Environmental statement - Flyndre and Cawdor - Maersk Oil

Environmental Statement 

Flyndre and Cawdor 

Development 

June 2011

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Flyndre and Cawdor Environmental Statement 

Standard Information Sheet 

STANDARD INFORMATION SHEET 

Project name Flyndre and Cawdor Development 

Development Location Blocks 30/13c and 30/14 

Licence No. 

Project Reference Number D/4114/2011 

Type of Project Field Development 

Undertaker 

Licensees/Owners 

Short Description 

Key Dates 

Significant Environmental 

Effects Identified 

Statement Prepared by 

The Flyndre and Cawdor development lies within UKCS Licence 

blocks 30/13c and 30/14 and block 1/5a in Norwegian waters. 

Maersk Oil North Sea UK Limited 

Crawpeel Road, Altens, 

Aberdeen, AB12 3LG. 

Block No. Licensee 

Block 30/13c Talisman, Maersk and Eni UK 

Block 30/14 Maersk, Noble Energy and Talisman 

Block 1/5 

Maersk Oil, Skeie Energy, Noreco, 

Statoil Hydro and Petoro 

The Flyndre and Cawdor development is located approximately 

290 km east southeast of Aberdeen and is within English waters. 

Maersk Oil intend to develop the fields by means of a previously 

drilled and suspended appraisal well at the Flyndre field and 1‐3 

wells at the Cawdor field. The fields will be tied back to the 

Talisman operated Clyde platform approximated 26 km east of the 

fields. 

Installation of pipelines, SSIV, 

production and umbilical risers 

Q3, 2012 – Q3, 2013 

Flyndre first oil Q3, 2013 

Drilling of Cawdor Phase I well Q2 ‐ Q3, 2014 

First oil at Cawdor well Q4, 2014 

Drilling of Cawdor Phase I well Q1‐Q3, 2017 

First oil at Phase II Cawdor wells Q3‐Q4, 2017 

None identified 

Maersk Oil North Sea UK Limited and Genesis Oil and Gas 

Consultants Limited. 

D/4114/2011 i

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Standard Information Sheet 

ii D/4114/2011


Non-Technical Summary 

NON TECHNICAL SUMMARY 

The Flyndre field straddles three blocks; 30/13c and 30/14 in the United Kingdom sector of the North 

Sea and 1/5a in the Norwegian sector. The Cawdor field lies across two blocks, 30/13c and 30/14 

both of which are in the UK sector. The fields lie in water depths of approximately 70 m. 

Maersk Oil North Sea Ltd. (Maersk Oil) propose to develop the Flyndre and Cawdor fields, by drilling 

one well at Cawdor and utilising the existing Flyndre appraisal well. The wells will be tied back via a 

common production line to Talisman’s Clyde platform located in UKCS block 30/17b. Based on 

production levels a further two wells may be drilled at the Cawdor field at a later date (Phase II). This 

ES considers the impact associated with the drilling of three wells and production from four wells. 

Production at the Flyndre field is expected to begin in Q3 2013, with production at the Cawdor field 

beginning in Q4 2014. Production at both fields is expected to continue to the end of 2026. 

SCOPE 

The scope of the Environmental Assessment (EA) reported by this Environmental Statement (ES) 

includes all activities associated with the Flyndre and Cawdor development. The environmental 

assessment covers the activities associated with the development as outlined below. 

Flyndre and Cawdor development 

It is proposed to use the Flyndre appraisal/keeper well (30/14‐3z) drilled in 2006 as the Flyndre 

producer, hence no further drilling is anticipated at this field. 

The Cawdor development wells are still to be drilled. Provisionally it is anticipated that one well is 

drilled in Cawdor in Phase 1 and if the production levels are favourable, Phase 2 consisting nominally 

of two wells will be drilled at a later date. 

The subsea concept design work has commenced to assess the options to determine architecture, line 

size, routing etc. Generally it is anticipated that a flowline (25‐30 km length) and control umbilical will 

be required with appropriate manifolding at the subsea locations. 

Screening of all potential hosts resulted in the Clyde platform (operated by Talisman) being selected 

for production of the Flyndre and Cawdor hydrocarbons. 

ENVIRONMENTAL MANAGEMENT AND MITIGATION 

Maersk Oil is committed to conducting activities in compliance with all legislation and operates an 

ISO14001:2004 verified Environmental Management System (EMS) as part of a wider Business 

Management System. Maersk Oil’s commitments to ensuring protection of the environment are set 

out in the HSE policy, a copy of which is provided in Appendix C. The EMS covers all aspects of Maersk 

Oil’s activities including exploration, drilling and production activities and will be applied to the 

proposed development. The activities associated with the proposed development are not anticipated 

to have a significant impact on the environment. However, a number of mitigation measures will be 

adhered to in order to minimise any impact. 

DEVELOPMENT CONCEPT 

Maersk Oil’s proposal for the development of the Flyndre and Cawdor fields will enable the economic 

recovery and export of oil and gas by the drill of one well and utilising an existing well. (Depending on 

D/4114/2011 iii



production an additional two wells may be drilled). A pipeline will be installed to transport the 

hydrocarbons to Talisman’s Clyde Platform. 

ENVIRONMENTAL AND SOCIOECONOMIC DEVELOPMENT 

The fields and platform associated with the proposed development are located in an area that is 

typical of offshore regions in the CNS, where hydrogeographical, meterological, geological and 

biological characteristics are relatively uniform over large areas. 

The seabed sediments along the proposed pipeline route can be described as a fine to medium silty 

sand with occasional scattered shell fragments and possible outcroppings of clay with coarser 

materials such as gravel, cobbles and coarse sand occurring in the southern region. 

No Annex I habitats have been identified in the area of the development. The closest is the Dogger 

Bank (pSAC) sandbank located 120 km south of the proposed development while to the northwest 

the Scanner and Braemar Pockmarks (both cSACs) are located 220 and 280 km respectively from the 

proposed development. It is not considered likely that the proposed development will have any 

impact on these designated areas at this distance. 

The flora and fauna in the area of the development are very similar to those found over wide areas of 

the Central North Sea (CNS). 

There is evidence of lemon sole, sprat, mackerel and Norway pout spawning in the area of the 

development while other species such as cod and whiting have spawning grounds nearby. Juvenile 

haddock, Norway pout and whiting use the area as a nursery ground while juvenile mackerel, cod and 

sandeels are found relatively close distances (≈ 60km) from the development area. 

Although several species of seabird (e.g. fulmars, gannets, razorbills, kittiwakes, herring gulls etc.) are 

found in the area of the proposed development, they occur in relatively low numbers, hence for the 

majority of the year the bird oil vulnerability is considered low. However in the winter months; 

October to January, the OVI is considered moderate to high during which time seabirds tend to 

remain offshore to feed. 

Of those species listed by the Habitats Directive (Annex II), only the harbour porpoise is found in large 

numbers in the area of the development. Other cetaceans (all of which are listed as European 

Protected Species) found in high numbers include the white‐sided dolphin, the white‐beaked dolphin 

and the minke whale. 

Scottish Executive data (Marine Directorate, 2009) shows that the fishing effort within the 

development area is relatively low. 

The level of shipping in the area is considered low in comparison to other areas of the North Sea. 

ENVIRONMENTAL EFFECTS 

The EIA process uses a standard, structured approach for the identification of environmental hazards. 

This involves breaking down potential impacts from the development option into individual phases 

and the key activities within each phase ; 

the drilling phase 

the installation of infrastructure 

the production phase 

iv D/4114/2011



For each key activity the environmental aspects and the potential effects were identified and 

quantified. Potential effects were assessed both in terms of their likelihood (how often they occur) 

and their significance (their magnitude). The full results from the EIA identified five moderate 

environmental risks requiring additional assessment (Table 0‐1). In addition to these a number of 

other environmental aspects have been discussed further in section 5 due to the being under 

regulatory control and also as a result of public interest. 

Environmental Aspect Source of Impact Environmental Risk 

Drilling 

Discharges to sea 

Accidental event 

Installation 

Drill cuttings and Rotomill 

treated OBMs 

Uncontrolled oil spill from well 

blowout 

Moderate 

Moderate 

Noise Pile driving activities Moderate 

Discharges to sea Disturbance of drill cuttings Moderate 

Production 

Discharges to sea Produced water Moderate 

Table 0‐1 Issues identified as requiring further assessment. 

MAIN CONCLUSIONS 

The proposed development will not result in any significant long‐term environmental, cumulative or 

transboundary effects. Mitigation measures for minimising emissions and discharges and preventing 

accidental spills will be strongly adhered to, to ensure no significant adverse impacts. 

D/4114/2011 v

GLOSSARY 



Bathymetry The measurement of ocean depth and the study of floor topography. 

Benthic Relating to organisms that are attached to, or resting on, the bottom 

sediments. 

Bioaccumulate The increasing concentration of compounds within fauna such as limpets, 

oysters and other shellfish. 

Block Sub‐division of sea for the purpose of licensing to a company or group of 

companies for exploration and production rights. A UK block is 

approximately 200 – 250km 2 . 

Demersal Living at or near the bottom of the sea. 

Flowline Pipe through which produced fluids travel 

Greenhouse gas Gas that contributes to the greenhouse effect. Includes gases such as 

carbon dioxide and methane. 

Greenhouse effect The greenhouse effect results in a rise in temperature due to infrared 

radiation trapped by carbon dioxide and water vapour in the Earth’s 

atmosphere. 

Infauna Benthic organisms that live within the sediment. 

Injection well Well into which gas or water is pumped to maintain reservoir pressure. 

ISO 14001 International management system standard. 

Macrofauna Larger bethic organisms. 

Manifold A piping arrangement which allows one stream of liquid or gas to be 

divided into two or more streams, or which allows several streams to be 

collected into one. 

Meiofauna Benthic organisms sized between 50µm and 1mm. 

Microfauna Benthic organisms sized less than 50µm. 

Pelagic Organisms inhabiting the water column of the sea. 

Phytoplankton Free floating microscopic plants. 

Tie‐in The action of connecting one pipeline to another or to another piece of 

equipment. 

Sidetrack Creation of a new section of the wellbore for the purpose of detouring 

around an obstruction in the main wellbore or to access a new part of the 

reservoir from an existing wellbore. 

Special Area of 

Conservation 

Areas considered to be important for certain habitats and non‐bird species 

of interest in a European context. One of the main mechanisms by which 

the EC Habitats and Species Directive 1992 will be implemented. 

Special Protection Area Sites designated by the UK Government to protect certain rare or 

vulnerable species and regularly occurring migratory species of birds. 

Thermocline Pronounced temperature incline. 

Well completion The process by which a finished well is either sealed off or prepared for 

production by fitting a wellhead. 

Zooplankton Free floating microscopic animals. 

vi D/4114/2011



ACRONYMS 

µg Microgram 

µg/l Micrograms per litre 

AHV Anchor Handling Vessel 

bbl Barrel 

bbl/d Barrels per day 

bcf Billion cubic feet 

BMS Business management system 

Bpd Barrels per day 

BOP Blowout preventer 

Bopd Barrels of oil per day 

°C Degrees celsius 

CAJ Controlled Acid Jet 

CoPA Control of Pollution Act 

cSAC Candidate Special Area of Conservation 

DECC Department for Energy and Climate Change 

DTI Department of Trade and Industry 

EAC Ecological Assessment Criteria 

EC European Commission 

EEC European Economic Community 

EEMS Environmental Emissions Monitoring System 

EHSMS Environmental Health and Safety Management System 

EIA Environmental Impact Assessment 

EMS Environmental Management System 

ERT Emergence Response Team 

ES Environmental Statement 

EU European Union 

FPSO Floating Production Storage and Offloading vessel 

HP High Pressure 

HSE Health Safety & Environmental (Management System) 

ICES International Council for the Exploration of the Sea 

IPPC Integrated Pollution Prevention and Control 

ISO International Standards Organisation 

IUCN International Union for the Conservation of Nature 

JNCC Joint Nature Conservation Committee 

kg Kilograms 

D/4114/2011 vii

km Kilometre 

kw Kilowatt 

LAT Lowest Astronomical Tide 

m metres 



MARPOL International Convention for the Prevention of Marine Pollution from 

Ships 

MDAC Methane Derived Authigenic Carbonate 

MESH Mapping European Seabed Habitats 

mg Miligram 

mm Millimetre 

m/s Metres per second 

MMbbls Million barrels 

MMO Marine Mammal Observer 

MMscf Million Standard Cubic Feet 

MMscf/d Million Standard Cubic Feet per Day 

MoD Ministry of Defence 

MSDS Material Safety Data Sheets 

MW Megawatt 

ng/l Nanograms per litre 

Nm Nautical Mile 

NORBIT Framework agreement between UK and Norway concerning cross 

boundary petroleum co‐operation. 

OBM Oil Based Mud 

OD Outside Diameter 

OPPC Oil Pollution Prevention and Control 

OSPAR Convention for the Protection of the Marine Environment in the North 

East Atlantic 

OVI Oil Vulnerability Index 

PAH Polycyclic Aromatic Hydrocarbon 

PCB Polychlorobiphenyls 

PEC Predicted Environmental Concentration 

PLONOR Pose Little Or No Risk to the environment. 

PON Petroleum Operations Notice 

PPC Pollution Prevention and Control 

RQ Risk Quotient 

SAC Special Area of Conservation 

SCANS Small Cetacean Abundance in the North Sea 

SEA Strategic Environmental Assessment 

SPA Special Protection Area 

viii D/4114/2011



TOC Total organic carbon 

TOM Total organic matter 

TTS Temporary Threshold Shift 

UK United Kingdom 

UKCS United Kingdom Continental Shelf 

UKOOA United Kingdom Offshore Operators Association 

D/4114/2011 ix

TABLE OF CONTENTS 



STANDARD INFORMATION SHEET ....................................................................... I 

NON TECHNICAL SUMMARY .............................................................................. III 

SCOPE ..................................................................................................................... III 

ENVIRONMENTAL MANAGMENT AND MITIGATION ............................................................. III 

DEVELOPMENT CONCEPT .............................................................................................. III 

ENVIRONMENTAL AND SOCIOECONOMIC DEVELOPMENT ....................................................... IV 

ENVIRONMENTAL EFFECTS ............................................................................................. IV 

MAIN CONCLUSIONS .................................................................................................... V 

GLOSSSARY ............................................................................................................... VI 

ACRONMYS .............................................................................................................. VII 

1. INTRODUCTION ................................................................................................. 1‐1 

1.1. PURPOSE OF THE PROJECT .......................................................................................... 1‐2 

1.2. PURPOSE OF THE ENVIRONMENTAL STATEMENT ............................................................... 1‐2 

1.3. SCOPE OF THE ENVIRONMENTAL STATEMENT ................................................................... 1‐3 

1.4. LEGISLATIVE OVERVIEW ............................................................................................. 1‐3 

1.5. ENVIRONMENTAL MANAGEMENT ................................................................................. 1‐6 

1.6. AREAS OF UNCERTAINTY ............................................................................................ 1‐6 

1.7. CONSULTATION PROCESS ............................................................................................ 1‐7 

2. PROPOSED DEVELOPMENT .............................................................................. 2‐1 

2.1. INTRODUCTION ........................................................................................................ 2‐1 

2.2. NATURE OF THE RESERVOIR ......................................................................................... 2‐2 

2.3. DEVELOPMENT OPTIONS ............................................................................................ 2‐4 

2.4. SCHEDULE OF ACTIVITIES ............................................................................................ 2‐4 

2.5. DRILLING ................................................................................................................ 2‐5 

2.6. SUBSEA INFRASTRUCTURE ......................................................................................... 2‐10 

2.7. CLYDE ‐ OVERVIEW OF EXISTING FACILITIES ................................................................... 2‐16 

2.8. FLYNDRE AND CAWDOR – OVERVIEW OF PROPOSED FACILITIES ........................................... 2‐19 

2.9. CHEMICAL USE AND DISCHARGE TO SEA ........................................................................ 2‐21 

2.10. PRODUCTION......................................................................................................... 2‐22 

2.11. PERMITTING .......................................................................................................... 2‐26 

2.12. DECOMMISSIONING ................................................................................................ 2‐27 

3. BASELINE ENVIRONMENT ................................................................................. 3‐1 

x D/4114/2011



3.1. METOCEAN CONDITIONS ............................................................................................. 3‐1 

3.2. ENVIRONMENTAL LEGISLATION PROTECTING HABITATS AND SPECIES ..................................... 3‐10 

3.3. THE SEABED .......................................................................................................... 3‐13 

3.4. BIOLOGICAL CONTAMINANTS ..................................................................................... 3‐22 

3.5. MARINE FLORA AND FAUNA ...................................................................................... 3‐22 

3.6. SOCIO‐ECONOMIC ENVIRONMENT .............................................................................. 3‐32 

3.7. OVERVIEW ............................................................................................................ 3‐36 

4. ENVIROMENTAL ASSESSMENT METHODOLOGY ............................................ 4‐1 

4.1. LIKELIHOOD ............................................................................................................. 4‐1 

4.2. CONSEQUENCE ......................................................................................................... 4‐1 

4.3. COMBINING LIKELIHOOD AND CONSEQUENCE TO ESTABLISH RISK ........................................... 4‐2 

5. ASSESSMENT OF POTENTIAL IMPACTS AND CONTROLS ................................ 5‐1 

5.1. DRILLING PHASE ....................................................................................................... 5‐2 

5.2. SUBSEA INSTALLATION ............................................................................................... 5‐6 

5.3. PRODUCTION PHASE ................................................................................................ 5‐16 

5.4. WIDER DEVELOPMENT CONCERNS ................................................................................ 5‐21 

6. HYDROCARBON RELEASES ................................................................................ 6‐1 

6.1. OIL SPILL REGULATIONS AND RISK ON THE UKCS ................................................................ 6‐1 

6.2. POTENTIAL SOURCE OF HYDROCARBON RELEASE AT THE FLYNDRE AND CAWDOR DEVELOPMENT .... 6‐2 

6.3. HYDROCARBON SPILL MODELLING ................................................................................. 6‐4 

6.4. ENVIRONMENTAL SENSITIVITIES .................................................................................. 6‐15 

6.5. SPILL PREVENTION AND CONTINGENCY PLANNING ............................................................ 6‐16 

7. CONCLUSIONS ................................................................................................... 7‐1 

7.1. ENVIRONMENTAL EFFECTS .......................................................................................... 7‐1 

7.1. MINIMISING ENVIRONMENTAL IMPACT .......................................................................... 7‐2 

7.2. OVERALL CONCLUSION .............................................................................................. 7‐4 

8. REFERENCES ....................................................................................................... 8‐1 

APPENDIX A – REGISTER OF ENVIRONMENTAL LEGISLATION........................................................A‐1 

APPENDIX B – ENVIRONMENTAL ASSESSMENT.............................................................................B‐1 

APPENDIX C – ENVIRONMENTAL MANAGMENT SYSTEM..............................................................C‐1 

D/4114/2011 xi


Section 1 Introduction 

1. INTRODUCTION 

The Flyndre field straddles three blocks; 30/13c and 30/14 in the United Kingdom sector of the North 

Sea and 1/5a in the Norwegian sector. The Cawdor field lies across two blocks, 30/13c and 30/14 

both of which are in the UK sector (Figure 1‐1). Both fields are located in the south eastern part of 

the Central Graben basin, 293 km east southeast of Aberdeen in a water depth of approximately 

70 m. 

Figure 1‐1 Flyndre and Cawdor fields location map. 

Maersk Oil North Sea Ltd. (Maersk Oil) propose to develop the Flyndre and Cawdor fields, by drilling 

one well at Cawdor and utilising the existing Flyndre appraisal well. The wells will be tied back via a 

common production line to Talisman’s Clyde platform located in UKCS block 30/17b, ≈ 25 km west of 

the Flyndre field in water depths of ≈ 79 m (Figure 1‐2). Based on production levels a further two 

wells may be drilled at the Cawdor field at a later date (Phase II). This ES considers the impact 

associated with the drilling of three wells and production from four wells. 

Neither the Flyndre or Cawdor fields are currently exploited for the production of oil and gas. The 

Maersk Oil development plan aims for first oil production from the Flyndre field in Q3 of 2013 while 

first oil production from the Cawdor development is expected in Q3 of 2014. The design life for the 

subsea system is such that production could continue to the end of 2026. 

D/4114/2011 1 ‐ 1

Figure 1‐2 Flyndre and Cawdor Development. 

1.1. PURPOSE OF THE PROJECT 



The purpose of the project is to develop the Flyndre and Cawdor fields in order to deliver 

hydrocarbons to the UK. This will in turn reduce the UK’s dependence on oil and gas imports. Taxes 

paid will contribute to the UK’s social programmes and provide high value employment. 

1.2. PURPOSE OF ENVIRONMENTAL STATEMENT 

The purpose of this Environmental Statement (ES) is to report on the Environmental Assessment (EA) 

process that has been carried out. The EA has been carried out to meet statutory and project 

requirements. 

The Offshore Petroleum Production and Pipelines (assessment of Environmental Effects) Regulations 

1999 (as amended 2007 and 2010) require; 

an evaluation of projects likely to have a significant effect on the offshore environment and 

formal public comment on the resulting ES. 

The ES is also required to take into account other European Directives and in particular the EU 

Habitats Directive 92/43/EEC (enacted in the UK by: The Offshore Petroleum Activities (Conservation 

of Habitats) Regulations 2001, SI 2001 No. 1754) and the EU Birds Directive 79/409/EEC. 

As the field operator Maersk Oil’s Environmental Management System requires that an assessment of 

the environmental consequences of all projects is undertaken to ensure the integration of 

environmental consideration into their project planning and design activities. 

1 ‐ 2 D/4114/2011



1.3. SCOPE OF THE ENVIRONMENTAL STATEMENT 

The scope of the EA and resultant ES includes all activities associated with the Flyndre and Cawdor 

development (Section 2.3). 

1.4. LEGISLATIVE OVERVIEW 

This section provides a brief overview of the current legislation. A full summary of applicable 

legislation is included in Appendix A of the ES. 

Current offshore environmental control has significantly developed over the past thirty years and is 

continuing to evolve in response to increasing awareness of the potential environmental impacts. 

Strands of both primary and secondary legislation, voluntary agreement and conditions in consents 

granted under the petroleum licensing regime and international conventions have all contributed to 

the current legislative requirements. 

The main controls for new projects are EIAs, which became a legal requirement of offshore 

developments in 1998. Current requirements are set out in the Offshore Petroleum Production and 

Pipelines (Assessment of Environmental Effects Amendment) Regulations 2007 and accompanying 

Guidance Notes for Industry (DECC, 2009). 

The Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects Amendment) 

Regulations 1999 (as amended 2007 and 2010), hereafter referred to as ES Regulations, require an ES 

to be submitted and prepared for; 

developments (or increase in production) which will produce 500 te or more per day of oil, or 

500,000 m 3 or more per day of gas 

pipelines of 800 mm diameter and 40 km or more in length. 

In addition, ESs may be required for developments which are: 

less than 40 km from the UK coast line 

within or less than 10 km from a Special Protected Area (SPA) or Special Area of Conservation 

(SAC) 

where designated archaeological features are present and may be damaged or disturbed 

areas which are subject to high seasonal environmental sensitivities and/or within herring or 

sandeel spawning grounds or important fisheries 

may significantly impact other users of the sea 

within 10 km of international boundaries where other member states may request to 

participate in the procedure. 

Following the submission of the ES a period of formal public consultation is required under both the 

ES Regulations and European Directive 2003/35/EC (Public Participation Directive). 

The EIA needs to consider the impact on the surrounding environment including any protected areas. 

These protected areas have been developed as a result of European Directives, in particular the EU 

Habitats Directive 92/43/EEC and the EU Birds Directive 79/409/EEC which have been enacted in the 

UK by the following legislation: 

The Conservation (Natural Habitats &c) Regulations 1994 (as amended): These regulations 

transpose the Habitats and Birds Directives into UK law. They apply to land and to territorial 

waters out to 12 nm from the coast and have been subsequently amended several times. 

The Conservation of Habitats and Species Regulations 2010: The Conservation of Habitats 

and Species Regulations 2010 consolidate all the various amendments made to the 

D/4114/2011 1 ‐ 3



Conservation (Natural Habitats, &c.) Regulations 1994 in respect of England and Wales. In 

Scotland the Habitats and Birds Directives are transposed through a combination of the 

Habitats Regulations 2010 (in relation to reserved matters) and the 1994 Regulations. 

The Offshore Marine Conservation (Natural Habitats, &c) Regulations 2007 (as amended 

2009 and 2010): These regulations transpose the Habitats Directive and the Birds Directive 

into UK law in relation to oil, gas and, under the Energy Act 2008 (Consequential 

Modifications) (Offshore Environmental Protection) Order 2010, CCS plans and projects in UK 

offshore waters (i.e. 12 nautical miles from the coast out to 200 nm or to the limit of the UK 

Continental Shelf Designated Area). 

Offshore Petroleum (Conservation of Habitats) Regulations 2001 (as amended 2007): These 

regulations originally implemented the habitats directive requirements for oil and gas 

activities and introduce a permitting scheme for geological surveys related to oil and gas 

activities. 

Until 1999 these Directives applied only to UK territorial waters (as defined in CoPA 1997) when their 

scope was extended to include the offshore with the Offshore Regulations being subsequently 

prepared to comply with the changes. As a result new offshore projects or developments must 

demonstrate that they are not “likely to have a significant impact on the integrity of the conservation 

objectives for the protected site” or “significantly disturb European protected species” either alone or 

in combination with other plans and projects. 

The disturbance of European Protected Species (EPS) has been further defined by the 2010 

amendments. An offence would occur for activities that; 

deliberately capture, injure, or kill any wild animal of a European protected species (termed 

the injury offence) 

deliberately disturbs wild animals of any such species (termed the disturbance offence). 

Disturbance of an animal includes in particular any disturbance which is likely to; 

impair the animals ability to survive, breed, reproduce, to rear and nurture their young and 

where applicable an animals ability to hibernate or migrate 

significantly affect the local distribution or abundance of the species to which they belong. 

In June 2000, OSPAR made a decision requiring a mandatory system for the control of chemicals 

(OSPAR Decision 2000/2 on a Harmonised Mandatory Control System for the Use and Reduction of 

the Discharge of Offshore Chemicals). This decision operates in conjunction with two OSPAR 

Recommendations; 

OSPAR Recommendation 2000/4; The application of a Harmonised Pre‐Screening Scheme for 

Offshore Chemicals to allow authorities to identify chemicals being used offshore. 

OSPAR Recommendations 2000/5; The application of a Harmonised Offshore Chemical 

Notification Format for providing data and information about chemicals to be used and 

discharged offshore. 

Under the broader umbrella of the Integrated Pollution Prevention and Control (IPPC) Act, the UK 

Government’s offshore oil and gas regulator, Department for Energy and Climate Change (DECC), 

implemented OSPAR Decision 2000/2 on the control of chemical use offshore, through the Offshore 

Chemicals Regulations (2002). 

The offshore industry is also operating the European Union’s Emissions Trading Scheme (EU ETS) 

enacted in the UK via the Greenhouse Gas Emissions Trading Scheme Regulations 2005 (Statutory 

Instrument 2005 No. 925) and the Greenhouse Gas Emissions Trading Scheme (Amendment) 

Regulations 2007 (Statutory Instrument 2007 No. 465). This scheme is one of a raft of measures 

introduced to reduce emissions of greenhouse gases and sets challenging targets for UK industry. 

1 ‐ 4 D/4114/2011



The Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 (& 

Amendments 2011) have been designed to encourage operators to continue to reduce the quantities 

of hydrocarbons discharged during the course of offshore operations. The 2011 OPPC Regulations 

update the definition of oil, introduce a permitting system for oil discharges and strengthen the 

powers to inspect and investigate oil discharges. The issue of permits under these Regulations is the 

mechanism used to implement OSPAR Recommendation 2001/1. In line with OSPAR 

Recommendation (2001/1), the UK (DECC) has introduced regulatory requirements to reduce the 

permitted average monthly oil discharge concentration to 30 mg/l. 

OSPAR Recommendation 2001/1 also requires a 15% reduction in the discharge of oil in produced 

water from 2006 measured against a 2000 baseline; controlled by the issue of permits to each 

installation. The permits replaced the granting of exemptions under the Prevention of Oil Pollution 

Act 1971 and are issued under the Offshore Petroleum Activities (Oil Pollution Prevention and 

Control) Regulations 2005. This target has been met and maintained by the industry as a whole. 

The Offshore Petroleum Activities (Oil Pollution Prevention and Control) (Amendment) Regulations 

2011 have introduced a number of changes to the Regulations. This includes a new definition of 

"offshore installation" which encompasses all pipelines ‐ some of which were not previously covered 

by the OPPC Regulations. The amending OPPC Regulations also include the concept of "release" to 

cover all unintentional emissions of oil that occur through accidental spills / leaks or non‐operational 

discharges. Intentional emissions are now clarified as discharges. However, given that the OPPC 

Regulations already covered oil spills and leaks, the concept of "release" is being incorporated by the 

amending Regulations solely for the purpose of conformity with the Offshore Chemicals 

(Amendment) Regulations 2011. 

The draft OSPAR Recommendation for produced water discharges (yet to come into force) requires 

operators to follow a risk based approach to the management of PW discharge from offshore 

installations. The implications of the Recommendation for discharges of PW into the UKCS are not 

yet defined, however, in alignment with the Recommendation it is likely that requirements will 

comprise undertaking risk characterisation; either on substances based approach or a whole effluent 

approach, or a combination of the two. 

The Marine and Coastal Access Act (MCAA) came into force in November 2009. The Act covers all UK 

waters except Scottish internal and territorial waters which are covered by the Marine (Scotland) Act 

(2010), which mirrors the MCAA powers. Licensing provisions in relation to MCAA came into force on 

1 st April 2011. The MCAA will replace and merge the requirements of FEPA Part II (environment) and 

the Coastal Protection Act (navigation). The following activities are exempt from the MCAA as they 

are regulated under different legislation; 

activities associated with exploration or production / storage operations that are authorised 

under the Petroleum Act 

additional activities authorised solely under the DECC environmental regime, for example, 

chemical and oil discharges. 

Therefore, activities which are not regulated by the Petroleum Act or under the DECC environmental 

regime, and decommissioning operations require an MCAA licence since April 2011. 

Oil Pollution Emergency Plans (OPEPs) are required under the Merchant Shipping (Oil Pollution in 

Preparedness, Response and Co‐operation Convention) Regulations 1998. The regulations require the 

arrangements for responding to incidents which cause or may cause marine pollution by oil to be in 

place and the consequence of incidents to be assessed including the potential environmental and 

socio‐economic impacts. 

D/4114/2011 1 ‐ 5

1.5. ENVIRONMENTAL MANAGEMENT 



Maersk Oil UK operates an ISO14001:2004 verified Environmental Management System (EMS) as part 

of the wider Business Management System (BMS). The Environmental component of the BMS has 

been independently verified as satisfying the principles of ISO14001 in both 2006 and 2008 and 

gained certification to ISO14001 in January 2011. The EMS covers all aspects of Maersk Oil’s activities 

including exploration, drill and production activities. 

The BMS comprises five key elements: 

Policy 

Organisation 

Planning and Implementation 

Performance Management 

Audit and Management Review. 

Together these five elements form Maersk Oil’s “Plan‐Do‐Check‐Act” approach to EHS management 

which actively promotes continuous improvement in all aspects of the organisation’s activities. The 

responsibility for implementation of the HSSE Policy rests with the MOUK UK Management Team 

(UKMT) in accordance with the Health, Safety, Security, Environmental and Quality (HSSEQ) 

Programme. 

The management system is subject to internal reviews and audits. Audits are planned and progress is 

reported monthly to senior management. In addition, Maersk Oil periodically evaluates compliance 

with environmental legislation, including applicable permits, licenses and other requirements. All 

non‐conformances with legislative requirements are reported and investigated. 

All the activities associated with the drilling, testing, subsea installation and production of the Flyndre 

and Cawdor wells will be covered by the EMS. 

Maersk Oil’s contractor management processes require that all contractors conform with either 

Maersk Oil’s BMS or their own management system, if Maersk Oil deem it acceptable. As part of the 

contractor selection process the contractors capabilities with respect to environmental management 

are evaluated with, if necessary, audits being performed to verify environmental capability. The 

contractor’s capabilities are assessed to varying levels dependent on the EHS –criticality of the service 

in question. 

A Flyndre and Cawdor environmental commitments registrar will be provided to Talisman and all 

other contracting parties, these will be formulated in project specific Environmental Management 

Plans. The compliance with environmental commitments will be audited and verified within the 

Environmental Management System used by Maersk and Talisman. 

Further details of the Maersk’s Oil Health Safety, Security and Environmental Policy are included in 

Appendix C. 

1.6. AREAS OF UNCERTAINTY 

1.6.1. NUMBER OF WELLS DRILLED AT THE CAWDOR LOCATION 

The final development plan for the Flyndre and Cawdor fields has yet to be determined such that it 

has yet to be confirmed if Phase II of the development i.e. the two additional Cawdor wells will go 

ahead. This will not be determined until after production from the first Cawdor well commences. For 

the purpose of this ES, it is assumed that two Phase II wells will go ahead. 

1 ‐ 6 D/4114/2011



1.6.2. INSTALLATION METHOD FOR THE UMBILICAL 

The final decision on the installation method for the umbilicals has also yet to be determined i.e. will 

they be trenched and mechanically back filled after or will they be simultaneously layed and trenched. 

1.6.3. DISTURBANCE OF CUTTING PILE AT THE CLYDE PLATFORM 

Maersk Oil is aware of the presence of cuttings piles at the Clyde platform which contain high levels of 

Total Hydrocarbons Concentrations (THC). The installation of the infrastructure within the 500 m 

zone has the potential to cause disturbance to these. The majority of the cuttings pile is located 

below the cutting chute, and disturbance to the pile could be minimised depending upon which area 

of the platform the riser and umbilical will be situated. The final engineering to determine the hook 

up locations for the riser and umbilical has yet to be completed, therefore there is uncertainty as to 

the potential degree of disturbance, if at all, to the cuttings pile. Once the preferred location for the 

riser and umbilical has been determined a full assessment of the disturbance of cuttings piles will be 

carried out in the PON15Cs for the Flyndre and Cawdor ES. 

1.6.4. QUANTITY OF GAS FLARED AT THE CLYDE PLATFORM 

Operating philosophies and procedures are currently under development and until this work is fully 

complete there will be uncertainty over the quantity of gas that needs to be flared at the Clyde 

platform. 

1.7. CONSULTATION PROCESS 

During the process to assess the environmental impact of the development meetings were held with 

the Department of Energy and Climate Change (DECC), other statutory conslultees were notified 

about the project, although no concerns were raised at the initial scoping stage (Table 1‐1). The 

process of consultation will continue throughout the project. 

Consultees Issues/Concerns 

DECC: 

16 th September 2010 

10 th February 2011 

Marine Scotland (consulted as 

development close to Scottish 

waters) 

CEFAS (Max La vedrine) 

DECC confirmed requirement for ES and requested that high 

case (P10) production volumes be included. 

None raised. 

JNCC None raised. 

Table 1‐1 Consultation Process. 

None raised via telephone conversation, although no formal 

scoping request supplied to CEFAS. 

D/4114/2011 1 ‐ 7


Section 2 Proposed Development 

2. PROPOSED DEVELOPMENT 

2.1. INTRODUCTION 

The Flyndre and Cawdor oil and gas fields are located over 293 km east southeast of Aberdeen, the 

Flyndre field lies 2 km to the north of the Cawdor field (Figure 2‐1). The reservoirs will be produced 

through a previously drilled development well at the Flyndre location and a new well to be drilled at 

the Cawdor location, the hydrocarbons will be transported to the Talisman operated Clyde platform 

through a new 12” pipeline. Production is expected to commence from the Flyndre field in 2013, with 

production commencing from the Cawdor field in 2014, the effective field life is 13 and 12 years 

respectively to the end of 2026. It is expected that 6.4 million tonnes of oil and 2.8 million Mm 3 of gas 

can be realised as a result of the Flyndre and Cawdor development. 

Figure 2‐1 Schematic showing location of proposed development and oil and gas export routes. 

The Clyde platform is located approximately 276 km east southeast of Aberdeen (Block 30/17b). It is 

a fixed platform on which there are facilities for drilling, production, accommodation and the 

associated utilities. The topsides operational weight of 20,000 tonnes is supported on a conventional 

eight‐leg steel jacket and a module support frame. The Clyde platform’s process facilities separate 

production from the Clyde, Leven, Medwin and Nethan reservoirs (the Clyde Fields) and the Orion 

subsea tie‐back into oil, and dried natural gas. Oil and gas are exported via the Shell Fulmar ‘A’ 

Platform to Teeside and St Fergus terminals respectively (Figure 2‐1). 

Multiple partners are associated with the development as illustrated in (Figure 2‐2). 

D/4114/2011 2‐1

Figure 2‐2 Ownership of the Flyndre and Cawdor fields. 



2.2. NATURE OF THE RESERVOIRS 

The reservoir to be developed in the Flyndre Field is in the Paleocene Balmoral Sand. Two minor 

hydrocarbon accumulations are found in the chalk of the Tor and Ekofisk Formations. These 

accumulations are sub commercial and are not considered for development at the moment. A 

structure map showing Top Balmoral Sand and the drilled exploration and appraisal wells along with 

the existing producer is shown in Figure 2‐3. 

Figure 2‐3 Structure map and cross section (illustrated by blue line) of Flyndre Balmoral Sand. 

2‐ 2 D/4114/2011



The reservoir to be produced in the Cawdor Field is in the Upper Cretaceous chalk of the Tor 

Formation. Two smaller hydrocarbon accumulations are found in the chalk of the Ekofisk Formation 

and in the Paleocene Balmoral Sand. These accumulations are also currently sub commercial and are 

not considered for development at the moment. A structure map showing the top Tor Formation and 

the drilled exploration wells as well as the proposed producer wells is shown in Figure 2‐4. The 

proposed producer well PRD‐4 is to be drilled first. 

Figure 2‐4 Structure map and cross section (illustrated by blue line) of Cawdor Tor Formation. 

The reservoir properties and the main summary of PVT (pressure, volume and temperature) data are 

summarised in Table 2‐1. 

Properties Flyndre Cawdor 

Reservoir type Palaeocene Balmoral Sandstone Upper Cretaceous Chalk 

Reservoir Pressure 6808 psig 7203 psig 

Reservoir Temperature 254 o F (123 o C) 276 o F (131 o C) 

Saturation Pressure 3465 psig 5939 psig 

Stock Tank Oil Density 0.8217 g/cm 3 0.8185 g/cm 3 

Solution GOR at Saturation 

Pressure 

1218 scf/bbl 2510 scf/bbl 

GOR at Separator Condition 999 scf/stb 2510 scf/stb 

Viscosity at reservoir Pressure 0.311 cP 0.277 cP 

Viscosity at Saturation Pressure 0.239 cP 0.232 cP 

Table 2‐1 Reservoir fluid and main PVT data. 

2.3. DEVELOPMENT OPTIONS 

The development option selected for the Flyndre and Cawdor fields was arrived at following a 

documented, technical and commercial host and concept selection process. This selection process 

took account of environmental, health and safety, technical, project execution and commercial issues 

and risks and included a comprehensive value assurance review. 

D/4114/2011 2‐3



Four platforms (Judy, Fulmar, Clyde, Ekofisk) and one FPU (Janice) were initially considered for 

production of the hydrocarbons from the Flyndre and Cawdor fields. Consideration was also given to 

tie‐backs to the manifolds at Orion and Affleck and at the Tommeliten development. Initial selection 

was narrowed down to the Maersk operated Janice FPU and the Talisman operated Clyde platform, 

these were also the only facilities that responded to Maersk Oil’s request for a suitable host facility. 

The Clyde platform is situated the closest distance to the Flyndre and Cawdor field and requires little 

infrastructure modification and has sufficient spare capacity to accommodate the produced fluids and 

gas. 

The proposed development of the Flyndre and Cawdor fields over Clyde will maximise production 

through existing facilities with minimal requirement for new infrastructure. It is therefore considered 

to offer the best development option in terms of both environmental and economic benefit. 

In summary the development programme will comprise 

Phase I 

the drilling of a well at the Cawdor field 

the Flyndre appraisal/keeper well (30/14‐3z) drilled in 2007 will act as the Flyndre producer, 

hence no further drilling is anticipated at the Flyndre field) 

subsea infrastructure including main pipeline from Flyndre well to Clyde platform; two 

manifolds, one at each field; SSIV; tie‐ins etc. 

production of Flyndre and Cawdor well. 

Phase II (production level dependent) 

drilling of two additional wells at Cawdor and tie‐backs to the Cawdor manifold 

production of the two additional wells. 

From the Clyde platform the oil and gas will be exported to the Teeside and St Fergus terminals 

respectively. 

2.4. SCHEDULE OF ACTIVITIES 

The proposed schedule of activities is shown in Table 2‐2. 

Subsea Installation 

Activities Date 

Installation of SSIV, production 

& umbilical risers 

Q3, 2012 – Q3, 2013 

Main pipelines etc. Q2‐Q3, 2013 

Flyndre well First Oil Q3, 2013 

Cawdor Wells Phase I 

Cawdor Well Phase II 

Drilling Q2‐Q3, 2014 

First Oil Q4, 2014 

Drilling Q1‐Q3, 2017 

First Oil Q3‐Q4, 2017 

Table 2‐2 Schedule of activities for Flyndre and Cawdor development. 

2.5. DRILLING 

The Flyndre appraisal well, 30/14‐3z, drilled in 2007 was completed, flow tested and is currently 

suspended. 

2‐ 4 D/4114/2011



A maximum of three wells are planned in the development of the Cawdor field. First oil from the first 

well (Phase I) is expected in Q4 2014, while the second and third Cawdor wells (Phase II) are expected 

to start producing in Q3 ‐ Q4 2017. 

The coordinates for the Flyndre well and the proposed Cawdor wells are given in Table 2‐3. 

Flyndre well 

Latitude 56 o 33’35.236” 

Longitude 2 o 37’57.773” 

Cawdor Phase I well 

Latitude 56 o 32’22.633” 

Longitude 2 o 34’28.244” 

Cawdor Phase II wells 

Latitude Not determined yet, however will be in within 100m radius 

of the Cawdor Phase I well. 

Longitude 

Table 2‐3 Well locations for Flyndre and Cawdor development. 

2.5.1. DRILLING SCHEDULE 

Drilling of the Phase I Cawdor well is expected to commence in Q2 ‐ Q3 2014 and to last for 

approximately 74 days. Drilling of the Cawdor Phase II wells is expected to commence in Q1 ‐ Q3 

2017 and is expected to be of a similar drilling period for each well. 

2.5.2. DRILL RIG 

At the time of writing this ES the drilling contract for the Cawdor wells had not yet been awarded, 

however, it is planned to use a semi‐submersible rig and it is expected that the wells will be drilled 

and completed using the Noble Ton van Langveld (NTvL) rig. Therefore for the purpose of assessing 

the environmental impacts from drilling activities, generic details of a semi‐submersible have been 

applied and the environmental impacts assessed accordingly in Section 5. 

2.5.3. DRILL RIG ANCHOR PATTERN 

The rig will be towed to location with the assistance of three Anchor Handling Vessels (AHVs), two in 

front and one to the rear. It will maintain station during drilling activities via the use of anchors. 

Semi‐submersible drilling rigs tend to have anchor facilities using an eight or twelve point chain wire 

mooring system. For the purpose of this ES the worst case scenario of 12 will be assumed. 

While in position a statutory 500 m exclusion zone will be established around the rig, in accordance 

with safety legislation. Unauthorised vessels including fishing vessels will not be permitted access to 

the area. The drilling rig will be equipped with navigation lights, radar and radio communications. 

D/4114/2011 2‐5

2.5.4. DRILL RIG SUPPORT ACTIVITY 



Various support vessels will be associated with the drilling of the Cawdor wells including three AHVs, a 

supply vessel and a standby vessel. Table 2‐4 summarises the drilling rig and support vessel activity 

and fuel usage during the drilling of the Phase I and II Cawdor wells. 

Vessel type 

Duration 

(days) 

Phase I Cawdor Well 

Working fuel 

consumption (Te/d) 1 

Total fuel use 

(Te) 

3 x Anchor Handling Vessel (transit) 24 2 50 1200 

3 x Anchor Handling vessel (working) 6 3 5 30 

1 x Semi‐submersible drilling rig 74 10 740 

1 x Supply vessel (transit) 88 4 10 880 

1 x Supply vessel (working) 22 5 110 

1 x Standby vessel (in transit) 4 0.8 3.2 

1 x Standby vessel (on station) 74 0.7 51.8 

Phase II Cawdor wells (2 wells) 

3 x Anchor Handling Vessel (transit) 51 5 50 2550 

3 x Anchor Handling vessel (working) 12 5 40 

1 x Semi‐submersible drilling rig 148 10 1480 

1 x Supply vessel (transit) 176 6 10 1760 

1 x Supply vessel (working) 44 5 220 

1 x Standby vessel (in transit) 4 0.8 3.2 

1 x Standby vessel (on station) 148 0.7 103.6 

Total 9172 

1 Source; The Institute of Petroleum, 2000. 

2 Estimate it takes 4 days to transport rig to and from well location, therefore 2 X 4 day trips per anchor vessel. 

3 Assumes a days’ work per vessel on arrival at location and when removing the rig. 

4 Assumes supply vessel makes two trips a week and takes 2 days to travel to and from well location (22 trips total). 

5 Assumes 4 days to transport rig to first well location and returning 74 days later to transport to second well location & one 

day to move between the two well locations. 

6 Assumes supply vessel makes two trips a week and takes 2 days to travel to and from well locations (44 trips total). 

Table 2‐4 Fuel consumption of vessels associated with drilling of the Cawdor wells. 

2.5.5. BLOW OUT PREVENTER 

The drilling rig used for the development will be fitted with a Blow Out Preventer (BOP) stack. The 

NTvL is fitted with a 10,000 psi high pressure Cameron Iron Works well control system and a BOP 

stack. The function of the BOP is to prevent uncontrolled flow from the well by positively closing the 

well at the seabed, as and when required. The BOP is made up of a series of hydraulically operated 

rams that can be closed in an emergency from the drill floor and also from a safe location elsewhere 

on the rig. 

2.5.6. WELL DESIGN 

Initially one well will be drilled in the Cawdor field, with two further wells anticipated in Phase II. 

Detailed well design and completion strategy has yet to be finalised however is expected to follow the 

design outlined below for all three wells (Table 2‐5) but may be reverted to an open hole acid frac 

system. 

2‐ 6 D/4114/2011



Section diameter 

(inches) 

36” 

Casing 

(inches) 

30 x 20” 

conductor 

17 1 /2” 13 3 /8 

Drilling fluid Depth (MDBRT) 

Sea water and high 

viscosity sweeps 

Sea water and high 

viscosity sweeps 

12 1 /4” 9 5 /8 OBM 

D/4114/2011 2‐7 

≈520 

≈4000 

Total depth is 

trajectory specific 

8 1 /2” n/a OBM 19000 

Table 2‐5 Cawdor well completion details. 

The 36” top hole section will be drilled using seawater and high viscosity sweeps to an approximate 

depth of 520 ft Mean Depth Bellow Rotary Table (MDBRT) with the 30” x 20” conductor being set and 

cemented. The vertical 17 1 /2” section will be drilled to a total depth of approximately 4,000 ft MDBRT 

with seawater and high viscosity sweeps. The 13 3 /8” casing will then be run and cemented in place. 

A 12 1 /4” hole section will be drilled using approximately 14ppg Versclean Oil Based Mud (OBM) with 

gamma ray, resistivity and possibly density and neutron measurements being logged (LWD tools). 

The trajectory will kick off at approximately 8000 ft Measure Depth (MD) gradually increasing the 

angle before entering the Tor chalk reservoir at +/‐ 89 o C incline at circa 11700 ft. The total depth of 

the 12 1 /4” will be trajectory specific. A 9 5 /8” casing will be run to total depth and cemented in place. 

It is planned to drill an 8 1 /2” hole to an anticipated total depth of 19000 ft MDBT, with a +/‐ 14.5 ppg 

whilst using OBM, during this process logging information will be carried out this will consist of 

gamma rays (with images) resistivity, neutron and density. 

A CAJ (predrilled)/ solid 7” liner will be run to total depth and set near the 9 5 /8” shoe. This will enable 

hydraulic fracking of the inner zones, before acid washing (with hydrochloric acid) the outer CAJ zone. 

A 5 1 /2” top completion will be run and the well cleaned up, before de‐mobilising the rig. A schematic 

of the proposed Cawdor production well design is illustrated in Figure 2‐5.

Figure 2‐5 Schematic of well design for Cawdor well. 

2.5.7. DRILLING MUD, CUTTINGS AND CHEMICAL DISCHARGES 

During drilling, fluids are required for a number of reasons including; 

transportation of the cuttings to the surface 

cooling and lubrication of the drill bit 

managing hydrostatic pressure. 



Table 2‐6 summarises the Phase I Cawdor well drill cuttings and mud masses. It is assumed that 

drilling of the Phase II Cawdor wells will produce similar mud and cuttings volumes. 

Section 

diameter 

36’’ 

17 1 /2” 

Drilling fluid 

Seawater and high 

viscous sweeps 

Seawater and high 

viscous sweeps 

Mud volume 

(m 3 ) 

Cuttings 

volume (m 3 ) 

Cuttings 

mass (Te) 

225 37 94 

1160 165 422 

Fate of 

cuttings 

Discharge to 

seabed 

Discharge to 

seabed 

12 1 /4” OBM 740 178 458 Rotomill 

8 1 /2” OBM 345 81 209 Rotomill 

Table 2‐6 Cawdor mud and cuttings mass. 

2‐ 8 D/4114/2011



While drilling the Cawdor well(s) the 36” and 17 1 /2” tophole sections will be drilled riserless using 

seawater with viscous sweeps. Cuttings from these sections will be discharged to the seabed. 

The 12 1 /4” and 8 1 /2” hole sections will be drilled with OBM, and the cuttings recovered from these 

sections will be processed using a Rotomill system. Use of the Rotomill for treatment and disposal 

of oil based mud and cuttings removes the requirement for shipping large numbers of skips of OBM 

back to shore for processing and disposal of the solids to landfill. Base oil will be recovered from the 

Rotomill and stored for reuse, while the recovered cuttings powder is mixed with recovered water 

and seawater and pumped to sea via an existing overboard chute. It is necessary to mix the cuttings 

powder with the recovered water to form a slurry which helps avoid formation of surface flocs of 

powder due to trapped air. Recovered powder and water will be monitored to ensure they meet all 

discharge limits i.e. oil content of >1% dry weight. 

As a contingency a ship and skip system will be in place. 

The mud formulation and drilling chemicals will be finalised during final well design and Petroleum 

Operations Notice 15Bs will be submitted to DECC prior to drilling. This statutory document will 

identify, quantify and assess the risks associated with all the chemicals that will be used. 

2.5.8. CEMENTING CHEMICALS 

Steel casings will be installed in the wells to provide structural strength to support the subsea valve 

trees as well as isolate unstable formations, different formation fluids and separate different wellbore 

pressure regimes. Each steel casing will be cemented into place to provide a structural bond and an 

effective seal between the casing and formation. 

During cementing excess cement may be produced. Uncontaminated cement will be treated and 

discharged to sea. It is anticipated that all cement will be mixed as required and as a result there 

should be limited operational discharge of any mixed cement or mixwater. 

All chemicals to be used will be selected based on their technical specifications and environmental 

performance. Chemicals with sub warnings will be avoided where technically possible. The 

cementing chemicals to be used have not yet been determined but will be detailed and included in 

subsequent PON 15B applications. 

2.5.9. OTHER RIG DISCHARGES 

Water generated from rig washdown may contain trace amounts of mud, lubricants and residual 

chemicals resulting from small leaks or spills and rainfall from open deck areas. The volume of these 

discharges depends on the frequency of washdown and amount of rainfall. Liquid storage areas and 

areas that might be contaminated with oil are segregated from other deck areas to ensure that any 

contaminated drainage water can be treated prior to discharge and accidental spills contained. 

Drainage water from these areas and machinery spaces is collected, treated to remove hydrocarbons 

(less than 15 ppm hydrocarbons in water, as required under the MARPOL Convention) and the 

cleaned water is discharged to sea. 

Black (sewage) and grey water is also collected, treated to meet the requirements of the MARPOL 

Convention and discharged to sea. 

These are all relatively low volume discharges containing small residual quantities of contaminants. 

Maersk Oil will ensure that the rig is equipped with suitable containment, treatment and monitoring 

systems as part of the contract specification. Maersk Oil will also ensure good housekeeping 

D/4114/2011 2‐9



standards are maintained to minimise the amount of hydrocarbons and other contaminants entering 

the drainage systems. 

2.5.10. WELL CLEAN‐UP AND WELL TEST OPERATIONS 

Prior to production, each well will be cleaned to remove any waste and debris remaining in the well in 

order to prevent damage to the pipeline or topsides production facilities. A well test will also be 

conducted to obtain reservoir information and fluid samples. 

The clean‐up operation will follow UKOOA Best Practice guidelines by isolating the clean‐up train & 

associated interface liquids for treatment by Rotomill and onshore treatment & disposal, and 

filtering the following displacement brine prior to any disposal. 

More detail about the well clean‐ups will be contained within the subsequent Cawdor PON15B’s and 

OPPC applications. 

Table 2‐7 presents an estimate of the tonnages of gas and oil that will be flared during the proposed 

well testing and clean‐up operations of each of the Cawdor wells. The Cawdor development (Phase I 

and II) is anticipated to have a maximum clean up duration of 84 hours, with 1,805 tonnes of gas and 

3,384 tonnes of liquid being flared. 

Phase I Cawdor 

Well 

Well Clean Up Duration 

(Max hrs) 

36 (18 hrs for each 

flow) 

Total gas flared 

(Te) 

Total liquids flared 

(Te) 

701 1,450 

First Phase II Cawdor well 24 552 967 

Second Phase II Cawdor well 24 552 967 

Total 84 1,805 3,384 

Table 2‐7 Well Clean‐up and Test tonnages. 

2.6. SUBSEA INFRASTRUCTURE 

This section details the installation of facilities required to produce and transport the reservoir fluids 

from the seabed to Talisman’s Clyde platform (Figure 2‐6). These include 

Xmas tree at each of the Cawdor wells 

manifold at each of the fields (two in total) 

the main pipeline from the Flyndre well to the Clyde platform and connecting pipelines 

from the Cawdor manifold to this pipeline 

SSIV structure adjacent to the Clyde platform. 

2‐ 10 D/4114/2011



Figure 2‐6 Flyndre and Cawdor Development. 

2.6.1. XMAS TREES 

The Xmas trees to be used in this development will be of the horizontal type, and will contain the 

standard instrumentation and sensors. The Xmas trees will house the subsea control modules, 

chokes, pressure and temperature gauges and a number of chemical injection points. The xmas tree 

has already been installed in the Flyndre well. 

The trees used will be fishing friendly and incorporate protection structures to provide the snag load 

resistance required. Each of the trees and associated protection structures will have a length of 

7.11 m and a width of 7.22 m, with a total subsea footprint of 154 m 2 (1) . 

2.6.2. MANIFOLDS AND SSIV 

Subsea manifolds will be put in place at the both Flyndre and Cawdor fields to provide support and 

protection for all the subsea equipment including controls equipment, manifold piping, flowmeters 

and valves required to produce the subsea wells. The primary steelwork comprises a structural 

tubular frame, arranged as a rectangular‐shaped protection structure with vertical sides. The total 

footprint of each of the manifolds is given in Table 2‐8. 

1 This takes into account the three Xmas trees associated with the three Cawdor wells. 

D/4114/2011 2‐11



Structure Dimensions (m x m) Total footprint (m 2 ) 

Flyndre manifold 5.5 x 5.2 28.6 

Cawdor manifold 12.4 x 10.8 133.92 

SSIV 5 x 5 25 

Table 2‐8 Subsea footprint of manifolds and SSIV associated with the development. 

The manifolds will be piled to resist accidental loadings arising from interaction with fishing 

equipment. Four piles will be used to hold each manifold in place, the piles have the following 

dimensions and penetration depths: 

penetration length = 15 m 

outside diameter = 600 mm 

The seabed conditions are expected to be similar to those found at the Affleck development. Maersk 

Oil has collected information on the pile driving information required to install piles at the Affleck 

development. In this case a submersible hammer (IHC Hydrohammer S‐90) and piles that had a 

diameter of 610 mm were installed to a depth of 16.5 m, details of this are presented in Table 2‐9. 

At the time of writing this ES it was expected that the drivability results presented here would 

represent the most onerous driving scenario at the Flyndre and Cawdor fields as the scenario 

presented is for a greater piling penetration length and a marginally wider outside pile diameter. 

Hammer 

Total Blows 

IHC Hydrohammer S‐90 

963 

Driving Time (min) 32 24 19 16 13 12 10 9 8 8 

Blow Rate (b/min) 30 40 50 60 70 80 90 100 110 120 

Table 2‐9 Drivability results summary. 

The SSIV will be a gravity based structure and will not require piling. 

2.6.3. PIPELINE DESIGN 

Hydrocarbons from the Flyndre and Cawdor fields will be tied back to the Clyde production facilities 

via a common Subsea 8”/12” pipe‐in‐pipe export pipeline. The Flyndre to Cawdor line is 4.2 km while 

the Cawdor to Clyde is 20.46 km. 

A pipe in pipe system was selected for the project as it provides the most robust system with regard 

to operability and integrity. The carrier pipe material will be carbon steel and a dry insulation will be 

used within the annulus. 

2.6.4. PIGGING REQUIREMENT 

Routine operational pigging is not envisaged, however to address unforeseen events, the pipeline will 

be designed to be pigged and the subsea facilities will be configured with a temporary pigging 

connection at the Flyndre end of the pipeline. The Clyde platform will provide space to enable 

temporary pig launching/receiving equipment to be installed. 

2‐ 12 D/4114/2011



2.6.5. METERING 

Subsea Multiphase Meters (MPM) will be installed subsea at both the Flyndre and Cawdor manifolds 

and additional meters will be fitted to the Cawdor trees. 

2.6.6. SUBSEA UMBILICALS 

A static subsea umbilical will be installed between the Clyde platform and the Cawdor manifold 

(20.46 km) and a second umbilical of similar construction will be installed between the Cawdor 

manifold and the Flyndre manifold (4.2 km). A breakout point will be located at the SSIV structure to 

provide controls for the SSIV. The umbilical will supply all required chemicals, hydraulic fluids and 

electrical power. 

2.6.7. SUBSEA INFRASTRUCTURE PROTECTION 

PIPELINE AND UMBILICAL TRENCHING 

A pipelay vessel that is equipped with Dynamic Positioning will be used. The pipeline will be laid and 

trenched and backfilled using a towed plough arrangement (Figure 2‐7). The plough will be used to 

firstly cut a trench containing the pipeline to a target depth of 1.8 m and then backfilled using a 

backfill plough. The trench is not envisaged to provide any obstruction to fishing gear that may 

encounter it. 

Figure 2‐7 Pipeline trenching plough (CTC Marine, 2011). 

There are two options for the installation of the subsea umbilical: 

Trench and mechanical backfill; The main umbilical is laid in a dedicated trench using a towed 

plough and the trench is either mechanically backfilled or left to backfill naturally. The 

backfilling operation can be carried out with the same plough as is used for trenching except 

that the blades are configured differently. 

Simultaneous lay and trench; A device similar to a pipeline plough (Figure 2‐8) is used to lay 

and trench the umbilical simultaneously. 

D/4114/2011 2‐13



Figure 2‐8 Modular trenching plough capable of simultaneous lay and trench (CTC Marine, 2011). 

The final decision on the installation method for the umbilicals has yet to be determined. 

ROCK PLACEMENT 

Rock placement will be required for pipeline dropped object protection, upheaval buckling mitigation 

and for pipeline crossings. 

An initial maximum estimate is that 20,000 tonnes of rock will be required for the development. 

Three pipeline crossings have been identified along the Flyndre and Cawdor pipeline development 

which will require additional spot rock placement of approximately 3,000 tonnes each. 

The final mass of rock required will be calculated by undertaking upheaval buckling analysis based on 

information provided from post trenching surveys. 

MATTRESSES 

Mattresses will be used to provide protection at sections where the pipelines and umbilicals are not 

trenched e.g. connections with wellheads and manifolds. It is estimated that 250 mattresses 

measuring 6 m x 3 m will be required covering a total area of 4,500 m 2 . 

2.6.8. SUBSEA INSTALLATION SUPPORT VESSELS 

Various support vessels will be associated with the subsea installation phases of this development. 

Vessel types, duration and fuel usage of vessel during installation are given in Table 2‐10. 

2‐ 14 D/4114/2011



Vessel type 

Duration 

(days) 

Working fuel 

consumption (Te/d) 1 

Total fuel 

use (Te) 

Survey 40 11 440 

Dynamically positioned reel‐lay vessel 25 23 575 

Trenching support 40 17 680 

Diving support vessel 75 18 1350 

Rock dumper 10 15 150 

Guard vessel 50 4 200 

Supply vessel 20 10 200 

Total 3595 

1 Source; The Institute of Petroleum 2000. 

Table 2‐10 Vessel type and fuel usage during installation of subsea infrastructure. 

2.6.9. FLOW ASSURANCE 

HYDRATES 

The initial flow assurance work suggests the Flyndre and Cawdor hydrocarbons will be susceptible to 

hydrate formation. The pipeline insulation design will ensure that the temperature profile during 

normal operation remains above the hydrate formation temperature. 

For extended shutdowns the hydrate mitigation philosophy is to blowdown the system at the host to 

a pressure below the hydrate formation envelope at ambient temperature. 

Hydrate prevention during start up will be by continuous methanol injection at the trees, upstream of 

the choke and may also be injected into the riser local to the platform. 

The Clyde platform will provide the necessary storage and injection equipment to enable methanol to 

be injected at the tree and upstream of wing and master valves. 

SCALING 

The need for scale inhibition at Cawdor is currently uncertain and will need to be assessed further 

once the first well is drilled. However, injection facilities will be provided in the subsea chemical 

delivery system to allow downhole scale injection should it be required. The Flyndre well is already 

completed with a downhole chemical injection service installed. 

SAND 

Sand is not anticipated from the Cawdor reservoir and is considered unlikely from the Flyndre 

reservoir. 

WAX 

The Wax Appearance Temperature (WAT) is currently estimated at 35 o C and 37 o C for Flyndre and 

Cawdor respectively. In addition to a low thermal loss design for the pipeline, a wax inhibition 

delivery system will be provided. The pipeline insulation design will ensure that the temperature 

profile during normal operations remains above the WAT. 

D/4114/2011 2‐15



The Clyde platform will provide the necessary storage and injection equipment to enable the inhibitor 

to be injected at the wellhead/pipeline as required. 

2.7. CLYDE ‐ OVERVIEW OF EXISTING FACILITIES 

Talisman’s Clyde platform (Figure 2‐9) was commissioned in 1986 and is located approximately 

276xkm east southeast of Aberdeen and receives on‐platform production from the Clyde, Leven, 

Medwin and Nethan reservoirs (referred to as the Clyde fields) as well as production from the Orion 

reservoir via a subsea tie‐back. The platform also receives dry gas production from the Affleck 

reservoir, which is commingled with the export gas from the platform. 

Separate top side production facilities are dedicated to production of the Clyde field hydrocarbons 

and those of the Orion field hydrocarbons. 

2.7.1. CLYDE PRODUCTION PROCESS 

Figure 2‐9 Talisman’s Clyde platform. 

Reservoir fluids from the Clyde fields passes from the wellhead assembly via the high pressure 

manifold to a first stage separator or via the low pressure manifold to the second stage separator 

before entering the third stage separator (Clyde separators). The first and second stage separators 

are three‐phase (oil, water, gas) separators and the third stage is a two‐phase (gas, liquid) separator. 

A smaller test and clean‐up separator is provided to test wells individually without affecting 

production by operating in parallel with the first or second stage separator. The test separator has 

also been designed to serve as a back‐up to the first stage production separator when this is out of 

commission for cleaning or maintenance. 

Processed crude is drawn from the third stage separator through a crude oil dehydrator which 

removes the remainder of the water from the oil to a specification maximum of 0.2% basic sediment 

2‐ 16 D/4114/2011



and water. The flow is then accurately measured by meters before the oil is exported via the Fulmar 

pipeline to the Shell Fulmar ‘A’ platform and from there to Teeside. 

Some of the produced gas is used for fuel gas; the remainder flows from the separators to gas 

compression stages where it is cooled and partly condensed. The condensate is then returned to the 

production separators to increase crude oil recovery. When the compressors are not running, 

produced gas from the separators may be routed to the flare system and burned. 

The gas compression, treatment and gas lift manifold systems comprise: 

four stages of compression, LP/IP/HP and export compressors in series which boost the 

produced gas to a pressure of 138 barg for export. 

a gas dehydration unit consisting of dual molecular sieve drying beds, regenerated 

alternately on a timed cycle, to remove water from the export stream. 

a fiscal metering skid. 

a gas lift manifold. 

Fuel gas is supplied either from the gas dehydration system or directly from the first stage separator, 

and is passed through a knock‐out drum, electric heaters and filters to achieve the quality required 

for supply to the main platform power generators. 

2.7.2. ORION PRODUCTION PROCESS 

Hydrocarbons from the Orion fields pass through a dedicated area of the platform (Orion topside 

production facilities) before commingling with fluids from the Clyde, Leven, Medwin and Nethan 

reservoirs at either the second or third stage separator. The Orion topsides production facilities 

consist of a single production separator, crude oil transfer pumps and allocation gas and crude oil 

metering facilities. Gas and oil from the Orion production separator is further processed in either the 

second or third stage separators (previously referred to as the Clyde second and third stage 

separators) where it commingles with hydrocarbons from the Clyde fields before being transferred to 

the Clyde dehydrator to remove any remaining water prior to export from the platform. 

The gas produced from the Orion separator is metered and transferred to the Clyde high pressure gas 

compressor where it is commingled with the Clyde field gases. The gas is dehydrated in the existing 

dehydration package and then compressed to 140 Barg for export to the Fulmar platform and 

subsequently to the St. Fergus terminal. 


Flow measurement of oil, gas and water produced by individual Clyde wells is provided via the test 

separator. For Orion, the dedicated production separator utilises ultrasonic and coriolis flow meters 

for measuring gas and liquid hydrocarbon flow respectively. 

Oil flowrate and gas flowrates are fiscally metered immediately prior to export from the Clyde 

platform. All consumed gas is metered; each source of fuel gas has a dedicated orifice plate meter 

with ultrasonic metering of flared gas. 

2.7.4. WATER TREATMENT 

On the Clyde platform produced water (PW) is mainly separated from the produced oil stream by 

gravity settling. The majority of PW in the reservoir fluid is expected to separate from the oil stream 

in the first and second stage separators. Dedicated hydrocyclone units are employed to treat PW 

from the first and second stage separators and from the test separator. These hydrocyclones are 

D/4114/2011 2‐17



designed to reduce the oil in water content (OIW) from typically 100‐500 ppm on the inlet to less than 

25 ppm on the outlet. 

The level of PW in each vessel is controlled by interface level controllers. The position of the interface 

may be readily adjusted, to suit operating conditions and water cut, to achieve sufficiently clean 

discharged water. 

Each PW flow is measured. Each line is also provided with corrosion monitoring probes and a sample 

point. 

2.7.5. FLARE SYSTEM 

The flare and vent systems are provided to collect releases of hydrocarbon gas from process systems 

under normal and emergency conditions and dispose of them safely. 

The flare system collects releases of a significant rate which are burnt, whereas the vent system 

collects small quantities of gas vented as a result of ‘breathing’ of low‐pressure tanks, and releases 

these directly to atmosphere without being burnt. Flare gas is burnt at the end of a boom 

cantilevered from the northeast corner of the platform. Vent gas is released at a point halfway up 

this boom. 

In general all relief valves fitted to process systems, which prevent mechanical failure due to 

overpressure, are directed into flare collection headers. 

Flared gas is collected, has condensate removed, and is burnt in two separate systems: 

HP system, which takes gas from all moderate or high‐pressure sources. The gas flows via 

the HP knock‐out drum, V2501, to the HP flare tip where it is burnt. The HP flare tip is a low 

emissivity type. It operates at high velocity to burn gas efficiently and without smoke. 

LP System, which takes gas from low‐pressure users which cannot flow into the higher 

pressure HP System. It also takes gas releases from blowdown of gas compressors (where a 

very low final pressure is required to prevent compressor seal leakage). The LP flare gas flows 

via the knock‐out drum, V2502, to the LP flare tip where it is burnt. 

The HP and LP flare tips are mounted as a single assembly at the end of a 73.5 m long boom, which is 

positioned at the north east corner of the platform and angled at 45° to the horizontal. Boom length, 

position and angle were chosen to take advantage of prevailing wind direction in blowing the flared 

gas away from the platform, and minimise radiation levels and the effect of hot flare plume on the 

platform. 

Total fluids flared on the Clyde platform in 2010 was 17,755 tonnes (EEMS, 2010). 

2.7.6. POWER GENERATION AND FUEL USE 

The main power is generated by seven gas turbine generators. Auxiliary power, produced by two 

diesel driven generators, is available to maintain supplies to priority services in the event of failure of 

the main stream. The primary power generation systems on the Clyde platform are outlined in Table 

2‐11. 

A further level of emergency support is provided by the uninterruptible power supplies system. This 

is battery powered and ensures that life‐support and safety systems are maintained under emergency 

conditions. The batteries are kept charged during normal operations by the main electrical supply. 

2‐ 18 D/4114/2011



Combustion 

Equipment 

AGT TB5000 Gas 

Turbine Generator 

(7 in total) 

Caterpillar 3516 

Drilling Engine A 

Ruston 8RKC 

Drilling Engines (2 

in total) 

TAG No. Fuel 

GZ‐41‐01 A 

/B/C/D/E/F/G Dual 

GZ‐98‐01A Diesel 

GZ‐98‐01B/C Diesel 

Primary 

Duty 

WHR 

Max. 

Thermal 

input 

(MWth) 

Rating 

Max. 

Load 

(MW) 

Peak 

Thermal 

efficiency 

(%) 

Main 

power 

generation 

No 15 3.6 25 

Power 

Generation 

Power 

No 6.20 1.82 29 

Generation Mo 6.2 1.82 29 

Table 2‐11 Main power generation & drilling power generators in use on the Clyde platform (Clyde 

PPC permit; Ref PPC34) 

The total fuel use for power generation on the Clyde platform in 2010 was 8,152 tonnes of diesel and 

24,371 tonnes of gas (EEMS, 2010). 

2.8. FLYNDRE AND CAWDOR – OVERVIEW OF PROPOSED FACILITIES 

2.8.1. PRODUCTION PROCESS 

One of the main drivers for the development of Flyndre and Cawdor is to minimise the impact on 

existing Clyde facilities and maximise the re‐use of existing equipment. 

The pipe‐in‐pipe subsea line will terminate at a subsea isolation valve (SSIV) within the Clyde 500 m 

zone. An 8" nominal bore (NB) pipeline will be routed from the SSIV to the existing bank of J‐tubes on 

the west side of the platform. An 8" NB rigid riser will be pulled up through one of the existing spare 

16" NB J‐tubes, with the umbilical pulled through the matched spare 10" NB J‐tube. New dedicated 

Flyndre/Cawdor subsea support systems will be installed on the Clyde platform. 

The existing Orion separator on the Clyde platform will be dedicated to receive Flyndre/Cawdor fluids 

and Orion production will be re‐routed to the Clyde 2 nd stage separator. The Orion separator will be 

converted from a two phase to three phase operation as per the original vessel design. Dedicated 

produced water treatment facilities will be provided, with the treated water discharged overboard via 

an existing produced water disposal caisson. 

The re‐routed Orion production fluids will be commingled with existing Clyde production upstream of 

the Clyde 2 nd stage separator. The 2 nd stage separator inlet device will be replaced with a vane type 

device to handle the additional vapour load from re‐routing Orion production fluids. 

To maximise Flyndre/ Cawdor production, the HP and export compressors will be re‐wheeled, new 

internals installed in the HP compressor discharge scrubber and the export compressor suction 

scrubber plus dehydration condensate knock‐out drum will be replaced. The pressure profile and 

design conditions across the compressor will not be modified. The compressor will operate at the 

same speed utilising the installed driver. 


Flow measurement of the Flyndre and Cawdor production is required to determine the tariff for the 

use of the Clyde facilities. This will be achieved by the measurement of gas, hydrocarbon liquid and 

water flows from the Orion separator. It has been determined that the existing ultrasonic and coriolis 

D/4114/2011 2‐19



flow meters for measuring gas and liquid hydrocarbon flow respectively will be utilised. A new 

coriolis flow meter is proposed for the measurement of the PW. 

A new oil metering station shall be provided on the oil outlet stream from the Clyde 2 nd stage 

separator and a new connection between the Orion flowline and the existing Clyde test separator 

shall also be provided. It is anticipated that the oil metering station will consist of 2 × 100% coriolis 

meters in parallel, complete with sampling facilities. 

2.8.3. WATER TREATMENT 

The majority of PW in the Flyndre and Cawdor reservoir fluids is expected to separate from the oil 

stream in the Orion production separator. In order to measure the water produced by the Flyndre 

and Cawdor development the water will be treated in a dedicated treatment package and discharged 

overboard. Any water carry over will pass to the Clyde third stage separator, which in turn ties into 

the crude oil dehydrator which has a long residence time and is provided to remove the last few 

percent of water from the oil stream to achieve the oil export specification of 0.2% basic sediment 

and water. 

2.8.4. FLARE SYSTEM 

As part of the development of the Flyndre and Cawdor fields there will be limited modifications to the 

Clyde as existing equipment is to be reused, however pipeline operations will increase flaring from 

the platform. Should the pipeline shutdown (planned or unplanned) extend beyond a defined ‘no 

touch time’ the pipeline will cool down to a temperature where hydrates may form. To mitigate this, 

the pipeline pressure requires to be reduced thus requiring flaring of the pipeline inventory. Restart 

of the pipeline will require a period of low pressure production to ensure the pipeline temperature 

rises above the hydrate potential limit prior to pressurisation. During this low pressure phase, gas 

flaring will be required from separation as operating pressure will be too low to access the HP gas 

compressor. The potential to minimise flaring by utilising LP compression will be considered as an 

option during FEED. 

If restart of the pipeline can be achieved within the ‘no touch time’ limit, gas flow direct to HP 

compression will be possible and so no additional flaring will be required. If the nature of the 

shutdown causes the pipeline to pack above normal settle out pressure, then the pipeline pressure 

will require blowdown to a safe level prior to restart. 

At the time of writing this ES, the specific operating requirements to accurately determine flaring 

limits had not been defined. An additional annual flaring load has been calculated on the following 

basis; 

24 hour ‘No Touch Time’ 

one of the annual Clyde planned shutdowns extending beyond no touch time 

six of the annual Clyde unplanned shutdowns extending beyond no touch time 

50 bar gauge pipeline settle out pressure 

120 bar gauge to 80 bar gauge pipeline pressure pack blow down required once per year 

24 hour flaring required to warming pipeline at a flowrate of 12 MMscfd 

On this basis the annual additional flaring load as a result of Flyndre and Cawdor development is 

estimated at 2,750 tonnes of gas. 17,755 te of gas were flared on the Clyde platform in 2010 (EEMS, 

2010). 

It should be emphasised that the data presented for anticipated additional flaring load is preliminary 

and subject to change as the design develops. 

2‐ 20 D/4114/2011



2.8.5. POWER GENERATION AND FUEL USE 

As part of the development of the Flyndre and Cawdor field there will be no requirement to install 

any other combustion equipment as there will be sufficient power generation capacity on the Clyde 

platform. Therefore no increase in fuel use for power generation is anticipated. 

2.9. CHEMICAL USE AND DISCHARGES TO SEA 

Maersk Oil aims to minimise the effect of the chemicals used/discharged during its operations. As 

such, and as part of the chemical permitting process, Maersk Oil sets internal targets to reduce the 

number of chemicals used with a substitution warning and/or product warnings. Wherever possible, 

chemicals will be chosen which are PLONOR (Poses Little or No Risk to the environment) or are of a 

Low Hazard Quotient, HQ

2.10. PRODUCTION 



Production profiles have been developed for the Flyndre and Cawdor development which forecast the 

likely volumes of oil, gas and water that will be produced from the reservoirs. Consequently Flyndre 

and Cawdors contribution to the total volumes of oil, gas and water processed on the Clyde have also 

been determined. Maximum case production profiles (P10) for oil, gas and produced water are 

provided in the following sections. 

2.10.1. OIL PRODUCTION RATE 

Table 2‐13 and Figure 2‐10 show the anticipated P10 oil production rate for the Flyndre and Cawdor 

development and its impacts on the volumes processed on the Clyde. Peak daily oil production at the 

Flyndre field occurs in the first year of production with a maximum production of 2,259 te/d in 2013, 

decreasing to 198 te/d in 2026; the last year of production. Peak production at the Cawdor field is 

expected in 2018 (794 te/d). When the projected production from the Flyndre and Cawdor fields are 

combined, peak production is expected in 2013 with a production rate of 2,259 te/d. The 

development will increase peak oil production at the Clyde platform from 1,115 te/d (without Flyndre 

and Cawdor) to 3,374 te/d in 2013. 

Year 

Clyde platform 

excluding 

Flyndre and 

Cawdor (te/d) 

Flyndre 

(te/d) 

Annual average oil production rate 

Cawdor 

(te/d) 



combined (te/d) 


including 



2011 1,069 ‐ ‐ ‐ 1,069 

2012 1,073 ‐ ‐ ‐ 1,073 

2013* 1,115 2259 0 2,259 3,374 

2014 1,095 1613 471 2,084 3,179 

2015 834 1123 521 1,644 2,478 

2016 551 866 521 1,387 1,938 

2017 489 778 661 1,439 1,928 

2018 510 778 794 1,572 2,082 

2019 621 778 774 1,552 2,173 

2020 564 778 712 1,490 2,054 

2021 496 778 629 1,407 1,903 

2022 449 778 550 1,328 1,777 

2023 404 762 554 1,316 1,720 

2024 365 562 426 988 1,353 

2025 336 385 325 710 1,046 

2026 309 198 268 466 775 

*2013 production values are only for 3 months 

Table 2‐13 Maximum case (P10) anticipated annual average oil production figures. 

2‐ 22 D/4114/2011



Te/d 

3500 

3000 

2500 

2000 

1500 

1000 

500 

0 

Year 

Figure 2‐10 P10 average oil production from Flyndre and Cawdor fields and total production at the 

Clyde platform. 

2.10.2. GAS PRODUCTION RATE 

Oil production profiles (P10) for development 

Clyde platform including Flyndre & Cawdor 

Clyde platform excluding Flyndre & Cawdor 



Table 2‐14 and Figure 2‐11 show the anticipated P10 gas production rate for the Flyndre and Cawdor 

development and its impacts on the volumes processed on the Clyde. Production from the Flyndre 

and Cawdor fields commences in 2013 and 2014 respectively with peak production at the Flyndre 

field occurring from the start (613 Mm 3 /d) and dropping to 55 Mm 3 /d in 2026. Peak production at 

the Cawdor field is expected in 2023 with an anticipated gas production of 553 Mm 3 /d. Combining 

the two fields peak production from the development is expected in 2023 with a production rate of 

753 Mm 3 /d. The development will increase peak gas production at the Clyde platform from 

207xMm 3 /d (without Flyndre and Cawdor) to 901 Mm 3 /d in 2014. 

D/4114/2011 2‐23

Year 


excluding 

Flyndre & 

Cawdor (Mm 3 /d) 


Annual average gas production rate 


(Mm 3 /d) 


(Mm 3 /d) 




(Mm 3 /d) 


including Flyndre 

& Cawdor 

(Mm 3 /d) 

2010 126 ‐ ‐ ‐ 126 

2011 266 ‐ ‐ ‐ 266 

2012 234 ‐ ‐ ‐ 234 

2013 223 613 ‐ 613 836 

2014 207 438 256 694 901 

2015 123 305 283 588 711 

2016 56 235 276 511 567 

2017 49 211 341 552 601 

2018 48 211 412 623 671 

2019 53 211 412 623 676 

2020 48 211 412 623 671 

2021 43 211 412 623 666 

2022 39 211 412 623 662 

2023 35 200 423 623 658 

2024 32 151 463 614 646 

2025 29 105 350 455 484 

2026 27 55 289 344 371 

Table 2‐14 Maximum case (P10) anticipated annual average gas production figures. 

900 

800 

700 

600 

500 

400 

300 

200 

100 

0 

Gas production profiles (P10) for development 

Figure 2‐11 P10 average gas production from Flyndre and Cawdor fields and total production at the 

Clyde platform. 

Year 





2‐ 24 D/4114/2011



2.10.3. WATER PRODUCTION PROFILE 

Table 2‐15 and Figure 2‐12 show the anticipated P10 produced water production profiles for the 

Flyndre and Cawdor development and its impacts on the volumes processed on the Clyde. Peak PW 

production at the Flyndre and Cawdor fields occurs in 2026 and 2023 respectively with a peak 

production of 1,074 Te/d at the Flyndre field and 40 te/d at the Cawdor field. Combining the two 

fields peak PW production from the development is expected in 2026 with a production rate of 1,110 

te/d. The development will increase peak PW production at the Clyde platform to 10,926 te/d in 

2024. 


excluding 



Annual average water production rate 


(te/d) 


(te/d) 



combined 

(te/d) 


including 



2010 6,563 ‐ ‐ ‐ 6,563 

2011 10,427 ‐ ‐ ‐ 10,427 

2012 10,669 ‐ ‐ ‐ 10,669 

2013 10,771 74 0 74 10,845 

2014 10,856 52 2 54 10,880 

2015 10,802 38 3 41 10,843 

2016 10,636 38 3 41 10,677 

2017 10,565 63 11 74 10,639 

2018 10,337 91 16 107 10,444 

2019 10,331 137 19 156 10,487 

2020 10,340 190 24 214 10,554 

2021 10,254 255 27 282 10,536 

2022 10,157 433 30 463 10,620 

2023 10,054 818 40 858 10,912 

2024 9,946 941 39 980 10,926 

2025 9,835 1033 37 1,070 10,905 

2026 9,723 1,074 36 1,110 10,833 

Table 2‐15 Maximum case (P10) anticipated annual average water production figures. 

D/4114/2011 2‐25

Te/d 

10000 

8000 

6000 

4000 

2000 

0 



Figure 2‐12 P10 average produced water production from Flyndre and Cawdor fields and total 

production at the Clyde platform. 

2.11. PERMITTING 

The Clyde platform already has permits in place covering both atmospheric emissions and discharges 

to sea. Details of any changes to these permits as a result of the Flyndre and Cawdor development 

are provided below. 

2.11.1. ATMOSPHERIC EMISSIONS 

Water production profiles (P10) for development 



Flyndre & Cawdor 

POLLUTION PREVENTION AND CONTROL (PPC) PERMIT (PERMIT REFERENCE: PPC34) 

The Clyde platform has an existing permit under the Offshore Combustion installations (Prevention 

and Control of Pollution) Regulations 2001. The emissions resulting from the incremental increase in 

fuel consumption are not expected to result in an increase in atmospheric emissions above those 

authorised under the PPC permit therefore it is anticipated that there will be no requirement to 

amend the permit. As there will be no change to the existing thermal capacity of the installation as a 

result of additional infill wells, there will be no requirement for a Substantial Change assessment 

under the regulations. 

EU EMISSIONS TRADING SCHEME (ETS) (PERMIT REFERENCE: DTI6000) 

As detailed above, the project will utilise existing ullage within the Clyde platform process systems 

and will not result in an increase in power demand that will generate additional emissions above 

historic levels. 

An application will be made to DECC by Talisman on behalf of Maersk to cover the increased 

emissions at the Clyde platform as a result of additional flaring, the application will be made to the 

new entrants reserve in the ETS. 

Year 

2‐ 26 D/4114/2011



2.11.2. DISCHARGES TO SEA 

OIL POLLUTION PREVENTION AND CONTROL (OPPC) (PERMIT REFERENCE: L00076) 

The Clyde platform has a permit for the discharge of produced water in accordance with the 

Petroleum Activities (Oil Pollution Prevention and Control) Regulations (OPPC) 2005(and amendments 

2011). It is anticipated that there will be an increase in the total volumes of produced water and oil 

discharged and therefore an amendment to the OPPC permit will be applied for as required. 

CHEMICAL USE (PERMIT REFERENCE PON15D/229) 

The relevant permits to use and discharge chemicals offshore will be amended in accordance with the 

Offshore Chemical Regulations 2002 (variation to the PON15D). All offshore activities are covered by 

the Regulations including oil and gas production, drilling of wells, discharges from pipelines and 

discharges made during decommissioning. Following on from a review of chemicals required a 

variation to the PON15D ‐229 will be made. 

2.12. DECOMMISSIONING 

At cessation of production, the wells, subsea structures and associated production facilities will be 

decommissioned in accordance with statutory requirements in force at that time. 

There are a variety of environmental effects relating to decommissioning the subsea infrastructure 

and pipelines. These include emissions to air and water, waste disposal, energy use, onshore disposal 

and recycling. The nature and extent of the potential environmental effects is dependent on the 

decommissioning strategy selected. 

It is outside the scope of this ES to present a detailed assessment of the decommissioning options. As 

an integral component of the decommissioning process, Maersk Oil will undertake a study to 

comparatively assess the technical, cost, health, safety and environmental aspects of 

decommissioning options, for which a further Environmental Impact Assessment will be required at 

that time. 

Detailed decommissioning plans will be submitted to the DECC for the decommissioning of the 

Flyndre and Cawdor development at the appropriate time, dependent on the COP and the end of field 

life. The date of cessation of production and the commencement of decommissioning of associated 

facilities will depend upon field performance, field economics, the production of other fields tied back 

to the Clyde platform and associated operating costs. 

The Marine and Coastal Access Act (MCAA) came into force in November 2009. The Act covers all UK 

waters except Scottish internal and territorial waters which are covered by the Marine (Scotland) Act 

2010 which mirrors the MCAA powers. The licensing provisions in relation to MCAA came into force 

on 1 st April 2011. 

MCAA will replace and merge the requirements of FEPA Part II (environment) and the Coastal 

Protection Act (navigation). Although some oil and gas exploration and production activities are 

exempt from MCAA, some decommissioning activities do require an MCAA license, including: 

removal of substances or articles from the seabed 

disturbance of the seabed (e.g. localised dredging to enable cutting and lifting operations) 

deposit and use of explosives that cannot be covered under an application for a Direction. 

disturbance of the seabed e.g. disturbance of sediments or cuttings pile by water jetting 

during abandonment operations. 

D/4114/2011 2‐27



The need to apply for MCAA licence or any future legislative requirement in place will be considered 

at the planning stage within the decommissioning schedule. 

2‐ 28 D/4114/2011


Section 3 Environmental Baseline 

3. BASELINE ENVIRONMENT 

This section describes the baseline environment, that is, the current nature and status of the 

potentially affected area to identify potential receptors. This is required in order to identify the 

potential environmental impact of the development, and to provide a basis for assessing the potential 

interactions of the proposed development with the environment. 

This section has been prepared with reference to available literature, expertise, previous experience 

and survey data. There have been two principal environmental surveys carried out for the Flyndre 

and Cawdor developments, an environmental pipeline route survey (Gardline, 2011) and the Flyndre 

site survey (Gardline 2006). Summaries of the data from these surveys have been included in the 

relevant sections of this report. The environmental pipeline route survey has been provided in a CD 

accompanying the Environmental Statement. 

In 2006 as part of the environmental site survey for the Flyndre appraisal well, a environmental and 

habitat site survey was carried out in a 1 km area centred around the proposed drill location, the 

results of which are discussed here and have previously been reported in the W/3273/2006 ‐PON15b 

for the Flyndre well. The acquisition tools used were single echo sounder, sidescan sonar and two sub 

bottom profilers. An environmental survey was carried out in conjunction with the site survey, four 

camera stations which included the proposed well location and features to the north and south of the 

survey area and three grab stations were selected as the site was uniform and featureless on side 

scan sonar records. 

Once the Flyndre appraisal well had encountered commercial quantities an environmental baseline 

survey and habitat assessment was carried out of potential pipeline routes. At the time of the 

survey, there were two potential hosts the Talisman operated Clyde platform and the Maersk 

Operated Janice FPU. The environmental assessment consisted of a geophysical survey and habitat 

investigation (Gardline, 2011). The environmental survey was completed in conjunction with a 

geophysical survey and habitat assessment survey, in order to establish the baseline physio‐chemical 

characteristics and benthic community over the proporsed pipeline route corridor. The geophysical 

survey used single‐ and multi‐beam echo sounders, sidescan sonar, magnetometer, pinger, boomer, 

coring and CPT equipment to provide a detailed assessment of the area. The habitat survey used a 

shallow water digital stills and camera system and benthic day grab. 

Environmental sampling was conducted at a maximum of two kilometre intervals along the centre 

line of the proposed pipeline routes. In total, eighteen stations were investigated with a digital stills 

and video system, prior to sampling with a day grab. 

Further environmental site surveys will be carried out in the Cawdor area when the drilling locations 

are determined and will be carried out a later date, the results of these will be incorporated into the 

relevant PON15Bs. 

3.1. METOCEAN CONDITIONS 

In order to design and operate offshore installations in a safe and efficient manner it is essential that 

a good knowledge is available of the metocean (meteorological and oceanographic) conditions to 

which the installation may be exposed. Sediment type, currents, tides and circulation patterns all 

influence the type and distribution of marine life in an area. Metocean conditions also influence the 

behaviour of emissions and discharges (including spills) from offshore facilities. For example, the 

speed and direction of water currents have a direct effect on the transport, dispersion and ultimate 

fate of any discharges from an installation while sediment type can influence the levels of 

contaminants that may be retained in an area. 

D/4114/2011 3 ‐ 1



The physical conditions of the environment influence the type and distribution of marine life in the 

area, help set the design parameters for offshore facilities and influence the behaviour of emissions 

and discharges from offshore facilities. 

3.1.1. BATHYMETRY, WATER MASSES, CURRENTS AND TIDES 

The topography in the vicinity of the Flyndre and Cawdor fields is generally considered to undulate 

gently with gradients



Figure 3‐2 A schematic diagram of the general circulation in the North Sea (European 

Environmental Agency, 2002). 

Mixing in the water column intensifies with increased tidal current speed. Over most of the North 

Sea, the strength of the tidal streams is generally less than 0.51 m/s, even at mean spring tide. Tidal 

currents over the proposed development area are relatively weak being between 0.16 m/s (neep 

tides) and 0.26 m/s (spring tides) (BODC, 1998). 

Semi‐diurnal tidal currents are relatively weak in offshore Northern and Central North Sea areas (DTI, 

2001). In the area of the development the maximum tidal current speed during mean spring tides is 

between 0.13 m/s and 0.26 m/s (0.25‐0.5 knots) (BODC, 1998). Surge and wind–driven currents, 

caused by changes in atmospheric conditions, can be much stronger and are generally more severe 

during winter. Storm events may also generate near‐bed, wave‐induced currents sufficient to cause 

sediment mobilisation (DTI, 2001). The maximum 50 year surge current in the region of the 

development is about 0.6 m/s (BODC, 1998). 

During storms, the resuspension and vertical dispersion of bottom sediments due to waves and 

currents affects most of the North Sea. In the area of the proposed development the storm surge 

elevation with a return period of 50 years is approximately 1.25 – 1.5 m (BODC, 1998). 

D/4114/2011 3 ‐ 3

3.1.2. OFFSHORE CLIMATE 



The CNS is situated in temperate latitudes with a climate that is strongly influenced by the inflow of 

oceanic water from the Atlantic Ocean and by a large‐scale westerly air circulation, which frequently 

contains low pressure systems (OSPAR Commission, 2000). The extent of this influence varies over 

time as changes in the strength and persistence of the westerly winds are influenced by the winter 

North Atlantic Oscillation (a pressure gradient between Iceland and the Azores). 

Wind speed and direction directly influence the transport and dispersion of atmospheric emissions 

from an installation. These factors are also important for the dispersion of marine emissions, 

including oil spills, by affecting the movement, direction and break up of substances on the sea 

surface. Wind data spanning 140 years (1854‐1994) across the North Sea show the occurrence of 

winds from all directions, with those from the south‐south‐west and south dominating. Predominant 

wind speeds throughout the year represent moderate to strong breezes (6 ‐ 13 m/s) with the highest 

frequency of gales (>17.5 m/s) during winter months (November–March). The major contrast 

between the NNS and central and southern areas is the relative frequency of strong winds and gales, 

particularly from the south. In northern areas (north of 57 o N) the percentage frequency of winds of 

Beaufort force 7 and above in January is >30% but 30% (DTI, 2001). 

3 ‐ 4 D/4114/2011



Beaufort scale 

Figure 3‐3 Prevailing wind direction and speeds in Quadrant 30 (56 o N to 57 o N; 02 o W to 03 o E). 

D/4114/2011 3 ‐ 5

Figure 3‐3 continued. 



3 ‐ 6 D/4114/2011



Mean annual rainfall across the North Sea varies between 340 and 500 mm, averaging 425 mm. 

Across much of the North Sea north of 54 o N (including the area of the proposed development) it 

ranges from 201‐400 mm (OSPAR Commission, 2000). 

In the area of the development fog is associated with wind directions of between south‐east and 

south‐west, and can reduce visibility to less than 1 km 3‐4% of the time (DTI 2001). 

3.1.3. WAVE HEIGHT 

Waves are the result of wind action on the sea surface and wave size is dependent on the distance or 

fetch over which the wind blows. The wave climate of the area is important in terms of the physical 

energy acting on structures including supply vessels, since this will have a large influence on the 

structural requirements of the design. The wave climate of the North Sea has changed in recent 

years, with a tendency towards increasing wave height. 

Significant wave height varies seasonally (Table 3‐1). Within the development area, the significant 

wave height of 3 m is exceeded 10% of the time and 75% of the time for heights greater than 1 m 

(BODC, 1998). 

Month Monthly mean significant wave height (m) 

January 3 ‐ 3.5 

February 2.5 ‐ 3 

March 2 ‐ 2.5 

April 2 ‐ 2.5 

May 1 ‐ 1.5 

June 1.5 ‐ 2 

July 1.5 ‐ 2 

August 1.5 ‐ 2 

September 1.5 ‐ 2 

October 2 ‐ 2.5 

November 2 ‐ 2.5 

December 2 ‐ 2.5 

Table 3‐1 Monthly mean significant wave height (BODC, 1998). 

3.1.4. TEMPERATURE 

The temperature of the sea affects both the properties of the sea water and the fates of discharges 

and spills to the environment. Average sea surface and seabed temperatures in the area of the 

Flyndre and Cawdor fields are given in Table 3‐2. 

Location Mean temperature in winter ( o C) Mean temperature in summer ( o C) 

Sea surface 5.5 – 6.0 15.5 ‐ 16 

Sea bottom 5.5 ‐ 6.0 6.5 ‐ 7.0 

Table 3‐2 Water temperature for area of the development (BODC, 1998). 

D/4114/2011 3 ‐ 7



During late spring the water column begins to stratify due to increased solar radiation and calmer 

conditions, which results in the formation of a thermocline in the water column separating a warm 

less dense surface layer from the rest of the water column, where winter temperatures remain. The 

thermocline increases in depth between May and September, and is typically between 50 m to 20 m 

deep during the summer (OSPAR Commission, 2000). In late August/early September stratification 

begins to break down due to decreasing solar heating and increasing wind and wave action. Water 

temperature remains relatively uniform throughout the water column during the winter months 

(Doody et al., 1993). 

3.1.5. SALINITY 

Like temperature, salinity affects the properties of seawater and the marine organisms inhabiting it. 

Fluctuations in salinity are largely caused by the addition or removal of freshwater from seawater 

through natural processes such as rainfall and evaporation. The salinity of seawater around an 

installation has a direct influence on the initial dilution of aqueous effluents such that the solubility of 

effluents increases as the salinity decreases. Salinity in the development area shows little seasonal 

variation, with mean seabed salinities of 35 in summer and winter, and mean sea surface salinities 

ranging between 34.75 in summer and 35.1 in winter (BODC, 1998). 

3.1.6. AMBIENT AIR QUALITY 

Whilst air quality is not monitored routinely at offshore sites, regular air quality monitoring is carried 

out by local authorities in many rural areas. Air quality readings from these onshore areas are used as 

an indication of the quality offshore. As such information for rural Scotland (Strath Vaich, 1997) is 

presented in Table 3‐3. 

Averaging Time NO 2 µg/m3 

Average 1.0 

98 th Percentile 7.5 

99.9 th Percentile 16.0 

100 th Percentile 16.8 

Converted assuming an ambient air temperature of 10 o C 

Closest statistic to 99.8 th percentile available, which is a conservative assumption 

Table 3‐3 Ambient concentration of NO2 for Strath Vaich (AEA Energy & Environment, 2008). 

3.1.7. WATER QUALITY 

Regional inputs from coastal discharges and localised inputs from existing oil and gas developments 

may affect water quality in different areas of the North Sea. Water samples with the highest levels of 

chemical contamination within the North Sea are generally found at inshore estuary and coastal sites 

subject to high industrial usage. Where concentrations of total hydrocarbons are found to be high 

offshore, these are normally in the immediate vicinity of installations, and concentrations generally 

fall to background levels within a very short distance of the point of discharge (CEFAS, 2001). 

Ecotoxicological Assessment Criteria (EACs) have been established for assessing chemical monitoring 

data (OSPAR Commission, 2000). EACs are the concentrations of specific substances in the marine 

environment below which no harm to the environment or biota are expected. EACs for selected trace 

metals and PAHs in water are given in Table 3‐4. Levels below those indicated in Table 3‐4 suggest 

that no harm to the marine environment should be expected. 

3 ‐ 8 D/4114/2011



Compound Concentration (mg/l) 

PAHs 

Mercury 0.005‐0.05* 

Zinc 0.5‐5* 

Nickel 0.1‐1* 

Copper 0.005‐0.05* 

Cadium 0.01‐0.1* 

Benzo(a)pyrene 0.01‐0.1* 

Fluoranthene 0.01‐0.1* 

Benzo(a)fluoranthene nd 

Indeno(1,2,3cd)pyrene nd 

PCB 0.001‐0.01* 

*= these values are provisional 

nd = no data available or insufficient data available 

Table 3‐4 Ecotoxicological Assessment Criteria (EACs) for selected trace metals and PAHs in water 

(OSPAR, 2000). 

The North Sea Quality Status Reports (North Sea Task Force, 1993) state that although the waters of 

the NNS as a whole do not contain contamination above normal background levels, slightly higher 

levels of some contaminants (e.g. copper, iron and vanadium) are typically found in the shallower 

SNS. Lead (Pb) is an exception as dissolved Pb is quickly removed onto the surfaces of suspended 

particulate matter which is relatively high in the coastal SNS area (apart from Dogger Bank region). It 

therefore does not get transported in the dissolved phase to the SNS by coastal circulation patterns 

(CEFAS, 1998). Since Pb from estuarine sources tends to be trapped in near shore areas, atmospheric 

inputs of Pb become increasingly important away from the coast. 

Similar to lead, polycyclic aromatic hydrocarbons (PAHs) generally absorb to particulate 

matter/suspended solids as they have low water solubility and are hydrophobic. Background water 

concentrations of PAHs are therefore often below the limit of detection. Similarly due to their low 

solubility, polychlorinated biphenyls (PCBs) concentrations in water are usually extremely low (

Location 

Oil & Gas 

Installations 

THC 

(µg/l) 

PAH 

(µg/l) 

PCB 

(µg/l) 

Nickel 

(µg/l) 


Copper 

(µg/l) 

Zinc 

(µg/l) 


Cadmium 

(ng/l) 

Mercury 

(ng/l) 

1‐30 ‐ ‐ ‐ ‐ ‐ ‐ ‐ 

Estuaries 12‐15 >1 30 ‐ ‐ ‐ ‐ ‐ 

Coast 2 0.02‐0.1 1‐10 0.2‐0.9 0.3‐0.7 0.5 10‐32 0.25‐41 

Offshore 0.5‐0.7



the local distribution or abundance of any protected species (termed the disturbance 

offence). 

EPS include all species of cetaceans, marine turtles, the sturgeon (Acipenser sturio) and the otter 

(Lutra lutra). The otter and sturgeon are principally coastal species and will therefore not be present 

at the Flyndre and Cawdor developmental area. 

3.2.1. HABITATS 

Of the habitat types listed in the Habitats Directive (Annex I) requiring protection, four of them occur 

or potentially occur in the UK offshore area (EC, 1999); 

sandbanks which are slightly covered by seawater at all times 

reefs 

‐ bedrock reefs; made from continuous outcroppings of bedrock which may be of 

various topographical shape (e.g. pinnacles and offshore banks) 

‐ stony reefs; aggregations of boulders and cobbles which may have some finer 

sediments in interstitial spaces 

‐ biogenic reefs; formed by cold water corals (e.g. Lophelia pertusa) and the 

polychaete worm Sabellaria spinulosa 

submarine structures made by leaking gases 

submerged or partially submerged sea caves. 

Currently in UK offshore waters there are five sites that are designated as cSAC/SCI, six as cSAC’s and 

four dSACs, descriptions of which are given in Table 3‐6. 

Survey results of the proposed pipeline route (Gardline, 2010) and those previously carried out at the 

Flyndre well location identified no environmentally sensitive habitats, protected under Annex I of the 

EC Habitats Directive. From the distribution of Annex I habitat types it appears very unlikely that 

there will be any areas identified in the further environmental surveys worthy as designation as 

protected areas, nonetheless Maersk will continue to carry out environmental surveys of areas prior 

to any planned activities. 

Of the areas listed in Table 3‐6 the Dogger Bank is in closest proximity and lies approximately 120 km 

south of the development. The Scanner and Braemar pockmarks lie approximately 220 km and 

280 km north of the development (Figure 3‐4). 

D/4114/2011 3 ‐ 11



Area Description Status 

Braemar Pockmarks Submarine structures made by leaking gas cSAC/SCI 

Scanner Pockmark 

North Norfolk Sandbanks and 

Saturn Sabellaria spinulosa reef 

Haisborough Hammond and 

Winterton 

Inner Dowsing, Race Bank and 

North Ridge 

Shallow depression approximately 600m by 300m & 

20m deep created by leaking gases 

cSAC/SCI 

Sandbanks and Sabellaria spinulosa reef communities. cSAC 

Sandbanks and Sabellaria spinulosa reef communities cSAC 

Sandbank and Sabellaria spinulosa reef communities cSAC 

Dogger Bank Large sublittoral sand bank pSAC 

North‐west Rockall Bank Biogenic reef, cold water corals and carbonate mounds cSAC 

Stanton Banks Bedrock reef cSAC/SCI 

Darwin Mounds 

Wyville Thomsom Ridge 

Sandy mounds topped with cold water coral Lophelia 

pertusa 

Rock and stony reefs supporting diverse biological 

communities 

cSAC/SCI 

Hatton Bank Volcanic rock with stony and cold water corals dSAC 

Bassurelle Sandbank 

Linear open shelf ridge sandbank, which is formed by 

tide currents 

Haig Fras Submarine, isolated bedrock outcrop cSAC/SCI 

Pisces Reef Complex 

Extensive mud plain through which three areas of 

Annex I bedrock and boulder reef protrude. 

3 ‐ 12 D/4114/2011 

cSAC 

cSAC 

dSAC 

Croker Carbonate Slabs Submarine structure made by leaking gas dSAC 

Wight‐Barfleur Reef Bedrock and stony reef dSAC 

Table 3‐6 Candidate, possible and draft SAC’s in UK waters (JNCC, 2011 Interactive Map).



Figure 3‐4 Location of proposed development relative to recognised cSACs and pSACs in closest 

proximity. 

DOGGER BANK 

The Dogger Bank is the largest single continuous expanse of shallow sandbank in UK waters and 

contains the Annex I habitat ‘Sandbanks which are slightly covered by sea water all the time’. It is 

located in the SNS, approximately 150 km north east of the Humber Estuary, and was formed by 

glacial processes before being submerged through sea level rise. The southern area of the bank is 

covered by water seldom deeper than 20 m and extends within the pSAC in UK waters down to 35‐ 

40 m deep. Its location in open sea exposes the bank to substantial wave energy and prevents the 

colonisation of the sand by vegetation. Sediments range from fine sands containing many shell 

fragments on top of the bank to muddy sands at greater depths (Krocke & Knust, 1995) supporting 

invertebrate communities typical of such sediments, characterised by polychaete worms, amphipods 

and small clams within the sediments, and hermit crabs, flatfish, starfish and brittlestars on the 

seabed (Wielking & Kroncke, 2003). Sandeels are an important prey resource found at the bank 

supporting a variety of species including fish, seabirds and cetacean (Cefas, 2007). Occasional, 

discrete areas of coarser sediments (including pebbles) were recorded on the bank, dominated by the 

soft coral Alcyonium digitatum, the bryozoan Alcyonidium diaphanum and Serpulid worms (Diesing et 

al., 2009). 

POCKMARKS (SUBMARINE STRUCTURES MADE BY LEAKING GASES) 

Pockmarks are usually found in soft, fine‐grained seabed sediments; often post‐glacial sediments of 

the Witch Ground Formation or Flags formation. They are typically greater than 10 m across and 

several meters deep. They are thought to be formed by the escape of gas or water from beneath the 

sediment and as such they are often associated with Methane‐Derived Authigenic Carbonate (MDAC), 

a mineral formation thought to be created by escaping methane, usually as a result of either microbial 

decomposition of organic matter (microbial methane) or the thermocatalytic destruction of kerogens 

(thermogenic methane) (Judd, 2001). 

D/4114/2011 3 ‐ 13



Pockmarks have been observed as habitats for unusual and prolific fauna which may be related to the 

carbon associated with the MDAC and an increase in sulphide compounds being available to enter the 

food chain or the physical presence of the MDAC as a hard substrate. In addition, as a result of the 

depression, currents are likely to be reduced within the pockmark and finer sediments with higher 

organic content are likely to accumulate. The lower bottom currents can lead to high levels of larval 

settlement, thus a higher abundance of deposit feeding organisms is often observed in comparison to 

the surrounding area. Bivalve species such as Thyasir sarsi and Lucinoma borealis are dependent on 

high sulphide concentrations and are only found within pockmarks, not the rest of the open North 

Sea. There is also a tendency for higher levels of suspended solids to be associated with the water 

within pockmarks which may lead to increased abundance of shrimps and euphausids. Fish also may 

take advantage of the sheltered conditions within the pockmark for example cod (Gadus morhua), 

torsk (Brosme brosme) and ling (Molva molva) (Dando, 2001). 

3.2.2. SPECIES 

The designation of fish species requiring special protection in UK waters is receiving increasing 

attention with particular attention being paid to large slow growing species such as sharks and rays. 

At a national level ‘The Wildlife and Countryside Act 1982, which implements the Convention on the 

Conservation of European Wildlife and Natural Habitats, lists seven protected species of marine and 

estuarine fish (European sturgeon, Allis and Twaite shad, basking shark, the whitefish Coregonus 

lavaretus, the giant goby and the couchs goby). Under the EC Habitats Directive there are six fish 

species (European sturgeon, Allis and Twaite Shad, River and Sea lamprey, basking sharks and the 

whitefish Coregonus lavaretus) that are afforded protection. In addition the International Union for 

the Conservation of Nature and Natural Resources (IUCN) has assessed the conservation status of a 

limited number of fish groups, and have recommended that two North Sea inhabitants; the basking 

shark (Cetorhinus maximus) and the common skate (Leucoraja batis), be added to the red list of 

endangered species. 

Few of the fish species listed above have distributions that extend into the offshore waters of the 

North Sea, and are thus not vulnerable to human activity in the areas of Quadrant 30. 

Of the species listed, only the European sturgeon (very rare offshore species), the basking shark (UK 

Biodiversity Action Plan & IUCN Red List – Endangered), tope (IUCN Red List – Vulnerable) and 

porbeagle (IUCN Red List – Vulnerable) are likely to occur in the CNS. Generally, these species occur 

in small numbers throughout the North Sea at times of peak zooplankton distribution and abundance 

(CEFAS, 2001). Although present within the North Sea they are uncommon and widely dispersed and 

are unlikely to be found in particular concentrations within this block. 

Four species from Annex II of the Habitats Directive occur in relatively large numbers in UK offshore 

waters; 

Grey seal (Halichorerus grypus) 

Common seal (Phoca vitulina) 

Bottlenose dolphin (Tursiops truncatus) 

Harbour porpoise (Phocoena phocoena). 

The bottlenose dolphin and harbour porpoise like all the cetacean species found in UK waters are also 

categorised as European Protected Species status, along with several other marine mammals found in 

UK waters. As such developers must consider the requirement to apply for the necessary licences 

should they consider there to be a risk of causing any of the potential offences to EPS species, this is 

discussed further in the section on marine mammals (Section 3.5.5.). Of the four species that are 

being considered for SAC, only the harbour porpoise inhabits the offshore area in the region of the 

proposed development. 

3 ‐ 14 D/4114/2011



3.3. THE SEABED 

3.3.1. SEABED SEDIMENTS 

Seabed sediments comprised of mineral and organic particles occur commonly in the form of mud, 

sand or gravel and are dispersed by processes driven by wind tides and contrasts in water density. 

The nature of the local seabed sediments is an important factor in providing information to help 

assess the potential for scouring of sediments around installed facilities. The seabed sediment 

distribution in the North Sea is illustrated in Figure 3‐5. 

Figure 3‐5 North Sea sediment type (MESH, 2007). 

In relation to offshore developments, the transport of sediments by seabed currents or sand wave 

activity may be an issue in terms of the disturbance of drilling solids and cement during installation 

operations. There is a direct relationship between particle size and bottom current strength at the 

final site of sedimentation; fine‐grained sediments are typical of low energy conditions whilst coarse 

sediments are typical of high energy conditions. It is likely that lighter particles would be transported 

further from the discharge point than heavier particles. 

The characteristics of the local sediments and the amount of sediment transport within a 

development area are important in determining the potential effects of possible future developments 

(drill cuttings, installation of pipelines, anchor scouring) on the local seabed environment. Particles of 

various types and sizes, notably the silt/clay fraction, can absorb petroleum hydrocarbons from sea 

water and through this pathway, hydrocarbons become incorporated into the sediment system. 

Organic matter within the sediment matrix is also likely to absorb hydrocarbons and heavy metals, 

providing a means of transport and incorporation into sediments. The bioavailability of contaminants 

D/4114/2011 3 ‐ 15



that are adsorbed to sediment or organic matter is poorly understood. However, in general terms 

prolonged contact between hydrocarbons and sediment may result in stronger bond formation and a 

subsequent reduction in bioavailability (Van Brummelen et al., 1998). This phenomenon is referred to 

as ‘ageing’, and is especially important for sediments with historic contamination such as prolonged 

discharge of drill cuttings or produced water. 

3.3.2. SEDIMENT CHARACTERISTICS (SEDIMENT TYPE, TOTAL ORGANIC MATTER & TOTAL ORGANIC CARBON) 

The distribution of seabed sediments within the CNS results from a combination of hydrographic 

conditions, bathymetry and sediment supply. Sediments classified as sand and slightly gravelly sand 

cover approximately 80% of the CNS (Gatliff, 1994). These sandy sediments occur over a wide range 

of water depths, from the shallow coastal zone down to about 110 m in the north and to below 120 m 

in isolated depths to the south and west. The carbonate content of the sand fraction is generally less 

than 10% (Gatliff, 1994). 

The sediments along the pipeline route consisted principally of silty sand with little variance along the 

pipeline corridor, this is illustrated in Figure 3‐7. There are a number of patches of silty sand that are 

found in section 2 of the pipeline route survey (heading towards the Clyde platform). Shown also in 

Figure 3‐7 are three side scan sonar outputs, two which illustrate an area of higher seabed reflectivity 

that corresponds with silty sand with numerous exposure of gravels and clay (in areas closer to the 

Janice and Clyde platform), the other side scan sonar image is representative of the majority of the 

pipeline route being flat and relatively homogenous. The seabed images that were collected along 

the pipeline route corridor illustrate the presence of fine sand, with occasional shell fragments in the 

majority of stations sampled. 

Sonar scan data from the pipeline route survey revealed a superficial covering (≈ 1 m) of fine to 

medium silty sand with occasional scattered shell fragments and possible outcroppings of clay. In the 

southern region of the proposed pipeline route there is evidence of coarser materials such as gravel, 

cobbles and coarse sand (Gardline, 2011). The sediments can exhibit signs of disturbance from 

previous drilling activity, as was shown in the side scan sonar results which can clearly show the spud 

can depression associated with the drilling of the Flyndre well (Figure 3‐6). The results of this suggest 

that any significant physical disturbance is likely to be visible for several years due to the lower levels 

of sediment movement in comparison to shallower waters of the Southern North Sea. 

Figure 3‐6 Illustration of the spud can depression from the jack‐up drilling rig at the drilled Flyndre 

well using an image obtained from side scan sonar data. 

3 ‐ 16 D/4114/2011



Janice FPU 

Clyde Platform 

Figure 3‐7 Seabed sediments along the Flyndre and Cawdro pipeline route, the Janice FPU location (section 3) and the Clyde plafrom 

Flyndre / Cawdor 

Drill location 

D/4114/2011 3 ‐ 17 

Fine sand with 

occasional large shell 

fragments 

Fine sand with 

occasional large shell 

fragments 

Fine sand with small 

shell fragments

3 ‐ 18 D/4114/2011 

[This Page Intentionally Left Blank] 


Section 3 Environmental Baseline



TOTAL ORGANIC MATTER 

Total Organic Matter (TOM) along the pipeline route ranged from 0.1% at section 2 (near Clyde) to 

1.2% at section 1 (near Flyndre and Cawdor drill location), with no apparent correlations with particle 

size or water depth, and was within the mean organic content of 1.6% reported by UKOOA (2001) 

from surveys in the central North Sea between 1975 and 1995. 

TOTAL ORGANIC CARBON 

Total Organic Carbon (TOC) along the pipeline route varied from 0.1% to 0.6%. The mean TOC 0.4% is 

slightly higher than that recorded in the previous surveys in the region (Gardline 2006, and 2009); 

while generally comparable with the wider area. 

3.3.3. SEDIMENT CONTAMINANTS 

Similar to water quality, OSPAR developed and adopted EACs as a method of assessing the degree of 

contamination in sediments. EAC values for selected metals and PAHs in sediment below which no 

harm to the environment is expected are given in Table 3‐7. 

PAHs 

Compound Concentration (mg/kg dw) 

Mercury 0.05‐0.5* 

Zinc 50‐500* 

Nickel 5‐50* 

Copper 5‐50* 

Cadmium 0.1‐1* 

Benzo[a]pyrene 0.1‐1* 

Fluoranthene 0.5‐5* 

Benzo[a]fluoranthene nd 

Indeno[1,2,3cd]pyrene nd 

PCB 0.001‐0.01* 

* = These values are provisional 

nd = no data available or insufficient data available 

Table 3‐7 Ecotoxicological Assessment Criteria (EACs) for selected trace metals and PAHs in 

sediment (OSPAR Commission, 2000). 

A summary of the contaminant levels typically found in surface sediments of the North Sea is given in 

Table 3‐8. Across the North Sea the quantity of total hydrocarbons in sediments tends to show an 

increase from the SNS to the NNS with background hydrocarbon concentrations being generally 

higher in fine sediments (muds and silts) than in coarser sediments (sand and gravels) due to their 

greater surface area and adsorptive capacity. Nevertheless, it is noteworthy that drilling activity and 

hence the input of oil derived contaminants has been considerably more intensive in the northern and 

central sectors compared to the SNS and consequently this would add to the higher levels recorded 

further north. 

D/4114/2011 3 ‐ 19

Location 

Oil & Gas 

Installations 

THC 

(µg/g) 

10‐450 

PAH 

(µg/g) 

0.02‐ 

74.7 

Estuaries ‐ 0.2‐28 

PCB 

(µg/g) 

Nickel 

(µg/g) 


Copper 

(µg/g) 


Zinc 

(µg/g) 

Cadmium 

(µg/g) 

Mercury 

(µg/g) 

1,917 17.79 17.45 129.74 0.85 0.36 

6.8‐ 

19.1 

‐ ‐ ‐ ‐ ‐ 

Coast ‐ ‐ 2 ‐ ‐ ‐ ‐ ‐ 

Offshore 17‐120 0.2‐2.7 5000m 

Nickel 17.79 15.36 9.18 9.5 

Copper 17.45 7.25 8.96 3.96 

Zinc 129.74 38.5 21.43 20.87 

Cadmium 0.85 5.56 0.2 0.43 

Mercury 0.36 0.22 0.33 0.16 

Lead 57.52 16.34 11.7 12.12 

Table 3‐9 Mean levels of total metals at selected distance increments from active platforms in ppm 

(Sheahan et al., 2001). 

Results of the hydrocarbon analysis of the grab samples collected during the pipeline route survey 

revealed concentrations largely representative of silty sandy sediments of the CNS (Gardline, 2011). 

However, there was considerable variation in concentrations across the proposed routes, consistent 

with changes in sediment characteristics and water depth. Total Hydrocarbons (THC) ranged from 

5.8 to 30.8 µg g ‐1 , with elevated concentrations at several stations, predominantly along Sections 2 

and 3, i.e. closer to the Clyde platform, both of the stations with increased THC were associated with 

increased fine sediment (



Total Poly Aromatic Hydrocarbons (PAH) concentrations ranged from 0.026 µg g ‐1 at section 1 (near 

the Flyndre and Clyde drill locations) to a high of 0.497 µg g ‐1 (near the Clyde platform), with an 

average of 0.089 µg g ‐1 . The total PAH concentrations were comparable to previous data from the 

region (Gardline Environmental 2007, 2009). 

PAHs were detected with predominantly higher molecular weight species, these are likely to have 

originated from pyrogenic inputs (associated with combustion of hydrocarbons), the only exception 

was a sample from section 1 (near Flyndre and Cawdor drill location) which appeared to have mixed 

inputs of petrogenic and pyrogenic PAHs. 

Results of the metals analyses (with the exception of Arsenic and Copper) appear generally 

comparable to or lower than previous data from the region, with all concentrations within 

background levels (OSPAR, 2005). The majority of metals were recorded in higher concentrations at 

sections 2 and 3, which might be expected given the higher proportion of fines and hydrocarbons at 

those stations, and the proximity to the Janice FPU and Clyde platform. Barite is an essential 

constituent of drilling muds hence Ba occurs in high concentrations in sediments surrounding any 

drilling activity. Concentrations of Barium (extracted using hydrofluoric acid) ranged from 160 µg g ‐ 

1 to 426 µg g ‐1 , with a mean concentration of 235 µg g ‐1 (+/‐ 74 standard deviation); Barium 

concentrations determined using an alternative method (alkali fusion) ranged form 141 µg ‐1 to 

339 µg g ‐1 , with a mean concentration of 194 µg g ‐1 (+/‐ 60 standard deviation). To put the Barium 

concentrations into a wider context, UKOOA (2001) recorded mean total Ba concentrations 

(measured by sodium fusion) more than 5 km from the installations in the central North Sea, typically 

in the region of 178 µg g ‐1 , with 95% of stations having concentrations

Figure 3‐8 Clyde platform and indicative 

seabed cuttings pile (UKOOA, 2005) 



Figure 3‐9 Elevation of cuttings piles at the 

Clyde Platform (UKOOA, 2005). 

The majority of the area with elevated THC levels of 50 mg/kg are within 1,000 m of the platform. 

Maximum THC levels are 150,000 mg/kg, although these are only found in the cutting pile 

immediately below the platform. The prevailing currents in the area (flowing west to east) have 

contributed to the higher THC concentrations in the sediments to the east of the Clyde platform. The 

main cuttings pile with very high levels of THC has a diameter of 100 m. 

Figure 3‐10 Total Hydrocarbon Contamination (ppm) in the sediment and cuttings piles at the Clyde 

platform (UKOOA, 2005). 

3 ‐ 22 D/4114/2011



3.4. BIOLOGICAL CONTAMINANTS 

Exposure of marine organisms to contaminants can occur either through uptake of dissolved fractions 

across the gills or skin or direct digestion of the pollutant. Organisms spending the majority of their 

life‐cycle in the water column are likely to receive highest exposure to contaminants that remain in 

solution though some will also accumulate sediment bound contaminants indirectly through their diet 

(i.e. digestion of animals that have accumulated the contaminants in their tissues). Organisms 

associated with the seabed (benthic organisms) are more exposed to particle bound contaminants 

with the main exposure route being either directly through ingestion of contaminated sediments or 

through their diet. Benthic organisms can also absorb contaminants through the surface membranes 

as a result of contact with interstitial water. 

Elevated levels of contaminants can affect organisms (flora and fauna) in a variety of ways (UK Marine 

SACs Project, 2001) ranging from cellular or organellular effects in individuals to ecosystem effects 

resulting from changes in population sizes or even the loss of an entire species. 

The incorporation of even minimal quantities of hydrocarbons in the tissue of a marine organism can 

affect its predators. At every link in the food chain, organisms consume around 10 kg of matter from 

the level below to produce 1 kg of their own living matter. If a contaminant passes from one level to 

another without being broken down, its concentration in the living matter multiplies nearly ten times 

at each link in the chain. Organisms at the top of the food chain can therefore be exposed to 

detrimentally high concentrations of a product which will not affect the organisms further down the 

chain. This is the phenomenon of bioaccumulation of chemicals through the food chain. Fortunately 

many of the components of oil and petroleum products are biodegradable at some level of the food 

chain. Of the hydrocarbons only the rarer, higher molecular weight PAHs tend to have a significant 

bioaccumulation potential. The primary risk from these PAHs is that some are carcinogenic with the 

impacts including acute toxicity, liver neoplasm and other abnormalities. 

PCBs are usually found in the sediment rather than the water column as they tend to absorb to 

particulate matter and have a relatively low water solubility. They have been identified as endocrine 

disruptors and have been shown to be toxic to aquatic organisms at a range of concentrations 

between 12 µg/l to 10 mg/l, however the main concern with PCBs is their potential to bioaccumulate. 

As with PAHs and PCBs the consequences associated with elevated heavy metal concentrations are to 

both aquatic organisms and humans as a result of consuming contaminated fish and shellfish 

(MPMMG, 1998). Depending on the metal and level of bioaccumulation the effects in animals can be 

as severe as anemia, renal failure and cancer. 

3.5. MARINE FLORA AND FAUNA 

Typical of a shallow region in a temperate climatic zone, the North Sea is a complex and productive 

ecosystem which supports important fish, seabird and marine mammal populations. Pelagic and 

benthic communities are interlinked in more or less tightly coupled food webs which together with 

the abiotic environment, make up marine ecosystems. The flora and fauna that interact to make up 

the North Sea ecosystem are discussed below. 

3.5.1. PLANKTON 

Plankton are drifting organisms that inhabit the pelagic zone of a body of water and include single 

celled organisms such as bacteria as well as plants (phytoplankton) and animals (zooplankton). 

Phytoplankton are the primary producers of organic matter in the marine environment and form the 

basis of marine ecosystem food chains. They are grazed on by zooplankton and larger species such as 

fish, birds and cetaceans. Therefore, the distribution of plankton directly influences the movement 

and distribution of other marine species. Plankton also includes the eggs, larvae and spores of non‐ 

D/4114/2011 3 ‐ 23



planktonic species (fish, benthic invertebrates and algae). This meroplankton population may have a 

very different seasonal cycle depending on the life cycle strategy of the fish species and benthic 

organisms which inhabit the area. 

The composition and abundance of plankton communities varies throughout the year and are 

influenced by several factors including depth, tidal mixing, temperature stratification, nutrient 

availability and the location of oceanographic fronts. Species distribution is directly influenced by 

temperature, salinity, water inflow and the presence of local benthic communities (Robinson, 1970). 

Produced water from oil and gas extraction may include dissolved hydrocarbons, organic acids and 

phenols which are used in biocides, corrosion and scale inhibitors and gas treatment. Plankton may be 

exposed to these contaminants through passive diffusion, active uptake or through eating 

contaminated prey. As plankton spend most of their lives in the water column, they will be 

particularly exposed to those contaminants that remain in solution (Sheahan et al., 2001). Produced 

water has been shown to affect recruitment in calanoid copepods (Hay et al., 1988). The toxicity of 

produced water will decrease as it disperses away from the source. Stomgren et al. (1995) found that 

acute toxicity in the diatom Skeletonema spp. was only likely in individuals in the immediate vicinity of 

the source of produced water, while at distances greater than 2 km the effects are negligible. 

Although plankton communities are vulnerable to continuous exposure to low levels of hydrocarbons 

and chemicals, work after the Sea Empress spill (72,000 tonnes of oil released) off the coast of 

southwest Wales found no significant effects on the plankton (Batten et al., 1998). This suggests that 

plankton communities are less vulnerable to one‐off incidents than they are to the continuous 

exposure associated with produced water release. 

3.5.2. BENTHOS 

Bacteria, plants and animals living on or within the seabed sediments are collectively referred to as 

benthos. Species living on top of the sea floor may be sessile (e.g. seaweeds) or freely moving (e.g. 

starfish) and collectively are referred to as epibenthic organisms. Animals living within the sediment 

are termed infaunal species (e.g. clams, tubeworms and burrowing crabs) while animals living on the 

surface are termed epifaunal (e.g. mussels, crabs, starfish and flounder). Semi‐infaunal animals, 

including sea pens and some bivalves, lie partially buried in the seabed. As shown in Table 3‐10 

benthic species may also be classified in terms of their size. 

Bacteria and benthic organisms play a major role in the decomposition of organic material that 

originates from primary production by phytoplankton in surface water and settles on the seabed 

(North Sea Task Force, 1993). For example bacteria degrade hydrocarbons through their utilisation as 

a food source (Clark, 1996). 

Benthic animals display a variety of feeding methods. Suspension and filter feeders capture particles 

which are suspended in the water column (e.g. sea pens) or transported by the current (e.g. mussels). 

Deposit feeders (e.g. sea cucumbers) ingest sediment and digest the organic material contained 

within it. Other benthic species can be herbivorous (e.g. sea urchins), carnivorous (e.g. crabs) or 

omnivorous (e.g. nematodes). 

Sessile infaunal species are particularly vulnerable to external influences that may alter the physical, 

chemical or biological community of the sediment as they are unable to avoid unfavourable 

conditions. Each species has its own response and degree of adaptability to changes in the physical 

and chemical environment. Consequently the species composition and relative abundance in a 

particular location provides a reflection of the immediate environment, both current and historic 

(Clark, 1996). Surveys of the North Sea show that the benthic fauna is characterised by water depth 

3 ‐ 24 D/4114/2011



and seabed type, with depth mainly influencing epifauna, whilst sediment characteristics are more 

important for the infauna (Basford et al., 1990). 

The recognition that aquatic contaminants may alter sediment benthos, together with the relative 

ease of obtaining quantitative samples from specific locations, has led to the widespread use of 

infaunal communities in monitoring the long‐term impact of disturbance to the marine environment. 

Size Categories 

Macrobenthos 

(>1 mm) 

Meiobenthos 

(50 µm to 1 mm) 

Microbenthos 

(



Polychaete dominance can be considered typical of North Sea sediments, and they are generally 

found to account for approximately 50% (Eleftheriou and Basford, 1989). This pattern of polychaete 

dominance was also recorded in previous surveys of the area (Gardline 2007; 2009). 

The results of the macrofaunal survey suggest this community within the proposed development area 

is highly diverse with 289 taxa being represented in the samples collected along the proposed pipeline 

route. The 289 taxa were made up of 124 Polychaeta, 69 Crustacea, 63 Mollusca, 15 Echinodermata 

and 18 others including sea pens and anemones (Gardline, 2011). The variation in the faunal 

community recorded over the pipeline route survey appeared to correlate with changes in sediment 

characteristics, most notably the proportions of finer sediments (



Month/Species J F M A M J J A S O N D Nursery 

Lemon sole 

Norway pout 

Sprat 

Mackerel 

Haddock 

Whiting 

Spawning Peak Spawning Nursery 

Table 3‐11 Summary of spawning and nursery activity for some commercial fish species found in 

area of the development (Coull et al., 1998). 

Spawning and nursery areas cannot be defined with absolute accuracy and are found to shift over 

time. The spawning and nursery grounds of some commercially important species within the North 

Sea are shown in Figures 3‐6, 3‐7 and 3‐8. Given that spawning and nursery grounds do shift over 

time it is worth noting that species such as cod and whiting have identified spawning grounds less 

than 90 km south of the proposed development area while nursery grounds for mackerel, cod and 

sandeels have been identified less than 60 km to the east. 

Figure 3‐11 Lemon sole and sprat spawning grounds. 

D/4114/2011 3 ‐ 27

SHARKS, RAYS AND SKATES 

Figure 3‐12 Mackerel and Norway pout spawning grounds. 


Figure 3‐13 Haddock, Norway pout and Whiting nursery grounds 


Due to their slow growth rates and hence delayed maturity and relatively low reproductive rates 

sharks, rays and skates (all members of the class Chondrichthyes) tend to be vulnerable to 

anthropogenic activities. Historically, Chondrichthyes species have been targeted by commercial 

fisheries (specifically common skate, long‐nose skate and angle shark) however overfishing has 

significantly depleted the numbers in the North Sea. More recently they tend to be taken as bycatch 

to such as extent that the stocks are still depleting in UK waters. Work is underway to develop 

National Plans of Action for the conservation and management of the Chondrichthyes. The species 

identified as being in need of immediate protection are the angle shark, common skate, longnose 

skate, Norwegian skate and white skate. It has been proposed to protect these species in UK waters 

in the same way as the basking shark is protected, under the Wildlife and Countryside Act (1981). 

3 ‐ 28 D/4114/2011



The distribution of the Chondrichthyes in the UKCS is not extensively documented. However available 

literature (Ellis et al., 2004) suggests that at least five species are present in the CNS; 

Squalus acanthias (spiny dogfish) 

Galeorhinus galeus (tope shark) 

Amblyraja radiate (commonly known as the thorny skate or starry ray) 

Leucoraja naevus (cuckoo ray) 

Scyliorhinus canicula (commonly known as the lesser spotted dogfish or the lesser spotted 

catfish) 

Total numbers recorded for each of these species is low (Ellis et al., 2004). 

3.5.4. SEA BIRDS 

Seabirds are generally not at risk from routine offshore production operations. However, they may be 

vulnerable to pollution from less regular offshore activities such as well testing and flaring when 

hydrocarbon dropout to the sea surface can occasionally occur, or from discharges such as oil spills. 

Birds are vulnerable to oily surface pollution, which could cause direct toxicity through ingestion and 

hypothermia as a result of the birds’ inability to waterproof their feathers. Birds are most vulnerable 

in the moulting season when they become flightless and spend a large amount of time on the water 

surface. This significantly increases their vulnerability to oil spills. Fulmars, guillemots and puffins are 

particularly vulnerable to surface pollutants as they spend the majority of their time on the surface of 

the water. Herring gulls, kittiwakes and great black‐backed gulls are less vulnerable as they spend a 

larger proportion of their time flying and therefore less time on the sea surface (Stone et al., 1995). 

After the breeding season ends in June, large numbers of moulting auks (guillemots, razorbills and 

puffins) disperse widely away from their coastal colonies and into offshore waters. At this time these 

high numbers of birds are particularly vulnerable to oil pollution. 

The Joint Nature Conservation Committee (JNCC) has produced an Oil Vulnerability Index (OVI) for 

seabirds encountered within each offshore licence block within the Southern, Central and Northern 

North Sea and the Irish Sea. For each block, an index of vulnerability for all species is given which 

considers the following four factors; 

the amount of time spent on the water 

total biogeographical population 

reliance on the marine environment 

potential rate of population recovery. 

Each of these factors is weighted according to its biological importance and the OVI is then derived 

(Williams et al., 1994). The OVI of seabirds within each offshore licence block changes throughout the 

year Table 3‐12. This is due to seasonal fluctuations in the species and number of birds present in an 

area. 

D/4114/2011 3 ‐ 29



Licence block J F M A M J J A S O N D All 

30/6, 30/7, 30/8 2 4 4 4 4 4 4 4 3 3 3 3 4 

30/12 2 4 4 4 4 4 4 4 4 3 4 3 4 

30/13 2 4 4 4 4 4 4 4 4 3 4 3 4 

30/14 3 4 4 4 4 4 4 4 3 4 3 4 

30/17, 30/18 2 4 4 4 4 4 4 4 4 3 3 3 4 

30/19 3 4 4 4 4 4 4 4 4 3 4 3 4 

Key 1= very high 2= high 3= moderate 4= low Blank = no data 

Table 3‐12 Monthly vulnerability of seabirds in the area of the development (JNCC, 1999). 

Table 3‐12 suggests seabird vulnerability to oil pollution in the development blocks and the 

surrounding area is low for much of the year and is highest during the winter months from October to 

January. Generally, seabird vulnerability decreases in the offshore water following the winter period 

when large numbers of seabirds leave the offshore waters returning to their coastal colonies for the 

breeding season. Species commonly found at relatively low numbers in and around this area include 

fulmars, gannets, razorbills, kittiwakes, and gulls including the greater and lesser black‐backed gulls 

and herring gulls (DTI, 2001; Batty, 2008). Other species which are recorded at lower levels include 

pomarine skuas, Arctic skuas, black‐headed gulls, common gulls, common terns, Arctic terns, little 

auks and puffins. 

3.5.5. MARINE MAMMALS 

Marine mammals include mustelids (otters), pinnipeds (seals) and cetaceans (whales, dolphins and 

porpoises), all of which are vulnerable to the direct effects of oil and gas activities such as noise, 

contaminants and oil spills. They are also affected indirectly by any processes that may affect prey 

availability. 

MUSTELIDS 

Only freshwater otters are to be found in European waters and hence routine offshore gas and 

petroleum activities do not directly affect these mammals. However in cases of extreme oil spills, 

such that the oil is washed ashore the effects could be detrimental to some local populations which 

are found to occur in estuarine waters. One such effect is hypothermia resulting from the otters fur 

being covered in oil and no longer being able to function as a thermal layer. The development is a 

considerable distance offshore and as such no otters will be found. 

PINNIPEDS 

Seals tend to frequent inshore waters but have been seen from a number of platforms in the North 

Sea (Cosgrove, 1996). Both grey seals (Halichoerus grypus) and common seals (Phoca vitulina) have 

breeding colonies along the coastline of the UK. Information on the distribution of seals is based 

almost entirely on observations at terrestrial haul out sites and although direct observations can be 

made at sea, sightings are rare and most observations continue to be made at inshore areas. 

Tagging studies on the behaviour and movement of seals at sea have been undertaken. Basic tags 

such as flipper tags have revealed that grey seal pups may travel far from their natal sites within their 

first few months at sea, being found as far afield as Norway (McConnell et al., 1984). Transmitters 

such as VHF (Thompson and Miller 1990; Thompson et al., 1989) and in particular satellite relay tags 

(McConnell et al., 1992 and 1999) have revealed that seal movements are on two geographical scales. 

3 ‐ 30 D/4114/2011



Common seals were shown to predominantly spend their time at or near haul out sites, with short 

trips to localised offshore areas. They were found occasionally to travel up to 45 km on feeding trips 

of up to 6 days, although the duration of most trips was less than 12 hours (Thompson et al., 1990). 

Grey seals on average spend the majority of their time within a similar range, with trip duration of less 

than 3 days, although they occasionally make long‐distance trips of over 100 km (McConnell et al., 

1999). Trips by pups have been reported over large areas, for example from the Isle of May up the 

Norwegian coast and down to the Netherlands (JNCC, 2007). However, the general pattern of close 

proximity to haul out sites suggests that these distant trips are uncommon and are possibly made by 

few individuals (Hammond, 2000). Since the area of the development lies approximately 270 km east 

of the UK coastline neither grey seals nor common seals are likely to occur in the area. 

CETACEANS 

Many of the activities associated with the oil and gas offshore industry have the potential to impact 

on cetaceans. The factors which could cause disturbance include noise or obstruction; however the 

impact will depend on the scale and type of activity. Activities with the potential to cause disturbance 

include; drilling, seismic surveys, vessel movements, construction work and decommissioning (JNCC, 

2010 draft). 

As marine mammals feed on fish and/or plankton, contamination of the water column affecting this 

food source could have a negative impact on cetaceans, either directly as a result of lack of prey or 

indirectly as a result of bioaccumulation of contaminants. However, as cetaceans tend to have large 

feeding grounds, the localised contamination associated with the normal activity of gas and 

petroleum installations is unlikely to have a major impact on individuals. 

As with most species, an optimal survey design for monitoring population sizes of cetaceans would 

involve surveying the species across its entire distribution at any one time. The impracticality of such 

a task combined with difficulties of species identification have made it difficult to confidently assess 

cetacean population sizes. The JNCC has complied an Atlas of Cetacean distribution in north‐west 

European waters (Reid et al., 2003) which gives an indication of the types of cetaceans and times of 

the year that they are likely to frequent areas of the North Sea. The Atlas is based on a variety of data 

sources including; 

at sea surveys carried out by the JNCC 

the UK Mammal Society Cetacean Group 

dedicated survey data collected in June and July 1994 by the Sea Mammal Research Unit at 

St Andrews University (SCANS ‐ Small Cetacean Abundance in the North Sea). 

Sightings of several species of cetacean have been recorded on the European continental shelf. 

However in many instances within the North Sea recorded sightings are associated with single 

individuals (Reid et al., 2003). Cetacean species sighted just once or in very low numbers in the North 

Sea include both whales (sei, fin, and pygmy sperm, humpbacked and beaked whales (northern 

bottlenose whale)) and dolphins (e.g. short beaked common dolphin, striped dolphin and Rissos 

dolphins). Killer whales and long finned pilot whales have been sighted in relatively higher numbers 

in the NNS while large numbers of bottlenose dolphins are to be found along the coastal regions of 

the UK (Reid et al., 2003). 

The CNS area is home to relatively large numbers of minke whales, white beaked dolphins, Atlantic 

white sided dolphins and harbour porpoises. A brief description of these four species is given in Table 

3‐13 while charts showing rate of sightings are given in Figure 3‐14. 

D/4114/2011 3 ‐ 31

White‐sided dolphin 

Lagenorhynchus acutus 

White‐beaked dolphin 

Lagenorhynchus 

albirostris 

Minke whale 

Balaenoptera 

acutorostrata 

Harbour porpoise 

Phocoena phocoena 



These dolphins show both seasonal and inter‐annual variability. Within 

the CNS they have been sighted in large pods of 10‐100 individuals. They 

can be sighted in the deep waters around the north of Scotland 

throughout the year and enter shallower continental waters of the North 

Sea in search of food. 

This species is usually found in water depths of 50 m to 100 m in pods of 

around 10 individuals, although larger pods of up to 500 animals have 

been sited. They are present in UK waters throughout the year, however 

more sightings have been made between June and October. 

Minke whales usually occur in water depths of 200 m or less and occur 

throughout the Northern and Central North Sea. They are usually sighted 

in pairs or in solitude; however feeding groups of up to 15 individuals have 

been recorded. Minke whales make seasonal migrations to the same 

feeding grounds. 

Harbour porpoises are frequently found throughout the UK waters. They 

usually occur in groups of one to three individuals in shallow waters, 

although they have been sighted in larger groups and in deep water. It is 

not thought that the species migrate. 

Table 3‐13 Overview of cetaceans found in high numbers in the offshore CNS area (Sources; Reid et 

al., 2003 and JNCC, 2008). 

3 ‐ 32 D/4114/2011



Figure 3‐14 Distribution of some cetaceans found in the North Sea and around the British Isles 

(Reid et al., 2003). 

In the SCANS II survey for the estimation of densities 

and abundances of cetaceans the wider North Sea area 

was divided several areas as shown in Figure 3‐15 

(JNCC, 2008). The Clyde platform is located in Area V. 

Based on shipboard surveys estimated densities 

(animals per km 2 ) of minke whales and harbour 

porpoises within this area are 0.028 and 0.294, 

respectively. Estimating densities of white beaked and 

white sided dolphins separately is more difficult due to 

their physical similarities and hence difficulty in telling 

them apart. 

Figure 3‐15 Chart showing how the North Sea was divided up during the SCANS II survey. 

3.6. SOCIO‐ECONOMIC ENVIRONMENT 

The need for socio‐economic assessment comes directly from EIA regulations which require that all 

new projects consider both positive and negative socio‐economic impacts in terms of benefits to the 

local communities and the country along with the potential interface with existing industries and 

communities. 

DECC’s remit to review Field Development Programmes ensures that licenses take into account 

implications for other offshore oil and gas developments in the area, and the interests of other users 

of the area. 

3.6.1. SOCIAL IMPACTS 

Socially the impacts of this development will be minor as it is a relatively small development super‐ 

imposed on a social system that is already changed due to the oil industry. The main social benefits 

will be short term and relate to continuation of jobs in the construction yards and offshore installation 

D/4114/2011 3 ‐ 33



vessels. The development will help maintain employment in local services and provide valuable 

monies into the economy. 

3.6.2. ECONOMIC IMPACTS 

The Flyndre and Cawdor fields will commence production in Q3 2013 and Q4 2014 respectively with 

production planned to continue to the end of July 2028 at both fields. During this time approximately 

41 and 23 million tonnes of oil and approximately 11 and 15 million Mm3 of gas will be produced 

from the Flyndre and Cawdor fields respectively. This will have a positive effect on both reducing UK 

imports of hydrocarbons and in providing revenue to the Exchequer. 

3.6.3. FISHING ACTIVITY 

One of the main areas of potential adverse impacts associated with the development of the offshore 

oil and gas industry is in relation to fishing activities. Offshore structures have the potential to 

interfere with fishing activities as their physical presence may obstruct access to fishing grounds. 

Knowledge of fishing activities and the location of the major fishing grounds is therefore an important 

consideration when evaluating any potential environmental impacts from offshore developments. 

In terms of marine ecosystems, ICES (International Council for Exploration of the Sea) is the primary 

source of scientific advice to the governments and international regulatory bodies that manage the 

North Atlantic Ocean and adjacent seas. For management purposes ICES collates fisheries 

information for individual rectangles measuring 30 nm by 30 nm. Each ICES rectangle covers one half 

of one Quadrant i.e. 15 license blocks. The importance of an area to the fishing industry is assessed 

by measuring the fishing effort which may be defined as; the number of days (time) X fleet capacity 

(tonnage and engine power). Due to the requirement by UK fishermen to report catch information 

such as total landings (includes species type and tonnage of each), location of hauls and catch method 

(type of gear/duration of fishing), it is possible to get an idea of the value of an area (ICES rectangle) 

to the UK fishing industry. 

The proposed development spreads across two ICES rectangles (42F1 and 42F2). Within these areas 

the UK fishing effort (Table 3‐14) varies throughout the year but annually can be considered low in 

comparison to other ICES rectangles where fishing effort can be as high as 20,000 hours per year. 

Year 

Total fishing effort (days) in 

UK total Rectangle 42F1 Rectangle 42F2 

42F1 & 42F2 combined 

as a % of UK total 

2007 222,183 256 76 0.15 

2008 215,051 332 134 0.002 

2009 436,560 425 38 0.11 

Table 3‐14 Fishing effort by vessels in UK fishing fleet measuring over 10 m (Sea Fisheries 

Management Division, Marine Directorate, 2011). 

As can be seen from Figure 3‐11, landings from ICES rectangle 42F1 are primarily made up of demersal 

(e.g. cod, haddock, hake, monkfish etc.) and shellfish species (primarily nephrops with



Figure 3‐16 Landings into UK ports from ICES rectangles 42F1 and 42F2 (includes both UK and non 

UK vessels). 

3.6.4. SHIPPING 

Shipping traffic within the SEA2 area of the North Sea is relatively moderate, with an average of 

between 1 and 10 vessels per day on routes passing through these waters. The majority of shipping 

traffic comprises ships, supply vessels and tankers (Cordah, 2001). 

Merchant vessels account for over 61% of vessels within the CNS with 45% of these vessels falling 

within the weight class of 0‐1499 dwt. Supply vessel routes originate in Aberdeen or Peterhead. A 

number of tanker routes exist within the SEA 2 region, the majority of which are orientated along a 

north/south heading. All tankers within the area weigh in excess of 40,000 dwt (Cordah, 2001). Table 

3‐15 shows the shipping classifications for the CNS. 

Shipping Type No. Routes Total No. Vessels Weight Class (dwt metric t) 

Merchant vessels 14 14,169 0‐1,499 

Supply vessels 20 8,564 0‐1,499 

Tankers 7 400 >40,000 

Table 3‐15 Shipping classifications for the Central North Sea (Cordah, 2001). 

Within the area of the development shipping density is considered very low (DECC, 2010). A shipping 

collision risk assessment will be carried out prior to any of the Cawdor wells being drilled. 

3.6.5. OIL AND GAS 

The proposed development is within a well developed oil and gas area of the North Sea (Figure 3‐12). 

The closest surface infrastructure to the development is the Maersk operated Janice FSPO which is 

approximately 6.5 km south‐south‐west of the Clyde platform while the Talisman operated Fulmar 

AD platform is approximately 9.5 km north‐west form the Clyde platform. 

D/4114/2011 3 ‐ 35



Several pipelines cross the route from the Flyndre and Cawdor wells to the Clyde platform. The 24” 

Jude oil export pipeline (PL998) crosses the proposed pipeline route in an ENE/WSW direction. Two 

parallel pipelines; Janice FPU to Norpipe Southern Wye (PL1361) and the Janice FPU to Judy Platform 

(PL1632), orientated northeast‐southwest cut across the area beyond the Clyde platform (Gardline, 

2011). 

Figure 3‐17 Oil and gas infrastructure in the vicinity of the proposed development. 

3.6.6. RENEWABLE INSTALLATIONS 

There are no wind or wave energy harvesting installations and no proposals for such in the area of the 

proposed development. 

3.6.7. SUBMARINE CABLES AND PIPELINES 

Survey results showed that the Norsea Communication Cable crosses the proposed pipeline route. 

The cable awareness charts indicate that there are no other submarine cables in the vicinity of the 

proposed development (Kingfisher, 2011) (Figure 3‐18). 

3 ‐ 36 D/4114/2011



Figure 3‐18 Cables in the vicinity of the proposed development area (Kingfisher, 2011). 

3.6.8. SHIPWRECKS 

No shipwrecks were identified by any of the surveys carried out in the development area. 

3.6.9. MILITARY EXERCISE AREAS 

Correspondence with the UK Hydrographic Office confirmed that there are no military exercise areas 

within 10 miles of the development area. 

3.7. OVERVIEW 

The topography in the vicinity of the Flyndre and Cawdor fields is generally considered to undulate 

gently with gradients



The flora and fauna in the area of the development are very similar to those found over wide areas of 

the North Sea. 

In general the planktonic and benthic communities found in the North Sea are widely distributed and 

continuous. Combined with the generally rapid dilution of routine offshore discharges, significant 

effects of offshore developments on planktonic and benthic communities are considered to be 

unlikely, while evidence also suggests that larger one off spills do not significantly affect benthic 

communities. 

Similar to planktonic and benthic species, fish species in the North Sea tend to be widely distributed. 

Spawning and nursery areas cannot be defined with absolute accuracy and are found to shift over 

time however there is evidence of lemon sole, sprat, mackerel and Norway pout spawning in the area 

of the development while other species such as cod and whiting have spawning grounds nearby. 

Juvenile haddock, Norway pout and whiting use the area as a nursery ground while juvenile mackerel, 

cod and sandeels are found relatively close distances (≈ 60km) from the development area. 

The number of cetacean sightings in the area are relatively low with the predominate species 

observed being harbour porpoise, white‐sided dolphin and minke whale. Of which the harbour 

porpoise is protected under Annex II of the Habitats Directive. 

Seabird vulnerability to oil pollution in the development blocks and the surrounding area is low for 

much of the year and is highest during the winter months from October to January. 

The proposed development spreads across two ICES rectangles (42F1 and 42F2). Within these areas 

the UK fishing effort varies throughout the year but annually can be considered relatively low in 

comparison to other ICES rectangles 

The development is outwith any known areas of renewable energy of military activity. The proposed 

development is within an area of current oil and gas activity. The Flyndre and Cawdor development 

will help maintain employment in local services and provide valuable monies into the economy. 

3 ‐ 38 D/4114/2011


Section 4 Environmental Assessment 

4. ENVIRONMENTAL ASSESSMENT METHODOLOGY 

In order to determine the impact that a proposed project may have on the environment it is 

necessary to conduct an environmental impact assessment (EIA). This should be a structured 

methodology for the identification and quantification, where necessary, of emissions and discharges, 

for determining the significance of the impact on the environment from these and, finally, reporting 

the mitigation measures used to reduce the impacts. 

Implicit in the EIA is a clear and well documented assessment of the impacts from each phase of the 

proposed project. The options screening process, and hence the initial stages of the EIA, is discussed 

more fully in Section 2. 

Potential effects are assessed both in terms of their likelihood, (how often they occur) and their 

potential significance (their magnitude) as described below. 

4.1. LIKELIHOOD 

The likelihood of occurrence of each potential effect was given a score between 1 and 5 (Table 4‐2). A 

low score means that the likelihood of an aspect leading to an impact is low. 

Activity Duration Likelihood of Event 

One year to many 

years 

One month to a year 

One week to a month 

One day to a week 

Less than a day 

Table 4‐1 Likelihood of Realisation of an Impact. 

4.2. CONSEQUENCE 

Likelihood 

Category 

Likely: More than once a year 5 

Possible: Less than once per year and more than one 

every 10 years 

Unlikely: Less than once every 10 years and more 

than once per 100 years 

Remote: Less than once every 100 years and more 

than once per 1,000 years 

Extremely remote: Less than once every 1,000 years 

and more than once every 10,000 years 

The magnitude of each potential environmental effect was also rated on a scale of one to five, five 

being the most severe, as shown in (Table 4‐2). Where magnitude appeared to fall within 2 

categories, the higher category was selected to provide a worst case scenario for the purposes of 

assessment. 

D/4114/2011 4 ‐ 1 

4 

3 

2 

1

Level Definition 

Severe 

(5) 

Major 

(4) 

Moderate 

(3) 

Minor 

(2) 

Negligible 

(1) 


Section 4 Environmental Assessment 

Change in ecosystem leading to long term (greater than 10 years) damage with poor 

potential for recovery to an area 2 hectares of more, or to internationally or nationally 

protected populations, habitats or sites. 

Likely effect on human health. 

Long term, substantial loss of private users of public finance. 

Change in ecosystem leading to medium term (greater than 2 years) damage with recovery 

likely within between 2 and 10 years to an area 2 hectares or more, or to internationally or 

nationally protected species, habitats or sites. 

Change in ecosystem leading to short term damage with likelihood for recovery within 2 

years to an area 2 hectares or less, or to protected or locally important sites. 

Possible but unlikely effect on human health. 

May cause nuisance. 

Possible short term minor loss to private users or public finances. 

Change is within scope of existing variability but potentially detectable. 

Effects are unlikely to be noticed or measured. 

Table 4‐2 Definition of Magnitude of Environmental Effects 

4.3. COMBINING LIKELIHOOD AND CONSEQUENCES TO ESTABLISH RISK 

The overall environmental hazard of each environmental aspect was assessed using the combination 

of the magnitude and likelihood scores in Table 4‐3 below. 

Likelihood of occurrence 

Magnitude of Effect 

5 4 3 2 1 

5 High High Moderate Moderate Low 

4 High High Moderate Moderate Low 

3 High High Moderate Low Low 

2 High High Moderate Low Low 

1 High Moderate Low Low Low 

Table 4‐3 Environmental Risk Classification Matrix. 

This process was undertaken for all identified aspects with the results presented in Appendix B. For 

those aspects identified as of moderate risk, additional mitigation measures were considered to 

demonstrate that the risk was as low as reasonably practicable (ALARP). The aspects identified as 

moderate risk are discussed in Section 5. 

4 ‐ 2 D/4114/2011


Section 5 Assessment of Potential Impacts and Control Measures 

5. ASSESSMENT OF POTENTIAL IMPACTS AND CONTROLS 

This section presents the results from the identification and assessment of environmental impacts 

from the proposed development. In the first instance, the information summarised in Sections 2, and 

3 of the ES was used to identify potential environmental hazards. These hazards were assessed and 

screened against the criteria set out in Section 4. 

Hazards that: 

are subject to regulatory control 

were found to pose a moderate or high risk to the environment 

were recognised during the consultation phase as areas of public concern 

were assessed further to determine the significance of the impact and/or risk posed to the 

environment. 

Table 5‐1 summarises the issues identified during the screening process as requiring further 

assessment. The remainder of this section discusses the results from the additional assessment while 

Appendix B lists all potential impacts identified and assessed. 

Phase/Issue Aspect/Source 

Drilling Emissions 

‐ rig and support vessels 

‐ well clean‐up and well test 

Discharges to sea of; flare drop out, drilling fluids and drill 

cuttings 

Physical disturbance from drill rig anchors 

Noise associated with drilling rig, supply vessels and drilling 

operations 

Physical presence of vessels and associated anchors 

Subsea Installation Exhaust emissions from pipe lay and support vessels 

Physical presence and disturbance 

‐ vessel anchors 

‐ subsea infrastructure and protection 

Discharges to sea 

‐ drill cutting piles at Clyde platform 

Noise associated with 

‐ vessels 

‐ piling 

Production Atmospheric emissions from 

‐ power generation*(no additional emissions anticipated, 

yet overall concern for greenhouse gases associated with 

power generation) 

‐ flaring 

Discharge of produced water 

Wider development concerns Accidental events 

Protected areas and species 

Cumulative impacts (atmospheric emissions, produced water, 

underwater sound) 

Transboundary impacts 

Table 5‐1 Issues identified as requiring further assessment. 

D/4114/2011 5 ‐ 1

5‐ 2 



This section covers the assessment of all impacts apart from those associated with accidental releases 

of hydrocarbons. Following DECCs latest guidance on oil pollution emergency preparedness issued on 

23 rd December 2010 a separate section encompassing hydrocarbon spills, their impacts and Maersk 

Oil’s response has been provided in Section 6. The hydrocarbon spill scenario covers both an 

uncontrolled release of hydrocarbons (well blow out) and also the loss of the diesel fuel inventory of 

the drilling rig. 

5.1. DRILLING PHASE 

Section 5.1 deals with the environmental impacts associated with the drilling phase of the Flyndre and 

Cawdor development and the proposed mitigation measures against them. 

5.1.1. EMISSIONS 

Gaseous emissions contribute to global atmospheric concentrations of greenhouse gases, regional 

acid loads and in some circumstances low‐level ozone and photochemical smog formation. The main 

greenhouse gases are carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O) and halogenated 

fluorocarbons (the latter are now strictly controlled under the Montreal Protocol). 

EXHAUST EMISSIONS FROM RIG AND SUPPORT VESSELS 

Section 2 discusses the predicted duration of the drilling phase and the likely support vessels required 

for the development. The predicted atmospheric emissions that will result from this are given in 

Table 5‐2. The emissions have been calculated using emission factors from the EEMS Atmospheric 

Calculations Issue 1.801a (Austin, 2008) and have been presented as a percentage of total emissions 

in 2009 from drilling activity in the UKCS. 

Fuel 

use (te) 

Emissions (te) 

CO2 NOx N2O SO2 CO CH4 VOC 

Drill Rig 2,220 1 7,104 132 0.49 8.88 35 0.40 4.44 

2009 total rig emissions 261,928 4,875 18 245 1,288 35 144 

Rig emissions during drilling of 

Cawdor wells as a % of 2009 total 

rig emissions 

1 Total fuel use assuming three Cawdor wells 

2.7 2.7 2.7 3.6 2.7 1.1 3.1 

Table 5‐2 Summary of emissions associated with drilling of the three Cawdor wells. 

The atmospheric emissions from vessels associated with drilling activities are given in Table 5‐3. 

These emissions have been combined with the atmospheric emissions from installation vessels to 

allow calculation of cumulative emissions when compared to UK total shipping emissions (Table 5‐5).



Vessel type 

Fuel Use 

(te) 1 



Anchor handling vessel 3,820 12,224 227 0.84 15.28 60 0.69 7.64 

Supply vessel 2,970 2 9504 176 0.65 11.9 46.6 0.53 5.94 

Standby vessel 162 518 9.6 0.04 0.65 2.5 0.03 0.32 

Total 6,950 22,246 412.6 1.53 27.83 109.1 1.25 13.9 

1 

Total fuel use assuming three Cawdor wells. 

2 

This is assuming the supply vessel is at worst only serving one rig each trip. This tends to be unlikely 

and therefore represents the worst case. 

Note; Atmospheric emissions have been calculated using emissions factors from EEMS Atmospheric 

Calculations Issue 1.810a (Austin, 2008) 

Table 5‐3 Summary of emissions associated with the drilling support vessels. 

Proposed Control Measures 

The drilling rig will be subject to audits ensuring compliance with UK legislation. 

The impact from emissions will be mitigated by optimising support vessel efficiency. 

Low sulphur fuels will be used in accordance with prevailing EU and MARPOL requirements. 

EMISSIONS TO AIR FROM WELL CLEANUP AND WELL TEST 

A screening assessment of the significance of the environmental risk associated with emissions to air 

from well clean‐up and well test operations was undertaken. The assessment indicated the risk to be 

low due to the low volumes of oil and gas flared and the short duration of activities. However, such 

activities may contribute to the greenhouse effect, acid rain and local air pollution. 

Well clean‐up is necessary to ensure the well no longer contains any drilling and completion related 

debris (mud, brine, cuttings) which could potentially damage the topsides when completion and 

production begins. A well test flow period may be required to obtain reservoir properties, flow rate 

information and fluid samples dependent on the information obtained during the drilling of the 

reservoir section. Emissions of CO2, CH4 and VOCs are higher during clean up and well test operations 

than similar emissions from rig and vessel activities associated with drilling and completions. 

A maximum of 2,151 tonnes of hydrocarbons (1,450 tonnes of liquids and 701 tonnes of gas) will be 

flared over no greater than a 24 hr period as part of the clean up and well test operations associated 

with each well. Assuming that a maximum of 3 production wells are drilled at Cawdor this will result 

in the flaring of 3,384 te of liquid and 1,805 te of gas. 

Atmospheric emissions resulting from the well test and clean up have been calculated using emissions 

factors from the EEMS Atmospheric Calculations Issue 1.10 (Austin, 2008) and are presented in Table 

5‐4. From Table 5‐4 it is evident that the emissions from the Cawdor wells clean up and well testing 

activities will account for a very small portion (e.g. for CO2 = 0.4%) of the total emissions produced as 

a result of well testing in UKCS waters. 

D/4114/2011 5 ‐ 3

5‐ 4 

Hydrocarbons 

flared (te) 




CO 2 NO x N 2O SO 2 CO CH 4 VOC 

Liquids 3,384* 10,829 12.51 0.273 0.044 30.9 84.6 84.6 

Gas 1,805* 5,054 2.16 0.146 0.023 12.1 81.22 9.02 

Total 15,883 14.67 0.419 0.067 73 165.82 93.62 

2009 total hydrocarbon 

well testing emissions 

from UKCS offshore 

activities, 

3,931,850 3,022 113 219 10,300 15,706 11,394 

Emissions from this 

development as a % of 

UKCS well testing 

emissions 

*Includes the three Cawdor wells 

0.4 0.48 0.37 0.03 0.71 1.06 0.82 

Note; Atmospheric emissions have been calculated using emissions factors from EEMS Atmospheric 

Calculations Issue 1.810a (Austin, 2008). 

Table 5‐4 Summary of emissions from the well clean up and well testing. 

The emissions from the well clean up and well test will be released approximately 290 km from 

nearest coastline (UK). The prevailing winds which are from the south and south west will carry the 

emissions away from the nearest coastline with very high dispersion and dilution of emissions 

occurring in the offshore environment (DTI, 2001). 


FLARE DROP OUT 

During any flaring and clean up operations there is the potential for flare drop‐out (unburned 

hydrocarbons) falling from the flare onto the sea surface, potentially causing an oily slick to form on 

the sea surface. This could impact on the environment, particularly seabirds that may be using the 

area during the well clean‐up operations. However seabird data obtained from the area suggests the 

density of seabirds is generally relatively low throughout the year thus minimising the potential 

impact of flare drop‐out. 

In order to minimise the risk of flare drop‐out occurring a green burner will be used on the drill rig 

which is designed to burn at a greater efficiency and consequently reduce the risk of flare drop‐out. 


Period of well testing will be kept to a minimum 

‘Green burners’ will be employed for well test operations, which will significantly reduce the 

levels of unburned hydrocarbons entering the environment. 

During flaring continuous observation of the sea surface will occur. The test will be 

suspended should a significant sheen be observed 

DISCHARGE OF DRILLING FLUIDS AND ASSOCIATED CUTTINGS 

The top hole sections (36” and 17 1 /2”) of the Cawdor wells will be drilled using seawater and high 

viscosity sweeps. The top hole sections of each well will produce 516 tonnes of cuttings which will be 

discharged to the seabed.



The 12 1 /4 and 8 1 /2” sections of the wells will be drilled with OBM. It is estimated that 1,085 m 3 of 

mud will be used and 259 m 3 of cuttings will be generated. The bottom hole sections of the three 

Cawdor wells are anticipated to use 3,255 m 3 of mud and generate 777 m 3 of cuttings. 

The OBM and cuttings will be Rotomill processed. Base oil will be recovered from the Rotomill 

and stored for reuse, while the recovered cuttings powder is mixed with recovered water and 

seawater and pumped to sea via an existing overboard chute. It is necessary to mix the cuttings 

powder with the recovered water to form a slurry which helps avoid formation of surface flocs of 

powder due to trapped air. The processed powder will be processed such that it contains

5‐ 6 



arise from the support vessels and anchor handling vessels. Anchored semi‐submersibles will 

generate considerably lower underwater source levels than dynamically positioned semi‐ 

submersibles. The anchor handling vessels will use dynamic positioning and be equipped with 

powerful engines and thrusters. Sound arising from vessels is assessed in Section 5.2.5. 

Noise associated with drilling from the semi‐submersible will propagate from any rotating machinery 

such as generators, pumps and the drilling unit and risers. Studies have shown that during drilling, 

underwater sound levels increase when compared to periods of non‐drilling, this has been related to 

the use of additional machinery and power demands (McCauley, 1998). 

The noise from drilling has been found to be predominantly low frequency, less than 1,000 Hz, with 

relatively low source levels



Vessel type 

Total fuel 

used (te) 

Emissions 


Survey vessel 440 1408 26.1 0.10 1.8 6.9 0.8 0.88 

DP reel‐lay vessel 575 1840 34.2 0.13 2.3 9.0 0.10 1.15 

Trenching support vessel 680 2176 40.4 0.15 2.7 10.7 0.12 1.36 

Diving support vessel 1350 4320 80.2 0.30 5.4 21.16 0.24 2.7 

Rock placement vessel 150 480 9.0 0.03 0.6 2.4 0.03 0.3 

Guard vessel 200 640 11.9 0.04 0.8 3.1 0.04 0.4 

Supply vessel 200 640 11.9 0.04 0.8 3.1 0.04 0.4 

Total from installation 3,595 11,504 213.7 0.79 14.4 56.36 1.37 7.19 

Total from drilling vessels 

(Table 5‐3) 6,950 22,246 412.6 1.53 27.83 109.1 1.25 13.9 

Total from all vessels 

10,545 33,750 626.3 2.32 42.23 165.46 2.62 21.09 

2008 UK domestic 

shipping emissions 1 

‐ 5,400,000 ‐ ‐ ‐ ‐ ‐ ‐ 

% of UK total ‐ 0.62 ‐ ‐ ‐ ‐ ‐ ‐ 

1 

Source; Department for Transport, 2010. 

Note: Atmospheric emissions have been calculated using emission factors from the EEMS Atmospheric 


Table 5‐5 Vessel emissions associated with installation infrastructure. 

From Table 5‐5 it can be seen that in the worst case scenario the vessel emissions associated with 

drilling of the three wells and installation of the infrastructure amounts to 0.62% of CO2 generated by 

UK domestic shipping emissions in 2008. 

5.2.2. PHYSICAL PRESENCE 

VESSEL ANCHORS 

A Dynamically Positioned (DP) reel‐lay vessel will be used to lay the pipelines and hence no anchor 

damage to the seabed will be associated with this vessel. However other vessels associated with 

laying the infrastructure may hold their position with the use of anchors and a wire mooring spread. 

Anchors and anchor spreads can interact with other infrastructure in the marine environment for 

example pipelines and cables. However, the risk of interaction between anchor spreads and subsea 

infrastructure occurring can be minimised by careful laying of the anchor spread to avoid existing 

infrastructure. 

As each anchor is laid the depth of anchor penetration will be dependent on the shear strength and 

load bearing capacity of the seabed soils; a firm seabed will result in less depth of penetration than a 

soft seabed. 

A small area of the seabed where each anchor is placed will be compressed as the anchors sink into 

the soft seabed, and further disturbance and re‐suspension will occur again as the anchors are 

retrieved. Anchor placement can cause mortality or displacement of benthic species in the 

immediate area surrounding the disturbed sediment, and a direct loss of habitat and mortality of 

sessile seabed organisms that cannot move away from the contact area. Additionally, when the 

anchors are removed there is the potential for scars/mounds to be left on the seabed. The seabed is 

soft, and damage caused from any anchors are expected to be visible for a number of years. Anchor 

scars are formed from the deployment and recovery of anchors in sedimentary areas, particularly 

where clay is present immediately beneath the seabed. Although the predominant seabed sediments 

D/4114/2011 5 ‐ 7

5‐ 8 



in the area of the development are fine to medium silty sand (see Section 3.3.2), it is still possible that 

anchor scars / mounds may form. 

Trawling over anchor mounds may result in sediment being retained in the trawl net with consequent 

damage to nets, equipment and catch. 

There were no habitats identified as being particularly sensitive to disturbance from anchors and 

chains, although physical evidence of disturbance is expected to last for several years. 


Pre‐deployment surveys will be undertaken and will be used to identify anchor locations. 

The anchors will be deployed in such a way as to minimise the risk of interaction with 

existing infrastructure. 

In consideration of the control measures above, the localised impact of anchor mounds and the ability 

of benthic communities to rapidly recolonise disturbed areas, the residual impact of anchor mounds 

from the pipelay vessel is considered to be negligible. 

WELLS, XMAS TREES, MANIFOLDS, SSIV AND TIE‐IN STRUCTURES 

The subsea infrastructure is likely to disturb the mobile benthic fauna and smother the mixed flora 

and fauna directly beneath. The structures could also cause a nuisance to fishing operations because 

of the potential snag risk. To mitigate against this the Xmas trees and the manifolds will be fishing 

friendly. 

Subsea infrastructure will be submitted for inclusion on the Admiralty Charts, so that it may be 

identified by fishing vessels. Subsea infrastructure will also be entered into the FishSafe database, an 

industry sponsored computer system linked to vessel navigation systems that improve the ability to 

detect, identify and avoid potential hazards. 

As a result of the proposed control measures listed below, the relatively low levels of fishing activity 

associated with the development area, the rapid reproductive cycles of the benthic organisms found 

in the area and the general widespread distribution of the animals found in the CNS, the impacts from 

the physical presence of the wellheads, Xmas trees, manifolds and tie‐in structures are thought to be 

low. 

PIPELINES AND UMBILICAL 

The total pipeline length and umbilical length is approximately 24.66 km; the Flyndre to Cawdor line is 

4.2 km while the Cawdor to Clyde is 20.46 km. The pipelines and umbilicals will be trenched and 

buried. Transition sections close to the drill locations and the Clyde platform and at pipeline crossings 

will be protected by rock and concrete mattresses. The total seabed area that is permanently 

disturbed will need to take account of the pipeline trench and the volume of rock, both of these are 

discussed below. 

The pipelines associated with the development will be trenched (1.8 m depth) and mechanically 

backfilled. Assuming a maximum trench width of 12 m total area to be affected by trenching can be 

estimated at 0.30 km 2 . 

Pipeline burial physically disturbs the benthic communities and their habitat within the area, and may 

cause some smothering of the communities in the wider area due to the excavated material. The 

project specific environmental survey undertaken along the pipeline route did not identify any 

particularly rare or sensitive species or habitats. Trenching can result in the creation of a temporary



plume of suspended solids resulting in short‐term smothering and difficulty for filter feeding 

organisms. 

Following the mechanical backfilling of the trenches, the benthic communities will return to normal 

over a relatively short duration as a result of their widespread distribution across the North Sea and 

their passive transport by the currents to the area of the development. 

ROCK PLACEMENT AND MATTRESSES 

All the pipelines will be trenched and mechanically back‐filled in order to protect the line from 

damage by third parties and provide stability. However additional rock placement will be required to 

provide further protection from upheaval buckling. For the purpose of this ES, the worst case 

scenario of 20,000 tonnes of rock plus an additional 3,000 tonnes at each pipeline crossing will be 

required. Three pipeline crossings have been identified. The final mass of rock required will be 

revised and minimised by undertaking upheaval buckling analysis and post trenching surveys. 

Mattresses will be used to provide protection at sections where the pipelines and umbilicals are not 

trenched e.g. connections with wellheads and manifolds. It is estimated that 250 mattresses 

measuring 6 m x 3 m will be required covering a total area of 4,500 m 2 . 

Table 5‐6 shows an estimate of the area of the seabed that will be impacted by the rock‐dumping and 

mattress laying. These have been calculated making the assumption that each tonne of rock dumped 

impacts on 1 m 2 of seabed. The rock‐dumping area is assumed to be within the trench corridor 

therefore no additional area will be impacted over and above that of pipelaying. However, the 

surface laying of rock will have a permanent effect on the habitat. 

Location 

Rock placement 

(tonnes) 

Area 

impacted (m 2 ) 

Mattresses 

(no.) 

Area 

impacted (m 2 ) 

Subsea pipelines including 

area surrounding pipeline 

crossings 

29,000 29,000 ‐ ‐ 

Untrenched areas of 

pipeline ‐ ‐ 250 4,500 

Total 29,000 29,000 250 4,500 

Table 5‐6 Area of seabed impacted by rock placement and mattresses. 

The areas of rock placement along the pipeline route will create a habitat for the types of benthic 

organisms that live on hard surfaces. Such organisms typically include tubeworms, barnacles, 

hydroids, tunicates and bryozoans, which are commonly found on submerged rocky outcrops, 

boulders and offshore structures. This material could also provide habitats for crevice‐dwelling fish 

(e.g. ling) and crustaceans (e.g. squat lobsters and crabs). However, the overall ecological change that 

would be brought about by the creation of a relatively small area of hard substratum, estimated to be 

less than 0.05 km 2 , within a large expanse of soft sediment habitat would be negligible. It is possible 

that, over time, the natural movement of sediments across the seabed would lead to the gradual 

burial of the hard substrate and infilling of the spaces between the crushed stones. 

In addition to the loss of habitat and the smothering of the benthos, the rock placement areas may 

also lead to temporary, or permanent, exclusion from presently used fishing areas or general nuisance 

to fishing operations because of the potential snag risk. 

Over time the mattresses will be colonised by marine organisms and potentially be buried or partially 

buried under the soft sediments. 

The following control measures are proposed to minimise the impact associated with rock‐dumping 

and mattresses. 

D/4114/2011 5 ‐ 9

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Minimise the mass of rock placement required by undertaking upheaval buckling analysis. 

The rock placement will be entered into FishSafe system so that it may be avoided by fishing 

vessels. 

As a result of the above mitigation measures the impacts from the physical presence of rock 

placement or mattresses will not cause a significant environmental impact. 


DISTURBANCE OF OIL BASED MUD DRILL CUTTINGS AT CLYDE PLATFORM 

The installation of the riser and the umbilical and laying of the pipeline and associated protection 

infrastructure at Clyde platform has the potential to cause disturbance to drill cuttings. The drill 

cuttings and their associated hydrocarbon contamination levels are discussed in Section 3.3.3. 

Contaminants within the cuttings if disturbed has the potential to release elevated levels of 

hydrocarbons into the water column, which could cause toxic or sub‐lethal effects to fauna in the 

immediate vicinity. If left undisturbed cuttings piles leach very little of the entrained hydrocarbons 

and contaminants into the water column, but over time the contaiminant levels especially the THC 

are expected to decrease. 

The final engineering has yet to be completed regarding the design of the riser and location of the 

umbilical to the Clyde platform. The majority of the cutting pile is situated beneath the cuttings 

chute, and it may be feasible to design and install the riser to minimise any disturbance to the main 

cutting pile. The final location for the riser and umbilical entry has yet to be determined, therefore 

there remains uncertainty as to the potential for disturbance to the cutting piles at this stage in the 

project. Maersk Oil will endeavour to minimise potential disturbance to cuttings piles through the 

selection of appropriate routing corridors and installation methods. This aspect has been identified as 

one of the project uncertainties for the Flyndre Cawdor project requiring further assessment, if the 

project is approved, it is envisaged that an assessment will be made of the potential for cuttings pile 

disturbance in the PON15C permit for the pipelines. 


Attempt to route infrastructure away from main cutting pile 

Assessment of potential for disturbance to cutting piles made at PON15C stage 

PIPELINE HYDROTESTING 

After installation pipelines need to be pressure tested. The lines are to be filled with potable water, 

dosed with methanol, scale, corrosion and wax inhibitors. The displaced water, along with chemical 

additives will be discharged to the sea at the Clyde platform. The total volume of water discharged at 

the Clyde platform will be 700 m 3 . 

5.2.4. NOISE FROM INSTALLATION 

VESSELS NOISE 

Vessel operation during the drilling and subsea installation phases may be considered as a potential 

source of noise disturbance to the local marine environment (Richardson et al., 1995). Vessel traffic is 

the largest contributor to anthropogenic ocean noise.



The use of vessels, especially Dynamically Positioned (DP) vessels, will cause elevated noise levels and 

it is expected that peak vessel activity will occur during subsea installation. During the subsea 

installation phase a number of vessels will be present and may be manoeuvring at relatively high 

power. It is also possible that several of them will be using DP which generates a relatively high noise 

output, these include anchor handling tugs and supply vessels, reel lay vessels, survey vessels, 

trenching and trenching support vessels and DSVs. 

In terms of direct physical injuries to hearing structures in marine mammals and potentially fish, it 

appears from the available data that quite loud and/or sustained exposures are required to cause 

even temporary changes in hearing sensitivity. Consequently, the likelihood that a single exposure of 

shipping noise would be sufficient to permanently damage the hearing of marine animals appears to 

be remote. However, short term behavioural effects may be observed amongst cetaceans and 

pinnipeds, but the overall impact of these is thought to be negligible. 


Minimise number of vessels required 

Minimise length of time vessels are on site 

PILE DRIVING NOISE 

The support frame for the two manifolds will be secured by piles driven into the seabed and during 

environmental screening, the noise was assessed as posing a moderate risk to the environment as pile 

driving is considered to be the only activity that would have the potential to generate underwater 

sounds levels capable of causing injury to marine life. 

The manifolds will be secured to the seabed by up to four piles. The piles will have an outside 

diameter of 0.60 m and a penetration length of 15 m. An underwater hydraulic pile‐driver suspended 

from a support vessel will be used. The duration of the installation period is expected to be 2 – 2.5 

hours for each pile and a total of 8‐10 hours for each manifold (based on driving time required for 

piles at Affleck field where piles were 0.61 m in diameter with a penetration length of 16.5 m). 

In order to provide an objective and quantitative assessment of the likely degree of any 

environmental effect upon marine receptors it is necessary to estimate the sound level as a function 

of distance. Very few empirical data sets exist for pile driving measurements, the source 

characteristic and frequency spectrum that was used in this model was undertaken during piling of a 

1.5 m diameter pile at the FINO‐1 Platform installation. The pile driving generated a source level of 

228 dB (peak) re 1µPa @ 1m (ITAP, 2005). As can be seen from Figure 5‐1 the dominant piling 

frequencies are those less than 1000 Hz. It is expected that piling of the manifolds will generate a 

similar spectra of frequencies to that shown below, with the majority of the sound pressure being 

generated at frequencies below 2 kHz. 

D/4114/2011 5 ‐ 11

5‐ 12 

Sound Pressure Leve l (peak) dB re 1 

micro Pa@1m 

230 

220 

210 

200 

190 

180 

170 

160 



Frequency Hertz (Hz) 

Figure 5‐1 Frequency Spectrum (1/3 rd Octave band level) of piling pulses used within modelling for 

the Flyndre and Cawdor manifolds. 

Applying the above frequency spectrum into a noise modelling programme allows the calculation of 

the decrease in sound pressure level with range. The model parameters were set for the North Sea 

environment and applied the environmental conditions on a sandy seabed and a water depth of 

≈70 m that are applicable at the manifold locations. 

The model estimates that the peak sound pressure levels will be 228 dB (zero‐peak) re. 1µPa @1m 

and these will fall to 180 dB re 1µPa within the first 250 m. At further distance of 2.5 km from the 

piling, the sound pressure levels are expected to be 161 dB re 1µPa and out to a distance of 50 km it 

will have decreased further to 73 dB re 1µPa (Figure 5‐2). 

Figure 5‐2 Frequency output plot of piling noise out to a distance of 50 km. 

Figure 5‐3 illustrates the frequency spectrum generated from piling activities. At a distance of 20 km 

it can be seen that the higher frequency components have all attenuated to a higher degree than the 

lower frequencies



signal 40‐1000 Hz are expected to be above ambient noise levels out to a distance of approximately 

25 km, beyond this they will fall below ambient levels and are expected to be indistinguishable from 

background noise levels. 

Figure 5‐3 Frequency output profiles for piling sound at source (1 m) and 20 km, shown is the 

audiogram for the harbour porpoise (adapted from Kastelein, Hagedoorn, & Au, (2002)) 

Overlain on Figure 5‐3 is the audiogram of the harbour porpoise, which illustrates the species’ 

frequency specific hearing ability. The modelling predicts that as some components of the piling 

signal are above both the ambient noise level and the hearing threshold it is possible that the piling 

noise could be audible to high frequency hearing cetaceans such as the harbour porpoise out to a 

distance of 20 km, although the zone of audibility of the sound will be dependent upon the prevailing 

weather conditions at the time (e.g. waves and sea state influence ambient noise levels). No 

appropriate audiograms are available to use for any low (e.g. minke whales) or mid‐frequency 

cetaceans (e.g. bottlenose dolphins). 

For marine mammals, hearing impairment can occur when sound levels are high and, in the case of 

transient noise sources, such as pile driving, when marine mammals are exposed to repeated sounds. 

The hearing loss can occur in two forms: 

Temporary Threshold Shift (TTS): On exposure to noise the ear’s sensitivity level will 

decrease as a measure to protect against damage. This process is referred to as a temporary 

shift in the threshold of hearing, and generally returns to normal in 24 hours. 

Permanent Threshold Shift (PTS): A permanent change in the threshold of hearing caused by 

a sound level, or cumulative exposure of a sound level that is capable of causing irreversible 

damage to the ear. 

On the basis of observed cetacean physiological and behavioural responses to anthropogenic sound 

Southall, et al. (2007) proposed precautionary noise exposure criteria for injury and behavioural 

responses. These criteria are currently considered the best available and are based on quantitative 

sound level and exposure thresholds over which PTS‐onset could occur for different groups of species. 

By comparing the modelled sound pressure outputs against the Southall thresholds, the sound levels 

will not be considered capable of causing Permanent Threshold Shift (PTS) to cetaceans, the range at 

which Temporary Threshold Shift extends to is a maximum of 1 m from the pile driver (Table 5‐7). 

D/4114/2011 5 ‐ 13

5‐ 14 



Criteria Sound threshold level 

Range from pile 

driving (m) 

Injury to cetaceans ‐ Permanent 

Threshold Shift 230 dB re 1 µPa Is not exceeded 

Injury to Cetacean ‐ Temporary 

Threshold Shift 224 dB re 1 µPa 1 

Injury to Pinniped ‐ Permanent 

Threshold Shift 218 dB re 1 µPa 5 

Injury to Pinniped ‐ Temporary 

212 dB re 1 µPa 6 

Threshold Shift 

Table 5‐7 Impact criteria for cetaceans and pinnipeds and the estimated ranges at which the 

auditory effects occur from the pile driver (figures from Southall et al. 2007) 

The peak sound pressure levels are higher than those thought capable of inducing a physical auditory 

injury on pinnipeds (218 dB re 1 µPa@1m). Modelling suggests that sound levels capable of inducing a 

PTS will be restricted to the immediate vicinity of the pile driver and beyond a distance of 6 m away 

from the source the sound levels will be below levels capable of causing PTS or TTS. 

The diameter of the pile has been found to be the biggest influence on the sound pressure levels 

generated from piling. The larger the pile to be installed then the larger the sound pressure levels 

which will be generated (Nedwell et al., 2007). Studies undertaken for the windfarm industry which 

use considerably larger piles have raised concern of their sound impact to marine life. The piles to be 

used for the Flyndre and Cawdor manifolds are relatively small in diameter and are not expected to 

generate comparable high sound levels to those generated for installing wind turbines. Moreover, 

the duration of installation is relatively rapid with piling being completed within a maximum of 10 

hours per mainfold, with a maximum duration of 20 hours. 

The only marine mammals that are considered to be at risk from pile driving activities would be seals, 

however given the location of the Flyndre and Cawdor developments the presence of any seals 

species being in the area is remote. In practice, it would be very unlikely that any marine mammal 

species would be present in such close proximity to the pile driver (




The JNCC piling protocol will be followed including: 

Piling will commence using soft start; 

A trained marine mammal observer will be present during piling operations ; and 

Follow JNCC guidance, no pile driving will commence if a marine mammal has been recorded 

within 500 m of the exclusion zone during the previous 20 minutes. 

5.2.5. PROTECTED SPECIES – MARINE MAMMALS 

Marine European Protected Species (EPS) include cetaceans, marine turtles and the Atlantic sturgeon. 

However, it is unlikely that marine turtles or Atlantic sturgeon will be found in the development area 

in any numbers worthy of further consideration. The EPS provisions do not apply to seals species. 

Therefore, the assessment has only focussed on the cetaceans likely to be encountered. 

The Offshore Marine Regulations 2007 (as amended, 2010) have a revised definition of ‘disturbance’ 

to European Protected Species. The Offshore Marine Regulations extended the offence to areas of UK 

jurisdiction beyond 12 nm. It is now an offence under UK Regulations to deliberately disturb wild 

animals of a European Protected Species (EPS) in such a way as to be likely to: 

(a) deliberately capture, injure, or kill any wild animal of a European protected species; (termed 

‘the injury offence’) 

(b) deliberately disturb wild animals of any such species (termed ‘the disturbance offence’) 

New developments must assess if their activity, either alone or in combination with other activities, is 

likely to cause an offence involving a European Protected Species. Figure 5‐4 illustrates the suggested 

approach to a risk assessment for the offences of deliberate injury and deliberate disturbance. If 

there is a risk of causing injury or disturbance of EPS that cannot be removed or sufficiently reduced 

by using alternatives and/or mitigation measures, then the activity may still be able to go ahead 

under licence. In the case of oil and gas activities the EPS licence assessment will be carried out by 

DECC. 

Figure 5‐4 A suggested approach to risk assessment for offences of ‘deliberate injury’ and 

‘deliberate disturbance’ (adapted from JNCC, 2010). 

Offshore pilling has been recognised as an activity that could, in certain circumstances, cause both an 

injury offence and a disturbance offence (JNCC, 2010). The risk will be managed by the control 

measures indicated above. The risk of causing an injury and disturbance offence are assessed in 

Section 5.4.2. 

D/4114/2011 5 ‐ 15

5‐ 16 



5.3. PRODUCTION PHASE 

Section 5.3 deals with the environmental impacts associated with the production phase of the Flyndre 

and Cawdor development. It considers the environmental impact of atmospheric emissions, and 

produced water discharges and lists the proposed mitigation measures to limit their effect. 

5.3.1. ATMOSPHERIC EMISSIONS FROM PRODUCTION 

Emissions from the production phase can primarily be divided into emissions associated with power 

generation and those associated with flaring, these are each are dealt with here separately. 

EMISSIONS FROM POWER GENERATION 

The main source of atmospheric emissions from the production of the Flyndre and Cawdor 

development will be from power generation. As discussed in Section 2.8.5 the power requirements 

are primarily met by seven gas turbine generators. 

It is anticipated that the production from the Flyndre and Cawdor development will not result in a 

significant increase in power demand on the Clyde platform. The energy requirements will come 

from the existing generators and compressors (described in Section 2.8.5). The principle routine 

operational emissions would be from combustion products which include CO2, CO, NOx, SO2, CH4 and 

VOCs. 

In 2010 total diesel and gas use on the Clyde platform was 8,152 and 24,371 tonnes respectively. The 

emissions associated with this fuel use are presented in Table 5‐8. 

Emissions (te) 1 


Fuel Gas 69,701 1,404 5.4 0.3 185 482 78 

Diesel 26,086 484 1.8 32 128 1.5 16 

Total 95,787 1,888 7.2 32.3 313 483.5 94 

1 

Atmospheric emissions have been calculated using emissions factors from EEMS Atmospheric Calculations Issue 

1.810a (Austin, 2008). 

Table 5‐8 2010 combustion emissions produced by Clyde platform. 

To put these emission levels into context Table 5‐9 shows the 2010 Clyde platform emissions in terms 

of the UK total emissions in 2009. Emissions from the Clyde platform production constitutes a very 

small portion of the UK total emissions e.g CO2 emissions from the Clyde represent



Taking into account the distance of the development from the mainland (minimum of 290 km), the 

strong dispersive weather regime of the area and the relatively low levels of emissions associated 

with the development it is not expected that atmospheric emissions associated with the production 

of the Flyndre and Cawdor hydrocarbons will have detrimental impacts on the local environment. 

EMISSIONS FROM FLARING 

While processing the Flyndre and Cawdor hydrocarbons it is anticipated that 2,750 te of gas will be 

flared annually. Total gas flared on the Clyde platform in 2010 was 17,755 te. The flaring load 

associated with the Flyndre and Cawdor development represents an increase of 15.5% of that flared 

on the Clyde platform in 2010. The atmospheric emissions associated with these flaring loads are 


Emissions (te) 1 


2010 emissions associated with 

flaring on Clyde platform 

Annual emissions associated 

49,714 21.3 1.44 0.23 119 320 35 

with flaring during Flyndre and 

Cawdor production 

7,700 3.3 0.22 0.03 18 49 5.5 

Total 57,414 24.6 1.66 0.26 137 369 40.5 

1 

Atmospheric emissions have been calculated using emissions factors from EEMS Atmospheric 


Table 5‐10 Flaring emissions during production on the Clyde platform and specifically those 

associated with the Flyndre and Cawdor development. 

In order to manage flaring levels Maersk Oil optimise equipment reliability via continuous servicing, 

scheduled maintenance routines and equipment replacement / upgrade. 


To reduce emissions from flaring there is in place a minimum start up frequency policy, adherence to 

good operating practices, maintenance programmes and optimisation of quantities of gas flared. 

Emissions from combustion equipment are regulated through EU ETS and PPC Regulations. As part of 

the existing PPC permit the following measures are in place; 

The emissions from the combustion equipment are monitored 

Plant and equipment are subject to an inspection and energy maintenance strategy 

UK and EU air quality standards are not exceeded 

Fuel gas usage is monitored. 

Taking into account the above mitigation measure, the distance of the development from the 

mainland, the strong dispersive weather regime of the area and the relatively low levels of emissions 

associated with the development it is not expected that atmospheric emissions associated with the 

production of the Flyndre and Cawdor hydrocarbons will have detrimental impacts on the local 

environment. 

5.3.2. PRODUCED WATER DISCHARGES 

Produced Water (PW) may contain residues of reservoir hydrocarbons as well as chemicals added 

during the production process, along with dissolved organic and inorganic compounds that were 

present in the geological formation. The impact of PW on the environment is dependent on a number 

of physical, chemical and biological processes including the volume and density of the discharge, 

D/4114/2011 5 ‐ 17

5‐ 18 



dilution, volatisation of low molecular weight hydrocarbons and biodegradation of organic 

compounds (OSPAR, 2009). 

The discharge of PW to sea is one of the largest discharges associated with the development and with 

offshore oil and gas developments as a whole. During the screening phase of the EA, the discharge of 

PW and associated chemicals was assessed as of moderate risk to the environment. 

The production fluids from the Flyndre and Cawdor wells will undergo primary processing on the 

Clyde platform. The processing will separate the water from the production fluids prior to export. As 

described in Section 2, it is anticipated from the P10 production profiles that water production from 

the Flyndre Cawdor development will peak in 2026 with a rate of 1,110 Te/d (Table 5‐11). The PW 

will be treated via the existing PW treatment system on the Clyde platform prior to discharge to sea 

(see Section 2.9.3.). A new dedicated produced water treatment system for the Flyndre Cawdor field 

has been proposed although has yet to be designed. During the FEED stage a review of Best Available 

Technique and Best Environmental Practice will be conducted and the system designed. 

OSPAR (2009) reported that there has been no effect or accumulation of substances from the PW in 

wild fish. When PW is discharged there is expected to be an immediate 30‐100 fold dilution, with a 

subsequent dilution of at least 1,000 by 500 m from the discharge point. Any impact from the PW 

discharges is expected to be localised to near‐field and limited to short term impact due to the 

dilution experienced and the mobility of the water column organisms. 

Maersk Oil are aware of the draft OSPAR recommendation 2011 applicable to PW discharges. This 

recommendation advocates the adoption of a risk based approach for oil discharges to the marine 

environment (Section 1.4). The Flyndre and Cawdor development is anticipated to only result in a 

marginal increase (



Year 

PW from Clyde 

platform excluding 


development (te/d) 

PW from Flyndre & 

Cawdor development 

(te/d) 

PW from Flyndre & Cawdor 

development as a % of Clyde 

production (te/d) 

2013 10,771 74 0.69 

2014 10,856 54 0.50 

2015 10,802 41 0.38 

2016 10,636 41 0.38 

2017 10,565 74 0.70 

2018 10,337 107 1.03 

2019 10,331 156 1.51 

2020 10,340 214 2.07 

2021 10,254 282 2.75 

2022 10,157 463 4.56 

2023 10,054 858 8.53 

2024 9,946 980 9.85 

2025 9,835 1070 10.88 

2026 9,723 1,110 11.42 

Table 5‐11 Anticipated Flyndre and Cawdor produced water profiles (P10) as a percentage of 

anticipated production at the Clyde platform in the absence of the development. 

Te/d 

14000 

12000 

10000 

8000 

6000 

4000 

2000 

0 

Historic and anticipated produced water 

profiles (P10) for the Clyde platform 

Year 

Clyde production including 

Flyndre & Cawdor production 

Clyde production excluding 

Flyndre & Cawdor production 


Figure 5‐5 Historic and anticipated produced water profiles (P10) at the Clyde platform. 

D/4114/2011 5 ‐ 19

5‐ 20 



OIL DISCHARGED WITH PRODUCED WATER 

In order calculate the maximum weight of oil discharged with the PW a discharge quality in line with 

regulatory requirements of 30mg/l oil in water content was used 

Table 5‐12 shows the maximum dispersed oil associated with the PW from the Flyndre and Cawdor 

development. 

During 2009 2,900 tonnes of oil was discharged with PW from offshore installations on the UKCS. A 

maximum additional annual discharge of 10.95 tonnes (based on 2026 PW production profiles for the 

Flyndre and Cawdor development) constitutes a relatively small increase (0.38%) of the existing oil in 

water discharges to sea from installations on the UKCS. As such the impact associated with the 

increased discharges is not anticipated to be significant. 

Source 

Dispersed oil associated with maximum PW 

production (2026) from Flyndre and Cawdor 

development 

Annual produced oil 

discharged (te) 

Produced oil discharged 

(te/d) 

10.95 2 0.03 

2009 UKCS dispersed oil in PW discharged 2,900 1 7.9 

As a % of UKCS total 0.38 0.38 

1 

Source; DECC (2011). 

2 

based on 2026 maximum PW production profiles from Flyndre and Cawdor development and 

assuming maximum oil in water content of 30mg/l. 

Table 5‐12 Dispersed oil associated with maximum anticipated produced water production profiles 

for Flyndre and Cawdor development. 

CHEMICALS DISCHARGED WITH PRODUCED WATER 

Chemical use and discharge during production of well fluids are regulated under the Offshore 

Chemical Regulations 2002. Details (e.g. type/volume) of all proposed chemicals will be provided in a 

PON15D variation. As described in Section 2.10 the chemicals to be used during processing of the 

Flyndre and Cawdor hydrocarbons have yet to be decided on, however chemicals which are PLONOR 

or are of a lowest toxicity HQ will be prioritised . 


The discharges of produced water are regulated by OPPC regulations and reported through EEMS. As 

such Maersk Oil are committed to the following mitigation measures; 

reporting total volumes of produced water discharged 

monthly reporting of the oil in water content of produced water 

bi‐annual sampling for chemical analysis. 

Ensure the installation meets



5.4. WIDER DEVELOPMENT CONCERNS 

The wider development concerns were identified as: accidental spills, potential for causing offences 

to European Protected Species and impacts to Protected Areas. 

5.4.1. ACCIDENTAL SPILLS 

Uncontrolled hydrocarbon spills following an uncontrolled blowout at both the Flyndre and Cawdor 

wells are modelled and discussed in Section 6. This section also models the fate of the loss of the 

diesel inventory from the drilling rig, and discusses the tiered response strategy of Maersk Oil to 

combat and mitigate such spills. 

5.4.2. PROTECTED AREAS AND SPECIES 

The closest protected area is the Dogger Bank pSAC which is situated 120 km to the south of the 

development. No significant impacts on any forms of marine or coastal protected areas have been 

identified. 

There are two forms of offences that can be caused to European Protected Species (EPS), the ‘injury 

offence’ and the ‘disturbance offence’, the control of potential offences to EPS is controlled by the 

issuing of licences, in the case of oil and gas activities this is by DECC. The EPS licence assessment for 

the activities associated with the Flyndre and Cawdor development are discussed below. 

INJURY EPS ASSESSMENT 

The loudest sounds generated from the Flyndre and Cawdor development will be during the 

installation of the 0.6 m diameter piles. If the activity was to proceed without any form of mitigation 

measures in place, there could be a very small risk of exposing cetaceans in the immediate vicinity of 

piling operations to sound levels that could cause a Temporary Threshold Shift, although the cetacean 

would have to be in such close proximity, 1m from the pile driver, this is considered unrealistic. A TTS 

is not a hearing injury, but a temporary reduced hearing sensitivity that is recoverable with time. 

Sound modelling illustrated that the received noise levels decrease very rapidly with increasing 

distance from the source, it is only in the immediate piling area, within the first few metres, that there 

is any risk of causing a temporary threshold shift in cetaceans. The modelling suggests the zone of 

injury was not exceeded. Providing the mitigation measures for piling are in place there will be a 

negligible risk of causing injury, and no requirement to apply for an EPS licence for the injury offence. 

DISTURBANCE EPS ASSESSMENT 

The modelling predicts that noise levels from piling may not fall below background levels out to a 

distance of 25 km. The piling sounds are likely to be audible (dependent upon prevailing ambient 

sound levels) to marine mammals out to this extent. It is possible that upon receiving these sound 

signals marine mammals could exhibit behavioural reactions and move away from the wider area of 

piling operations, as has been demonstrated from research studies into piling undertaken by the wind 

farm industry (Carstensen et al., 2006; Tougaard et al. 2009). In order to ascertain how many marine 

mammals could potentially be exposed to the sound levels, abundance and density estimates were 

calculated for the area affected using the SCANS‐II survey information, (this is currently the best 

available abundance and density estimates for the species likely to be present in the development 

area). 

A conservative estimate of the number of marine mammals that could be exposed to levels of sound 

above ambient levels within an area of 25 km 2 (derived from π * radius 2 ) i.e. area around each 

manifold is shown in (Table 5‐13). 

D/4114/2011 5 ‐ 21

Species 

5‐ 22 



Density (individuals per km 2 ) and 

abundance estimates (Area ‘V’‐ Central 

North Sea)* 

Number of animals exposed to 

sound from piling (total area where 

sound is above background levels X 

density of animals) 

Harbour porpoise 

0.294 

(47,131 harbour porpoises in area ‘V’) 

577 

Minke whale 

0.028 

(4,449 minke whales in area ‘V’) 

54 

Bottlenose 

0.08 

Not likely to be exposed coastal 

dolphin 

(123 bottlenosed dolphins in area ‘V’) 

distribution 

Lag. species 

0.04 

(6,460 Lag. Species in Area ‘V’) 

78 

*See Figure 3‐10 for location of Area ‘V’. 

**Lagerorhynchus species are combined due to the difficulty in identifying similar species. 

It is worth noting that the numbers provided are approximations e.g. they assume animals will be 

distributed evenly throughout Area ‘V’. Therefore they should be considered a rough estimate of the 

number of animals potentially exposed (calculations not applicable for bottlenose dolphins – coastal 

distribution). 

Table 5‐13 Abundance and density of marine mammals in the development area and approximate 

numbers of individuals potentially exposed to piling sounds above the ambient noise level (Table 

adapted from SCANS‐II, 2008). 

A disturbance offence, as described by the Habitat Regulations, has been interpreted by JNCC as a 

type of reaction that can cause a sustained or chronic disruption of behaviour scoring 5 or more in the 

Southall et al. (2007) behavioural response severity scale. It is possible that relatively high numbers of 

animals, for example 5,777 harbour porpoises, could be exposed to piling sound levels above their 

hearing thresholds and be audible to them. Beyond the immediate zone of piling operations, the 

levels of noise received are not likely to cause sustained or chronic disruption to behaviour. Beyond 

the immediate piling area the received sound levels are more likely to induce minor behavioural 

responses, for example, it is possible animals could move away to areas of lower sound levels. As the 

duration of each piling event spans a relatively short time frame



There are not anticipated to be any significant impacts to other marine users as a result of the 

proposed Flyndre and Cawdor development. 

5.4.4. CUMULATIVE IMPACTS 

The cumulative impacts assessment has considered three environmental aspects, atmospheric 

emissions, underwater noise and produced discharges. 

The Flyndre and Cawdor development will contribute an increase of approximately 2.7% of drilling 

emissions when compared to 2009 total rig emissions (Table 5‐2); vessel emissions are expected to be 

0.61% of the UK total from shipping emissions when compared to 2008 values (Table 5‐5) and well 

test emission are 0.4% when compared to 2009 values from the UKCS (Table 5‐4). The generation of 

emissions will add to the greenhouse gases in the atmosphere and hence marginally contribute to the 

effects of global warming. The emissions are not significant when considered in context of emissions 

from the UKCS oil and gas and shipping activities, consequently no significant cumulative impacts are 

anticipated. 

The impacts of underwater sound have been receiving increased scientific attention, with potential 

cumulative impacts raised as a potential cause of concern for acoustically sensitive marine life 

(OSPAR, 2009). The construction sounds, principally vessel and drill rig movements will contribute to 

increasing the local sound levels. There are few practical measures that are possible to minimise the 

sound from vessels on a project basis and are more appropriately dealt with by international 

collaboration within the shipping industry and regulatory bodies. The loudest levels of sounds are 

expected to arise during the piling activity, the risk to marine life will be reduced by implementing the 

JNCC procedures within the piling protocol (Section 5.2.4). The underwater sound levels will be 

principally restricted to the drilling and construction phases of the development which is temporary 

and only affect a local area with elevated sound levels, consequently there are not anticipated to be 

any significant cumulative or residual impacts as a result of the underwater noise levels. 

The produced water from the Flyndre and Cawdor field increases as the reservoirs are depleted, the 

maximum volume of oil in water is 10.95 tonnes produced in 2026. When these discharges are 

compared to the oil in water discharges arising from the UKCS sector it represents an increase of 

0.38%. The result of the increases in oil in water as a result of the Flyndre and Cawdor development 

are not anticipated to result in any adverse cumulative impacts. 

5.4.5. TRANSBOUNDARY IMPACTS 

The impact assessment determined that there are not anticipated to be any significant transboundary 

impacts to countries as are result of planned activities and accidental events. 

The consideration of transboundary impacts is of relevance as the Flyndre field crosses over the 

UK/Norwegian median line, with the Cawdor field being situated approximately 5 km away from the 

line in the UK sector. 

The oil spill modelling indicated that in a blow out situation there is a probability of 1‐5% that a 

surface sheen of 4µm thickness could be present in the waters of nearby European countries 

including Norway, Denmark, Germany and Netherlands. There is not anticipated to be any risk of oil 

beaching on any neighbouring European countries. 

Should a spill be likely to enter into Norwegian waters it will be necessary to implement the NORBRIT 

agreement, which outlines procedures to be followed in joint Norwegian / UK spill counter pollution 

operations at sea. 

D/4114/2011 5 ‐ 23

5‐ 24 



Germany, Denmark, Holland and UK are all signatories to the Bonn agreement and as such have 

agreements in place to ensure intergovernmental co‐operation dealing with pollution and in 

particular aerial surveillance co‐ordination by sharing information which would be required in the 

event of a highly unlikely event such as a blow out. 

Therefore with the exception of a highly unlikely oil spill resulting from a blowout accidental event the 

Flyndre and Cawdor development is not anticipated to result in any significant transboundary 

impacts. 


Oil spill control measures to be followed as outlined in the OPEP for the Flyndre and Cawdor 

development 

Communication of international pollution agreements between European states including 

Bonn and UK / Norway NORBRIT agreement


Section 6 Hydrocarbon Releases 

6. HYDROCARBON RELEASES 

The Department of Energy and Climate Change (DECC) issued new advice on their requirements 

relating to oil pollution emergency preparedness on 23 rd December 2010. This section aims to satisfy 

these new requirements. Three hydrocarbon release scenarios are presented; total loss of fuel from 

the semi‐submersible drilling rig and a 90 day uncontrolled blowout from each of the Flyndre and 

Cawdor wells. 

In the event of an accidental discharge of hydrocarbons from the Flyndre and Cawdor development 

there is the potential to impact the waters of the North Sea. Oil fate modelling has been undertaken 

using the SINTEF Oil Spill Contingency And Response (OSCAR) model which has significant scientific 

research and validation, e.g. Reed et al. (1995, 1996) and Johansen et al. (2001). OSCAR calculates 

and records the distribution (as mass and concentrations) of contaminants on the water surface, on 

shorelines, in the water column, and in sediments. For subsurface releases (e.g. blowouts or pipeline 

leaks), the near field part of the simulation is conducted with a multi‐component integral plume 

model that is embedded in the OSCAR model. The near field model accounts for buoyancy effects of 

oil and gas, as well as effects of ambient stratification and cross flow on the dilution and rise time of 

the plume. 

The model databases supply values for water depth, sediment type, ecological habitat, and shoreline 

type. The system has an oil properties database that supplies physical, chemical and biological 

parameters required by the model. The version of OSCAR used is that contained within the Marine 

Environmental Modelling Workbench 6.0 (the latest version at time of writing). 

6.1. OIL SPILL REGULATIONS AND RISK ON THE UKCS 

6.1.1. REGULATORY CONTROL 

The key regulatory drivers that will assist in reducing the possible occurrence of oil or chemical spills 

are as follows: 

The Merchant Shipping (Oil Pollution Preparedness, Response and Co‐operation Convention) 

Regulations 1998; 

The International Convention on Oil Pollution, Preparedness, Response and Co‐operation (OPRC), 

which has been ratified by the UK, requires the UK Government to ensure that operator’s have a 

formally approved Oil Pollution Emergency Plan (OPEP) in place for each offshore operation, or 

agreed grouping of facilities; 

Offshore Installations (Emergency Pollution Control) Regulations 2002; These Regulations give 

the Government the power to intervene in the event of an incident involving an offshore 

installation where there is, or may be a risk of significant pollution, or where an operator has 

failed to implement proper control and preventative measures. These Regulations apply to 

chemical and oil spills; 

EC Directive 2004/35 on Environmental Liability with Regard to the Prevention and Remedying of 

Environmental Damage. The Environmental Liability Directive enforces strict liability for 

prevention and remediation of environmental damage to ‘biodiversity’, water and land from 

specified activities and remediation of environmental damage for all other activities through fault 

or negligence. 

6.1.2. UKCS OIL SPILL HISTORY 

Tina Consultants Ltd (2010) report that on the UKCS during the period 1975 ‐ 2007 a total of 17,012 

tonnes of oil (excluding regulated discharges from the produced water systems, but including spills of 

base oil and OBM) were discharged from 5,826 individual spill events. Figure 6‐1 shows volumes 

spilled and number of reported spills from 1991 to 2009 (DECC, 2009b). Analysis of spill data between 

1975‐2005 (UKOOA, 2006) shows that 46% of spill records relate to crude oil, with 18% relating to 

D/4114/2011 6‐1



diesel, and the other 36% relate to condensates, hydraulic oils, oily waters and other unknown types 

of oil. 

Spilled amount (tonnes) 

900 

800 

700 

600 

500 

400 

300 

200 

100 

0 

Figure 6‐1 Volume of spilled oil and number of spills in UKCS waters. 

6.2. POTENTIAL SOURCE OF HYDROCARBON SPILLS AT THE FLYNDRE AND CAWDOR 

DEVELOPMENT 

6.2.1. DIESEL SPILL FROM DRILLING RIG 

Historical data collected since 1975 indicate that mobile offshore drilling units (MODU) account for 

only 23% of all diesel spills. The majority of these spills are caused by hose failure and drain overflows 

and the releases are relatively small, predominantly less than 0.1 tonnes (Oil and Gas UK, 2009). Table 

6‐1 presents data submitted to DECC from the period 2001‐2007. 

Maintenance/operation 

activities 

Total amount spilled (tonnes) Total number of oil spill reports 

10‐100 

tonnes 



Period 

1990‐1999 2000‐2007 

Number Frequency Number Frequency 

160 0.246 78 0.172 

Table 6‐2 Number and frequency of spills from MODUs in UKCS waters (Oil and Gas UK, 2009). 

Apart from blowouts the worst case spill scenario from MODUs would results from incidents such as 

vessel grounding, collision or explosion leading to a total loss of fuel. The results from modelling such 

a scenario during the drilling of the Cawdor wells are presented in Section 6.3.1. 

6.2.2. UNCONTROLLED OIL SPILL FROM WELL BLOW‐OUT 

A well blowout refers to the uncontrolled release of hydrocarbons from a well after the pressure 

control systems have failed. 

Primary well control is achieved by maintaining a hydrostatic pressure in the wellbore greater than 

the pressure of the fluids in the formation being drilled, but less than the formation fracture pressure. 

If the pressure of the fluid in the wellbore is less than the formation pressure, the well will flow and 

an influx will enter the wellbore. If fluid pressure is greater than the formation fracture then the 

formation fractures and the wellbore fluid is lost into the formation (losses); in a worst case scenario 

there can be insufficient wellbore fluids left in the wellbore to resist formation pressure and an influx 

occurs. 

Flow of reservoir fluids into the well is stopped by closing the Blow Out Preventer (BOP) which is the 

initial stage of secondary well control. Secondary well control is completed by circulating the well to 

kill weight fluid and displacing the influx out of the well. If primary and secondary well control fails a 

blow out can occur. 

Based on revised guidance issued by DECC (DECC, 2010), drilling engineers considered six potential 

scenarios when determining the worst‐case scenario for a well blow‐out. These are: 

1. The first time the reservoir is penetrated is while drilling 12 1 /4” hole. If the well were to flow 

at this stage (for instance due to the fact that a large hydrocarbon influx has entered the 

well), it is possible hydrocarbons may reach the surface as the wellbore pressures in the 

12 1 /4” open hole will be significantly below what is required to keep the shales back. Hole 

collapse and plugging is expected to occur within a couple of days or weeks. 

2. Similarly, during the drilling of the 8‐ 1 /2” reservoir hole section it is possible hydrocarbons 

may reach the surface. Hole collapse and plugging would be expected within a couple of 

weeks if a blow‐out were to occur while drilling the reservoir. 

3. Once the sand screens have been installed, before the completion is run, there is a full steel‐ 

lined conduit in place from reservoir to surface, with an 8.5” internal diameter from the top 

of the sandscreens. If the well is live and the drilling rig would somehow lose station with 

the BOP not holding pressure and all hydraulic control lost, the well will have an unrestricted 

flow through the 9 5 /8” production casing with an internal diameter of 8½”. This will present 

a lower pressure loss conduit to the environment than when the well is completed. This 

scenario constitutes the worst case blow out event for the spill modelling. 

4. In the completion phase hydrocarbons are purposely introduced into the wellbore during the 

production clean‐up. Although this would appear to introduce more blow‐out risk than in 

any drilling scenario, there are no less than 4 barriers in place: The sub‐surface safety valve 

(SSSV), the subsurface test tree, lubricator valves above the subsurface test tree and the 

surface test tree. Moreover, the SSSV, the subsurface & surface test trees have valves which 

fail closed. If the well is live and the rig would somehow lose station with the BOP not 

holding pressure and all hydraulic control lost, the subsurface test tree and SSSV will close 

D/4114/2011 6‐3



automatically and shut in the well. This blow‐out scenario in the completion phase will result 

in a smaller oil spill than scenario 3 as the well is restricted by the internal diameter of the 5½ 

upper completion, 5½” tubing retrievable sub‐surface safety valve (TRSSSV) and 5” subsea 

tubing hanger landed in the horizontal production tree spool. In addition, most barriers in 

this section are fail closed making it a less likely worst‐case scenario. 

5. A scenario where more than a single well blowout occurs simultaneously. This would require 

the loss of integrity of two or more wells simultaneously which is extremely unlikely as there 

is only one drilling rig planned to be operating over either drill centre at any one time. 

6. A scenario where a well being drilled intersects with a completed producing well at a 

relatively shallow depth. This would require failure of directional drilling/surveying 

procedures/safeguards and result in either scenario 3 or 4 occurring. 

Oil spill modelling was conducted on scenario 3 which is considered the worst case scenario and 

extremely unlikely. As required by DECC, the modelling assumes no intervention: that is; it is 

assumed that there will be no response to mitigate the impacts by, for instance, the use of booms to 

contain the spill or dispersants to enhance degradation. In this sense, the modelling gives an unlikely 

outcome. 

When crude oil is spilled on the surface of the sea it is subjected to a number of processes including: 

spreading, evaporation, dissolution, emulsification, natural dispersion, photo‐oxidation, 

sedimentation and biodegradation. The fate and effect of crude oil is dependent on the chemical and 

physical properties of the oil which has been taken into account in the modelling. 

The International Association of Oil & Gas producers has issued datasheets (OGP, 2010) on blowout 

for offshore operations of North Sea Standard (NSS) where the operation is performed with BOP 

installed including shear ram and where the two barrier principle is followed. The dataset is derived 

from the International SINTEF blowout database where a blowout is defined as an incident where 

formation fluid flows out of the well or between formation layers after all the predefined technical 

well barriers or the activation of the same have failed. The blowout frequencies indicated that for gas 

reservoirs the likelihood of a blowout is higher in comparison to oil reservoirs (Table 6‐3). 

Operation Category Average Gas Oil Unit 

Exploration Deep 

normal wells 

Blowout 3.1 x 10 ‐3 

3.6 x 10 ‐3 

2.5 x 10 ‐3 Per well 

drilled 

Well release 2.5 x 10 ‐3 2.9 x 10 ‐3 2.0 x 10 ‐3 Per well 

drilled 

*Denotes the blowout proportion that would happen at the surface and the platform 

Fraction 

Subsea* 

Table 6‐3 Blowout and well release frequencies for offshore operations of North Sea Standard 

(OGP, 2010). 

6.3. HYDROCARBON SPILL MODELLING 

The extent of impacts of total diesel discharge from the drilling rig and blowouts during maximum 

flow rate from the Cawdor and Flyndre wells were modelled. For each scenario a stochastic analysis 

was carried out to determine the probability of a surface sheen >0.04 µm, the probability of a water 

concentration of > 50 ppb and the probability of oil reaching any coastline. 

The > 0.04 µm surface thickness threshold was chosen as this is the minimum surface thickness 

identified by the Bonn Agreement Oil Appearance Code (BAOAC) capable of producing a visible sheen 

(Table 6‐4). The BAOAC states that oil films below ≈ 0.04 µm thickness are considered invisible. 

6 ‐ 4 D/4114/2011 

0.39 

0.39



Code Description ‐ Appearance 

Layer thickness 

Interval (µm) 

Litres per km 2 

1 Sheen (silver/grey) 0.04‐0.30 40 ‐ 300 

2 Rainbow 0.3‐5.0 300 ‐ 5,000 

3 Metallic 5.0‐50 5,000 ‐ 50,000 

4 Discontinuous true oil colour 50‐200 50,000 ‐ 200,000 

5 Continuous true oil colour ≥200 ≥ 200,000 

Table 6‐4 Bonn Agreement Oil Appearance Code. 

The water column distribution has been curtailed at a concentration of 50 ppb. Below this threshold 

there is no expectation of significant acute toxic effects as this is the lowest acute concentration for 

any oil component that is deemed to present a 5 % risk to marine life using standard ‘no‐effect’ risk 

assessment methodologies. This is a very conservative approach since this treats all the oil as the 

most toxic component. 

The blowout model is run assuming it will take Maersk Oil no longer than 90 days to complete a relief 

well and get the spill under control. The model is also run for an additional 30 days in order to model 

the fate of the oil after the spill has been controlled. 

In addition to the varied wind data used in the above modelling the fate of the hydrocarbons in the 

presence of unvarying offshore and onshore 30 knot winds is presented, as per the DECC guidance. 

6.3.1. LOSS OF DIESEL FROM THE DRILLING RIG 

The NTvL drilling rig has a fuel capacity of 1,143 tonnes (i.e. 8,642 bbls) of diesel. Modelling of this 

volume of diesel discharged onto the sea surface over 1 hour and dispersing for 30 days has been 

undertaken to simulate a total loss of inventory from the NtvL. A stochastic analysis was undertaken 

by modelling 20 scenarios utilising a broad range of weather and current data. The model output 

indicates the calculated probability of a surface sheen > 0.04 µm thickness being present at a specific 

location at any point in time over the duration of the model run per well. 

Figure 6‐2 shows that in the unlikely event of total loss of diesel from the NTvL drilling rig the 

predicted surface oiling at a thickness of > 0.04 um would be visible within a radius of ≈ 70 km. A 

visible surface sheen is not predicted to reach any shore. 

D/4114/2011 6‐5



Figure 6‐2 Probability of a diesel surface sheen with a thickness >0.04µm occurring following a total 

loss of fuel from the NTvL. 

The fate of the diesel is shown in Figure 6‐3. By day six the amount of diesel on the sea surface is 

negligible with approximately 60% of the diesel having either evaporated or decayed. Components of 

the diesel are predicted to persist at very low and non toxic concentrations with < 1% of the 

discharged volume remaining in the water column by day 30. Around 15% of the diesel is predicted 

to be deposited in the seabed sediments over a very wide area (≈ 50,600 km 2 ) at densities that are 

not expected to cause a significant effect. Ultimately this diesel will biodegrade into harmless 

components, in a timescale of 1‐2 years. 

6 ‐ 6 D/4114/2011



ONSHORE AND OFFSHORE WINDS 

Mass balance 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

Figure 6‐3 Fate of diesel following release from NTvL. 

The impact assessment indicates that the probability of diesel being discharged from the drilling rig is 

small and that the loss of the total fuel inventory is a low probability event. Should there be a 

discharge, the area of impact will be within the vicinity of the drilling operations and it is predicted 

that no diesel would reach the shore. 

The fate of the diesel in the presence of unvarying 30 knot onshore and offshore winds is presented in 

Section 6.3.3. 

Maersk Oil require that the drilling contractor has in place management systems to reduce the risk of 

a spill occurring and to minimise any potential environmental impact should an accident occur. This is 

assured through robust auditing and monitoring. 

6.3.2. BLOWOUT 

Fate of diesel following total loss from the NTvL drilling rig 

0 1 2 3 5 6 7 8 9 10 11 12 14 15 16 17 18 19 20 21 23 24 25 26 27 28 29 

Time (days) 

Evaporated 

The uncontrolled flow rate from drilling activities at both the Flyndre and Cawdor well locations has 

been modelled. For each well a stochastic analysis was undertaken by modelling 58 scenarios utilising 

a broad range of weather and current data. For the Flyndre well a maximum unrestricted flow rate of 

5,872 te/day was used and for the Cawdor wells a maximum flow rate of 3,188 te/day was applied. 

The model was run for 120 days assuming that the spill would be controlled after 90 days and 

allowing 30 days to examine the fate of the residual oil. 

The oil types chosen from the OSCAR database were Frфy:Lillefrigg 75:25 (API = 40.4) as the closest 

analogue to the Flyndre and Cawdor oil types respectively. Gas oil ratios of 178 and 651 respectively 

were used for the Flyndre and Cawdor. 

A release diameter of 9 5 /8 ‘’ was assumed. The diameter of production tubing is 8 1 /2”, however at the 

surface this opens out to 9 5 /8‘’. The modelling parameters used are summarised in Table 6‐4. 

D/4114/2011 6‐7 

Surface 

Dispersed 

Sediment 

Decayed



The surface spill blowout was not modelled as it was not considered that an ongoing blowout at the 

surface was a realistic scenario to model for a semi‐submersible as there are a number of mechanisms 

by which the rig should either detach from the well location. 

Well Coordinates 



56 o 33’35.24’’N 

2 o 37’57.77’’E 

56 o 32’22.63’’N 

2 o 34’28.24’’E 

Volume 

(Te/d) 

Gas:Oil 

Ratio 

m 3 /m 3 

Table 6‐5 Main parameters used for modelling of oil spills. 

6 ‐ 8 D/4114/2011 

API 

Release diameter 

(inches) 

5,872 178 40 9 5 /8 

3,188 651 42 9 5 /8 

For each well the model was run to incorporate an area of ≈ 680,000 km 2 and included UK, Dutch, 

Danish and Norwegian coastlines. Less than 0.05% of the oil was found to have moved outside this 

area for either well. 

Figures 6‐4 and 6‐5 show that in the unlikely event of an uncontrolled blowout at the Flyndre and 

Cawdor wells the predicted surface oiling at a thickness of > 0.04µm would be visible within a 

maximum radius of ≈ 450 km and 315 km and 315 km from each well respectively. For both the 

Flyndre and Cawdor wells there is over 90% probability of oil entering Norwegian, Dutch and Danish 

waters. A visible surface sheen is not predicted to reach any shore. 

The fate of the hydrocarbons for each well are shown in Figures 6‐6 and 6‐7. It is clear that by day 15 

and day 8 for the Flyndre and Cawdor wells respectively that less than 1% of the oil remains on the 

surface. 

For both the Flyndre and Cawdor wells the model output suggests that some finely dispersed oil in 

the water column might reach the coastline. This, would however be in such low concentrations that 

it would be undetectable and therefore of negligible environmental significance.



Figure 6‐4 Probability of a surface sheen with a 4µm thickness occurring following a blowout with 

anticipated maximum unrestricted flow rate at the Flyndre well. 

D/4114/2011 6‐9



Figure 6‐5 Probability of a surface sheen with a 4µm thickness occurring following a blowout with 

anticipated maximum unrestricted flow rate at the Cawdor well. 

The fate of the oil at any one time during the release is illustrated in Figures 6‐6 and 6‐7. By day 20 

approximately 40% of the hydrocarbons from both wells will have either decayed or evaporated. By 

this time



Mass balance 

Figure 6‐6 Fate of oil following a blowout at the Flyndre well. 

Mass balance 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 


Time (days) 


Time (days) 

Figure 6‐7 Fate of oil following a blowout at the Cawdor well. 

Evaporated 

D/4114/2011 6‐11 

Surface 

Dispersed 

Sediment 

Stranded 

Decayed 

Evaporated 

Surface 

Dispersed 

Sediment 

Stranded 

Decayed



Time elapsed Surface Evaporated Water column Sediments Decays 


Day 4 19.9 12 57 0.1 11 

Day 20 0.3 11 26 34 29 

Day 90 0.6 11 6.4 40 42 

Day 120



Figure 6‐8b Concentrations of hydrocarbons in the water column 80 days after release begins at the 

Flyndre well. 

Figure 6‐9a Concentrations of hydrocarbons in the water column 10 days after release begins at the 

Cawdor well. 

D/4114/2011 6‐13



Figure 6‐9b Concentrations of hydrocarbons in the water column 80 days after release begins at the 

Cawdor well. 

At the Flyndre well 30 days after the release has been controlled maximum hydrocarbon 

concentrations in the water column are ≤ 0.005 ppm (i.e. 5 ppb) and are therefore well below the 

50 ppb threshold levels deemed to present a risk to marine life. Thirty days after a release at the 

Cawdor well is controlled maximum water concentrations are < 0.001 ppm (i.e.1 ppb). 

Thirty days after a release from the Flyndre well is controlled the sediment concentrations of 0.0001 

to 0.3 kg/m 2 are found at a maximum of 140 km from the release site. Outside this area sediment 

concentration is < 0.00001 kg/m 2 . Assuming a sediment density of 2 kg/m 3 and assuming the 

hydrocarbons are contained within the top 10 cm of the sediment a hydrocarbon concentration 

outside a radius of 145 km 2 equates to 5 ppm. This is tenfold below 50 ppm; the level at which toxic 

effects begin to be observed in the sediment. These low concentrations are found at a maximum 

distance of 420 km in an easterly direction. To the north and west sediment contamination occurs at 

a maximum of 90 km from the release site. 

At the Cawdor well hydrocarbon concentrations in the sediment are not expected to go above 

0.1 kg/m 2 . Outside a maximum radius of 130 km sediment concentrations are below 5 ppm. 

6.3.3. ONSHORE AND OFFSHORE WINDS 

In addition to the varied wind data used above, the models were run assuming unvarying 30 knot 

onshore and offshore winds (referred to as a deterministic analysis). The fate of the diesel from the 

drilling rig and the hydrocarbons from the Flyndre and Cawdor wells in such an instance are 


It should be noted that at these wind speeds, wave heights are predicted to be 5‐6 m in height using 

the in‐built fetch/wind speed predictions in OSCAR. and oil on the surface is predicted to be 

negligible due to the action of waves. 

6 ‐ 14 D/4114/2011



Hydrocarbon 

source 

Drilling rig 

Flyndre well 

Cawdor well 

Wind direction 

Time take to cross 

median 

Evidence of 

beaching 

Offshore 30 knot westerly wind 15 hours No 

Onshore 30 knot easterly wind 6.5 days No 

Offshore 30 knot westerly wind 18 hours No 


Offshore 30 knot westerly wind 13 days No 


Note: In the presence of onshore winds subsea currents will cause the oil to cross the UK/Norwegian median line 

Table 6‐7 Deterministic onshore and offshore modelling results summary. 

6.4. ENVIRONMENTAL SENSITIVITIES 

6.4.1. SEABIRDS 

The effects of oil on birds has been widely studied and includes both immediate chronic impacts 

which can kill birds or longer‐term, sub‐lethal, impacts that could affect individuals and populations 

over many years (e.g. Camphuysen, et al. 2005, Perez, et al. 2009). To assist in determing the likely 

impact on birds from a release of oil, the JNCC has produced an Oil Vulnerability Index (OVI) from 

which it is possible to indicate the sensitivities of bird families that could be impacted (Section 3.5.4). 

The OVI of seabirds within each offshore licence block in the vicinity of the Flyndre and Cawdor 

development are shown in Table 3‐12. The JNCC monthly seabird vulnerability Index indicates an 

overall low vulnerability in the area of the development; all the spring and summer months are 

categorised as being of low vulnerability whic hmay be associated with a higher proportion of birds 

moving inshore to breed. The OVI increases to moderate to high in some of the winter months as 

particular seabird species are present in greater densities. This higher OVI index may also be due to 

the annual moult in feathers when birds are more susceptible to the impacts of any surface oil. 

Coastal seabirds would be vulnerable to surface oil that could coat feathers and thereby reduce 

buoyancy or be ingested through preening, causing illness and other sub‐lethal effects. While 

reduced survival cannot be ruled out, the fact that any oil that may reach the coastline would be of 

very low concentrations, the effects are likely to be small and rehabilitation of any affected birds 

would have a reasonable chance of success. 

6.4.2. MARINE MAMMALS 

Marine mammals that come into contact with oil may be impacted in a number of ways. The 

insulation properties of fur are greatly reduced when covered in oil. The loss of insulation properties 

is not considered to be a significant risk for seals and cetaceans that have relatively little fur, although 

it is of significance for seal pups. Where oil does come in contact with the skin there is the potential 

for it to cause irritation to the eyes or burns to mucous membranes. Ingestion of oil by marine 

mammals can damage the digestive system or affect the functioning of livers and kidneys. If inhaled, 

hydrocarbons can impact the respiratory system. Section 3.5.5 summarises the marine mammals 

associated with the area of the development. The main species occurring in the area are cetaceans 

with seals being infrequently recorded. There are no concentrations of breeding seals that appear to 

be at risk from the any accidental releases. No significant risk to marine mammal populations is 

anticipated such that any adverse impacts to individual cetaceans would not affect the species at a 

population level. 

D/4114/2011 6‐15

6.4.2.1. FISH 



Several fish species have been recorded across the North Sea (e.g. annual fish landings data presented 

to ICES include over 200 species of fish and shellfish.). Some of the more commercially important 

species known to spawn in the area of the development are given in Table 3‐11. 

It is likely that fishing would be suspended in the vicinity of a release until monitoring could be carried 

out, reflecting the fact that oil in water concentrations very close to the release point could be toxic 

to fish and cause tainting. Modelling predicts that water column oil and surface oil will disperse, 

degrade and evaporate within days and weeks of the release ceasing. 

6.5. SPILL PREVENTION AND CONTINGENCY PLANNING 

Maersk Oil’s commitments to ensuring protection of the environment are set out in the corporate 

HSE policy, a copy of which is provided in Appendix C. Maersk Oil’s EMS covers all aspects of Maersk 

Oil activities including exploration, drilling and production and will be applied to the proposed 

development. The activities associated with the proposed development are also covered in a project 

specific HS&E plan which ensures that the project is managed in such a way that all of Maersk Oil’s 

health, safety and environmental policies are adhered to throughout all phases of the Flyndre and 

Cawdor development. Particular emphasis will be paid to having a robust design, quality equipment, 

quality construction and operational best practices. 

The following provides a high level overview of proposed areas of planning and preparation that 

either reduce the probability of a failure of well control or reduce the consequence of a failure of well 

control. 

The wells and the recompletions are designed to Maersk Oil’s internal technical practices. 

During well operations, the primary well control barrier is weighted fluid and the secondary 

barrier is the BOP equipment. The production casing is part of the pressure containment 

vessel, sealed‐off in the wellhead and featuring cement isolation between the reservoir and 

shallower formations; 

The rig will have a UK Safety Case and will be class certified by a recognised certifying 

authority. Maersk Oil will perform assurance assessments prior to rig acceptance to confirm 

all critical systems such as surface BOP equipment and drilling fluid circulating and processing 

systems are fully certified and working as designed; 

The BOP stack minimum pressure rating will always be greater than the reservoir pressure; 

Maersk Oils control response procedures detail the action to be taken in response to a well 

control event and defines the roles and responsibilities for all responders to the event and 

details technical and operational support for different scenarios; 

The proposed measures will be documented in the OPEP for consideration by the authorities 

prior to the operation. 

Maersk Oil is certified to the international ISO 14001 standard, and has an externally verified 

Environmental Management System (EMS). The EMS governs those aspects of the environment that 

can be controlled, such as discharges, and establish a subsequent auditing process. 

Maersk Oil is party to the Offshore Pollution Liability Association Limited (OPOL) which is a voluntary 

oil pollution compensation scheme from offshore oil pollution incidents from exploration and 

production facilities. 

Maersk Oil is a member of the Operators Co‐Operative Emergency Services. This is the organisational 

framework under which oil and gas companies operating in the waters of the North Sea and adjacent 

waters of the North West European Continental Shelf co‐operate and share resources in the event of 

an emergency situation. 

6 ‐ 16 D/4114/2011



Maersk will enter into contracts with the drilling contractor to ensure that appropriate control 

measures are in place and will undertake an audit of the drilling rig. 

In addition Maersk Oil is supported by Oil Spill Response Limited (OSRL), which is an industry, 

recognised expert company in the containment and management of hydrocarbons accidently 

released into the environment. Access to competent personnel and equipment is available at short 

notice for mobilization to the site of any spill to assist in the remedial containment and subsequent 

clean of hydrocarbons. 

Equipment available under contract with OSRL covers onshore and offshore containment, treatment, 

collection and clean‐up hardware and includes a range of approved chemical dispersants that could 

be deployed from vessels or aircraft as required. The readiness of the company is regularly tested via 

emergency response simulation which includes formal statutory oil spill response. 

A number of mitigation measures will be in place to minimise the impact of any major or minor 

hydrocarbon release associated with the development of the Flyndre and Cawdor field. 

6.5.1. EMERGENCY PREPAREDNESS AND RESPONSE 

A summary of the reporting system for oil and chemical spills is summarised here, further details of 

the roles and responsibilities will be provided in the OPEP. 

For all accidental / unplanned discharges or spills of oil or chemicals to sea, regardless of volume the 

Maersk Oil Emergency Co‐ordinator (onshore) is notified. The nearest HM Coastguard station is 

contacted by telephone. A petroleum Operations Notice (PON 1) that provides details of the spill will 

be sent to the HM Coastguard station (Maritime Rescue Coordination Centre Aberdeen), DECC and 

JNCC. If spill exceeds one tonne within 25 nautical miles of the coast or is within an environmentally 

sensitive area the incident reporter is to telephone JNCC and DECC. For a spill in any area exceeding 

25 tonnes the incident reporter must telephone JNCC (Figure 6‐10). 

Figure 6‐10 Notification pathway for oil and chemical spills 

The UK and Norway have the NORBRIT agreement which details counter pollution measures between 

the two countries, whilst similar measures are in place with European countries signatory to the Bonn 

Convention. The authorities for the territorial waters within which a major oil spill occurs, shall 

immediately notify the authorities of the other country if their territorial waters are threatened. For a 

spill that could enter into Norwegian waters this notification shall be transmitted between the UK 

D/4114/2011 6‐17



Coastguard MRCC, Aberdeen and the Norwegian Coastguard RCC, Stavanger and between the 

Norwegian Pollution Control Authority (NPCA) and the Maritime & Coastguard Agency (MCA). 

Maersk Oil recognises three tiers of oil spill incident (Table 6‐8). Tier 1 spill response is undertaken 

from the infield resources at the Field System under the command of the OIM. When these resources 

are insufficient to counteract the oil spill, Tier 2 and/or Tier 3 resources can be sought via the onshore 

Emergency Response Team (ERT). 

Tier 1/2/3 

Tier 1/2/3 

Tier2 

Tier 2/3 

Response 

Team 

OIM Infield 

Maersk Oil 

Emergency 

Response 

Team (ERT) 

Oil Spill 

Response 


Crisis 

Management 

Team (CMT) 

Location Function 


Emergency 

Response 

Centre (ERC), 

Aberdeen 

Southampton 

Maersk 

House, 

Aberdeen 

Table 6‐8 Three tier oil spill incident classification. 

The main function of the OIM is to; 

From initial alarm, take charge of the situation and assume role of 

On‐Scene Commander 

Be responsible for the initial notification of statutory bodies 

Notify the Drilling Contractor (onshore). 

The Maersk Oil ERT is comprised of a group of specifically trained 

personnel who are available to assist if required in the event of a 

major incident. The ERT will be lead by Maersk Oil Emergency Co‐ 

ordinator, be based in Aberdeen and will coordinate the spill response 

aspects of the incident. The main function of the ERT is to; 

In conjunction with the drilling contractor, provide support to the 

offshore response teams 

Assist in maintaining the safety and wellbeing of offshore 

personnel and integrity of the drilling rig 

Directly liaise with the drilling contractor 

Notify statutory authorities as the onshore notification matrix 

Mobilise specialist external resource requirements (response and 

other identified contractors) 

Authorise the proposed response strategy 

Directly liaise with the response contractors 

Authorise the proposed response strategy following discussion 

Monitor the incident and manage the ongoing response. 

The Oil spill response is comprised trained personnel whose function 

is to; 

Provide contracted spill response services, communicating with 


Provide spill prediction modelling 

On operational matters, liaise directly with statutory authorities 

Once approved by the statutory bodies to mobilise and directly 

manage the appropriate aerial and other services 

Develop an appropriate response strategy and propose to 

Maersk Oil and the statutory authorities 

Once approved, liaise with Maersk Oil on the appropriate aerial 

and operational response 

Provide situation reports to Maersk Oil and statutory authorities 

Provide changes of response strategy as the situation develops. 

The main functions of the Maersk Oil CMT are to; 

Address the strategic issues that affect Maersk Oil 

Provide support to Maersk Oil staff and relatives 

Assist in coordination of media response. 

Maersk oil have in place a management system to reduce the risk of accidental spills occurring and 

measures in place to minimise any potential environmental impacts should an accident occur. 

Potential emergency situations are identified within the environmental aspects register and risk 

6 ‐ 18 D/4114/2011



assessments form a component part of individual Oil Pollution Emergency Plans (OPEPs). Procedures 

for emergency preparedness and response are detailed in Procedure “Onshore Emergency 

Response”. Procedures for oil pollution preparedness and response are detailed in procedure 

“Response and reporting requirements for accidental oil and chemical discharges” and the offshore 

asset‐specific and drilling OPEPS. These procedures apply for all spills of hydrocarbons and chemicals 

to sea. The measures are described below; 


Trained and competence assured drill crew and supervisory team. 

All OPEP commitments (training, exercises, etc) captured in specific rig audit programme. 

Robust BOP pressure and functional testing regime. 

Routine ROV inspections of the BOP on the seabed, as well as visual integrity checks 

whenever BOPs are recovered to the surface. 

The wells are drilled with an overbalance which is higher than the customary trip margin, as 

the mud weights are dictated by shale stability considerations. 

Higher hazard and risk awareness and understanding in light of lessons learned from the 

GOM/Deep Water Horizon incident. 

Enhances sharing of industry best practices via the OSPRAG Work Group. 

Co‐ordinated industry oil spill response capability. 

An approved OPEP will be in place prior to any activities being undertaken by the drilling rig. 

6.5.2. MANAGEMENT OF WASTE STREAM FROM OFFSHORE / ONSHORE SPILL RESPONSE 

Since the modelling identifies that no surface oil is predicted to reach the coast, any oil in the water 

column will be finely disposed, there is virtually no potential for wastes to be generated from 

shoreline clean up activities. 

Offshore booming and recovery may be attempted but is not considered essential to preserve 

sensitive environmental resources. Consequently waste oily water and fouled booms should present 

a small and manageable issue. 

D/4114/2011 6‐19


Section 7 Conclusions 

7. CONCLUSIONS 

A detailed EIA of the development has been carried out in order to determine the potential impacts 

on the environment and their significance. The identification of the potential impacts was based on 

the nature of the proposed activities and was undertaken using available literature and guidance 

documents, industry specific experience and discussions with relevant authorities including DECC, 

JNCC and Marine Scotland. The EIA process will continue throughout the project with the 

incorporation of the commitments made in this ES into the design process, construction and 

ultimately affecting the way in which the field is produced. 

7.1. ENVIRONMENTAL EFFECTS 

The development area is considered to be a typical CNS offshore environment there are no biological 

habitats or other features that are particularly sensitive to the type of development proposed. No 

Annex I habitats are present within the vicinity of the development. The project may impact very 

briefly upon fisheries in the area during the installation period. 

The environmental aspects of the key activities during the production phase were identified and, 

where possible, the potential effects quantified in terms of their likelihood, potential significance and 

magnitude. The results were assessed on the basis of the risk posed to the environment and were 

summarised as either low, moderate or high risk. 

The initial screening assessment showed that the majority of the key activities are of low risk and that 

there are no key activities which are of high risk. During the drilling phase the risk associated with the 

deliberate discharge of drilling fluids and the associated chemicals were found to be moderate. An 

uncontrolled 90 day blowout from wells was also found to be of a moderate risk as no beaching is 

predicted to occur. 

Noise resulting from piling was also found to be of a moderate risk as was the discharge of produced 

water during production. Disturbance of historic cuttings piles at the Clyde platform was also 

identified as a moderate environmental risk, further engineering studies are planned in relation to the 

design of the riser and umbilical tie in points, only when this is completed will a better assessment of 

the potential for disturbance of cuttings be possible, so this is remains a project uncertainty. 

Following the identification of suitable mitigation measures, an additional assessment was 

undertaken for the activities which were initially identified to be of moderate risk. With the adoption 

of appropriate mitigation there are only low residual risks to the environment. 

7.2. MINIMISING ENVIRONMENTAL IMPACT 

Overall, the execution of the proposed development following the incorporation of the control 

measures, is not expected to have a significant impact on the environment. 

In order to capture the commitments and environmental issues identified from the assessment of the 

Flyndre and Cawdor development, these will be transferred into Maersk Oil’s action tracker, ‘Synergi’. 

The Synergi system is used for the management of reports and data relating to and actions resulting 

from: 

Incidents 

Audits 

D/4114/2011 7 ‐ 1

Inspections 

Reviews 

Investigations 

Synergi is used for the following environmental items: 

Environmental emissions/spills, including hydrocarbon leaks 

Breaches of legal requirements including breaches of permits 

Actions arising from audits, inspections and reviews 

7‐ 2 D/4114/2011 

Flyndre adn Cawdor Environnemental Statement 


The Synergi system implements the requirements of ISO14001 for the tracking of non‐conformance 

and corrective and preventive action. All non‐conformances to the requirements of the EMS are 

recorded and reviewed. Suitable action is taken to correct each non‐conformance, deal with any 

environmental impacts resulting from it and, where necessary, initiate appropriate action taken to 

eliminate the cause of the non‐conformance. Target dates and people responsible for ensuring the 

measures are implemented will be identified for each of the mitigation measures. Synergi is reviewed 

on a monthly basis and overdue actions brought to the management’s attention. 

Commitments and mitigation measures to minimise the impact of the development on the 

environment have been highlighted throughout the ES and are summarised below. They have been 

separated out into drilling, subsea installation, production and accidental events. 

Drilling: Atmospheric emissions 

The drilling rig will be subject to audits ensuring compliance with UK legislation. 

The impact from emissions will be mitigated by optimising support vessel efficiency. 

Low sulphur fuels will be used in accordance with prevailing EU and MARPOL requirements. 

Drilling: Discharges to sea 

Period of well testing will be kept to a minimum 

‘Green burners’ will be employed for well test operations, which will significantly reduce the 

levels of unburned hydrocarbons entering the environment. 

During flaring continuous observation of the sea surface will occur. The test will be 

suspended should a significant sheen be observed 

OBM and drill cuttings will be Rotomill treated before discharged to the seabed. 

Drilling: Physical presence 

Pre‐deployment surveys will be undertaken and will be used to identify anchor locations. 

The anchors will be deployed in such a way as to minimise the risk of interaction with 

existing infrastructure.



Subsea installation: Physical presence 

Minimise the mass of rock placement required by undertaking upheaval buckling analysis. 

The rock placement will be entered into FishSafe system so that it may be avoided by fishing 

vessels. 

Subsea installation: Discharges to sea (Oil Based Mud cuttings at Clyde Platform) 

Attempt to route infrastructure away from main cutting pile 

Assessment of potential for disturbance to cutting piles made at PON15C stage 

Subsea installation: Noise (Vessels) 

Minimise number of vessels required 

Minimise length of time vessels are on site 

Subsea installation: Noise (piling of manifold) 

The JNCC piling protocol will be followed including: 

Piling will commence using soft start; 

A trained marine mammal observer will be present during piling operations ; and 

Follow JNCC guidance, no pile driving will commence if a marine mammal has been recorded 

within 500 m of the exclusion zone during the previous 20 minutes. 

Production: Atmospheric emissions 

To reduce emissions from flaring there is in place a minimum start up frequency policy, adherence to 

good operating practices, maintenance programmes and optimisation of quantities of gas flared. 

Emissions from combustion equipment are regulated through EU ETS and PPC Regulations. As part of 

the existing PPC permit the following measures are in place; 

The emissions from the combustion equipment are monitored 

Plant and equipment are subject to an inspection and energy maintenance strategy 

UK and EU air quality standards are not exceeded 

Fuel gas usage is monitored. 

Production: Produced water 

The discharges of produced water are regulated by OPPC regulations and reported through EEMS. As 

such Maersk Oil are committed to the following mitigation measures; 

reporting total volumes of produced water discharged 

monthly reporting of the oil in water content of produced water 

bi‐annual sampling for chemical analysis. 

D/4114/2011 7 ‐ 3

Ensure the installation meets


Section 8 References 

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Appendix A - Register of Environmental Legislation 

APPENDIX A ‐ REVIEW OF LEGISLATION 

General 

Issue Legislation Regulator and Requirements 

General 

The Energy Act 2008 (Consequential 

Modifications) (Offshore Environmental 

Protection) Order 2010 

EC Directive 2009/31 on geological storage of 

carbon dioxide 

Part 1 of the Energy Act 2008 introduces two new licensing regimes for the storage and unloading of combustible gas and the 

permanent storage of carbon dioxide. These regulations amend the following pieces of legislation to include carbon capture and 

storage (CCS): 

Offshore Petroleum Production and Pipe‐lines (Assessment of Environmental Effects) Regulations 1999 

Offshore Petroleum Activities (Conservation of Habitats) Regulations 2001 

Offshore Marine Conservation (Natural Habitats, &c.) Regulations 2007 

Offshore Combustion Installations (Prevention and Control of Pollution) Regulations 2001 

Offshore Chemicals Regulations 2002 

Offshore Installations (Emergency Pollution Control) Regulations 2002 

Greenhouse Gases Emissions Trading Scheme Regulations 2005 

Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 

REACH Enforcement Regulations 2008 

Fluorinated Greenhouse Gases Regulations 2009 

EC Directive 2009/31 on the geological storage of carbon dioxide amends the following directives to include CCS: 

Directive 85/337 (the EIA Directive) 

Directive 2000/60 (the Water Framework Directive) 

Directive 2001/80 (the Large Combustion Plants Directive) 

Directive2004/35 on Environmental Liability 

Directive 2006/12 (the Waste Framework Directive) (repealed by Directive 2008/98) 

Directive 2008/1 (the IPPC Directive) 

MARPOL 73/78 UK Regulations apply to all vessels regardless of flag whilst in UK Territorial Waters (12nm from coastline), and implement the 

requirements of MARPOL 73/78. Similarly, MARPOL 73/78 requirements apply to all vessels whilst on the High Seas (outside territorial 

waters). 

Annexes I Prevention of pollution by oil, II 

Control of pollution by noxious liquid 

substances, IV Prevention of Pollution by 

Sewage from Ships, V Prevention of pollution 

by garbage from ships and VI Prevention of Air 

The international Maritime Organisation (IMO) may designate areas of sea as ‘Special Areas’ for oceanographic reasons, ecological 

condition and in relation to character of shipping and other sea users. The North West European Waters (including the North Sea) have 

been given ‘Special Area’ status from August 1999. In these areas special mandatory methods for the prevention of sea pollution is 

required and these special areas are provided with a higher level of protection than other areas of the sea. 

D/4114/2011 A ‐ 1

Territorial Waters 

Public 

Participation 

Environmental 

Liability 

Marine 

Management 

Pollution from Ships of MARPOL 

Territorial Sea Act 1987 

Territorial Waters Order 

Control Oil Pollution Act 1974 

Defines the territorial waters of the UK. 



EC Directive 2003/35 on Public Participation The Public Participation Directive (PPD) was issued by the European Commission in order to provide members of the public with 

opportunities to participate on the permitting and ongoing regulation of certain categories of activities within Member States, including 

Environmental Impact Statements. 

EC Directive 2004/35 on Environmental 

Liability with Regard to the Prevention and 

Remedying of Environmental Damage 

Environmental Damage (Prevention and 

Remediation) Regulations 2009 (as amended 

2010) 

The Environmental Damage (Prevention and 

Remediation) (Wales) Regulations 2009 

Environmental Liability (Scotland) Regulations 

2009 

EC Directive 2008/56 (the Marine Strategy 

Framework Directive) 

The Marine Strategy Regulations 2010 

The Environmental Liability Directive enforces strict liability for prevention and remediation of environmental damage to ‘biodiversity’, 

water and land from specified activities and remediation of environmental damage for all other activities through fault or negligence. 

These regulations implement EC Directive 2004/35 on Environmental Liability, forcing polluters to prevent and repair damage to water 

systems, land quality, species and their habitats and protected sites. The polluter does not have to be prosecuted first, so remedying 

the damage should be faster. 

The Regulations were previously amended in 2009 to include the seabed out to the limits of the continental shelf anywhere other than 

the seabed out to the limits of the renewable energy zone around England. The regulations were amended again in 2010 to provide for 

the devolution to the Scottish Ministers of certain of the Secretary of State’s functions with respect to preventing and remedying 

damage to marine nature conservation in the Scottish offshore region. However, the Secretary of State still enforces preventing and 

remedying damage caused by oil, gas and carbon dioxide storage activities and marine transport activities. 

The Marine Strategy Regulations 2010 transpose the requirements of the Marine Strategy Framework Directive into UK law. The 

Directive requires Member States to implement measures to achieve or maintain good environmental status of their marine 

environment by 2020. Specifically, the Directive requires Member States to create a strategy for the following: 

an initial assessment of the current environmental status of a Member State's marine waters by 2012 

development of a set of characteristics which describe what “Good Environmental Status” means for those waters by 2012 

establishment of targets and indicators designed to show the achievement of Good Environmental Status by 2012 

establishment of a monitoring programme to measure progress toward achieving Good Environmental Status by 2014 

establishment of a programme of measures designed to achieve or maintain Good Environmental Status (to be designed by 

2015 and implemented by 2016). 

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Marine and Coastal Access Act 2009 

Marine (Scotland) Act 2010 

The Marine and Coastal Access Act (MCAA) came into force in November 2009. The Act covers all UK waters except Scottish internal 

and territorial waters which are covered by the Marine (Scotland) Act 2010 which mirrors the MCAA powers. The licensing provisions in 

relation to MCAA came into force on 1 st April 2011. 

MCAA will replace and merge the requirements of FEPA Part II (environment) and the Coastal Protection Act 1949 (navigation). The 

following activities are exempt from MCAA as they are controlled under different legislation: 

Activities associated with exploration or production / storage operations that are authorised under the Petroleum Act 1998 

and Energy Act 2008 

Additional activities authorised solely under the DECC environmental regime, such as chemical and oil discharges 

 

The offshore oil and gas activities that will require an MCAA licence are as follows: 

Deposits of substances or articles in the sea or on the seabed, e.g. pipeline crossing works prior to use of pipeline 

authorisation works (PWA) or related Direction, or deposit of materials associated with abandonment operations 

Removal of substances or articles from the seabed, e.g. pre‐sweep dredging with disposal of material at a remote location, or 

removal of seabed infrastructure during abandonment operations 

Disturbance of the seabed, e.g. pre‐sweep dredging using a levelling device or by side‐casting material, or disturbance of 

sediments or cuttings pile by water jetting during abandonment operations 

Installation of certain types of cable that cannot be covered by a PWA e.g. communication cables 

Deposit and use of explosives that cannot be covered under an application for a Direction, e.g. during abandonment 

operations 

Licences will be valid for a maximum period of one year however, applications for licence renewals can be made. 

D/4114/2011 A ‐ 3

Consenting 


EIA 

EC Directive 85/337 (the EIA Directive) (as 

amended by Directives 97/11, 2003/35 and 

2009/31) 

Offshore Petroleum Production and Pipelines 

(Assessment of Environmental Effects) 

Regulations 1999 (as amended 2007) (as 

amended by the Energy Act 2008 

(Consequential Modifications) (Offshore 

Environmental Protection) Order 2010) 



Under the EIA Directive all Annex I projects are considered to have an effect on the environment and require EIA (and consequently an 

Environmental Statement (ES)), this includes oil and gas exploration and production projects and more recently, under Directive 

2009/31, certain CCS projects. 

Regulator: Department of Energy and Climate Change (DECC) 

The Secretary of State for Energy and Climate Change will take into consideration environmental information in making decisions 

regarding consents for offshore developments and projects. 

A statutory ES and public consultation is mandatory for: 

new field developments or increase in production where production is predicted to exceed 500 tonnes of oil per day or 

500,000 cubic meters or more per day of gas; 

new pipelines or extensions to pipelines of 800mm diameter and 40km or more in length 

a project which has, as its main object, a storage or unloading activity, and in the respect of related installations, or the 

construction of a pipeline conveying combustible gas or carbon dioxide (under the amendments made by the Energy Act 

2008 (Consequential Modifications) (Offshore Environmental Protection) Order 2010). 

A formal process has been established for the submission of an ES and public consultation which involves: 

Submission of the ES to DECC and their advisors (Environmental Authorities); 

The ES must be advertised in the national and local press; 

The ES must be available for public consultation for at least 28 days following the advertisements (longer if this includes a 

public holiday); 

The public may request a copy of the ES and the maximum allowable charge which may be made for this is £2; 

The public, Environmental Authorities, consultees and other organisations make their comments to DECC; 

DECC may require more information/clarifications from the operator or may require resubmission of the ES should they feel 

that they have insufficient information on which to evaluate the environmental implications of the proposed project. 

Following consideration, DECC may issue a project consent which is then advertised in the Gazette, following which there is a 

six week period during which those who feel ‘aggrieved’ by this decision may challenge it. 

The requirement for a Statutory ES is at the discretion of the Secretary of State for: 

Smaller developments and pipelines; 

Exploration, appraisal and development wells and any sidetracks; 

Production consent variations and renewals. 

If a Direction as to the requirement for an ES is desired then the following Petroleum Operations Notice 15 (PON15) online application 

A ‐ 4 D/4114/2011



Field Development 

Plan 

Pipeline Works 

Authorisation 

Petroleum Act 1998 Regulator: DECC 

Petroleum Act 1998 Regulator: DECC 

forms on the UKOilPortal should be used: 

PON 15b when seeking a direction for drilling a proposed well including new sidetrack wells and/or seeking a chemical 

permit; 

PON 15c when seeking a direction for a proposed pipeline and/or seeking a chemical permit; 

PON 15d when seeking a direction for proposed development (or for variation, renewal or extension of a production consent) 

and/or seeking a chemical permit; 

PON15e seeking a chemical permit during decommissioning operations (not on portal – paper version of application form can 

be found at https://www.og.decc.gov.uk/regulation/pons/index.htm and should be emailed to the Environmental Management 

Team at DECC); 

PON 15f seeking a chemical permit during workover/well intervention operations. 

Operator is required to submit plans for development of field to DECC for approval. 

Construction of a pipeline is prohibited in, under or over controlled waters, except in accordance with an authorization granted by the 

Secretary of State (known as the Pipeline Works Authorisation – PWA). 

Application for authorisation is made under Section 14 of the Act , to the Secretary of State; 

the Secretary of State decides whether applications are to be considered or not. If not to be considered reasons will be 

given; 

if an application is being considered, the Secretary of State will give directions with respect to the application; 

the applicant is to publish a notice giving such details as directed by the Secretary of State, allowing 28 days from first 

publication of the notice for public consultation; 

publication must provide a map and such other information as directed by the Secretary of State and must make these 

available for public view during the specified period; 

notice must also be provided to any other parties as directed by the Secretary of State; 

the Secretary of State considers any representations and issues authorisation. 

The PWA process addresses the requirements for DEPCON (Deposits Consent) required under the Petroleum Act 1998. The DISCON 

(Discharge Consent) has now been replaced by the requirement to get a permit (with a PON 15c) under the OCR 2002. 

Model Clauses of Authorisation In the Submarine Pipeline Works Authorisation (PWA) the Secretary of State for Energy and Climate Change will authorise the project to 

construct and to use the submarine pipelines and associated equipment, subject to a number of terms and conditions, including; 

the pipeline shall be used only for the transport of condensate, not of oil; 

the pipeline shall be constructed, installed and subsequently maintained in conformity with the plans, specifications and 

other information furnished by the project; 

the pipeline shall be used and operated in accordance with the requirements and shall be maintained in a proper state of 

D/4114/2011 A ‐ 5



repair and any damage to the pipeline shall be properly acted upon. 

the project shall ensure that there is insurance cover in order to enable liability to third parties caused by the release or 

escape of any of the contents of the pipelines. 

the pipelines shall be installed so that they will not impede or prevent the laying of further pipelines or cables; 

those sections of the pipelines that are to be trenched shall be lowered into the subsoil as soon as practicable following pipe 

laying so that wherever practicable the uppermost surface of the pipelines is below the undisturbed level of the surrounding 

seabed; 

if any part of these sections of the pipelines above the level of the seabed causes actual interference with fishing or with 

other activities the Secretary of State may require that part of the pipelines should be lowered below the level of the 

surrounding seabed by trenching; 

any parts of the said pipelines left on the seabed during the period of construction shall be covered in such a way that they 

will not interfere with fishing gear; 

the pipelines shall be suitably protected to ensure that they are not susceptible to third party damage; 

the pipelines shall possess such negative buoyancy as may be required for them to remain stable where placed on the sea 

floor; 

an effective leak detection system shall be installed; 

consent shall be obtained from the placement of rock and concrete mattresses for burying, protecting or supporting the 

pipeline and conditions may be attached to that consent; 

no object, equipment or material of any kind which is not an integral part of the pipeline shall be disposed of at sea or 

abandoned on the seabed during the construction and installation of the pipelines. Where such items are accidently dropped 

or left in the sea, every reasonable effort shall be made to recover them; 

so far as is reasonably practicable that part of the sea bottom which is disturbed by the laying or trenching operations shall 

be restored to a condition that will not interfere with fishing activities; 

appropriate fishing organisations shall be informed every 24 hours of the positions at which construction work is being 

carried out during the first 24 hours and on the following 3 days. Radio broadcasts shall be made from the installation vessel 

twice daily; 

if any defects in the pipelines are disclosed by an inspection or monitoring, the Secretary of State shall be notified, such work 

as may be necessary to rectify it shall be carried out as soon as practicable; 

any contents of the pipelines released by way of a pressure relief system shall be disposed of safely and in such a manner so 

as to ensure that as far as is reasonably practicable no pollution occurs; 

substances introduced into the pipelines or any part thereof other than those consisting entirely of untreated seawater or 

sweet water shall not be discharged into the sea or other waters except with the prior written consentof the Secretary of 

State and in accordance with any conditions which may be attached to that consent. 

Notifications, information and documents concerning the pipelines shall be submitted to: 

the Secretary of State; 

the Hydrographer of the Navy; 

the Department for Environment, Food and Rural Affairs (DEFRA); 

A ‐ 6 D/4114/2011



Seabed lease 

Location of 

structures 

Well consent 

Licensing 

Planning 

Crown Estate Act 1961 Regulator: Crown Estate Commissioners 

Coast Protection Act 1949 Regulator: DECC 

Continental Shelf Act 1964 

The Continental Shelf (Designation of Areas) 

(Consolidation) Order 2000 (as amended 

2001) 

Petroleum Act 1998 

Petroleum Operations Notice No 4 

Petroleum Licensing (Production) (Seaward 

Areas) Regulations 2008 (as amended 2009) 

Marine Coastal Access Act 2009 and Marine 

(Scotland) Act 

Minute of agreement required for occupation of seabed. 

The issuing of 'consent to locate' under the Coast Protection Act 1949 Section 34, Part II by the Secretary of State to an individual or 

organisation provides an indication that impacts have been considered with respect to (i) navigation and (ii) the local habitat within the 

proposed area; that no significant impacts would occur as a consequence of the proposed offshore installation. 

The consent issued as part of the PWA for work in support of pipelines or part of the PON 4 for drilling (if it is a separate vessel not from 

a surface installation). 

Regulator: DECC 

The Coastal Protection Act 1949 requires consent for offshore installations in UK territorial waters, the Continental Shelf Act extends the 

UK government’s right to grant licences to explore (and exploit) hydrocarbon resources to the UK Continental Shelf (UKCS). 

The Continental Shelf (Designation of Areas) (Consolidation) Order 2000 consolidates the various Orders made under the Continental 

Shelf Act 1964 which have designated the areas of the continental shelf within which the rights of the United Kingdom with respect to 

the sea bed and subsoil and their natural resources are exercisable. 


Application for consent to drill exploration, appraisal and development wells must be submitted to DECC through the WONS. 

Petroleum Licensing (Production) (Seaward Areas) Regulations 2008 were issued under the Petroleum Act 1998. In order to search, 

bore for or get petroleum within Great Britain, or beneath the UK territorial sea and Continental Shelf a licence should be obtained from 

the Secretary of State. 

Petroleum Licensing (Amendment) Regulations 2009 amendments to the regulations include updates to the standard application fees 

for petroleum licences. 

The Marine (Scotland) Act aims to introduce a new statutory marine planning system to sustainably manage the increasing, and often 

conflicting, demands on our seas. 

The Marine and Coastal Access Act 2009 makes provision for the amendment of the Environmental Damage (Prevention and 

Remediation) Regulations 2009 in order to place responsibility for enforcement in the Scottish offshore region with the Scottish 

Ministers, when there is significant damage to species and habitats protected under the EU Habitats and Wild Birds Directives. This 

responsibility will not include enforcement of the prevention and remediation of damage caused by oil and gas activities or CO2 storage 

activities which will remain with DECC 

D/4114/2011 A ‐ 7

Drilling 


Muds, cuttings and 

chemical use and 

discharge 

Deposits in the Sea (Exemption) Order 1985 

(as amended (England and Wales only) 2010) 

The Offshore Petroleum Activities (Oil 

Pollution Prevention and Control) Regulations 

2005 (as amended 2011) (OPPC regulations) 

(as amended by the Energy Act 2008 



(replacing Prevention of Oil Pollution Act 1971 

(as amended)) 

Offshore Chemicals Regulations 2002 (as 

amended 2011) (as amended by the Energy 

Act 2008 (Consequential Modifications) 

(Offshore Environmental Protection) Order 

2010) 

PON 15b Implementing the requirements of 

OSPAR Decision 2000/2 on a Harmonised 



Regulators: DECC supported by Marine Scotland and Centre for Environment, Fisheries and Aquaculture Science (CEFAS) 

Deposits in the sea were regulated through FEPA, which, as of April 2011, was subsequently replaced by the MCAA (2009). Discharge of 

drill cuttings and muds during drilling are specifically excluded from the licensing requirements of FEPA by the paragraphs 14 and 15 of 

Schedule 3 or the Deposits in the Sea (Exemption) Order 1985: 

14. Deposit on the site of drilling for, or production of oil or gas, of any drill cuttings or drilling muds in the course of such drilling or 

production. 

15. Deposit under the seabed on the site of drilling for, or production of, oil or gas of any substance or article in the course of such 

drilling or production. 

Deposits in the Sea (Exemptions) (Amendment) (England and Wales) Order 2010 came into force in April 2010 in England and Wales 

only, making minor amendments to the Deposits in the Sea (Exemption) Order 1985, however, the above still applies. 


Under OPPC it is illegal to discharge reservoir hydrocarbons and cuttings to the marine environment without an exemption from the 

Secretary of State. The Paris Commission decision 92/2 established a maximum oil on cuttings concentration of 1% by weight for 

discharge of cuttings to sea. 

The contamination of cuttings by muds comes under the Offshore Chemical Regulations 2002 (as amended), but discharges/cuttings 

contaminated with reservoir oil fall under the OPPC regulations. 

A permit is required for discharge of oil to sea and is obtained from DECC. Under the Energy Act 2008 (Consequential Modifications) 

(Offshore Environmental Protection) Order 2010 permits now extend to CCS activities 

The Offshore Petroleum Activities (Oil Pollution Prevention and Control) (Amendment) Regulations 2011 came into force on March 30 th 

2011. These amendments include a new definition of “offshore installation”, which now includes pipelines. This ensures that all 

emissions of oil from pipelines used for offshore oil and gas activities and, under the Energy Act 2008 (Consequential Modifications) 

(Offshore Environmental Protection) Order 2010, gas storage and unloading activities will now be controlled under the OPPC 

regulations. 


Under these Regulations, offshore drilling operators need to apply for permits to cover both the use and discharge of chemicals. The 

permits are applied for through the PON15b online application form (UKoilPortal). The application requires a description of the work 

carried out, a site specific environmental impact assessment and a list of all the chemicals intended for use and/or discharge, along with 

a risk assessment for the environmental effect of the discharge of chemicals into the sea. The permit obtained may include conditions. 

These Regulations amend the Deposits to Sea (Exemptions) Order 1985 to make the discharges of chemicals to sea exempt from 

requiring a licence under FEPA (subsequently replaced by the MCAA) when the discharge has a permits under the Offshore Chemicals 

A ‐ 8 D/4114/2011



Rig Stabilisation 

Dangerous Goods 

Chemical data 

sheets and 

labelling 

Mandatory Control System for the Use and 

Reduction of the Discharge of Offshore 

Chemicals (as amended by OSPAR Decision 

2005/1) and associated Recommendations. 

OSAPR Recommendation 2006/5 on a 

management scheme for offshore cuttings 

piles 

Offshore Petroleum Production and Pipelines 

(Assessment of Environmental Effects) 

Regulations 1999 (as amended 2007) (as 

amended by the Energy Act 2008 



Offshore Petroleum (Conservation of Habitats) 

Regulations 2001 (as amended 2007) 

The Merchant Shipping (Dangerous Goods and 

Marine Pollutants) Regulations 1997 (as 

amended 1999) 

The Chemicals (Hazard Information and 

Packaging for Supply) Regulations 2002 (as 

amended) (revoked by the Chemicals (Hazard 

Information and Packaging for Supply) 

Regulations 2002 (as amended 2011). Under the Energy Act 2008 (Consequential Modifications) (Offshore Environmental Protection) 

Order 2010, permits extend to CCS activities. 

The Offshore Chemicals (Amendment) Regulations 2011 also came into force on march 30 th 2011. The key change is to ensure that 

enforcement action can be taken in respect to non‐operational emissions of chemicals, such as accidental leaks or spills. Under the 

2002 regulations a permit can only be granted in respect of discharge of chemicals which occur during day to day oil and gas production, 

as a discharge is limited to “an operational release of offshore chemicals.” Therefore, it is not an offence to emit chemicals other than in 

the course of normal operations, for example, as a result of leaks or spills. The 2011 amendments remedy this. Under the regulations, a 

“discharge” now covers any intentional emission of and offshore chemical and a new definition of “release” has been inserted which 

catches all other emissions (regulation 4(a) and (h) of the amendments). 

OSPAR Recommendation 2006/5 outlines the approach for the management of cuttings piles offshore. The purpose of the 

Recommendation is to reduce to a level that is not significant, the impacts of pollution by oil and/or other substances from cuttings 

piles. 

The Cuttings Pile Management Regime (outlined by the Recommendation) is divided into two stages: 

Stage 1 involves initial screening of all cuttings piles. This should be completed within 2 years of the Recommendation taking 

effect. 

Stage 2 involves a BAT and/or BEP assessment and should, where applicable, be carried out in the timeframe determined in 

Stage 1. 


Deposits to sea for the purpose of rig stabilisation requires a Direction under the EIA and Habitat Regulations. This is in addition to the 

Direction required for deposits associated with pipelines. 

The deposit of stabilisation or protection materials, such as jack‐up rig stabilisation/anti‐scour deposits, or pipeline protection/free‐span 

correction deposits, must be the subject of a direction under the Offshore Petroleum Production and Pipelines (Assessment of 

Environmental Effects) Regulations 1999 (as amended). Some of these deposits were previously authorised under FEPA 1985, Part II 

Deposits in the Sea, but this was deemed inappropriate and all deposits in connection with the exploration and exploitation of offshore 

oil and gas should be regulated under the Petroleum Act 1998 and/or the related environmental regulations. However, this does not 

apply to decommissioning sediments, which will require an MCAA license (see Decommissioning). 

Regulator: Maritime and Coastguards Agency 

The regulations require that dangerous goods and marine pollutants are labelled and packed according to the International Maritime 

Dangerous Goods (IMDG) code and that dangerous goods declarations are provided to vessel masters prior to loading. 

Regulator: Health and Safety Executive 

The transport of chemicals to and from offshore fields is principally by road to shore base and then by sea. These regulations 

(commonly known as CHIP 3) specify safety data sheet format and contents and required packaging and labelling of chemicals for 

supply. 

D/4114/2011 A ‐ 9



Regulations 2009) The 2009 regulations, CHIP4, consolidate all amendments made to the Chemicals (Hazard Information and Packaging for Supply) 

Regulations since 2002. 

EC Regulation 1907/2006 (REACH) 

REACH Enforcement Regulations 2008 SI 2852 

Regulator: DECC (and SEPA within Scottish territorial waters) 

Reach deals with the registration, evaluation, authorisation and restriction of chemical substances. 

REACH now extends to CCS activities, as stated under the Energy Act 2008 (Consequential Modifications) (Offshore Environmental 

Protection) Order 2010. Furthermore, the duty to enforce REACH within the seaward limits of the Scottish Territorial sea now lies with 

SEPA. 

A ‐ 10 D/4114/2011



Vessels 


Rock dumping and 

other deposits of 

the seabed 

Fisheries liaison 

Machinery space 

drainage from 

shipping 

The Petroleum Act 1998 Regulators: DECC supported by Marine Scotland and CEFAS and within territorial waters Scottish Government Marine Directorate 

Model Clauses of Licence 

HSE Offshore Safety Division Operations 

Notice 3 

The Merchant Shipping (Prevention of Oil 

Pollution) Regulations 1996 ( as amended 

2000 and 2005) (as amended by the Merchant 

Shipping (Implementation of Ship‐Source 

Pollution Directive) Regulations 2009) 

Deposits in the sea were regulated through the MCAA but, as a result of the Petroleum Act 1998 this does not apply to anything done: 

(a) for the purpose of constructing a pipeline as respects any part of which an authorisation (within the meaning of Part III of the 

Petroleum Act 1998) is in force; or 

(b) for the purpose of establishing or maintaining an offshore installation within the meaning of Part IV of that Act. 

The equivalent of the DEPCON (deposition consent) required under the Petroleum Act 1998 for these activities is incorporated within 

the PWA process. Similarly, the DISCON (discharge consents) required under the Act is incorporated within the PON 15 process. 

However, a licence is required for “the deposit, by means of seabed injection, of material arising from offshore hydrocarbon exploration 

and production operations” and for deposits of rock, mattresses etc (excluding rig stabilisation) 


From the 7 th and 8 th Licensing rounds onwards, operators have been required to appoint a Fisheries Liaison Officer to liaise with the 

fishing industry and Government Fisheries Departments on exploration and production activities. 

HSE Offshore Safety Division Operations Notice 3, Liaison with Other Bodies, June 2008 outlines liaison routes to improve 

communication between operators and other users of the sea and includes a requirement for a Fisheries Liaison. 


These regulations implement MARPOL Annex I (Prevention of Pollution by Oil) into UK legislation. 

Within a ‘Special Area’ ships which are 400GT or above can discharge water from machinery space drainage providing the oil content of 

the water does not exceed 15ppm. Vessels must be equipped with oil filtering systems; automatic cut offs and oil retention systems. All 

vessels must hold an approved Shipboard Oil Pollution Emergency Plan (SOPEP) and must maintain a current Oil Record Book and the 

ship must be proceeding on its voyage. 

All vessels must hold a UKOOP certificate or an IOPC certificate for foreign ships. Installations can obtain a temporary exception from 

MCA under an informal agreement between the UKO&G and the MCA, however new installations need to demonstrate their 

‘equivalence’ to other offshore installations where temporary installations are being issued and they are unlikely to obtain a certificate 

unless they fully comply with the requirements. Note, if all machinery drainage is routed via the hazardous or non‐hazardous drainage 

systems this will fall under OPPC and not require a UKOOP certificate. 

MARPOL 73/78 also defines a ship to include "floating craft and fixed or floating platforms" and these are required where appropriate to 

comply with the requirements similar to those set out for vessels. 

The amendments made under the Merchant Shipping (Implementation of Ship‐Source Pollution Directive) Regulations 2009 close an 

D/4114/2011 A ‐ 11

Waste from 

vessels and 

construction 

Sewage from 

vessels 

existing loop hole, where some large oil and chemical spills were not open to prosecution under MARPOL. 



MARPOL 73/78 Annex V Annex V totally prohibits the disposal of plastics anywhere into the sea, and severely restricts discharges of other garbage from ships 

into coastal waters and "Special Areas". 

The Merchant Shipping (Prevention of 

Pollution by Sewage and Garbage) Regulations 

2008 (as amended 2010) 

MARPOL 73/78 Annex IV Regulations for the 

Prevention of Pollution by Sewage from Ships 

The Annex also obliges Governments to ensure the provision of facilities at ports and terminals for the reception of garbage. 

The special areas established under the Annex are: 

the Mediterranean Sea 

the Baltic Sea Area 

the Black Sea area 

the Red Sea Area 

the Gulfs area 

the North Sea 

the Wider Caribbean Region and 

Antarctic Area 

Regulator: Maritime and Coastguard Agency 

The Merchant Shipping (Prevention of Pollution by Sewage and Garbage) Regulations 2008 implements Annexes IV and V of MARPOL 

and supersedes The Merchant Shipping (Prevention of Pollution by Garbage) Regulations 1998) 

Under the regulations all wastes are to be segregated and stored and returned to shore for disposal and no garbage can be dumped 

overboard in a ‘Special Area’ 

Food waste can be discharged only if: 

Greater than 12 miles from coastline; and 

Ground to less than 25mm particle size. 

Vessels must have a garbage management plan with suitable labelling and notices displayed. 


Requirement for ships to discharge sewage only under certain conditions: 

Comminuted and disinfected sewage may only be discharged more than 4nm from the coast; 

Non‐comminuted or disinfected sewage may only be discharged 12nm from the coast; 

Original international regulations entered into for in September 2003 and the revised annex entered into force in 2005. 

This does not apply of offshore installations as defined in the Petroleum Act 1998. 

A ‐ 12 D/4114/2011



Atmospheric 

emissions from 

vessels 


Pollution by Sewage and Garbage) Regulations 

2008 (as amended 2010) 

MARPOL 73/78 Annex VI the Prevention of Air 

Pollution from Ships 

The Merchant Shipping (Prevention of Air 

Pollution from Ships) Regulations 2008 (as 

amended 2010) 


Implements Annexes IV and V of MARPOL 

Supersedes The Merchant Shipping (Prevention of Pollution by Garbage) Regulations 1998) 

No consent is required unless the vessel is >400 GRT or

Antifouling coating 

on vessels 

Discharges 

Vessel movements 

International Convention on the Control of 

Harmful Antifouling Systems on Ships 2001; EC 

Regulation 782/2003 on the Prohibition of 

Organotin Compounds on Ships 

The Merchant Shipping (Anti‐Fouling Systems) 

Regulations 2009 

EC Directive 76/464 

Surface Waters (Dangerous Substances) 

(Classification) Regulations 1998 

OSPAR and Helsinki Conventions 



2005 (as amended 2011) 




(replaced the Prevention of Oil Pollution Act 

1971) 





2010) PON 15c 

International Regulation for Preventing 

Collisions at Sea 1972 (COLREGS) (as amended 

1981, 1987, 1989, 1993, 2001 and 2007) 

The 2010 amendments primarily implement provisions concerning the sulphur content of marine fuels 



It was proposed by the International Convention on the Control of Harmful Antifouling Systems on Ships that the use of tributyltin (TBT) 

will be banned on new vessels from 2003 with a total ban on all hulls from 2008. However, currently, in the UK, the use is only restricted 

under the Surface Waters (Dangerous Substances) (Classification) Regulations, 1997. Additionally, it is listed as a priority hazard 

substance under the Water Framework Directive, for priority action under the OSPAR and Helsinki Conventions and it’s sale and use are 

restricted under the Control of Pesticides Regulations (as amended). 

EC Regulation 782/2003 prohibits ships from having organotin compound based anti‐fouling paints applied to their hulls or other 

external surfaces, and it establishes a survey and certification regime in relation to anti‐fouling systems. The Merchant Shipping (Anti‐ 

Fouling Systems) Regulations 2009 implements the EC Regulation into UK law. 

EC Directive 76/464 deals with pollution cause by certain dangerous substances discharged into the aquatic environment. The Surface 

Waters (Dangerous Substances) (Classification) Regulations 1998 prescribe a system for classifying the quality of inland freshwaters, 

coastal waters and relevant territorial waters with a view to reducing the pollution of those waters by the dangerous substances within 

List II of EC Directive 76/464. 


As with drilling, discharges contaminated with reservoir oil during installation require an OPPC permit. These can be either term permits 

or life permits depending on the duration of the discharge. Under the 2011 amendments to the OPPC, a permit is now required for 

discharges from pipelines. An OPPC permit is not required if the discharge originated from a vessel covered by the Merchant Shipping 

(Prevention of Oil Pollution) Regulations. Under the Energy Act 2008 (Consequential Modifications) (Offshore Environmental Protection) 

Order 2010, permits now extend to CCS activities. 

A permit is required for discharge of oil to sea and is obtained from DECC. Specific monitoring and reporting requirements will be 

included on each permit. Reporting is via the Environmental Emissions Monitoring System (EEMS). 


Under these Regulations, offshore pipeline installations need to apply for permits to cover both the use and discharge of chemicals. 

Under the 2011 amendments, this applies to both operational and non‐operational emissions of chemicals, for example, accidental leaks 

or spills. The permits are applied for through the PON15c online application form (UKoilPortal). The application requires a description 

of the work carried out, a site specific EIA and a list of all the chemicals intended for use and or discharge, along with a risk assessment 

for the environmental effect of the discharge of chemicals into the sea. The permit obtained may include conditions. 

Permits now extend to CCS activities under the Energy Act 2008 (Consequential Modifications) (Offshore Environmental Protection) 

Order 2010. 

Regulator: IMO 

The COLREGs are designed to minimise the risk of vessel collision at sea and apply to all vessels on the high seas. They include 38 rules 

divided into five sections: 

A ‐ 14 D/4114/2011



The Merchant Shipping (Distress Signals and 

Prevention of Collisions) Regulations 1996 

Part A – General 

Part B ‐ Steering and Sailing 

Part C ‐ Lights and Shapes 

Part D ‐ Sound and Light signals 

Part E ‐ Exemptions. 

There are also four Annexes containing technical requirements concerning lights and shapes and their positioning; sound signalling 

appliances; additional signals for fishing vessels when operating in close proximity, and international distress signals. 

The Merchant Shipping (Distress Signals and Prevention of Collisions) Regulations 1996 the COLREGS into UK law. Vessels to which these 

regulation apply must comply with Rules 1‐36 of Annexes I to III of the COLREGS 

D/4114/2011 A ‐ 15

Commissioning and Operations 


Discharges of 

linefill and 

hydrotest fluids 

Displacement 

water 

Chemical use and 

discharge 

Dangerous goods 



The Petroleum Act 1998 Regulator: DECC supported by Marine Scotland and CEFAS and within territorial waters Scottish Government Marine Directorate 



2005 (as amended 2011) 





amended 2011) 




PON 15 c, d and f 

The Merchant Shipping (Dangerous Goods and 

Marine Pollutants) Regulations 1997 

Deposits in the sea, including liquid discharges, were regulated through the MCAA but, as stated above, as a result of the Petroleum Act 

1998 this does not apply to anything done: 

(a) for the purpose of constructing a pipeline as respects any part of which an authorisation (within the meaning of Part III of the 

Petroleum Act 1998) is in force; or 

(b) for the purpose of establishing or maintaining an offshore installation within the meaning of Part IV of that Act. 

Discharges of linefill and hydrotest fluids are permitted under the Petroleum Act 1998 and this is incorporated and permitted within the 

PON 15c process. 


The discharge of oil requires an OPPC permit which are issued by DECC. The 2011 amendments to the regulations extend permits 

requirements to pipelines as well as installations. Specific monitoring and reporting requirements will be included on each permit. 

Reporting is via the EEMS. 


Under these Regulations, offshore pipeline installations need to apply for permits to cover both the use and discharge of chemicals. 

Under the 2011 amendments, permits now apply to both operational and accidental releases. Types of permit required for the 

operations would be: 

PON15 c for use and discharges from pipelines 

PON15 d for use and discharges during operations 

PON15 f for use and discharges during workovers /intervention operations 

The permits are applied for through the PON15 online application form (UKoilPortal). The application requires a description of the work 

carried out, a site specific environmental impact assessment and a list of all the chemicals intended for use and or discharge, along with 

a risk assessment for the environmental effect of the discharge of chemicals into the sea. The permit obtained may include conditions. 

Note: Permits now extend to carbon sequestration activities under the Energy Act 2008 (Consequential Modifications) (Offshore 

Environmental Protection) Order 2010. 


The regulations require that dangerous goods and marine pollutants are labelled and packed according to the International Maritime 

A ‐ 16 D/4114/2011



Chemical data 

sheets and 

labelling 

Machinery space 

drainage from 

shipping 

Radioactive 

sources 

Produced water 

The Chemicals (Hazard Information and 

Packaging for Supply) Regulations 2002 

(revoked by the Chemicals (Hazard 

Information and Packaging for Supply) 

Regulations 2009) 

The Merchant Shipping (Prevention of Oil 

Pollution) Regulations 1996 (as amended 2000 

and 2005) (as amended by the Merchant 

Shipping (Implementation of Ship‐Source 

Pollution Directive) regulations 2009) 

Dangerous Goods (IMDG) code and that dangerous goods declarations are provided to vessel masters prior to loading. 

Regulator: Health and Safety Executive 

The transport of chemicals to and from offshore fields is principally by road to shore base and then by sea. These regulations 

(commonly known as CHIP 3) specify safety data sheet format and contents and required packaging and labelling of chemicals for 

supply. 

The 2009 regulations, CHIP4, consolidate all amendments made to the Chemicals (Hazard Information and Packaging for Supply) 

Regulations since 2002. 


The Merchant Shipping (Prevention of Oil Pollution) Regulations 1996 (as amended) implement Annex I of MARPOL into UK legislation. 

Within a ‘Special Area’ ships which are 400GT or above can discharge water from machinery space drainage providing the oil content of 

the water does not exceed 15ppm. Vessels must be equipped with oil filtering systems; automatic cut offs and oil retention systems. All 

vessels must hold an approved Shipboard Oil Pollution Emergency Plan (SOPEP) and must maintain a current Oil Record Book and the 

ship must be proceeding on its voyage. 

All vessels must hold a UKOOP certificate or an IOPC certificate for foreign ships. Installations can obtain a temporary exception from 

MCA under an informal agreement between the UKOG and the MCA, however new installations need to demonstrate their 

‘equivalence’ to other offshore installations where temporary installations are being issued and they are unlikely to obtain a certificate 

unless they fully comply with the requirements. Note, if all machinery drainage is routed via the hazardous or non‐hazardous drainage 

systems this will fall under OPPC and not require a UKOOP certificate. 

MARPOL 73/78 also defines a ship to include "floating craft and fixed or floating platforms" and these are required where appropriate to 

comply with the requirements similar to those set out for vessels. 

The amendments made under the Merchant Shipping (Implementation of Ship‐Source Pollution Directive) Regulations 2009 close an 

existing loop hole, where some large oil and chemical spills were not open to prosecution under MARPOL. 

Radioactive Substances Act 1993 Regulator: SEPA or Environment Agency (EA) 



2005 (as amended 2011) 


A certificate, issued by SEPA or EA is required for any new sources brought onto installations. The application must refer to all 

temporary or permanent radioactive sources taken offshore. The certificate must be displayed or be easily accessible to those whose 

work activity may be affected. 

Amendments to the Act are scheduled to come into force in October 2011 (see pending legislation). 


Discharge limits under OPPC are: 

A monthly average oil‐in‐water concentration of 30mg/l; 

D/4114/2011 A ‐ 17

Hazardous and 

non‐hazardous 

drainage 

(excluding 

machinery space 

drainage) 

Well workover, 

intervention and 

service fluid 

discharges 

Maintenance and 

cleaning 



Convention on the Protection of the Marine 

Environment of the North East Atlantic 1992 

(OSPAR Convention) 

OSPAR Recommendation 2001/1 For the 

Management of Produced Water on Offshore 

Installations (as amended by 

Recommendation 2006/4) 



2005 (as amended 2011) 






2005 (as amended 2011) (as amended by the 

Energy Act 2008 (Consequential 


Protection) Order 2010) 





2010) 






A maximum oil‐in‐water concentration of 100mg/l with no more than 4% of samples in any month to exceed this; 

Each installation has a specific discharge limit expressed as cubic meters per day. 

In addition, each installation will have permit for re‐injection of produced water. Permits now extend to pipelines, under the 2011 

amendments to the OPPC regulations. 

Monthly reporting of produced water discharges is via EEMS. Bi‐annual sampling and analysis is required for total aliphatics, total 

aromatics and total hydrocarbons (BTEX, NPDs, PAHs, organic acids, phenols and heavy metals). Other specific monitoring requirements 

are attached to each permit. 

Regulators: DECC 

OSPAR Recommendation 2001/1 (as amended) requires that no individual offshore installation exceeds a performance standard for 

dispersed oil of 30 mg/l for produced water discharged into the sea. It also required a 15% reduction in the discharge of oil in produced 

water from 2006 measured against a 2000 baseline; controlled by the issue of permits to each installation. This is implemented under 

OPPC. 


Requires a permit for hazardous drainage and non‐hazardous drainage discharges. Specific monitoring and reporting requirements are 

required on each schedule permit. Reporting is via EEMS. 

Permits now extend to pipelines under the 2011 amendments and to CCS activities under the Energy Act 2008 (Consequential 

Modifications) (Offshore Environmental Protection) Order 2010. 


The OPPC requires a permit for well workover, intervention and service fluid discharges. Under these regulations a permit is not 

required for the discharge of OBM/OPF and SBMs as these are permitted under the Offshore Chemical Regulations 2002 (as amended). 

However any material being discharged or reinjected that has been contaminated by hydrocarbons from the reservoir will require a 

permit. Specific monitoring and reporting requirements are included on each schedule permit and reporting is via EEMS. 

Note: Under the Energy Act 2008 (Consequential Modifications) (Offshore Environmental Protection) Order 2010, permits now extend 

to carbon sequestration activities. 


The OPPC requires a permit for maintenance and cleaning discharges, however it may be possible to include it in an existing permit. 

A ‐ 18 D/4114/2011



discharges 

Other minor oily 

discharges 

Oily sand and 

sludge 

Combustion 

emissions 
















EC Directive 2008/1 on Integrated Pollution 

Prevention and Control (IPPC) (replacing EC 

Directive 96/61) (as amended by EC Directive 

2009/31) 

Pollution Prevention and Control Act 1999 

(applies to waters outside the 3nm limit) 

Environmental Permitting (England and Wales) 


The Pollution Prevention and Control 

(Scotland) Regulations 2000 (as amended 

2008) 

Permits extend to both installations and pipeline under the Offshore Petroleum Activities (Oil Pollution Prevention and Control) 

(Amendment) 2011. Specific monitoring and reporting requirements are included on each schedule permit and reporting is via EEMS. 


to CCS activities. 


The OPPA requires a permit for minor oily discharges such as those associated with BOP actuation, subsea valve actuation, subsea 

production start‐up and pipeline disconnection. Specific monitoring and reporting requirements are included on each schedule permit 

and reporting is via EEMS. 


to CCS activities. 


The OPPA requires permits for discharge of oily substances to sea with measurement and reporting of total oil and sand discharged. A 

permit is required to discharge oil contaminated sand and scale. Under the 2011 amendments, permits now extend to pipelines. 


to carbon sequestration activities 

The IPPC Directive requires industrial and agricultural activities with a high pollution potential to have a permit. This permit can only be 

issued if certain environmental conditions are met, so that the companies themselves bear responsibility for preventing and reducing 

any pollution they may cause. 

Annex I of the Directive defines all applicable industrial and agricultural activities, including combustion installations located on offshore 

oil and gas platforms and, under EC 2009/31, CCS installations where an item of combustion plant on its own, or together with any other 

combustion plant installed on a platform, has a rated thermal input exceeding 50 MW(th). 


The Pollution Prevention and Control Act 1999 implements the EC IPPC Directive into UK law. More specifically Sections 1 and 2 of the 

Act confer on the Secretary of State power to make regulations providing for a new pollution control system to meet the requirements 

of the IPPC Directive and for other measures to prevent and control pollution. 

The Pollution Prevention and Control (Scotland) Regulations 2000 enact the IPPC Directive in Scotland and were made under the 

Pollution Prevention and Control Act 1999. 

The Environmental Permitting (England and Wales) Regulations 2007 came into force on 6 th April 2008 making existing legislation more 

efficient by combining Pollution Prevention and Control and Waste Management Licensing regulations. These were extended by the 

Environmental Permitting (England and Wales) (Amendment) (No.2) Regulations 2010 which aim to simplify the permitting process and 

came into force October 1 st 2010. 

The regulations require operators to apply for a permit for new offshore combustion processes which are to be permanently installed 

D/4114/2011 A ‐ 19

CO2 Combustions 

Sources and 

Emissions 

Offshore Combustion Installation (Prevention 

and Control of Pollution) Regulations 2001 (as 

amended 2007) 

EC Directive 2003/87 establishing a scheme 

for greenhouse gas emission allowance 

trading with the community 



and, on its own or in addition to existing equipment on that installation, will result in a thermal rated input greater than 50MW. 

Requirements included: 

The operator to apply for a permit, in writing to Secretary of State with prescribed information detailed in the Regulations. 

Secretary of State will publish applications in the Gazettes specifying where applications can be obtained, and specifying a 

date not less than 4 weeks from the final Gazette publication, by which public will be permitted to make representations; 

Public consultation period must be at least 28 days; 

Permit will either be granted, along with conditions, or rejected (reasons for rejection will be given). 

Regular permit reviews are required to check whether the permit conditions are still relevant. These will be carried out by DECC at least 

once every five years. Following which the Department may either request an application for a permit variation or proceed to issue a 

revised permit. 

The 2001 Regulations implement the IPPC Directive and apply to combustion installations located on offshore oil and gas platforms and 

where an item of combustion plant on its own, or together with any other combustion plant installed on a platform, has a rated thermal 

input exceeding 50 MW(th). Under EC Directive 2009/31 and the Energy Act (Consequential Modifications) (Offshore Environmental 

Protection) Order 2010, the Offshore Combustion Installation (Prevention and Control of Pollution) Regulations 2001 permits now 

extend to installations on structures used for or in connection with gas storage or unloading activities 

The 2007 Amendments implement the amendments made to EC Directive 96/61 by the Public Participation Directive (which are 

included in the replacement EC Directive 2008/1 on IPPC) and bring in tighter requirements for public consultation as part of the permit 

application process. 

The EU Emissions Trading Scheme (EU ETS) Directive was published in October 2003 and came into effect in January 2005. It aims to 

achieve reductions in GHG emissions as outlined in the Kyoto Protocol. The EU ETS Directive covers six GHG however, to date, only CO2 

is covered. The Directive applies to numerous installations, including those with combustion facilities with a combined rated thermal 

input of >20 MW (th). 

The Directive has been by three acts: 




The revised Directive outlines Phase III of the EU ETS, which will take place between 2013 and 2020. Phase III includes: 

Centralised, EU‐wide cap which will decline annually by 1.74% delivering an overall reduction of 21% below 2005 verified 

emissions by 2020. 

Adjustment of the EU ETS cap up to the 30% GHG reduction target when the EU ratifies a future international climate 

agreement. 

A significant increase in auctioning levels – at least 50% of allowances will be auctioned from 2013; compared to around 3% 

A ‐ 20 D/4114/2011



Ozone Depleting 

Substances 

Greenhouse Gas Emissions Trading Scheme 


The Greenhouse Gas Emissions Data and 

National Implementation Regulations 2009 

EC Regulation 842/2006 

Fluorinated Greenhouse Gases Regulations 

2009 

in Phase II. 

The revised EU ETS Directive will be transposed into UK law in two stages. Stage 1 by 31 st December 2009 and Stage 2 by the end of 2012 

(See pending legislation). 


Greenhouse Gas Emissions Trading Scheme Regulations 2005 (as amended) provide a framework for a GHG emissions trading scheme 

and implement Directive 2003/87/EC establishing a scheme for GHG emission allowance trading. A permit is required to emit GHG from 

combustion plants which an aggregate thermal rating of >20MW(th) and from flaring. The requirement must be registered and an 

application made from the UK allocation plan. 

Under the amendments made to the regulations by the Energy Act 2008 (Consequential Modifications) (Offshore Environmental 

Protection) Order 2010, “offshore installations” does not include gas storage and unloading installations within the seaward limits of the 

territorial sea adjacent to Wales or Scotland. 

The Regulations give effect to two parts of the EU ETS Directive. Firstly, the Regulations enable specified GHG emissions data to be 

collected. Secondly, the Regulations enable production and other data to be collected for the purpose of enabling the United Kingdom, 

as it is required to do so by the Directive, to publish and submit to the European Commission its national implementation measures for 

the third phase of the GHG emission allowance trading scheme which commences on 1st January 2013 (EU ETS Phase III). 


Provisions relating to the control and prohibition of F‐gas emissions including: 

Prevent and repair detected leakages of F‐gases from all equipment covered by the EU F‐Gases Regulation. 

Undertake periodic leakage inspections to equipment that contains 3kg or more of F‐gases 

Maintain records 

Monitor and annually report (by 31 March each year) data to EEMS on all emissions of HFCs / PFCs and SF6 from relevant 

equipment 

The Fluorinated Greenhouse Gases Regulations 2009 prescribe offences and penalties applicable to infringements of EU 

Regulation 842/2006 on certain fluorinated greenhouse gases (F gases), amongst others, as well as dealing with other 

requirements relating to leakage checking, reporting and labelling, together with proposed powers for authorised persons to 

enforce these Regulations. 

There Regulations also give effect to the following EC Regulations relating to certain fluorinated GHGs: 

- EC Regulation 1493/2007 








D/4114/2011 A ‐ 21

Flaring and 

Venting 

Nearshore 

Discharges 

EC Regulation No 1005/2009 on substances 

that deplete the ozone layer (as amended by 

EC Regulation No 744/2010) 

The Environmental Protection (Controls on 

Ozone Depleting Substances) Regulations 

2002 (as amended 2008) 




The regulations now extend to carbon sequestration activities under the Energy Act 2008 (Consequential Modifications) 

(Offshore Environmental Protection) Order 2010. 

These regulations consolidate and replace EC Regulation 2037/2000 as amended by introducing tighter controls on the use/reuse of 

certain controlled substances. 

UK Statutory Instruments providing for EC Regulation 2037/2000 will continue to be in force until updated/amended for the new 

consolidated Regulation (see pending legislation). 

EC Regulation No 744/2010 extends the cut off date for the use of certain essential uses of halons in fire protection systems 


Model Clauses of Licences Regulator: DECC 

EC Directive 2000/60 (The Water Framework 

Directive) (as amended by EC Directive 

2009/31) 

Implemented in England and Wales by: 

The Water Environment (Water Framework 

Directive) (England and Wales) Regulations 

The Environmental Protection (Controls on Ozone Depleting Substances) Regulations 2002 (as amended) make provision in the UK for EC 

Regulation 2037/2000 (as amended by Regulation no. 1005/2009 and 744/2010) and provide for a system of measures and penalties to 

control (amongst others) the emission of certain substances (in particular halons) that deplete the ozone layer. 

Controls the emissions from refrigeration systems, air‐conditioning units, fire‐protection systems and heat pumps. Requires operators 

to: 

Maintain annual records 

Check relevant equipment annually for leakages of ODS 

Monitor and annually report (by 31 March each year) data to EEMS on all emissions of halons, CFCs (if applicable) and HCFCs from 

relevant equipment. 

Due to the recent amendments to the EC regulations, further amendments to the UK legislation are required (see pending legislations). 

The Model clauses are incorporated into the Production Licences and require a flare and venting consent to be granted by DECC. Annual 

flare consents must be obtained from DECC. During commissioning and start up flare consents for short durations can be issued until 

flaring levels have stabilised. Flaring requirements must not exceed installations’ flare consent. 

Regulator: SEPA and EA 

The Water Framework Directive’s ultimate objective is to achieve “good ecological and chemical status” for all Community waters by 

2015. Other objectives include: 

preventing and reducing pollution 

promoting sustainable water usage 

environmental protection 

A ‐ 22 D/4114/2011



Sewage from 

installations 

Waste 

2003 

The Water Resources Act 1990 (superseded by 

the Water Resources Act 1991) 

Implemented in Scotland by: 

Water Environment and Water Services 

(Scotland) Act 2003 

the Water Environment (Controlled Activities) 

(Scotland) Regulations 2011 

Food and Environment Protection Act 1985 (as 

amended) 

Deposits in the Sea (Exemptions) Order 1985 

the Deposits in the Sea (Exemptions) 

(Amended) (England and Wales) Order 2010 

(extends to England and Wales only) 

EC Directive 2006/12 (EU Waste Framework 

Directive) (repealed by EC Directive 

2008/98) ( as amended by EC Directive 

2009/31 

improving aquatic ecosystems. 

In the UK, discharges to controlled waters need consent from either SEPA or EA. The discharge of waste to coastal waters or estuaries is 

controlled by these regulations and requires consent obtainable from either SEPA or EA. The consent will have conditions associated 

with it, including volume, rate of discharge and concentrations of specified substances. 

The Water Environment (Controlled Activities) (Scotland) Regulations 2011 came into force on 31 st March 2011 and consolidate the 

Water Environment (Controlled Activities) Regulations 2005 and the Water Environment (Controlled Activities) (Scotland) Amendment 

Regulations 2007. 

Regulator: DECC supported by CEFAS and Marine Scotland 

Discharges of sewage, and grey and black water as part of routine operations are permitted discharges under the Deposits in the Sea 

(Exemptions) Order 1985. 

Deposits in the Sea (Exemptions) (Amendment) (England and Wales) Order 2010 came into force in April 2010 in England and Wales 

only, making minor amendments to the Deposits in the Sea (Exemption) Order 1985, however, the above still applies. 

The Waste Framework Directive establishes a legal framework for the treatment of waste in the EU. It aims at protecting the 

environment and human health through the prevention of the harmful effects of waste generation and waste management. It does not 

apply to the following (which are captured under various other regulations discussed): 

gaseous effluents 

radioactive elements 

decommissioned explosives 

faecal matter 

waste waters 

animal by‐products 

carcasses of animals that have died not from being slaughtered 

elements resulting from mineral resources 

National Waste Strategy Commits the UK to a target of cutting landfill of biodegradable waste by two thirds by 2020. 

MARPOL Annex V: Prevention of pollution by 

garbage from ships 


Pollution by Sewage and Garbage from Ships) 



There have been significant amendments to Annex V of MARPOL since it first entered into force in 1998. The Merchant Shipping 

(Prevention of Pollution by Sewage and Garbage from Ships) Regulations 2008 (as amended) supersede Merchant Shipping (Prevention 

of Pollution by Garbage from Ships) Regulations 1998 and bring the previous implementing regulations into line with the current version 

of Annex V. 

D/4114/2011 A ‐ 23

Environmental Protection Act 1990 – Duty of 

Care (replaced by the Environmental 

Protection (Duty of Care) Regulations 1991) 

Environmental Protection (Duty of Care) 

(England) (Amendment) Regulations 2003 

Hazardous Waste Regulations (England and 

Wales) 2005 (as amended 2009) 

Special Waste (Scotland) Regulations 1997 (as 

amended) has been superseded by the Special 

Waste Amendment (Scotland) Regulations 

2004. 

The Waste Batteries (Scotland) Regulations 

2009 

Under the regulations: 



All wastes to be segregated and stored and returned to shore for disposal. 

No garbage to be dumped overboard from an installation (including incinerator ashes from plastics as they may contain toxic 

or heavy metal residues). 

Food waste can be discharged only if ground to less than 25mm particle size. 

Installation must have a garbage management plan and suitable labelling and notices displayed. 

Regulator: EA and SEPA 

Duty of Care requires correct segregation, identification and disposal of wastes. 

Regulator: EA and SEPA 

Under these Regulations waste transfer notes (for general waste) and Waste Consignment Notes (for waste designated ‘Special’ in 

Scotland or ‘Hazardous’ in England and Wales) are to be used for hazardous wastes. In addition, the regulatory authorities need to be 

notified regarding the disposal of hazardous or special waste. 

Regulator: SEPA 

The Waste Batteries (Scotland) Regulations amends the Pollution Prevention and Control (Scotland) Regulations 2000/323 to ban 

incinerating waste industrial and automotive batteries and amends the Landfill (Scotland) Regulations 2003/235 to ban waste industrial 

and vehicle batteries from landfills. 

Rock dumping etc Petroleum Act 1998 Regulators: DECC supported by Marine Scotland and CEFAS and within territorial waters Marine Scotland or DEFRA 

Deposit of Materials Consent (DepCon) is required for the deposit of materials e.g. rock dumping or mattresses. This forms part of the 

Pipeline Works Authorisation (PWA) application process. 

A licence under the MCAA is required in cases where not covered by a PWA, for example: 

Pipeline crossing preparations or other works before a PWA or related Direction is in place 

Installation of certain types of cable, e.g. communications cables 

A ‐ 24 D/4114/2011



Decommissioning 


Chemical use and 

discharge 

Preliminary 

discussions 

Decommissioning 

proposals 





2010) 

PON 15e 

Petroleum Act 1998 (as amended by the 

Energy Act 2008 and in accordance with 

OSPAR Decision 98/3 ) 

IMO Guidelines and Standards for the 

removal of offshore installations and 

structures on the continental shelf 1989 

DECC Guidance note for Industry 

Decommissioning of Offshore Installations 

and Pipelines 2009 


Under these Regulations, permits to use and discharge chemicals, including decommissioning chemicals, need to be obtained. Types 

of permit required for the operations would be a PON15e for use and discharges of chemicals during decommissioning. The permits 

are applied for using the application form found at https://www.og.decc.gov.uk/regulation/pons/index.htm and emailed to 

Environmental Management Team at DECC. The application requires a description of the work carried out, a site specific 

environmental impact assessment and a list of all the chemicals intended for use and/or discharge, along with a risk assessment for 

the environmental effect of the discharge of chemicals into the sea. The permit obtained may include conditions. 

Permits now extend to operational and non‐operational emissions of chemicals under the 2011 amendments and to carbon 

sequestration activities under the Energy Act 2009 (Consequential Modifications) (Offshore Environmental Protection) Order 2010. 


OSPAR Decision 98/3 concerns the decommissioning of installations. It requires that decommissioning will normally remove the 

whole of an installation, although there are some exceptions for large structures. However, currently, there are no international 

guidelines for the decommissioning of pipelines. 

Under the terms of the OSPAR Decision 98/3 there is a prohibition on dumping and leaving wholly or partly, in place of offshore 

installations. All installations installed post 1999 should be removed entirely. For those installed pre 1999 the topsides must be 

returned to shore and all installations with a jacket weight of less than 10,000 tonnes completely removed for re‐use, recycling or final 

disposal on land with installations of greater than 10,000 tonnes being considered on an individual basis with the base case being that 

they will be removed entirely. 

The Petroleum Act 1998 sets out requirements for undertaking decommissioning of offshore installations and pipelines including 

preparation and submission of a Decommissioning Programme. Decommissioning proposals for pipelines should be contained with a 

separate Decommissioning Programme from that of installations. However, programmes for both pipelines and installations in the 

same field may be submitted in one document. 

Part III of the Energy Act 2008 amends Part 4 of the Petroleum Act 1998 and contains provisions to enable the Secretary of State to 

make all relevant parties liable for the decommissioning of an installation or pipeline; provide powers to require decommissioning 

security at any time during the life of the installation and powers to protect the funds put aside for decommissioning in case of 

insolvency of the relevant party. 

The Petroleum Act 1998 as amended stipulated that a decommissioning programme needs to be prepared and agreed with DECC. 

The main stages of the decommissioning process are: 

Stage 1 ‐ Preliminary discussions with DECC 

D/4114/2011 A ‐ 25

Stabilisation Materials 

Power Generation 

Offshore Petroleum Production and 

Pipelines (Assessment of Environmental 

Effects) Regulations 1999 (as amended 

2007) 

Pipelines Safety Regulations 1996 (as 

amended 2003) 

OSAPR Recommendation 2006/5 on a 

management scheme for offshore cuttings 

piles 





Offshore Combustion Installations 

(Prevention and Control of Pollution) 

Regulations 2001 (as amended by the 




Stage 2 – Detailed discussions submission and consideration of a draft programme 

Stage 3 – Consultations with interested parties and the public 

Stage 4 – Formal submission of a programme and approval under the Petroleum Act 

Stage 5 – Commence main works and undertake site surveys 

Stage 6 – Monitoring of site 



Although there is no statutory requirement to undertake and EIA at the decommissioning stage, the decommissioning programme 

should be supported by and EIA The ES submitted for the development takes decommissioning into account, however, due to the 

lengthy period between the project sanction and decommissioning , the requirement for a detailed assessment of decommissioning is 

deferred until closer to the time of actual decommissioning and submitted as part of the Decommissioning Programme. 

These Regulations, administered by the Health and Safety Executive (HSE) provide requirements for the safe decommissioning of 

pipelines. 

This recommendation outlines the approach for the management of cuttings piles offshore. The assessment of the disposal options of 

cuttings takes into account a number of factors, including timing of decommissioning. 

Although most activities associated with exploration or production/storage operations that are authorised under the Petroleum Act or 

Energy Act are exempt from the MCAA, this exemption does not extend to decommissioning operations. A licence under the MCAA 

(and the Marine (Scotland) Act 2010) will be required for all decommissioning activities including: 

Removal of substances or articles from the seabed 

Disturbance of the seabed (e.g. localised dredging to enable cutting and lifting operations) 

Deposit and use of explosives that cannot be covered under an application for a Direction. 

Disturbance of the seabed e.g. disturbance of sediments or cuttings pile by water jetting during abandonment operations 

FEPA Licence was required for deposit of stabilisation or protection materials related to decommissioning operations, however, this 

has been replaced by the MCAA (see above). A licence under these acts will be required for all decommissioning activities and for any 

deposits, removals or seabed disturbance during abandonment 

As discussed previously, under the Offshore Combustion Installations (Prevention and Control of Pollution ) Regulations a permit is 

required if the aggregated thermal capacity of the combustion installation exceeds 50 MW(th). Such permits will have been issued 

prior to decommissioning operations and when aggregated thermal capacity falls below the 50 MW 9 th ) threshold during the course of 

decommissioning operations the installation will no longer be subject to the controls and the operators will be required to surrender 

the permit. 

A ‐ 26 D/4114/2011



The Greenhouse Gas Emissions Trading 

Scheme Regulations 2005 (as amended 

2007) 

Similarly, under these Regulations a permit is required to cover the emission of greenhouse gases if the aggregated thermal capacity 

of the combustion equipment on the installation exceeds 20 MW(th). Such permits will have been issued prior to decommissioning 

and must be surrendered when the aggregated thermal capacity falls below the threshold. The installation will then be deemed 

closed and will drop out of the EU TS. Installations will be able to retain and trade any surplus allowance for the year of closure, but 

will not receive any allowances for future years. 

D/4114/2011 A ‐ 27

Accidental Events 


Oil pollution 

emergency 

planning 

(Installations) 

Offshore Installations (Emergency Pollution 

Control) Regulations 2002 (as amended by the 

Energy Act (Consequential Modifications) 


2010) 

Offshore Chemical Regulations 2002 (as 


Act (Consequential Modifications) (Offshore 


Offshore Petroleum Activities (Oil Pollution 

Prevention and Control) Regulations 2005 (as 

amended 2011)(as amended by the Energy 

Act (Consequential Modifications) (Offshore 





In the event of an incident or accident involving an offshore installation where there may be a risk of significant pollution of the marine 

environment or where the operator fails to implement effective control and preventative operation the Government is given powers to 

intervene. 

DECC under agreement with MCA will notify Secretary of State Representative (SOSREP) in the event of an incident if there is a threat of 

significant pollution into the environment. The SOSREP’s role is to monitor and if necessary intervene to protect the environment in the 

event of a threatened or actual pollution incident in connection with an offshore installation. 

The Energy Act 2008 (Consequential Modifications) (Offshore Environmental Protection) Order 2010 amends the Offshore Installations 

(Emergency Pollution Control) Regulations 2002 to ensure that the powers of the Secretary of State to prevent or reduce accidental 

pollution extend to accidents resulting from CCS. 

These Regulations require all use and discharge of chemicals at offshore oil and gas installations to be covered under a permit 

system. Exceedance of discharge limits must be reported. 

Amendments to the Offshore Chemicals Regulations 2002, made under Schedule 2 of the Offshore Petroleum Activities (Oil Pollution 

Prevention and Control) Regulations 2005 (OPPC) increase the powers of DECC inspectors to investigate non‐compliances and risk of 

significant pollution from chemical discharges, including the issue of prohibition or enforcement notices. 

Under these Regulations it is an offence to make any discharge of oil other than in accordance with the permit granted under these 

Regulations for oily discharges (e.g. produced water). However, it will be a defence to prove that the breach of permit arose from an 

event that could not be reasonably prevented. 

Permits now extend to pipelines under the 2011 amendments and to carbon sequestration activities under the Energy Act 

(Consequential Modifications) (Offshore Environmental Protection) Order 2010. 

OSPAR Recommendation 2010/18 OSPAR recommendation 2010/18 on the prevention of significant acute oil pollution from offshore drilling activities came into force on 

24 th September 2010. 

Oil pollution The Merchant Shipping (Implementation of 

Ship‐Source Pollution Directive) Regulations 

According to OSPAR recommendation 2010/18, contracting parties should: 

Continue or, as a matter of urgency, start reviewing existing frameworks (i.e. the regulatory mechanisms and associated 

guidance applied by the Contracting Parties in the OSPAR area), including the permitting of drilling activities in extreme 

conditions. Extreme conditions include, but are not limited, to, depth, pressure and weather 

evaluate activities on a case by case basis and prior to permitting. 

EC Directive 2005/35 on ship‐source pollution and on the introduction of penalties for infringements states that ship‐source polluting 

discharges constitute in principle a criminal offence. According to the Directive this relates to discharges of oil or other noxious 

A ‐ 28 D/4114/2011



emergency 

planning 

(shipping) 

Pipeline 

emergency 

prevention 

2009 substances from vessels. Minor discharges shall not automatically be considered as offences, except where their repetition leads to a 

deterioration in the quality of the water, including in the case of repeated discharges 

The Merchant Shipping (Oil Pollution 

Preparedness, Response and Co‐operation) 


Pipeline Safety Regulations 1996 (as amended 

2003) 

The Directive applies to all vessels, polluting discharges are forbidden in: 

Internal waters, including ports, of the EU 

Territorial waters of an EU country 

Straits used for international navigation subject to the regime of transit passage, as laid down in the 1982 United Nations 

Convention on the Law of the Sea (UNCLOS) 

The exclusive economic zone (EZZ) of an EY country 

The high seas 

The Merchant Shipping (Implementation of Ship‐Source Pollution Directive) Regulations 2009 implement EU Directive 2005/35/EEC by 

making amendments to the following: 

The Merchant Shipping Act 1995 

the Merchant Shipping (Prevention of Oil Pollution) Regulations 1996 

The Merchant Shipping (Dangerous or Noxious Liquid Substances in Bulk) Regulations 1996 

The Regulations limit the defences available to the master or owner of a ship involved in an oil spill or chemical spill and extend liability 

for the discharge to others such as charterers and classification societies. This closed a loop hole in the existing legislation where some 

large spills were not open to prosecution under MARPOL. 


Requires the Operator to produce a site specific Oil Pollution Emergency Plan (OPEP) to be submitted to DECC and statutory consultees 

at least 2 months prior to start of activities. An OPEP needs to cover the procedures and reporting requirements on how to deal with an 

incident where hydrocarbons are being released into the sea. 

All approved OPEPs must be reviewed and resubmitted to DECC and consultees no later than five years after initial submission. In order 

to ensure adequate cover the operator must submit the plan at least 2 months prior to the end of this deadline. 

Regular reviews are further required to ensure response capabilities, operation details and contact details remain current. 

Vessels that are in transit will be covered under the SOPEP however when once on site and carrying out work for the operator the 

vessels should be covered by the operators OPEP. 

Under the Pipeline Safety Regulations 1996 (as amended): 

pipelines must be designated and constructed to ensure safe and effective shut‐down in the event of an emergency 

HSE must be notified of proposed pipeline construction 

pipelines must have emergency shutdown valves and major accident prevention documentation. 

D/4114/2011 A ‐ 29

Spill reporting 

Model Clauses of Licence 

PON 1 


All oil spills must be reported to DECC, the nearest HM coastguard and JNCC using a PON 1. 



A ‐ 30 D/4114/2011



Wildlife Protection 


Birds and other 

wildlife 

Protected sites and 

species 

SACs and SPAs 

EC Directive 2004/35 on Environmental 

Liability (as amended by EC Directive 2009/31) 

European Council Directive 79/409 (The Birds 

Directive) (as amended by EC Directive 

2009/147) 

European Council Directive 92/43/EEC (EC 

Habitats Directive) (and 97/62/EC and 

2006/105/EC amendments) 

Wildlife and Countryside Act 1981 (as 

amended 1991) 

Countryside and Rights of Way Act (CRoW) 

Act 2000 

Nature Conservation (Scotland) Act 2004 

The Conservation (Natural Habitats &c.) 

Regulations 1994 (The Conservation of 

Species and Habitats Regulations 2010 

consolidate all amendments made to the 

1994 regulations) 

The Directive establishes a framework for environmental liability based on the "polluter pays" principle, with a view to preventing and 

remedying environmental damage. 

Under the terms of the Directive, environmental damage is defined as: 

direct or indirect damage to the aquatic environment covered by Community water management legislation 

direct or indirect damage to species and natural habitats protected at Community level by the Birds or Habitats Directives 

direct or indirect contamination of the land which creates a significant risk to human health. 

The Birds Directive aims to protect ranges of species, as well as population and breeding, of certain populations of birds. 

Under the Birds Directive, Member States are to take measures to conserve certain areas, including the establishment of Special 

Protection Areas (SPAs) both on land and within UK territorial waters 

The main aim of the Habitats Directive is to promote the maintenance of biodiversity by requiring Member States to take measures to 

maintain or restore natural habitats and wild species listed on the Annexes to the Directive at a favourable conservation status, 

introducing robust protection for those habitats and species of European importance. 

The regulations provide for the designation and protection of Special Areas of Conservation (SACs) 

The Wildlife and Countryside Act consolidates and amends existing national legislation to implement the Birds Directive into UK law. 

The Act provides for the establishment of Sites of Special Scientific Interest (SSSIs). 

The CRoW Act applies to England and Wales only. The Act provides for public access on foot to certain types of land, amends the law 

relating to public rights of way, increases measures for the management and protection for Sites of Special Scientific Interest (SSSI), 

strengthens wildlife enforcement legislation, and provides for better management of Areas of Outstanding Natural Beauty (AONB). 

The Nature Conservation (Scotland) Act 2004 places duties on public bodies in relation to the conservation of biodiversity, increases 

protection for SSSI, amends legislation on Nature Conservation Orders, provides for Land Management Orders for SSSIs and associated 

land, strengthens wildlife enforcement legislation, and requires the preparation of a Scottish Fossil Code. 

The Conservation (Natural Habitats &c.) Regulations 1994 (as amended) transpose the Habitats and Birds Directives into UK law. They 

apply to land and to territorial waters out to 12 nautical miles from the coast and have been subsequently amended several times. The 

Conservation of Habitats and Species Regulations 2010 consolidate all the various amendments made to the Conservation (Natural 

Habitats, &c.) Regulations 1994 in respect of England and Wales. In Scotland the Habitats and Birds Directives are transposed through a 

combination of the Habitats Regulations 2010 (in relation to reserved matters) and the 1994 Regulations. 

The Conservation (Natural Habitats &c.) Amendment (Scotland) Regulations 2011 make amendments to the 1994 regulations (in 

Scotland only). The amendments place a legislative requirement on Scottish Ministers to classify SPAs in terrestrial and inshore 

D/4114/2011 A ‐ 31

Birds 

Cetaceans 

The Offshore Maine Conservation (Natural 

Habitats, &c) Regulations 2007 (as amended 

2009 and 2010) (as amended by the Energy 



2010) 

Offshore Petroleum (Conservation of 

Habitats) Regulations 2001 (as amended 

2007) 

The Petroleum Act 1998 

Convention on Wetland of International 

Importance Especially as Waterfowl Habitats 

1971 (The Ramsar Convention) 

Agreement on the Conservation of Small 

Cetaceans of the Baltic and North Seas 1991 

(ASCOBANS) and 2008 amendments 



environments. Since the Birds Directive first came into force in 1979, the UK government and Scottish Ministers (since devolution) have 

actively delivered this responsibility without a legislative requirement (153 SPAs have been classified in Scotland to date). In recent 

years, SPAs have been identified in accordance with agreed guidelines for the selection of SPAs which were published by the Joint 

Nature Conservation Committee (JNCC) in 1999. The amendments came into force on 6th April 2011. 

The Conservation of Species and Habitats Regulations 2010 also implement aspects of the Marine and Costal Access Act 2009 

These regulations transpose the Habitats Directive and the Birds Directive into UK law in relation to oil, gas and, , under the Energy Act 

2008 (Consequential Modifications) (Offshore Environmental Protection) Order 2010, CCS plans and projects in UK offshore waters (i.e. 

12 nautical miles from the coast out to 200nm or to the limit of the UK Continental Shelf Designated Area). 

The 2010 Amended Regulations make various insertions for new enactments (e.g. amendments to the Birds Directive by EC Directive 

2009/147) and also devolve certain powers to Scottish Ministers. 

The Offshore Petroleum (Conservation of Habitats) Regulations require consent to be obtained for geological surveys related to oil and 

gas activities undertaken on the UKCS. The 2007 amendments extend these provisions to UK waters (sea adjacent to UK from the low 

water mark up to the seaward limits of territorial waters), as well as requiring prior consent for the testing of equipment to be used in 

geological surveys. 

Regulation 5 of the 2001 Regulations requires the Secretary of State to consider whether an appropriate assessment should be 

undertaken prior to granting a licence under the Petroleum Act 1998, where the licence relates to an area wholly or partly on the UKCS. 

The amended Regulations extend this requirement to those licenses within UK waters. Licenses now extend to carbon sequestration 

activities in the UKCS as a result of the Energy Act 2008 (Consequential Modifications) Offshore Environmental Protection) Order 2010 

The Ramsar convention aims to prevent encroachment or loss of wetlands on a worldwide scale, recognising the importance of a 

network of wetlands on waterfowl. It is applicable to marine areas to a depth of 6m at low tide and other areas greater then 6m depth 

that are recognised as important to waterfowl habitat. 

Requires governments to undertake habitat management, conduct surveys and research and to enforce legislation to protect small 

cetaceans. 

Originally ASCOBANS only covered the North and Baltic Seas, as of February 2008 the ASCOBANS area has been extended to include the 

North East Atlantic and Irish Sea. 

A ‐ 32 D/4114/2011



Pending Legislation 


Emissions EU ETS Phase III (2013 – 2020) The aim of Phase III of the EU ETS will be to reduce EU emissions by 21% between 2005 and 2020. There will be no National Allocation 

Plans (NAPs) and allocations will managed centrally by the EU. 

Ozone depleting 

substances 


Liability 

The Climate Change Act 2008 

Climate Change (Scotland) Act, 2009 

Revision of the industrial emissions legislation 

in the EU 

EC Directive 2009/29 (which outlines Phase III) is being transposed into UK law, Stage 1 was completed by the end of 2009 and Stage 2 is 

scheduled for the end of 2012. 

The Climate Change Act intends to introduce powers to combat climate change by setting targets to reduce CO2 emissions by at least 

60% by 2050 and an interim target of 26‐32% by 2020, against a 1990 baseline. 

Similarly, the Climate Change (Scotland) Act targets for an 80% reduction in CO2 emissions from 1990 levels by 2050 with an interim 

target of 42% by 2020. The Act also requires that the Scottish Ministers set annual targets, in secondary legislation, for Scottish 

emissions from 2010 to 2050. 

On the 21st December 2007 the Commission adopted a Proposal for a Directive on industrial emissions. The proposal recast seven 

existing Directives related to industrial emissions into a single legislative instrument. This recast includes, in particular, The IPPC 

Directive, and six “sectoral” Directives, namely the Large Combustion Plants Directive (EC Directive 2001/80), the Waste Incineration 

Directive (EC Directive 2000/76), the Solvents Emissions Directive (EC Directive 1999/13), and three Directives relating to the production 

of titanium dioxide (EC Directives 78/176, 82/883 and 92/112). 

Fluorinated GHGs By 4th July 2011, the EU will publish a report on the application of the F‐Gases Regulation, which may lead to proposals for revising 

elements of it. This guidance document will consequently be amended by DECC in line with any future EU proposals that are adopted 

and which may require enforcement offshore. 

EC Regulation No 1005/2009 (and 744/2010 

amendments) on substances that deplete the 

ozone layer 

The Environmental Liability (Scotland) 

Regulations 2009 

EC Regulation No 1005/2009 came into force in January 2010. It consolidates and replaces EC Regulation 2037/2000 as amended by 

introducing tighter controls on the use/reuse of certain controlled substances. However, in August 2010 EC Regulation 1005/2009 was 

amended by EC Regulation 744/2010. EC Regulation No 744/2010 extends the cut off date for the use of certain essential uses of halons 

in fire protection systems. 

Amendments to existing UK Regulations will be required to ensure all requirements under the new EC Regulations are captured. 

However, UK Statutory Instruments providing for EC Regulation 2037/2000 will continue to be in force until updates/amendments 

incorporating the new EC Regulations come into force 

EC Directive 2009/31 on the geological storage of carbon dioxide amends the following directives to include CCS: 

85/337/EC 

2000/60/EC 

2001/80/EC 

2004/35/EC 

2006/12/EC 

D/4114/2011 A ‐ 33

Radioactive 

sources 

OSPAR Recommendation 2006/3 on 

Environmental Goals for the Discharge by the 

Offshore Industry of Chemicals that are, or 

which Contain Substances Identified as 

Candidates for Substitution ‐ UK National Plan 

The Radioactive Substances Act 1993 

Amendment (Scotland) Regulations 2011 

2008/1/EC 



The Environmental Liability (Scotland) Amendment Regulations 2011 amend the 2009 regulations in accordance with EC Directive 

2009/31 and come into force on 25 th June 2011. 

In line with OSPAR Recommendation 2006/3, contracting Parties to OSPAR should have phased out the discharge of offshore chemicals 

that are, or which contain substances, identified as candidates for substitution, except for those chemicals where despite considerable 

efforts, it can be demonstrated that this is not feasible due to technical or safety reasons. This should be done as soon as is practicable 

and not later than 1 January 2017 

A UK National Plan for a phase out of chemicals to meet the requirements of the OSPAR Recommendation is being developed. This will 

involve continuation of the PON15D permit review process and annual reporting to DECC, extending the scheme to term permits and 

development of a prioritised National List of Candidates for Substitution. 

As part of a UK wide project, the Scottish Government has reviewed the regime for exempting radioactive materials and radioactive 

waste from the need for registration and authorisation under Radioactive Substances Act 1993. The Radioactive Substances Act 1993 

Amendment (Scotland) Regulations 2011 come into effect on 1st October 2011 and will amend sections 1 and 2 of the Radioactive 

Substances Act 1993, changing the definitions of radioactive material and radioactive waste. These regulations apply to Scotland only. 

A ‐ 34 D/4114/2011

Flyndre and Cawdor Development Environmental Statement 

Appendix B – Environmental Impact Assessment 

APPENDIX B – ENVIRONMENTAL ASSESSMENT 

Potential impacts for each key project and associated environmental effect before and after mitigation measures. 

Key ‐ Risk 

Drilling Phase 


Aspect 

Emissions to air 

Key 

High Moderate Low 

Source 

Exhaust 


drilling 

operations (i.e. 

burning of fuel 

gas or diesel) 

Well clean up 

and testing 

Exhaust 


support vessels 

and helicopter 

transfers 

Activity 

Description 

Generation of power 

during the proposed 

drilling operations will 

result in emissions of 

various combustible 

gases. 

Flaring from the well 

clean‐up & well test will 

result in the emissions of 

various combustible 

gases. 

Support vessels consist 

of anchor handling 

vessels, supply vessels, 

standby vessels etc. 

Potential effects and significance of potential 

impacts 

May contribute to climate change (CH4, CO2), 

acidification effects (SOx, NOx) and potentially 

localised smog formation (VOC, NOx & 

particulates). Possible transboundary effects. 

Likelihood Consequence Risk 

5 1 Low 




particulates). Possible transboundary effects. 


5 1 Low 




particulates). 

Mitigation of impacts and 

actions to address 

concerns 

Audit to ensure rig 

complies with UK 

standards, engines are 

maintained and operated 

correctly. 

Use of low sulphur diesel in 

vessels. 

No extended well testing is 

planned. 

Minimise number of 

vessels and vessel travel 

time where possible. 

Residual impact 

and/or concern 

None envisaged as 

contribution of 

emissions to 

worldwide levels is 

negligible when 

compared to other 

industrial sources. 



emissions to 







emissions to 



D/4114/2011 B ‐ 1

Discharges to 

Sea 

Discharge of 

CFCs and HCFCs 

Halocarbon 

release during 

emergency 

events 

Deliberate 

discharges from 

drilling 

operations 

Contained and 

treated drilling 

fluids 

Traditionally CFCs have 

been utilised as a 

coolant medium in 

refrigeration units. 

Fire fighting systems can 

be designed to release 

harmful halocarbons. 

Brine, cementing 

chemicals & clean up 

chemicals all required in 

the drilling process 

Rotomill treated OBMs, 

OBM contaminated 

brine spacer, cuttings & 

cleaning chemicals. 

Other oily slops. 



Likelihood Consequence Risk compared to other 


5 1 Low 

CFCs contribute to ozone depletion and are 

regarded as greenhouse gases 


2 1 Low 

Halons cause depletion in the upper atmosphere 

and are regarded as greenhouse gases 


2 1 Low 

Short term impact on water quality and localised 

smothering of seabed and associated biota 


5 2 Moderate 

Release of untreated OBM’s can result in toxic or 

sub‐lethal effects on sensitive organisms and 

ecosystems. Bioaccumulation of heavy metals in 

marine organisms. Burial of benthic organisms/ 

modification to the benthic environment. 


5 1 Low 

Drilling rig contractors are 

phasing out the use of 

HCFCs in compliance with 

legal requirements. 

Drilling rig contractors are 

phasing out halons in 

compliance with legal 

requirements. 

Halocarbons will only be 

used in the event of a fire. 

Maximum efficient use of 

WBM. 

Use of PLONOR chemicals 

(i.e. low toxicity chemicals). 

All OBM’s will be processed 

using Rotomill % of oil on 

cuttings discharged



Contained and 

treated drainage 

water 

Liquid waste 

(domestic 

sewage & food 

waste) 

associated with 

drilling 

operations, 


etc. 

Disposal to land General waste 

from drilling 

operations and 

support vessels. 

Open drains collect spills 

& drainage water from 

all hazardous areas on 

the rig. 

These drains feed into 

the drainage cassion 

which provides oil & 

water separation. 

Discharge of sewage 

(grey & black water 

macerated to < 6mm 

prior to discharge via a 

sewage caisson). 

No discharge of food to 

sea. 

Drilling rigs and support 

vessels generate a 

number of wastes during 

routine operations 

including waste oil, 

chemical & oil 

contaminated water, 

scrap metal etc 

Uncontrolled discharge of oil in water can result 

in narcotic, toxic, teratogenic impacts and 

localised water column enrichment etc. 


2 2 Low 

Sewage and food waste has a high BOD resulting 

from organic & other nutrient matter in the 

detergents & human wastes that can impair 

water quality in the immediate vicinity of the 

discharge. 


5 1 Low 

Impacts associated with onshore disposal are 

dependent on the nature of the site or process. 

Landfills – land take, nuisance, emissions 

(methane), possible leachate, limitations on 

future land use. Treatment plants‐ nuisance, 

atmospheric emissions, potential for 

contamination of sites. 


5 1 Low 

MARPOL compliant 

filtration and monitoring 

equipment with discharges 

of oil in water at less than 

15ppm. 

Tanks and machinery 

spaces are fitted with 

bunding to collect spillages 

and waste. 

Drains are plugged on 

RVTL. 

Sewage treatment unit on 

board rig (MARPOL) and 

vessels to reduce BOD prior 

to discharge, this will aid 

biological breakdown on 

release. 

Wastes will be minimised 

by use of appropriate 

procurement controls. 

All wastes to be properly 

segregated for 

recycling/disposal 

/treatment onshore. 

Waste will be dealt with in 

accordance with regulatory 

requirements. 

D/4114/2011 B ‐ 3 

None 

None envisaged 

None envisaged

Physical 

presence 

Semi 

submersible 

drilling rig and 


Noise and 

vibration. 

Positioning of semi‐sub 

rig using anchors and 

chains 

Support vessel 

movements. Daily supply 

vessels anticipated. 

Sources include 

semi‐sub drilling 

operations & support 

vessels. 

The drilling rig will have an impact on the seabed 

due to the anchor spread. 

Presence of a rig and the increase in associated 

vessel movements has the potential to impact 

other users of the sea 


5 1 Low 

Generates elevated sound levels which can affect 

the behaviour of fish and marine mammals in the 

area. 


5 1 Low 



Rig moves will be 

minimised. 

Other users of the area will 

be notified. 

The rig will be present over 

a relatively short period of 

time for each well. 

Short term and very 

localised impact 

with the area 

expected to rapidly 

restore/ 

recolonise. 

No long term 

impacts to other 

users of the sea. 


B ‐ 4 D/4114/2011



Minor 

accidental 

events 

Chemical spills. Chemical storage‐ 

accidental spills, leaks, 

containment damage. 

Lube and 

hydraulic oil 

spills 

Accidental spillage of oils 

may result from 

rupture/corrosion of 

drums in storage; loss of 

containment during 

decanting; rupture of 

hydraulic hose in use. 

Spill may enter drainage 

system and be 

discharged to sea 

May result in a variety of impacts including 

increased chemical or biochemical oxygen 

demand, toxicity, persistence, bioaccumulation in 

animals 


2 2 Low 

Minor spillage that would impair water quality 

and marine life in immediate vicinity of discharge. 


2 2 Low 

Optimised quantities 

procured & stored. COSHH, 

Task Hazard Assessments 

are completed and MSDS 

sheets are available. 

All transfer operations 

suspended in rough 

weather. All bulk hoses and 

connections must be 

inspected before and after 

use by competent 

personnel. 

Chemicals stored in tote 

tank area. OPEP is 

implemented as 

appropriate in the result of 

a spill as per Emergency 

Response Process. 

Statutory reporting of all 

spills. 

Trained personnel 

undertake decanting 

operations. Storage tanks 

and hoses are subject to an 

inspection and engineering 

maintenance strategy. 

OPEP is implemented in 

the event of a spill as per 

Emergency Response 

Process. 

None envisaged. 


D/4114/2011 B ‐ 5

Diesel spills Accidental spillage 

during bunkering 

operations and rupture 

of diesel tanks. 

Oil spills Loss of hydrocarbon 

containment includes 

accidental discharges of 

untreated OBMs, OBM 

contaminated cleaning 

fluids, drillings etc. 

Impacts depend on spill size, prevailing wind, sea 

state & temperature & sensitivity of 

environmental features affected. Birds are most 

sensitive offshore receptor. Also affected are 

plankton, fish/fisheries, seabed animals & marine 

mammals. 


2 1 Low 

Impact dependent on spill volume and weather 

conditions. Birds are most sensitive offshore 

receptor. Also affected are plankton, 

fish/fisheries, seabed animals & marine 

mammals. 


2 2 Low 



Trained personnel involved 

in fuel transfer. Diesel 

storage tanks and transfer 

hoses are subject to 

inspection & engineering 


Bunded storage tanks. 

Annually replace bunker 

hoses on the NTvL. 




Process. 

Procedures in OPEP are 

implemented should a spill 

occur. Training is provided 

on oil spill response to all 

appropriate personnel. 

Maersk are members of 

OSRL (OSRL are on standby 

to provide oil spill clean‐up 

when required). Tanks 

have a spill over area. 


Diesel should rapidly 

evaporate and 

disperse. 

Spills may cause 

local elevation of 

hydrocarbon levels 

and contamination 

and toxic effects. 

B ‐ 6 D/4114/2011



Major 

accidental 

events 

Loss of well 

control /fire 

explosion 

Loss of drilling rig 

diesel 

Loss of control of well 

resulting in release of oil 

and gas which may 

ignite. 

Complete loss of rig fuel 

e.g. through loss of 

vessel. (NTvL has a fuel 

capacity of 1,143 tonnes) 

Damage to commercial fisheries, sediment and 

water quality impairment and release of 

atmospheric emissions. 


1 4 Moderate 

Potential impacts on marine life particularly sea 

birds. 


1 2 Low 

Dispersant on board 

standby vessel available for 

local response. 

Maersk member of OSRL 

Emergency Response Plan 

implemented in the result 

of a loss of well control/fire 

and explosion and 

activation of fire‐fighting 

systems. Regular drills 

held. 

Inspection &engineering 

maintenance strategy 

based on preventative 

maintenance. 




Process. 

Oil spill modelling has 

assessed the risk and 

consequence of loss of 

diesel inventory. 

OSPAR modelling 

suggests following a 

90 day uncontrolled 

spill during 

maximum flow 

rates, no coastline 

will be affected. 

30 days after spill is 

controlled

Installation Phase 


Aspect 

Greenhouse 

gases/ Air 

emissions 

Discharges to 

Sea 

Source 

Exhaust 

emissions 

associated with 


and installation 

of subsea 

infrastructure 

e.g. infield 

pipelines, 

manifolds, SSIV, 

concrete 

mattresses and 

rock placement. 

Discharge from 

pipeline pressure 

testing. 

Discharge of fluid 

from the open 

subsea control 

Activity 

Description 

Subsea wellheads will be 

fixed in position on the 

seabed surface. All 

infield pipelines and 

control lines will be 

trenched. This operation 

will require a trenching 

vessel with associated 

exhaust emissions. A 

separate vessel will 

complete the rock 

dumping if required. 

After installation 

pipelines need to be 

pressure tested. The 

lines are to be filled with 

potable water, dosed 

with methanol, & scale, 

corrosion and wax 

inhibitors. The displaced 

water, and chemical 

additives will be 

discharged to the sea 

Hydraulic control of 

subsea facilities. 

Control systems use 


impacts 






5 1 Low 

Localised effect on water quality associated with 

discharge to sea of water containing chemicals 

from hydrotesting of lines. 


5 1 Low 

In an open system fluids will be released to sea 

with resultant short term effects on local flora 

and fauna. 





concerns 

Minimise duration of 

pipeline trenching and rock 

placement operations. 

All chemicals will be risk 

assessed as part of 

Offshore Chemical 

Regulations requirements 

and reported in PON 15C. 

Discharge of fluids, if 

required, will be carried 

out in a manner which will 

minimise environmental 

impact. 

Only PLONOR chemicals 

will be added to the water 

based hydraulic fluids. 





emissions to 






Rapid dispersion and 

dilution will occur in 

close proximity to 

the discharge point. 


B ‐ 8 D/4114/2011



system. water based hydraulic 

fluid in an open system. 

Disturbance of 

Drill cuttings at 

Clyde 

Disposal to land General waste 

from pipelay, 

installation of 

infield infra‐ 

structure and 


Physical 

presence 

Installation 

vessels 

The installation of the 

riser and umbilical at the 

Clyde platform may 

disturb historic drill 

cuttings piles that 

contain Oil Base Mud 

cuttings. 

Pipelay & installation 

generate a number of 

wastes during routine 

operations including 

waste oil, scrap metal 

and domestic wastes. 

Presence of installation 

vessels. 


5 1 Low 

UKOOA study has found high levels of THC 

underneath the Clyde platform, these have the 

potential to impact upon benthic fauna and cause 

toxic effects. Contaminants are released when 

cutting piles are disturbed. 


5 2 Moderate 



Landfills – land take, nuisance, emissions 


future land use. Treatment plants‐ nuisance, 




5 1 Low 

Displace other marine users e.g. shipping and 

commercial fishing vessels are prohibited from 

entering the safety zones around installation 

vessels. 


5 1 Low 

Engineering will be made 

aware of cutting pile 

locations. Disturbance to 

the piles will be minimised 

by selecting appropriate 

riser location. 

To minimise waste Maersk 

Oil ‘s waste hierarchy of 

reduce, reuse, recycle will 

be followed. 

All wastes to be properly 

segregated for recycling 

/disposal onshore. 

Waste will be dealt with in 

accordance with regulatory 

requirements. 

The installation vessels will 

be present for as short a 

time as possible. 

Other users of the sea area 

will be notified of the 

planned operations. Guard 

vessels will operate to 

warn other users of the sea 

of planned activities. 

Potential for local 

release of 

hydrocarbons if 

cutting piles are 

disturbed within 

500 m of the 

platform. 

Contribute to 

pressures on land 

based waste 

disposal. Project 

associated wastes 

predicted to have a 

negligible impact. 

Only a temporary 

physical obstruction. 

No lasting residual 

impacts. 

D/4114/2011 B ‐ 9

Minor 

accidental event 

Infrastructure All infield subsea 

infrastructure; 

manifolds, wells, 

24.66km pipeline & 

control umbilical 

Noise Surface & subsea noise 

produced during 

operations, of which 

piling is likely to be the 

dominant sound source 

Chemical spills Chemical storage‐ 


containment damage 

Disturbance of benthic communities living in the 

trenched/ploughed areas & the possible wider 

smothering caused by the resultant sediment 

plume. Potential impacts to fishing activities. 


5 1 Low 



area. 


5 2 Moderate 




animals 


2 2 Low 



Minimisation of foot‐ print 

through design. 

Optimisation of pipeline 

route. 

Impact area is expected to 

rapidly restore/ recolonise. 

Adherence t principles 

within JNCC piling protocol 

e.g. use of MMO’s during 

piling activity. 


procured & stored. COSHH, 

Task Hazard Assessments 

are completed and MSDS 

sheets are available. All 

transfer operations 


weather. All bulk hoses and 

connections must be 



personnel. Chemicals 

stored in tote tank area. 

OPEP is implemented as 




Temporal physical 

disturbance effect 

on local benthic 

communities 

recovery expected 

with time. Hard 

structures will 

attract different 

species. 

Short term impact 

upon sensitive 

species, no impacts 

beyond the 

installation period 


B ‐ 10 D/4114/2011




hydraulic oil 

spills 

Accidental spillage of oils 

may result from 














and marine life in immediate vicinity of discharge. 


2 1 Low 






mammals. 


2 1 Low 

Storage tanks and hoses 

are subject to an inspection 

and engineering 





Process. 

Trained deck operations 

personnel. Diesel storage 

tanks and transfer hoses 

are subject to inspection & 

engineering maintenance 

strategy. Bunded storage 

tanks. OPEP is 

implemented in the event 

of a spill as per Emergency 

Response Process. Oil spill 

modelling completed as an 

integral part of OPEP. 



diesel should rapidly 


disperse, diesel 

evaporates 

contribute are a 

form of greenhouse 

gases. 

D/4114/2011 B ‐ 11

Production Phase 


Aspect 

Greenhouse 

gases/ Air 

emissions 

Source 

Flaring of 


Cawdor reservoir 

fluids 

Power 

requirement. 

Activity 

Description 

Flaring occurs during 

emergencies and 

blowdowns. 

No new power 

generation equipment 

will be installed and it is 

not anticipated that 

there will be no increase 

in fuel gas usage. 


impacts 

Flaring may contribute to climate change (CH4, 

CO2), acidification effects (SOx, NOx) and potential 

localised smog formation (VOC, NOx and 



2 1 Low 


acidification effects (SOx, NOx) and potential 

localised smog formation (VOC, NOx). 


5 1 Low 





concerns 

Compliance with Flaring 

Consent. Minimum start 

up frequency, adherence 

to good operating 

practices, maintenance 

programmes & 

optimisation of quantities 

of gas flared. 

UK and EU air quality 

standards not exceeded. 

Permit and EU ETS 

Monitoring and Reporting 

Plan. UK and EU air quality 

standards not exceeded. 

Fuel gas system is subject 

to an inspection and 


strategy. Compliance with 

EU ETS 





emissions to 








power generation 

from Flydre and 


development is 

negligible 

B ‐ 12 D/4114/2011



Discharges to Sea Produced water 

discharge 

Produced water is 

treated to reduce 

discharge of oil in water 

comprising condensed 

and formation water. 

Produced water will only 

be released when 

produced water 

injection facilities are 

not operational (

Drainage water Discharge of oily 

drainage water to sea. 

Open drains collect spills 

& drainage from all 

hazardous and non‐ 

hazardous areas of the 

platform. These drains 

feed into the drainage 

caisson which provides 

oil & water separation. 

Chemical 

discharges 

There will be a increase 

in chemical use 

associated with the 


development. This will 

not result in an increase 

in chemical discharges at 

the platform as 

chemicals will be 

transported entrained 

within reservoir 

hydrocarbons. 

Oil in water can result in narcotic, toxic, 

teratogenic and enrichment impacts. 


5 1 Low 

Chemicals released into the marine environment 

can result in a variety of impacts including 


demand, toxicity, persistence and 

bioaccumulation in animals. 


5 2 Low 



Regular maintenance of 

drainage system through 

inspection & engineering 

maintenance strategy with 

safety critical elements 

being subject to a higher 

degree of maintenance. 

Use of skimming pump. 

Talisman as the operator 

of the Clyde facility has a 

Company Policy to 

minimise waste which 

includes reducing the 

quantity of chemicals 

used. Usage must not 

exceed permit conditions. 

Tanks are fitted with 

overflow alarms. Drums 

are stored in bunded areas 

(at skids or in storage 

areas). Most equipment is 

provided with drip trays. 

Chemicals used are 

generally the lowest 

toxicity HQ category. 



B ‐ 14 D/4114/2011



Waste Liquid Waste 

(domestic 

sewage and food 

waste). 

Discharge of sewage 

(grey & black water 

macerated to < 6µm 

prior to discharge via a 

sewage caisson). 

Disposal of food waste 

to sea (macerated and 

discharged to sea). 

There will be no increase 

in liquid waste as a 

result of the production 

covered in this ES. 

Hazardous waste Onshore disposal of 

solid & liquid waste 

including chemical 

contaminated wastes, 

hydrocarbon 

contaminated wastes 

etc. 

Hazardous wastes 

produced by the Clyde 

platform will increase as 

a result of the 

production covered in 

this ES. 

Sewage and food waste has a high BOD resulting 

from organic & other nutrient matter in the 

detergents & human wastes that can impair 

water quality in the immediate vicinity of the 

discharge. 


5 1 Low 



Landfills ‐ land take, nuisance, emissions 


future land use. Treatment plants ‐ nuisance, 




5 1 Low 

A combined system of 

domestic drains handles all 

sanitary, kitchen and floor 

drainage. Domestic 

drainage is discharged 

untreated via the sewage 

disposal caisson. The 

domestic drainage system 

is separate from the 

process systems with no 

inter connection of pipe 

work eliminating the 

possibility of hydrocarbon 

contamination. Tidal 

currents and wave action 

will rapidly disperse the 

discharges. 

Talisman has a Company 

Policy to minimise waste. 

Waste segregated by 

personnel at source and 

stored in waste receptacle 

until transferred ashore for 

disposal. 

Waste Management 

Procedure of reduce reuse 

recycle is followed. 

Monthly reporting of 

waste returned to shore. 

No hazardous waste is 

disposed to the marine 

environment. 


Minor 

environmental 

impact. 

Resources used to 

treat and store 

hazardous wastes at 

onshore facilities. 

No significant 

volumes of 

hazardous wastes 

generated as a 

result of production 

at the Flyndre and 

Cawdor fields. 

D/4114/2011 B ‐ 15

Physical 

presence 

General waste Onshore disposal of 

solid waste e.g. bin bags, 

scrap metal, plastics etc. 

Oil and gas 


Noise and 

Vibration 

Physical presence of 

subsea infrastructure 

e.g. pipeline, wells, etc. 

Surface infrastructure 

will not be significantly 

modified as a result of 

the development. 

Exclusion zones will be 

in place around the 


development. 

Noise and vibration 

generated by operation 

of production processing 

equipment and 

maintenance. 



Landfills ‐ land take, nuisance, emissions 


future land use. Treatment plants ‐ nuisance, 




5 1 Low 

May conflict with other users e.g. fishing, 

shipping. Attraction of marine life to the 

structure. 


5 1 Low 



area. 


5 1 Low 



Talisman has a Company 


Waste segregated by 

personnel at source & 

transferred ashore for 

disposal. 

Waste Management 

Procedure of reduce reuse 

recycle followed. 

Monthly reporting of 

waste sent to shore. 

500m exclusion zone 

around the Clyde platform 

and Flyndre and Cawdor 

drilling locations to 

mitigate against collision 

risk. The location will be 

marked on charts. 

Protective structures on 

pipeline, manifolds, SSIV 

etc. to prevent interaction 

with fishing gear. 

Operations will constitute 

a localised noise source. 

The source levels emitted 

will be below the sounds 

levels of concern for 

marine fauna. 

Minor 

environmental 

impact. 


development will 

not generate 

significant volumes 

of general waste. 

Loss of relatively 

small area of the 

seabed to other 

users of the sea. 


B ‐ 16 D/4114/2011



Minor accidental 

events 

Chemical spills Chemical storage‐ 


containment damage 


hydraulic oil 

spills 

Accidental spillage of 

oils may result from 












animals 


1 2 Low 


and marine life in immediate vicinity of 

discharge. 


2 2 Low 


procured & stored. 

COSHH, Task Hazard 

Assessments are 

completed and MSDS 

sheets are available. All 

transfer operations 


weather. All bulk hoses 

and connections must be 



personnel. Chemicals 

stored in tote tank area. 

OPEP is implemented as 




Statutory reporting of all 

spills. Contaminated 

chemical spill kits are 

generally disposed of 

onshore. 




Process. 



D/4114/2011 B ‐ 17





Oil spills Accidental spillage of 

oils may result from 









Produced water 

spills 

Accidental discharge of 

produced water above 

regulatory limits of 

30mg/l. 






mammals. Affect also on amenity value, 

property (e.g. vessels in marinas) & commercial 

interests. 


2 1 Low 

Impact dependent on spill volume and weather 

conditions. Birds are most sensitive offshore 

receptor. Also affected are plankton, 

fish/fisheries, seabed animals & marine 

mammals. Affect also on amenity value, 

property (e.g. vessels in marinas) & commercial 

interests. 


2 2 Low 

Oil in water can result in narcotic, toxic, 

teratogenic impacts and enrichment etc. 


3 2 Low 



Trained deck operations 

personnel. 

Diesel storage tanks and 

transfer hoses are subject 

to inspection & 


strategy. 

Bunded storage tanks. 




Process. 

Oil spill modelling 

completed as an integral 

part of OPEP. 

Procedures in OPEP are 

implemented should a spill 

occur. Training is provided 

on oil spill response to all 

appropriate personnel. 

Talisman are members of 

OSRL (OSRL are on standby 

to provide oil spill clean‐up 

when required. 

Procedures in the OPEP 

are implemented should a 

spill occur. 


Diesel should rapidly 


disperse, diesel 

evaporates 

contribute are a 

form of greenhouse 

gases 

Localised , short 

term impact. 


B ‐ 18 D/4114/2011



Other 

environmental 

aspects 

Consumption of 

materials 

Thermal 

discharges 

Maintenance Paint & shot 

blasting, 

cathodic 

protection, 

fouling 

protection, 

engineering 

maintenance 

activities, supply 

of materials by 

3 rd parties & well 

operations 

Use of finite materials 

such as chemicals and 

steel. There will be a 

increase in chemical use 

with production, 

however there will be no 

changes to the surface 


Cooling fans used to 

reduce the operating 

temperature of turbines 

and engines discharges 

warm air. No increase in 

thermal discharges are 

expected with the 

Flyndre Cawdor 

development. 

None of the 

maintenance operations 

in place on the GPIII will 

change as a result of the 

Flyndre Cawdor 

development. 

Use of non‐renewable resources. Talisman has an 

expectation to recognise 

the limitations of resource 

availability. Company 


Likelihood Consequence Risk This includes reducing the 

quantity of materials used. 

1 2 Low 

Increase in air temperature at point of discharge. Adherence to operating 

procedures and well 

maintained equipment. 


1 1 Low 

Wastes from some of these procedures may 

affect water quality and marine life while others 

will generate atmospheric emissions. 


1 2 Low 

Adherence to operating 

practices and well 

maintained equipment. 


None adhered. 


D/4114/2011 B ‐ 19


Appendix C Environmental Management 

C ‐ 1

Environmental statement - Flyndre and Cawdor - Maersk Oil

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