sidetrack well, Stickle-3, obtained further well engineering and 

drilling data. Development planning is underway, including a review of the viability of 

the tie-in of the adjacent West Murion oil discovery made in the early 1990s. 

BHP Billiton has undertaken feasibility studies to select a preferred development 

option for the project. 

The Scarborough gas fi eld was discovered in 1979 by the drilling of Scarborough-1 well 

in more than 900 m of water. The gas fi eld is a relatively simple anticlinal structure 

at a depth of about 1800 m. At the time of discovery, the lack of technology and 

undeveloped gas markets made the remote, deepwater gas fi eld uneconomic 

to develop. 

In early 1996, a 2440 km 2 seismic survey was completed over the fi eld to 

defi ne possible well locations for appraisal drilling. Based on this data, 

the Scarborough-2 appraisal well was spudded in June 1996 and drilled 

to a total depth of 2068 m measured depth. 

In July 2003, BHP Billiton was awarded exploration permit WA-346-P, immediately 

to the north of Retention Lease WA-1-R, which BHP Billiton hold jointly with Esso 

Australia. These blocks are in water depths of 900 to 1500 m and contain the 

Scarborough gas fi eld, discovered in 1979. WA-346-P also contains the smaller Jupiter 

gas discovery and has potential for further gas resources. BHP Billiton estimates the 

Scarborough and Jupiter gas fi elds contain a proven plus probable gas resource in 

excess of 8 Tcf. 

During 2004, BHP Billiton acquired a 912 km 2 3D seismic survey over the Scarborough 

fi eld in both the permits. BHP Billiton operated the acquisition of the survey in WA-1-R 

with the agreement of Esso Australia. In December 2004, BHP Billiton commenced a 

three-well appraisal drilling program of the Scarborough gas fi eld. 

GAS MARKETING AND DEVELOPMENT 

The Scarborough gas fi eld is under retention lease and the WA-1-R Joint Venture 

currently has no planned development. Outside Joint Venture activities, BHP Billiton 

commenced pre-feasibility studies in January 2004 for an LNG project based on 

developing the Scarborough gas fi eld and other existing and potential gas resources 

BHP Billiton own in the area. 

This work is progressing, and BHP Billiton has selected a preferred site 4.5 km 

southwest of Onslow, for the planned gas-processing, liquefaction, storage and export 

facilities. The initial phase of this project is expected to produce approximately 6 Mt/a 

of LNG for export into either Asia or the United States.

Location 

425 km north of Broome 

Basin 

Browse, offshore 

Permits 

WA-28-R to WA-32-R, TR/5, R/2 

Ownership 

WA-28-R and WA-29-R 

Woodside Energy Ltd. (Operator) 25% 

BP Developments Australia Ltd 20% 

ChevronTexaco Australia Pty Ltd 20% 

BHP Billiton Petroleum (NWS) Pty Ltd 20% 

Shell Development (Australia) Pty Ltd 15% 

WA-30-R to WA-32-R, TR/5, R/2 

Woodside Energy Ltd (Operator). 50.00% 



BHP Billiton Petroleum (NWS) Pty Ltd 8.33% 


Contact 



PERTH WA 6000 

Tel: +61 8 9348 4000 

Fax: +61 8 9325 8178 



Scott Reef–Brecknock–Brecknock South Gas and Condensate 

Stybarrow Oil 

Location 

55 km northwest of Exmouth 

Basin 



WA-255-P(2) 

Ownership 



Woodside Energy Ltd. 50% 

Contact 




PERTH WA 6000 

Tel: +61 8 9278 4888 

Fax: +61 8 9278 4899 


The Scott Reef gas discovery was made in 1971. A subsequent appraisal well recorded 

gas fl ows of up to 1270 kcm/d (45 MMcf/d). The Brecknock gas discovery was made 

in 1979 with the Brecknock-1 well intersecting a net gas–condensate interval of some 

72.5 m. 

The Brecknock South gas discovery was made in 2000 and intersected a net gascolumn 

of 119 m. With the exception of areas around Scott Reef lagoon, all fi elds are 

in relatively deep water ranging from 400–800 m. 

The estimated contingent resources of the fi elds are 20.49 Tcf of dry gas and 311 MMbbl 

of condensate. 

The joint venture participants hold retention leases covering the discoveries. 

Potential markets for the gas include LNG to the Asia–Pacifi c region and natural gas 

into Australian markets. 

In February 2003, Stybarrow-1 was drilled in 825 m of water and encountered a 23-m oilcolumn, 

with no water leg, in the target Macedon Member Sandstones. After sidetracking 

to acquire core across the reservoir, the well was plugged and abandoned. Eskdale-1 was 

drilled to test a different trapping confi guration on March 2003, 12.5 km north of Stybarrow-1. 

It was plugged and abandoned after intersecting non-commercial oil shows. In June 2003, an 

updip appraisal of the discovery known as Stybarrow-2 intersected a 22-m oil-column in the 

target Macedon Member Sandstones, with no gas or water legs. 

In April 2004, BHP Billiton contracted the deepwater, semi-submersible rig, the Atwood 

Eagle, to further appraise the discovery at Stybarrow and the oilshows at Eskdale-1 and 

drilled Eskdale-2 in 825 m of water. Eskdale-2 encountered a 24-m gas-column and 13-m 

oil-column, with no water leg in the target Eskdale Member Sandstones. After sidetracking to 

acquire core across the reservoir, the well was plugged and abandoned. 

Following Eskdale-2, the Stybarrow-3 appraisal well, located 2 km north of the Stybarrow-1 

discovery well was drilled. The objective was to defi ne the oil accumulation’s northern limit. 

Stybarrow-3 encountered a 6.5-m gross oil-column in the Macedon Sandstone. A sidetrack 

well, Stybarrow-4, was subsequently drilled targeting 350 m to the southwest and intersected 

a 16-m gross oil-column. The results of the two appraisal wells increased BHP Billiton’s 

estimation of the potential oil volume in the Stybarrow fi eld. 

BHP Billiton examined a number of alternative developments with an FPSO selected as the 

preferred option. Also under consideration is the construction of a gas pipeline between the 

proposed Stybarrow Development and the Griffi n Venture, known as the Griffi n to Stybarrow 

(GTS) pipeline. 


73


74 


Tern–Petrel Gas 

Location 

250 km west of Darwin 

Basin 


Permit 

WA-27-R, WA-6-R, NT/RL-1 

Ownership 

Tern 

Santos Ltd Group 100% 

Petrel 

Santos Ltd Group 95% 

Origin Energy Bonaparte Pty Ltd 5% 

Contact 

Santos Limited 

Ground Floor Santos House 

91 King William Street 

ADELAIDE SA 5000 

Tel: +61 8 8218 5111 

Fax: +61 8 8218 5666 

Web: www.santos.com.au 

Whicher Range Gas 

Location 

21 km south of Busselton 

Basin 


Permit 

EP 408 

Ownership 

Southern Amity Inc. (Operator) 47.957% 

GeoPetro Resources Company 17.043% 

SCGAU Pty Ltd 15.000% 

Korea National Oil Corporation 20.000% 

Contact 

Antares Energy Limited (formerly Amity 

Oil Limited) 

2nd Floor, 18 Richardson Street 


Tel: +61 8 9324 2177 

Fax: +61 8 9324 1224 

Email: mail@antaresenergy.com 

Web: www.antaresenergy.com 

PETREL 

The Petrel fi eld is located on the Western Australian – Northern Territory seabed border in 

permits WA-6-R and NT/RL-1. Six wells have been drilled in the fi eld, including the discovery 

well in May 1969 which blew out for a period of 14 months prior to drilling a relief well. 

The fi ve subsequent wells were successful in delineating the fi eld with recorded rates 

ranging from 14.5–28.7 MMcf/d. 

Petrel-5 fl owed gas at a rate of 980 kcm/d (34.6 MMcf/d) and condensate at a rate of 

16.6 bbl/d in October 1994. Located in the western side of the fi eld within WA-6-R, the well 

was plugged and abandoned. 

In November 1995, Petrel-6 was drilled to a total depth of 3915 m but was plugged and 

abandoned after failing to intersect the reservoir sands that were targeted. 

TERN 

The Tern fi eld is located approximately 60 km from Petrel in Western Australian waters within 

permit WA-27-R. It was discovered in 1971 when the Tern-1 well encountered more than 36 m 

of gross-pay and fl owed gas at a rate of 200 kcm/d (7 MMcf/d). In 1982, Tern-2 intersected over 

28 m of gross-pay and fl owed gas at rates of up to 420 kcm/d (14.8 MMcf/d). The Tern-3 well, 

drilled in 1988 on a satellite structure to the south, was dry. 

Tern-4 was drilled to a total depth of 2633 m in October 1994 and confi rmed the existence of gas 

in the southeast area of the fi eld. Tern-4 was not completed as a production well as the hole was 

specifi cally designed to provide information on the reservoir. 

In January 1998, the Tern-5 well fl owed gas at a rate of 447 kcm/d (15.8 MMcf/d) and 

indicated a gross gas-column of 35 m after reaching a total depth of 2702 m. 

DEVELOPMENT OPTIONS 

The joint venture estimates that the Tern and Petrel fi elds contain a contingent gas reserve of 1.4 Tcf. 

Development options include a tie-in to the proposed Blacktip facility to supply the NT electricity 

generation market or a dedicated pipeline to Darwin to supply an expanded LNG facility. 

Union Oil discovered the Whicher Range gas fi eld in 1968 when the Whicher Range-1 well fl owed 

a gas rate of 54 kcm/d (1.9 MMcf/d) from a 9-m sand. Several other sands were also tested, 

making a cumulative gas rate of 156 kcm/d (5.5 MMcf/d) from these individual sands. Because of 

the gas prices at the time, the fi eld developed was rendered uneconomic. 

Mesa Petroleum and British Petroleum drilled two subsequent appraisal wells in 1980 and 1982 

respectively. These wells confi rmed the signifi cant size of the fi eld, however, the fl ow rates from 

the tight sands were still not enough to justify the fi eld development. 

HYDRAULIC FRACTURE STIMULATION 

Amity Oil took over the rights to the Whicher Range permit in July 1997 with the intention of 

applying fracture stimulation technology. As a result, Amity farmed-in Pennzoil Exploration 

Australia and participated in the Whicher Range-4 drilling, Whicher Range-1 re-entry and 

fracture stimulation of these wells. The projects were completed in June 1998 and were operated 

by Pennzoil. 

Whicher Range-4 was fracced in four zones and Whicher Range-1 in three zones. In spite of the 

fracs completion as planned, the well productivities were disappointing, the stabilised gas fl ows 

being 40 kcm/d (1.4 MMcf/d) from each well. Moreover, these gas fl ow rates were lower than 

pre-frac measurements. 

The investigation conducted to explain this unusual behaviour concluded that the water-based 

fi ltrate of the fracturing fl uid caused water blockage in the fracture walls, restricting severely 

the gas fl ow from the reservoir to the fracture. As a result, a remedial stimulation to remove the 

water-block was recommended.


REMEDIAL STIMULATION – WHICHER RANGE-4 

Based on petrophysical work on a reservoir core sample, Stimlab Inc. recommended a highpressure 

injection of liquid carbon dioxide into the Whicher Range-4 well. The injected carbon 

dioxide would dissolve into the water phase of the water-block, then the combined effect of 

Formation temperature and pressure reduction, caused by blowing down the well to atmosphere, 

would generate carbon dioxide expansion and rapid withdrawal from the sand face, removing in 

this way the water-block. 

In late 1999, Amity (86 per cent) and GeoPetro Resources Company (14 per cent) undertook the 

remedial program, which resulted in the well fl owing gas at a stabilised rate of 87 kcm/d 

(3.08 MMcf/d). Subsequent production logging indicated that only one sand was producing out of 

three zones; therefore, if these three zones were properly remedially stimulated, the total well 

fl ow rate would have been even higher. 

Whicher Range-4 was suspended as a future commercial production well. The success of 

fracture stimulation and the remedial program, which more than doubled the gas fl ow rate from 

the well, indicated that fracture stimulation could generate commercial fl ow rates from the 

reservoir, provided minimum skin damage was achieved. 

WHICHER RANGE-5 

Amity Oil drilled Whicher Range-5 from October 2003 to January 2004. The initial drilling design 

included the air drilling of the whole Sue Reservoir section to eliminate skin damage, but after the 

failure of three attempts to air drill this section the well was drilled using conventional KCL mud. 

While air drilling moderate gas fl ows were noted, indicating the reservoir gas content. 

WHICHER RANGE-5 FRACTURE STIMULATION 

To neutralize potential water blockage and eliminate skin damage the use of diesel basefracturing 

fl uid was recommended. The procedure entailed under-balanced, oriented 

perforations. 

The reservoir is composed of 17 sand layers of 5 m to 30 m thickness, from which fi ve prominent 

sands were chosen to be frac stimulated. It was expected that through vertical fracture growth, 

the adjacent sands would also be stimulated. 

Unfortunately, a higher than expected fracture gradient complicated the fracture operation. 

The high rock stress caused injection pressure greater than the surface facilities pressure rating. 

In spite of these drawbacks, four fracs were conducted from July to October 2004, from which 

two were successfully completed. 

At this stage it was clear that the area around Whicher Range-5 presented unusual high rock 

stress, complicating any fracture operation. Moreover, it was apparent that to achieve reasonable 

fracture geometry, higher-pressure-rated facilities and additional numbers of pumps would be 

required, making the project uneconomical. For these reasons it was decided to terminate the 

fracture campaign. 

WHICHER RANGE-5 WELL TESTING AFTER FRACTURE STIMULATION 

Following the termination of the fracturing campaign, the bridge plugs were drilled, the diesel 

unloaded and the well left to fl ow for clean-out. The total diesel injected during the campaign 

was 7450 bbl, from which a total of 3546 bbl were recovered after 36 days of production. 

As a result of the poor well performance and the presence of water, it was decided to shut-in the 

well in preparation for it to be plugged and abandoned. With these results it was clear that the 

well would not be commercial, consequently it was plugged and abandoned on 11 February 2005. 

GAS MARKETING 

The joint venture estimates that the Whicher Range fi eld contains in-place gas resources of 

28–113 Bcm (1–4 Tcf). The fi eld is just 65 km from the end of the DBNGP and is close to the 

growing mineral-processing industry market in the southwest of Western Australia, as well as 

to the towns of Busselton, Margaret River and Dunsborough. Gas quality from Whicher Range is 

suited for domestic consumption as it contains less than 1.5 per cent inert gases and no sulphur. 

Furthermore, the new technologies to monetise low deliverability gas reservoir are applicable 

to Whicher Range. This includes the generation of electricity at well site; thus eliminating the 

necessity of pipeline and plant treatment constructions. For this to be achievable, a low but 

sustainable long-term fl ow deliverability is required. 


75


76 

WESTERN AUSTRALIAN PETROLEUM FACT SHEET 

TABLE 1. PRODUCTION AND RESERVES AS AT 31 DECEMBER 2004 - DEVELOPED FIELDS 

Field Operator Annual Production # Reserves ## 

Oil Condensate Gas Oil Condensate Gas 

(bbl) (bbl) (kcm) (MMbbl) (MMbbl) (Bcm) 

2004 2004 2004 90% 50% 90% 50% 90% 50% 

Agincourt Apache 86,175 1,003 1,798 0.48 0.61 0.00 0.00 0.00 0.00 

Barrow Island ChevronTexaco 3,001,612 0 59,113 20.98 31.36 0.00 0.00 0.47 0.80 

Beharra Springs Origin 0 3,226 50,044 0.00 0.00 0.00 0.01 0.05 0.14 

Beharra Springs North Origin 0 2,235 35,136 0.00 0.00 0.00 0.00 0.00 0.00 

Blina Kimberley Oil 9,624 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

Boundary Kimberley Oil 2,197 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

Buffalo Nexen 1,065,542 0 6,470 0.00 0.00 0.00 0.00 0.00 0.00 

Campbell Apache 0 21,177 33,923 0.00 0.00 0.03 0.06 0.05 0.08 

Chinook–Scindian BHP Billiton 1,539,716 0 183,654 2.14 3.71 0.00 0.00 0.14 0.30 

Cossack Woodside 3,616,698 0 17,426 22.01 44.03 0.00 0.00 0.06 0.14 

Cowle ChevronTexaco 39,072 0 2,236 0.03 0.07 0.00 0.00 0.00 0.00 

Crest ChevronTexaco 14,586 0 3,197 0.01 0.02 0.00 0.00 0.00 0.00 

Dongara ARC Energy 2,488 1,542 40,322 0.00 0.00 0.00 0.00 0.38 0.81 

Double Island Apache 1,026,980 4,621 6,949 1.13 1.64 0.01 0.01 0.01 0.01 

East Spar Apache 0 1,560,832 977,821 0.00 0.00 5.28 9.69 2.96 5.41 

Echo–Yodel Woodside 0 10,857,767 2,331,520 0.00 0.00 7.55 16.98 2.35 4.53 

Endymion Apache 0 108,027 132,159 0.00 0.00 0.06 0.09 0.06 0.01 

Gibson Apache 0.00 0.00 0.00 0.00 0.00 0.00 

Gipsy Apache 165,847 566 6,503 1.60 1.88 0.01 0.01 0.02 0.02 

Goodwyn Woodside 0 12,130,257 7,745,850 8.18 13.21 92.46 144.04 92.79 122.81 

Griffi n BHP Billiton 2,581,279 0 30,577 4.43 9.31 0.00 0.00 0.04 0.09 

Gudrun Apache 478,582 359 4,180 0.31 0.44 0.00 0.00 0.00 0.00 

Harriet Apache 382,925 1,176 12,749 1.97 2.30 0.00 0.00 0.14 0.15 

Hermes Woodside 5,700,572 0 58,573 15.01 35.85 0.00 0.00 0.11 0.31 

Hoover Apache 113,018 926 1,435 0.03 0.05 0.00 0.00 0.00 0.00 

Hovea-Eremia ARC Energy 2,248,630 0 23,129 4.40 6.92 0.00 0.00 0.00 0.00 

Jingemia Origin 754,082 0 5,491 2.74 4.69 0.00 0.00 0.00 0.00 

Lambert Woodside 969,070 0 7,604 8.18 16.98 0.00 0.00 0.08 0.17 

Laminaria East Woodside 340,689 5,837 866 0.00 0.44 0.00 0.00 0.00 0.00 

Legendre North Woodside 8,821,401 0 253,256 3.77 5.03 0.00 0.00 0.00 0.00 

Legendre South Woodside 245,290 0 68,466 0.00 0.00 0.00 0.00 0.00 0.00 

Linda Apache 0 998,610 565,349 0.00 0.00 4.28 5.19 2.67 3.19 

Little Sandy Apache 58,834 333 705 0.06 0.09 0.00 0.00 0.00 0.00 

Lloyd Kimberley Oil 1,564 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

Monet Apache 909,388 2,629 5,337 0.03 0.06 0.00 0.00 0.00 0.00 

Mount Horner ARC Energy 17,386 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

North Gipsy Apache 0.00 0.00 0.00 0.00 0.00 0.00 

North Pedirka Apache 50,924 329 831 0.01 0.02 0.00 0.00 0.00 0.00 

North Rankin Woodside 0 3,085,713 4,707,740 0.00 0.00 45.92 70.45 145.61 169.39 

Pedirka Apache 271,562 1,841 3,186 0.46 0.51 0.00 0.00 0.00 0.00 

Perseus-Athena Woodside 0 9,023,347 6,887,330 0.00 0.00 162.91 225.17 189.30 256.69 

Roller ChevronTexaco 794,672 0 22,481 1.64 2.41 0.00 0.00 0.00 0.02 

Rosette Apache 0.00 0.00 0.00 0.00 0.00 0.00 

Saladin ChevronTexaco 699,646 0 18,361 1.14 1.94 0.00 0.00 0.02 0.03 

Simpson Apache 515,042 5,722 10,138 0.17 0.45 0.00 0.00 0.00 0.00 

Sinbad Apache 0.00 0.00 0.01 0.01 0.01 0.02 

Skate ChevronTexaco 0 0 139 0.00 0.00 0.00 0.00 0.01 0.00 

South Plato Apache 809,021 988 6,427 1.47 1.60 0.00 0.00 0.01 0.01 

Stag Apache 3,235,235 0 26,004 13.65 23.96 0.00 0.00 0.00 0.00 

Sundown Kimberley Oil 2,062 0 0 0.00 0.00 0.00 0.00 0.00 0.00

Field Operator Annual Production # Reserves ## 

Oil Condensate Gas Oil Condensate Gas 

(bbl) (bbl) (kcm) (MMbbl) (MMbbl) (Bcm) 

2004 2004 2004 90% 50% 90% 50% 90% 50% 

Tanami Apache 140,400 1,555 2,324 0.72 1.00 0.01 0.02 0.02 0.03 

Tubridgi Origin 0 0 14,080 0.00 0.00 0.00 0.00 0.00 0.00 

Victoria Apache 3,273 79 103 0.01 0.01 0.00 0.00 0.00 0.00 

Wanaea Woodside 23,433,782 0 794,573 54.72 119.51 1.89 3.77 1.70 3.48 

Wandoo Mobil 3,015,859 0 80,223 10.72 31.45 0.00 0.00 0.04 0.00 

West Terrace Kimberley Oil 9,231 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

Wonnich Apache 0 182,427 320,765 0.00 0.00 1.23 1.77 1.88 2.71 

Woodada ARC Energy 0 916 32,733 0.00 0.00 0.00 0.00 0.01 0.04 

Woollybutt Eni 8,721,198 0 37,765 2.07 4.01 0.00 0.00 0.00 0.00 

Xyris ARC Energy 0 541 9,748 0.00 0.00 0.02 0.03 0.15 0.22 

Yammaderry ChevronTexaco 21,222 0 1,323 0.02 0.03 0.00 0.00 0.00 0.00 

Yardarino ARC Energy 0 0 189 0.00 0.00 0.00 0.00 0.00 0.00 

Total 75,916,370 38,004,579 25,648,299 184.38 365.60 321.65 477.30 441.14 571.70 

# Production fi gures were provided to the Department of Industry and Resources by operating companies. 

## Reserve fi gures are based on those provided to the Department of Industry and Resources by operating companies at 31/12/04. 

Table 2. RESERVES AS AT 31 DECEMBER 2004 - UNDEVELOPED FIELDS 

Category 1: Potential for Short-Term Development 

Field Operator Reserves ## 

Oil (MMbbl) Condensate (MMbbl) Gas (Bcm) 

90% 50% 90% 50% 90% 50% 

Angel Woodside 0.00 0.00 59.12 84.28 38.79 52.39 

Apium ARC Energy 0.00 0.00 0.01 0.01 0.09 0.09 

Bambra Apache 5.56 7.30 0.18 0.22 0.41 0.49 

Bambra East Apache 0.00 0.00 1.20 1.53 0.71 0.91 

Blacktip Woodside 0.00 0.00 2.52 3.77 13.53 18.17 

Caribou Apache 0.00 0.00 0.57 1.76 0.30 0.97 

Cliff Head Roc Oil 14.00* 0.00 0.00 0.00 0.00 

Coaster ChevronTexaco 0.00 0.00 0.00 0.00 0.00 0.00 

Coniston BHP Billiton 1.89 6.29 0.00 0.00 0.00 0.00 

Corvus Apache 0.00 0.00 0.19 0.50 1.40 3.42 

Doric–Ulidia Apache 0.00 0.00 0.21 0.26 0.55 0.67 

Enfi eld Woodside 96.23 127.68 0.00 0.00 0.00 0.00 

Exeter Santos 8.99 15.98 0.00 0.00 0.00 0.00 

Gorgon ChevronTexaco 0.00 0.00 93.09 120.76 299.90 397.30 

Ichthys Inpex 0.00 0.00 155.99 233.00 115.34 170.01 

John Brookes Apache 0.00 0.00 6.04 7.99 23.84 29.04 

Laverda Woodside 25.79 30.19 0.00 0.00 0.00 0.00 

Lee Apache 0.00 0.00 0.97 1.23 1.15 1.44 

Mutineer Santos 16.98 46.98 0.00 0.00 0.00 0.00 

Narvik Apache 0.00 0.00 0.00 0.00 0.52 0.69 

North Alkimos Apache 0.69 1.11 0.03 0.03 0.03 0.05 

Novara BHP Billiton 1.26 4.40 0.00 0.00 0.00 0.00 

Reindeer Apache 0.00 0.00 1.26 1.95 6.86 10.54 

Rose Apache 0.00 0.00 1.74 2.48 1.16 1.70 

Sage Apache 3.21 4.65 0.00 0.00 0.00 0.00 

Searipple Woodside 0.00 0.00 3.15 4.40 0.76 0.99 

Skiddaw BHP Billiton 1.89 3.77 0.00 0.00 0.00 0.00 

Stybarrow BHP Billiton 61.01 74.85 0.00 0.00 0.00 0.00 

Total 223.5 323.21 326.25 464.20 505.33 688.96 

* Revised fi gure provided by Roc Oil 


77


78 

WESTERN AUSTRALIAN PETROLEUM FACT SHEET 

Category 2: Expected Medium- to Long-Term Development 



90% 50% 90% 50% 90% 50% 

Chamois Apache 1.32 2.33 0.00 0.00 0.00 0.01 

Dockrell Woodside 0.00 6.29 7.55 15.72 8.86 17.22 

Eskdale BHP Billiton 5.03 7.55 1.26 1.89 0.00 0.00 

Gaea Woodside 0.00 0.00 1.89 3.15 1.95 3.26 

Goodwyn–South Pueblo Woodside 0.63 2.52 3.15 9.43 1.99 5.84 

Gungurru Apache 0.63 1.20 0.00 0.00 0.17 0.21 

Keast Woodside 0.00 0.00 4.40 10.06 5.42 9.94 

Lambert Deep Woodside 0.00 0.00 1.26 2.52 5.66 7.36 

Outtrim BHP Billiton 3.15 5.66 0.00 0.00 0.00 0.00 

Oryx Apache 2.14 3.21 0.00 0.00 0.01 0.01 

Penguin Woodside 0.00 0.00 0.63 1.26 1.94 3.99 

Scafell BHP Billiton 0.00 0.00 0.00 0.00 0.80 2.10 

Taunton Apache 2.20 3.33 1.51 1.64 0.01 0.01 

Tidepole Woodside 1.26 10.06 6.29 15.72 6.23 14.72 

Tusk Apache 1.01 1.82 0.00 0.00 0.00 0.01 

Vincent Woodside 52.83 71.70 0.00 0.00 0.51 0.56 

Total 70.19 115.67 27.93 61.39 33.55 65.24 

Category 3: Not currently viable; Held under Retention Lease 



90% 50% 90% 50% 90% 50% 

Blencathra Apache 2.52 4.40 0.00 0.00 0.02 0.03 

Brecknock Woodside 0.00 0.00 52.21 103.15 102.67 147.06 

Brecknock South Woodside 0.00 0.00 59.75 86.80 78.15 111.00 

Chrysaor–Dionysus ChevronTexaco 0.00 0.00 20.06 29.00 57.20 82.90 

Dixon–West Dixon Woodside 18.24 25.79 3.15 7.55 1.93 4.13 

Egret Woodside 5.03 7.55 0.00 0.00 0.78 1.36 

Egret Deep Woodside 0.00 0.00 0.63 1.26 0.85 1.42 

Eurytion ChevronTexaco 0.00 0.00 19.81 30.95 105.16 164.86 

Flinders Shoal Apache 0.00 0.00 0.00 0.00 0.46 0.53 

Gaea Woodside 0.00 0.00 0.63 0.63 0.65 0.85 

Geryon ChevronTexaco 0.00 0.00 67.43 86.80 73.00 94.00 

Iago ChevronTexaco 0.00 0.00 7.60 15.80 17.52 27.67 

Io–Jansz ChevronTexaco 0.00 0.00 16.37 35.83 116.83 180.88 

Jansz Mobil 0.00 0.00 26.04 73.59 140.00 395.00 

Macedon BHP Billiton 0.00 0.00 0.00 0.00 9.60 18.50 

Maitland Apache 0.00 0.00 1.38 1.70 0.39 0.49 

Orthrus–Meanad ChevronTexaco 0.00 0.00 13.90 31.20 15.00 33.95 

Petrel Santos 0.00 0.00 0.00 0.00 9.45 27.47 

Prometheus–Rubicon Kerr-McGee 0.00 0.00 0.63 0.63 5.84 7.26 

Pyrenees BHP Billiton 0.63 3.77 0.00 0.00 0.20 1.10 

Rankin–Sculptor Woodside 0.00 0.00 1.26 13.84 0.85 11.04 

Scarborough Mobil 0.00 0.00 0.00 0.00 125.00 147.00 

Scott Reef Woodside 0.00 0.00 63.02 121.02 170.88 322.16 

Spar ChevronTexaco 0.00 0.00 1.20 6.42 1.40 9.10 

Tern Santos 0.00 0.00 2.23 5.65 10.20 13.25 

Turtle Basin Oil 5.22 7.74 0.00 0.00 0.00 0.00



90% 50% 90% 50% 90% 50% 

Urania ChevronTexaco 0.00 0.00 6.33 7.80 6.14 7.54 

West Tryal Rocks ChevronTexaco 0.00 0.00 24.09 37.68 31.50 48.70 

Wilcox Woodside 0.00 0.00 13.21 19.50 6.18 9.34 

Total 31.64 49.25 400.92 716.77 1087.83 1868.59 

## Reserve fi gures are based on those provided to the Department of Industry and Resources by operating companies at 31/12/04. 

Table 3. Unbooked Resources as at 31 December 2004 ** 

The following are a number of discoveries which may or may not eventually prove viable. 

Field Operator 

Baker Apache Gas 

Cadell Apache Gas 

Chamois Apache Oil 

Crosby BHP Billiton Oil and Gas 

Eaglehawk Woodside Oil 

Gwydion Nexen Oil 

Harrison BHP Billiton Oil 

Ishmael Woodside Gas 

Josephine Apache Gas 

Leatherback Apache Oil 

Mardie Tap Oil Gas 

Montague Woodside Gas 

Monty Apache Gas 

Nasutus Apache Oil and Gas 

Nimrod BHP Billiton Gas 

Outtrim BHP Billiton Oil and Gas 

Ravensworth BHP Billiton Oil and Gas 

South Chervil Apache Oil and Gas 

Stickle BHP Billiton Oil and Gas 

Tarantula Origin Energy Oil 

Whicher Range Amity Gas 

** Unbooked resources are resources which have not at present been delineated, audited or appraised by an independent third party as at the time of writing this 

publication. Anyone wanting more information should contact the relevant operators or the Department’s Petroleum Division. . 

RESERVES IN WESTERN AUSTRALIA 

Petroleum Reserves in Western Australia have been compiled under two main headings, Developed Fields and Undeveloped Fields. 

Developed Fields are those currently producing fi elds located offshore in either Commonwealth or State waters or onshore within Western Australia. 

Undeveloped Fields have been subdivided into three categories as follows: 

Category 1 Potential for Short-Term Development. 

Category 2 Expected Medium- to Long-Term Development. 

Category 3 Not Currently Viable; Subject to Retention Lease. 

In all of the above categories, reserves or resources have been quoted at the 90% and 50% probability of recovery levels. 


79


80 

ABBREVIATIONS, PERMITS AND CONVERSIONS 

ABBREVIATIONS 

API standard method of measuring density of crude oils 

by the American Petroleum Institute 

APPEA Australian Petroleum Production and Exploration 

Association 

bbl barrels 

bbl/d barrels per day 

bbl/MMcf barrels per million cubic feet 

Bcf billion cubic feet 

Bcm billion cubic metres 

Btu British thermal unit 

CALM catenary anchor leg mooring 

CGS concrete gravity substructure 

DBNGP Dampier to Bunbury natural gas pipeline 

DCQ daily contract quantities 

DST drill stem test 

dwt dead weight tonnes 

EOI expression of interest 

FPSO floating production storage and offloading 

FSO floating storage and offloading 

GGT Goldfields gas transmission 

GJ gigajoules 

Gl gigalitres 

Gm gigametres 

GWC gas-water contact 

HBI hot briquetted iron 

kcm thousand cubic metres 

kcm/d thousand cubic metres per day 

km kilometres 

km2 square kilometres 

l litres 

LNG liquefied natural gas 

LPG liquefied petroleum gas 

m metres 

m3 cubic metres 

m3 /bbl cubic metres per barrel 

m3 /d cubic metres per day 

MMcf million cubic feet 

MMcf/d million cubic feet per day 

mm millimetres 

MMbbl million barrels 

MMm2 million cubic metre 

MOPU mobile offshore production unit 

Mt/a million tonnes per annum 

MW megawatts 

n/a not available 

NCC navigation, control and communication 

NWS North West Shelf 

NWSGP North West Shelf Gas project 

OWC oil-to-water contact 

PJ petajoules 

RTM riser turret mooring 

RT rotary table 

scf/bbl standard cubic feet to barrels 

t tonnes 

t/a tonnes per annum 

t/d tonnes per day 

Tcf trillion cubic feet 

TJ terajoules 

TJ/d terajoules per day 

TVDSS total vertical distance subsea 

UAE United Arab Emirates 

WA Western Australia 

2D two-dimensional 

3D three-dimensional 

$ Australian dollars unless otherwise noted 

PERMITS/LICENCES 

State Petroleum Act 1967 

EP1 Exploration Permit 

L1 Production Licence 

State Petroleum Act 1936 and 1967 

L1H Petroleum Licence 

State Petroleum Pipeline Licences Act 1969 

PL/1 Pipeline Licence 

State Petroleum (Submerged Lands) Act 1982 

TP/1 Territorial Sea Exploration Permit 

TL/1 Territorial Sea Production Licence 

TPL/1 Territorial Sea Pipeline Licence 

Commonwealth Petroleum (Submerged Lands) Act 1967 

WA-1-P Exploration Permit 

WA-1-L Production Licence 

WA-1-PL Pipeline Licence 

WA-1-R Retention Licence 

AC/P1 Ashmore–Cartier Production Licence 

NTRL-1 Northern Territory Retention Licence 

CONVERSIONS 

1 barrel of oil = 0.158987 kilolitres of oil 

1 kilolitre of oil = 6.28981 barrels of oil 

1 standard cubic = 35.3147 cubic feet of 

metre of natural gas natural gas 

1 billion cubic metres 

of natural gas 

= 730 000 tonnes of LNG 

1 terajoule = 26 300 cubic metres of 

natural gas 

= 0.929 million cubic feet of 

natural gas 

1 metric tonne of LNG 

0ºC 

= 1333 cubic metres of natural gas at 

1 million tonnes of = 1.333 billion cubic metres per year 

LNG per year 3.65 million cubic metres of natural 

gas per day


Industry and Resources 

Head office: 

Mineral House 

100 Plain Street 

EAST PERTH WA 6004 

Telephone: +61 8 9222 3333 

Facsimile: +61 89222 3430 

Email: enquiries@doir.wa.gov.au 

This publication is now available on our website 

www.doir.wa.gov.au 

DoIRMay05_187

Western Australian Oil and Gas Review 2005 - Department of Mines ...

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