Environmental Statement - Maersk Oil

Environmental Statement 

Balloch Field Development 

August 2012

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Balloch Field Development Environmental Statement 

Standard Information Sheet 

STANDARD INFORMATION SHEET 

Project name Balloch Field Development Environmental Statement 

Development Location Block 15/20a 

Licence No. P.1041 

Project Reference Number D/4126/2011 

Type of Project Field Development 

Undertaker Maersk Oil UK Limited 

Crawpeel Road, Altens, Aberdeen 

AB12 3LG 

Licensees/Owners Maersk Oil UK Ltd (100%) 

Short Description Maersk Oil propose to develop the Balloch field as a subsea tieback to 

the Global Producer III FPSO which currently handles production from 

the Donan and Lochranza fields. The Balloch wells will be connected 

to the existing Donan DC2 production manifold utilising available 

production slots. The proposed Balloch field development will initially 

consist of the drilling of an appraisal well with a sidetrack production 

well (Phase I). Depending on the success of the initial well, up to two 

further production wells may be drilled (Phase II). This will be 

supported by the additional information from the appraisal well and 

the initial Balloch production to optimise any system modifications. 

Subsea infrastructure tying the wells back to the Donan DC2 

production manifold will also be installed as part of the proposed 

development. The DC2 manifold is currently tied back to the GPIII. Oil 

will be exported from GPIII to shore by tanker and gas will be exported 

via the North Sea Producer FPSO for onward transport to the Frigg 

pipeline. 

Key Dates Activities Date 

Significant Environmental 

Effects Identified 

Drilling and completion November ‐ December 2012 

Subsea installation January 2013 – April 2013 

Commissioning April 2013 

First Oil Q3 2013 

None identified. 

Statement Prepared by Maersk Oil UK Limited, Genesis and Senergy Development Solutions. 

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Balloch Field Development Environmental Statement


Non‐Technical Summary 

NON‐TECHNICAL SUMMARY 

The Balloch field is located in Block 15/20a of the Central North Sea (CNS) in a water depth of 

approximately 140 m. The field lies approximately 225 km north‐east of Aberdeen and 36 km west of 

the UK/Norwegian median line. Maersk Oil UK Ltd (hereafter referred to as Maersk Oil) propose to 

develop the Balloch field as a subsea tieback to the existing Global Producer III (GPIII) Floating 

Production, Storage and Offloading facility (FPSO). The proposed field development will consist of the 

drilling of an initial appraisal well, from which a sidetrack production well will be drilled. Depending 

on the success of the first production well, up to two additional production wells will be drilled. 

The wells will be tied back to the GPIII FPSO, which currently handles production from the Donan and 

Lochranza fields. Balloch fluids will be commingled with the Donan and Lochranza hydrocarbons and 

will undergo processing on the GPIII through existing topsides equipment. Oil will be exported to 

shore by tanker and gas will be exported via the North Sea Producer (NSP) FPSO to the Frigg Pipeline. 

The Balloch production will be managed such that coincident condensate volumes remain within the 

safe operating limits of the GPIII topside processing facilities. 

GPIII operations continually monitor export specifications and, as the gas production declines and 

richer fluids are processed through GPIII, Maersk Oil will continue to optimise operations. When the 

export route is unavailable, the gas will be injected per the recent Donan/Lochranza Field 

Development Plan (FDP) amendment. It should be noted that, due to impending fuel gas deficiency, a 

project has been initiated by the area operators to change the export line duty to a gas import line 

circa 2014. Introduction of Balloch fluids and the implications of increased condensate loading will be 

incorporated into this consideration and, as part of the GPIII production strategy, mitigations have 

been identified and will be implemented to address the changing fluid composition and production 

profiles across the facility. 

The development comprises the installation of subsea tieback infrastructure to transport the Balloch 

reservoir fluids to the GPIII FPSO. GPIII is currently operated via condensate recirculation; the Balloch 

field development will be processed within the existing processing train. Condensate accumulates 

within the knock out drums in the High Pressure (HP) and Low Pressure (LP) compression trains and is 

routed back to the first stage separator; condensate is cycled until it reaches equilibrium between the 

oil and the gas export streams. This is a recognised processing constraint and the base production is 

managed to alleviate and manage this. Recent peak liquid throughput has been in the region of 

35,000 bbl/d from the L3Z well, which has a richer composition than the previous GPIII fluids. This has 

been comfortably handled within the GPIII processing capacity. 

Post Balloch first oil, condensate re‐circulation will continue. Control of the GPIII base production will 

allow well management to optimise overall GPIII production. 

However, it is recognised that Balloch is under‐appraised and there is potential for the high case 

profile to be realised. It is predicted that this could exceed current condensate handling capacity. 

GPIII operation strategy will address this risk and, as part of the ongoing topside processing 

optimisation, mitigations have been identified and will be implemented as necessary. It is accepted 

that, as wells decline and richer wells are brought on stream, the production profiles and 

compositions will vary during continued GPIII operation and will be addressed throughout the Balloch 

field life. Any modifications put in place will recognise this and include sufficient flexibility to address 

future gas and liquid handling. 

This document provides details of the Environmental Impact Assessment (EIA) that has been 

undertaken to support Maersk Oil’s application for consent to undertake the project. This process 

includes a period of public consultation followed by a comprehensive review by various bodies 

including the Department of Energy and Climate Change (DECC), Marine Scotland, the Joint Nature 

Conservation Committee (JNCC) and the Scottish Fisheries Federation. 

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SCOPE 

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This ES sets out to assess the environmental implications of any emissions, planned and unplanned 

discharges and noise resulting from the Balloch development on potential environmental and socio‐ 

economic receptors. 

The Balloch development consists of the following phases: 

The drilling of one appraisal well; 

Side tracking of the appraisal well to provide the first production well; 

Drilling of up to two additional production wells on success of the initial production well; 

Installation of production and gas lift pipelines and umbilicals (~80 m) and cooling spools 

to connect the wells to the existing Donan DC2 manifold; 

Production of the Balloch fluids. 

ENVIRONMENTAL MANAGEMENT AND MITIGATION 

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

ISO14001 certified 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 HSSE 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 

An option selection process was carried out to determine the preferred development concept. The 

chosen option was a short subsea tieback from the existing Donan DC2 manifold, consisting of up to 

three production wells tied back to the GPIII FPSO. 

ENVIRONMENTAL AND SOCIO‐ECONOMIC CONSIDERATIONS 

Prior to undertaking the EIA, an environmental and socio‐economic baseline was compiled. A brief 

summary is presented here. The Balloch developmental area has comparable flora and fauna to that 

found over wide areas of the CNS. The site and pipeline route surveys undertaken within the 

development area identified no environmentally sensitive habitats protected under Annex I of the EC 

Habitats Directive. 

There is evidence of Norway pout and Nephrops spawning within the development area, while sprat 

and whiting have spawning grounds nearby. Juvenile Norway pout, Nephrops, and blue whiting use 

the area as a nursery ground, while juvenile haddock and sprat are found at relatively close distances 

(15 ‐ 40 km) from the development area. 

The overall seabird vulnerability to surface pollution is moderate and monthly vulnerability is highest 

during November. During the proposed drilling period the Offshore Vulnerability Index (OVI) ranges 

from low to very high. 

The main cetacean species present in the area include white‐sided dolphin, white‐beaked dolphin, 

minke whale and harbour porpoise. Of the main cetaceans regularly sighted, the harbour porpoise is 

the only one protected under Annex II of the Habitats Directive. 

The Balloch field development is within an area of relatively low fishing effort, representing 

approximately 1 % of the total UK fishing effort over recent years. The area is predominately targeted 

for demersal and shellfish species. Similar to effort, landings within the area are relatively low 

compared with other areas of the UK, representing less than 1 % of live catches over recent years.



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 

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 (magnitude). The full results from the EIA identified one high risk and five 

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

others have been further discussed in Section 5, due to them being under regulatory control and/or of 

public interest. 

Table 0‐ 1 Issues identified as requiring further assessment. 

Phase/Issue Aspect/Activity 

Environmental 

Risk (Screening) 

Residual impact 

(after mitigation) 

Drilling Discharge of mud to sea Moderate Low 

Discharge of chemicals to sea Moderate Low 

Discharge of produced water Moderate Low 

Installation Installation of subsea cooling spool Moderate Low 

Accidental events 

(Section 6) 

MAIN CONCLUSIONS 

Subsea blowout (drilling) High Low 

Major accidental events loss of platform/pipeline Moderate Low 

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. 

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Non‐Technical Summary


Glossary 

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 

– 250 km 2 . 

Cetacean Aquatic animals comprising porpoises, dolphins and whales. 

Demersal Living at or near the bottom of the sea. 

Dinoflagellates Plankton with two flagellae. 

Down hole Down a well. The expression covers any equipment, measurement, etc., in a well 

or designed to be used in one. 

Environmental aspect An activity that causes an environmental effect. 

Environmental effect Any change to the environment or its use. 

Flowline Pipe through which produced fluids travel. 

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. 

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

dioxide and methane. 

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 benthic 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. 

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. 

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

equipment. 

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. 

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ACRONYMS 

µg Microgram 

µg/g Micrograms per Gram 

µg/kg Micrograms per Kilogram 

µg/m³ Micrograms per Cubic Metre 

µm Micrometre 

µPa Micropascal 

ALARP As Low as Reasonably Practicable 

AHV Anchor Handling Vessel 

API American Petroleum Institute 

BAOAC Bonn Agreement Oil Appearance Code 

bbl Barrel 

bbl/d Barrels per Day 

BMS Business Management System 

BODC British Oceanographic Data Centre 

BOP Blow Out Preventer 

°C Degrees Celsius 

CAD Computer Aided Design 

CAPEX Capital Expenditure 

CCS Carbon Capture and Storage 

CEFAS Centre for Environment, Fisheries and Aquaculture Science 

CHARM Chemical Hazard Assessment and Risk Management 

cm Centimetre 

CMT Crisis Management Team 

CNS Central North Sea 

COP Cessation of Production 

COPA Control of Pollution Act 

CPI Carbon Preference Index 

CPT Cone Penetration Testing 

dB Decibels 

DBT Dibenzothiophene 

DECC Department of Energy and Climate Change 

DP Dynamically Positioned 

DSV Dive Support Vessel 

DTI Department of Trade and Industry 

dwt Deadweight Tonnage 

EC European Commission 

EEA European Environment Agency 

EEMS Environmental Emissions Monitoring System 

EGM East Gannet and Montrose Fields 

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Glossary


Acronyms 

EIA Environmental Impact Assessment 

EMS Environmental Management System 

EPS European Protected Species 

ERC Emergency Response Centre 

ERT Emergency Response Team 

ES Environmental Statement 

ESDV Emergency Shut Down Valves 

ETS Emissions Trading Scheme 

EU European Union 

EU ETS European Union’s Emissions Trading Scheme 

FDP Field Development Plan 

FEPA Food and Environmental Protection Act 

FOF Firth of Forth Banks Complex 

FPSO Floating Production, Storage and Offloading Unit 

FRS Fishing Research Service 

ft Feet 

GOM Gulf of Mexico 

GOR Gas/Oil Ratio 

GPIII Global Producer III 

HAB Harmful Algal Blooms 

HAT Highest Astronomical Tide 

HP High Pressure 

HQ Hazard Quotient 

HSE Health, Safety and Environment 

HT High Temperature 

Hz Hertz 

ICES International Council for the Exploration of the Sea 

IPPC Integrated Pollution Prevention and Control 

JNCC Joint Nature Conservation Committee 

kHz Kilohertz 

km Kilometre 

LAT Lowest Astronomical Tide 

LP Low Pressure 

LWD Logging While Drilling 

m Metres 

m³/day Cubic Metres per Day 

m/s Metres per Second 

MBOPD Thousand Barrels of Oil Per Day 

MCAA The Marine and Coastal Access Act 

MCZ Marine Conservation Zone 

MD Measured Depth 

MDAC Methane‐Derived Authigenic Carbonate 

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MDBRT Measured Depth Below Rotary Table 

MEG Monoethylene Glycol 

MESH Mapping European Seabed Habitats 

mg/kg Milligrams per Kilogram 

mg/l Milligrams per Litre 

mm Millimetre 

mmscf Million Metric Standard Cubic Feet 

mmscm Million Metric Standard Cubic Metres 

MPA Marine Protected Area 

MW Megawatt 

NBSP Norwegian Boundary Sediment Plain 

NER New Entrants Reserve 

ng/g Nanograms per Gram 

nm Nautical Mile 

NNS Northern North Sea 

NPV Net Present Value 

NSP North Sea Producer 

NTvL Noble Ton van Langeveld 

OBM Oil Based Mud 

OGP International Association of Oil and Gas Producers 

OIM Offshore Installation Manager 

OPEP Oil Pollution Emergency Plans 

OPOL Offshore Pollution Liability Association 

OPPC Oil Pollution Prevention and Control 

OPRC Oil Pollution, Preparedness, Response and Co‐operation 

OSCAR Oil Spill Contingency and Response 

OSPAR 

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Acronyms 

Oslo and Paris Convention for the Protection of the Marine Environment in the 

North East Atlantic 

OSPRAG Oil Spill Prevention and Response Advisory Group 

OSRL Oil Spill Response Limited 

OVI Offshore Vulnerability Index 

PAHs Polycyclic Aromatic Hydrocarbons 

PCBs Polychlorinated Biphenyls 

PEC:PNEC Predicted Environmental Concentration:Predicted No Effect Concentration 

PLONOR Poses Little or No Risk 

ppb Parts per Billion 

PPC Pollution Prevention and Control 

ppm Parts per Million 

PTS Permanent Threshold Shift 

PW Produced Water 

PWRI Produced Water Re‐injection 

ROV Remotely Operated Vehicle


Acronyms 

SAC Special Area of Conservation 

SAHFOS Sir Alister Hardy Foundation for Ocean Silence 

SCANS Small Cetacean Abundance in the North Sea 

SCI Site of Community Importance 

scm Standard Cubic Metres 

SCM Subsea Control Module 

SEA Strategic Environmental Assessment 

SMRU Sea Mammal Research Unit 

SNH Scottish National Heritage 

SNS Southern North Sea 

SPA Special Protection Areas 

SPM Suspended Particulate Matter 

SSIV Subsea Isolation Valves 

SST Sea Surface Temperature 

SSSV Sub‐Surface Safety Valve 

TD Target Depth 

te Metric Tonnes 

THC Total Hydrocarbon Concentration 

TOM Total Organic Matter 

TRSSV Tubing Retrievable Sub‐Surface Safety Valve 

TTS Temporary Threshold Shift 

TVP True Vapour Pressure 

UK United Kingdom 

UKCS United Kingdom Continental Shelf 

UKOOA United Kingdom Offshore Oil Association 

USCG United States Coast Guard 

V Volts 

VHF Very High Frequency 

VOC Volatile Organic Compound 

WBM Water Based Mud 

WHRU Waste Heat Recovery Units 

WWC Wild Well Control Inc. 

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Acronyms


Contents 

CONTENTS 

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

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

SCOPE……………………………………………………………………………………………………………………………………………...IV 

ENVIRONMENTAL MANAGEMENT AND MITIGATION .................................................................................... IV 

DEVELOPMENT CONCEPT ...................................................................................................................... IV 

ENVIRONMENTAL AND SOCIO‐ECONOMIC CONSIDERATIONS .......................................................................... IV 

ENVIRONMENTAL EFFECTS ...................................................................................................................... V 

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

GLOSSARY ..................................................................................................................................... VII 

ACRONYMS .................................................................................................................................. VIII 

CONTENTS ................................................................................................................................... XIII 

1. INTRODUCTION 1‐1 

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

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

1.3. SCOPE OF THE ENVIRONMENTAL STATEMENT .............................................................................. 1‐2 

1.4. LEGISLATIVE OVERVIEW ......................................................................................................... 1‐2 

1.5. ENVIRONMENTAL MANAGEMENT ............................................................................................ 1‐5 

1.6. AREAS OF UNCERTAINTY ........................................................................................................ 1‐5 

1.7. CONSULTATION PROCESS……………………………………………………………………………………………………….1‐6 

2. PROPOSED DEVELOPMENT 2‐1 

2.1. NATURE OF THE RESERVOIR .................................................................................................... 2‐3 

2.2. DEVELOPMENT OPTIONS ....................................................................................................... 2‐5 

2.3. SCHEDULE OF ACTIVITIES ....................................................................................................... 2‐9 

2.4. DRILLING ........................................................................................................................... 2‐9 

2.5. SUBSEA INFRASTRUCTURE .................................................................................................... 2‐16 

2.6. FPSO FACILITY .................................................................................................................. 2‐20 

2.7. CHEMICAL USE .................................................................................................................. 2‐25 

2.8. PRODUCTION .................................................................................................................... 2‐25 

2.9. PERMITTING ..................................................................................................................... 2‐30 

2.10. DECOMMISIONING……………………………………………………………………………………………....2‐30 

3. BASELINE ENVIRONMENT 3‐1 

3.1. THE SURROUNDING AREA ...................................................................................................... 3‐1 

3.2. SURVEY INFORMATION .......................................................................................................... 3‐1 

3.3. METOCEAN CONDITIONS ....................................................................................................... 3‐2 

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Contents 

3.4. PROTECTED HABITATS AND SPECIES .......................................................................................... 3‐7 

3.5. THE SEABED ..................................................................................................................... 3‐12 

3.6. MARINE FLORA AND FAUNA ................................................................................................. 3‐17 

3.7. SOCIO‐ECONOMIC ENVIRONMENT ......................................................................................... 3‐30 

3.8. OVERVIEW ....................................................................................................................... 3‐35 

4. ENVIRONMENTAL ASSESSMENT METHODOLOGY 4‐1 

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

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

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

5. ASSESSMENT OF POTENTIAL IMPACTS AND CONTROLS 5‐1 

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

5.2. INSTALLATION PHASE ............................................................................................................ 5‐6 

5.3. PRODUCTION PHASE ........................................................................................................... 5‐10 

5.4. NOISE ............................................................................................................................. 5‐15 

5.5. ACCIDENTAL EVENTS ........................................................................................................... 5‐19 

5.6. WIDER DEVELOPMENT CONCERNS ......................................................................................... 5‐19 

5.7. CUMULATIVE IMPACTS ........................................................................................................ 5‐21 

6. HYDROCARBON RELEASES (SPILL MODELLING) 6‐1 

6.1. OIL SPILL REGULATIONS AND RISK ............................................................................................ 6‐1 

6.2. POTENTIAL SOURCE OF HYDROCARBON SPILLS FROM THE BALLOCH PROJECT ...................................... 6‐3 

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

6.4. MODELLING RESULTS ............................................................................................................ 6‐7 

6.5. ENVIRONMENTAL RISKS ‐ FATE OF OIL IN THE MARINE ENVIRONMENT ............................................ 6‐24 

6.6. SUMMARY OF ENVIRONMENTAL SENSITIVITIES AND POTENTIAL IMPACTS ......................................... 6‐25 

6.7. SPILL PREVENTION AND CONTINGENCY PLANNING ...................................................................... 6‐28 

7. CONCLUSIONS 7‐1 

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

7.2. MINIMISING ENVIRONMENTAL IMPACT ..................................................................................... 7‐1 

7.3. OVERALL CONCLUSION .......................................................................................................... 7‐4 

8. REFERENCES 8‐1 

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

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

APPENDIX C – MAERSK OIL HSSE POLICY........................................................................................C‐1


Section 1 Introduction 

1. INTRODUCTION 

Maersk Oil UK Limited (Maersk Oil) propose to develop the Balloch field as a subsea tieback to the 

Maersk Oil‐operated Global Producer III (GPIII) Floating Production Storage and Offloading facility 

(FPSO). The field development will initially consist of the drilling of a single appraisal well with a 

sidetrack production well and installation of subsea tieback infrastructure (Phase I). After a period of 

~6 ‐ 12 months from the drilling of the first development well, further development drilling may take 

place (Phase II). This will be dependent upon the outcome of the first appraisal/production well. A 

maximum number of three production wells could be drilled into the Balloch reservoir. This 

Environmental Statement (ES) assesses the impacts of the proposed Balloch development. 

The Balloch reservoir was discovered by well 15/20b‐18z in July 2010. The Balloch field lies beneath 

the Donan field and is situated in Block 15/20a, which is in the UK sector of the continental shelf. The 

Balloch field is located in the North Sea 225 km northeast of Aberdeen and 36 km west of the 

UK/Norway median line, in water depths of approximately 140 m. The location of the Balloch 

development is shown in Figure 1‐1. 

The GPIII FPSO currently handles production from the Donan and Lochranza fields. Balloch fluids will 

be commingled with that of Donan and Lochranza at the Donan DC2 manifold and transported to the 

FPSO via the 13½ ” PL2662 production pipeline. As Balloch has a higher reservoir temperature than 

Donan and Lochranza, subsea cooling spools are required to tie the well to the manifold. Oil is 

exported from the FPSO via tanker and gas is exported to the Frigg pipeline via the North Sea 

Producer (NSP) FPSO. Balloch gas and oil processing and export will be as per GPIII operation. It 

should be noted that the Donan field was redeveloped as the ‘Dumbarton’ field by Maersk Oil in 

2006. However, the field is still officially called Donan and will therefore be referred to as Donan in 

this ES. 

Figure 1‐1 Balloch field location. 

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1 ‐ 2 



The Balloch field is situated in Licence P.1041. Maersk Oil has 100 % equity and is the sole owner and 

operator of the GPIII FPSO. 

Production is expected to commence from the Balloch field in Q3 2013 and run to the end of 2019. 

However, it is possible that field life of the GPIII will be extended via infill well drilling and tiebacks 

that would in turn allow the Balloch field to continue producing. In this instance, a cessation of 

production (COP) would be anticipated closer to the end of 2026 with the final date for COP 

dependent upon well performance. Assuming a COP at the end of 2026, high case production (P10) at 

the Balloch development is anticipated to be approximately 3.9 million m3 of oil and 313 million m3 

of gas. 

1.1. PURPOSE OF THE PROJECT 

The purpose of the project is to develop the Balloch field 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 Impact 

Assessment (EIA) process undertaken to meet both statutory and Maersk Oil project requirements. 

The ES was prepared in accordance with the Offshore Petroleum Production and Pipelines 

(Assessment of Environmental Effects) Regulations 1999 (as amended 2007 and 2010). These 

regulations require: 

An evaluation of projects likely to have a significant effect on the offshore environment; 

Formal public comment on the resulting ES. 

The ES reports on the conclusions from the EIA, which investigates and evaluates routine and non‐ 

routine environmental impacts associated with the development. 

1.3. SCOPE OF THE ENVIRONMENTAL STATEMENT 

An ES is required under the Offshore Petroleum Production and Pipelines (Assessment of 

Environmental Effects Amendment) Regulations 1999 (as amended 2007 and 2010) as the Balloch 

development will produce in excess of 500 tonnes (approximately 3,750 barrels) per day. 

The scope of the EIA and resultant ES includes all activities associated with the Balloch development, 

namely: 

The drilling of one appraisal/production well and a further two production wells. The first 

production well will be a sidetrack off the appraisal well; 

Installation of production and gas lift pipelines and umbilicals (~100m) and cooling spools to 

connect the wells to the existing Donan DC2 manifold; 

Modifications to the GPIII and NSP FPSOs; 

Commissioning of the wells. 

This ES sets out to assess the implications of any discharges and emissions from the development on 

the environment. These include additional atmospheric emissions, permitted and accidental 

discharges to sea and the impacts of noise on marine mammals. In addition, the disturbance to the 

seabed habitat caused by subsea infrastructure and its potential interaction with fishing activities 

have been considered. 

1.4. LEGISLATIVE OVERVIEW 

This section provides a brief overview of the current legislation. Appendix A provides a full list of 

legislation regarding the offshore oil and gas industry.



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

continuing to evolve in response to increasing awareness of 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 framework. 

The main controls for new projects are EIAs, which have been a legal requirement for offshore 

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

and Pipelines (Assessment of Environmental Effects) Regulations 1999 (as amended 2007 and 2010), 

hereafter referred to as the EIA Regulations, and accompanying Guidance Notes for Industry (DECC, 

2009). 

The EIA Regulations require an ES to be submitted and prepared for: 

Developments which will produce 500 tonnes or more per day of oil or 500,000 cubic meters 

or more per day of gas; 

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

In addition, an ES may be required for developments which are: 

Less than 40 km from the UK coast line; 

Within, or less than 10 km from, an SPA or SAC (protected areas); 

In areas where designated archaeological features are present and may be damaged or 

disturbed; 

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

or sandeel spawning grounds or important fisheries; 

Involving operations which 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 

or sites currently undergoing the process of being designated as protected. These areas have been 

developed as a consequence of European Directives, in particular the EU Habitats Directive 92/43/EEC 

and the EU Birds Directive 79/409/EEC (both amended by EU Directive 2006/105/EC), which have 

been enacted in the UK by the following legislation: 

The Conservation (Natural Habitats &c) Regulations 1994 (as amended 2012): These 

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

territorial waters out to 12 nautical miles (nm) from the coast and have been subsequently 

amended several times. 

The Conservation of Habitats and Species Regulations 2010 (as amended 2011): These 

regulations 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 

and the 1994 Regulations. 

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

2009, 2010 and 2012). These regulations transpose the Habitats Directive and the Birds 

Directive into UK law in relation to oil and gas and also the provisions of the Energy Act 2008 

relating to carbon capture and storage plans and projects. 

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

regulations implement the requirements of the Habitats Directive for oil and gas activities, 

the 2007 amendments extend these provisions to UK waters. 

Until 1999 these Directives applied only to UK territorial waters (i.e.

1 ‐ 4 



offshore areas with the Offshore Petroleum (Conservation of Habitats) Regulations (as amended 

2007) 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 cause an “offence”, to any European 

protected species, either alone or in combination with other plans and projects. 

The disturbance of European protected species has been further defined by the 2010 amendments to 

the Offshore Marine Conservation Regulations, where it is an offence to: 

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

the injury offence) and/or ‐ 

Deliberately disturb 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 animal’s ability to survive, breed, reproduce, to rear and nurture their young and 

where applicable an animal’s ability to hibernate or migrate and/or ‐ 

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

In June 2000, the Convention for the Protection of the Marine Environment in the North East Atlantic 

(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 Pollution Prevention and Control (IPPC) Act 1999, which 

implements the EU IPPC Directive into UK law, the UK Government’s offshore oil and gas regulator, 

the Department of Energy and Climate Change (DECC), implemented OSPAR Decision 2000/2 on the 

control of chemical use offshore through the Offshore Chemicals Regulations 2002 (as amended 

2011). 

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 (as amended 

2011) and the Greenhouse Gas Emissions Trading (Nitrous Oxide) Regulations 2011. This scheme is 

one of a raft of measures introduced to reduce emissions of greenhouse gases and set challenging 

targets for UK industry. 

In line with OSPAR Recommendation (2001/1), the UK (DECC) has introduced regulatory requirements 

reducing 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 (as amended 2011). This target has been met and maintained by the 

industry as a whole. 

The Marine and Coastal Access Act (MCAA) (as amended 2011) 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 the 

MCAA came into force on 1 st April 2011. The MCAA replaces and merges the requirements of the 

Food and Environmental Protection Act (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 as of 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. 

1.5. ENVIRONMENTAL MANAGEMENT 

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

ISO14001 certified Environmental Management System (EMS) as part of the wider Business 

Management System (BMS). The EMS was independently certified to ISO14001 in 2011. Maersk Oil’s 

commitments to ensuring protection of the environment are set out in the HSEQ 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. 

The Business Management System comprises five key elements: 

1. Policy; 

2. Organisation; 

3. Planning and Implementation; 

4. Performance Management; 

5. Audit and Management Review. 

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

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

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

field will be covered by the EMS. 

Maersk Oil’s contractor management process requires that all contractors conform to either Maersk 

Oil’s BMS or their own management system. As part of the contractor selection process, capabilities 

with respect to environmental management are evaluated with audits being performed to verify 

environmental capability. The contractor’s capabilities are assessed to varying levels dependent on 

the environment, health or safety criticality of the service in question. 

1.6. AREAS OF UNCERTAINTY 

There are a number of aspects of the Balloch project where the chosen development option has yet 

to be defined. Where a number of development options exist, the project has chosen to assess the 

worst case scenario for environmental impact. This section details the areas of uncertainty for the 

Balloch project. 

1.6.1. WELL LOCATION 

The proposed location of the Balloch wells may be subject to a minor adjustment following on from 

site survey results. 

1 ‐ 5

1.6.2. ADDITIONAL PRODUCTION WELL(S) 

1 ‐ 6 



Dependent upon the results of the first production well, further wells may be drilled into the Balloch 

field. A maximum of three development wells are anticipated although the ultimate number of wells 

will depend on production performance. The EIA considers drilling one appraisal/production well and 

up to two additional production wells. Should additional production wells be required, Maersk Oil will 

consult with DECC on the appropriate consenting route for additional drilling at the Balloch field. 

1.6.3. FIELD LIFE 

Production is expected to commence from the Balloch field in 2013 and is expected to last to the end 

of 2019, although the final date of COP could be as late as 2026 if the field life of the GPIII is extended 

via infill well drilling and tiebacks thus allowing the Balloch field to continue producing . 

1.7. CONSULTATION PROCESS 

DECC were consulted on the proposed development with all consultation having been verbal with the 

Environmental Management Team. At the consultation stage, DECC raised no concerns over the 

proposed Balloch development. No other organisations were directly consulted on the proposed 

development.


Section 2 Proposed Development 

2. PROPOSED DEVELOPMENT 

The purpose of this ES is to assess the impacts associated with the development of the Balloch field 

and subsequent hydrocarbon production. This section provides a description of the proposed 

development in terms of the infrastructure required and the oil, gas and water production profiles 

that will be received at the GPIII. 

The Balloch field is located beneath the Donan field (redeveloped as the Dumbarton field in 2006, but 

still officially called Donan) in Block 15/20a of the UKCS. It lies in water depths of approximately 

140 m LAT, 225 km northeast of Aberdeen and 36 km west of the UK/Norwegian median line (Figure 

2‐1). 

Figure 2‐1 Schematic showing the location of the Balloch field. 

Maersk Oil propose to develop the Balloch field as a subsea tieback to the GPIII FPSO which currently 

handles production from the Donan and Lochranza fields. The proposed field development will 

consist of the drilling of one appraisal well and up to three production wells. The first production well 

will be a sidetrack off the appraisal well, hereafter referred to as the appraisal/production well 

(Phase I). The drilling of the two additional wells will be dependent on the success of the first 

production well (Phase II). 

The proposed development also includes the installation of subsea infrastructure to tie the proposed 

wells to an existing manifold (Donan DC2) currently tied back to the GPIII. The Balloch wells will be 

connected to the Donan DC2 production manifold using either spare slots or replacing high water 

content production wells. The Balloch fluids will be commingled with the Donan and Lochranza 

hydrocarbons at the manifold and then transported to the FPSO via the PL2662 13½” production 

flowline. The fluids will be offloaded to tanker and any in spec excess gas will be exported to the Frigg 

pipeline via the North Sea Producer (NSP) FPSO if the export route is available. 

Balloch gas is richer (potential for lots of liquids to condense out) than historical production across the 

GPIII and could therefore potentially increase the load on the condensate re‐circulation system on the 

2‐1

2 ‐ 2 



GPIII topsides. Modelling can be used to predict how much condensate will be generated and the 

impact it may have on base production. This will be clarified during the early production phase of the 

initial appraisal/production well. It is predicted that low and mid case Balloch profiles can be 

accommodated within the existing GPIII topside processing capacity. However, as Balloch is an under‐ 

appraised development there is potential for a much higher profile to be realised, thereby increasing 

the condensate liquid loading. The development plan mitigates this uncertainty by optimising 

Balloch, Donan and Lochranza production jointly, monitoring the impact on the facilities and 

managing the condensate production within the safe operating limits of the GPIII topside processing 

facilities. GPIII process optimisation studies have identified steps that could be taken to de‐ 

bottleneck the condensate handling constraint, allowing production from Balloch, Donan and 

Lochranza to be further optimised if required. Any deferred base production required to 

accommodate initial peak flow rates may be recovered by extending the field life. 

Continuous future gas availability for fuel and start‐up of the GPIII is uncertain. It is envisaged that at 

some point GPIII gas export will no longer be sufficient or suitable for export and/or use as fuel gas on 

downstream production facilities (NSP and Piper). As a consequence, gas will be imported via the 

export line from Piper/Saltire; a project is already in progress in this regard. 

As Balloch has a higher reservoir temperature than Donan, subsea cooling spools will be required for 

the Balloch wells. The initial production well will have a dedicated cooling spool while the proposed 

second and third wells will be connected to a second cooling spool. Dedicated subsea multiphase 

flow meters will be installed at the Balloch wells. 

Directional drilling is planned as the wells are offset from the reservoir. This was selected as the most 

viable option as it involves the smallest amount of pipelay to connect the wells to the DC2 manifold. 

The subsea field layout is shown in Figure 2‐5. 

The GPIII FPSO is located approximately 2.5 km southwest of the proposed Balloch well (Figure 2‐1). 

Condensate and gas is exported to the NSP for onward transport to Piper B which is located 

approximately 12 km west‐southwest of the proposed Balloch development. The NSP is based on the 

conversion of a 10,000 deadweight tonnage (dwt) petroleum tanker previously known as the Dagmar 

Maersk. 

Figure 2‐2 Global Producer III FPSO. 

Production is expected to commence from the Balloch field in Q3 2013 and run to the end of 2019. 

However it is possible that field life of the GPIII will be extended via infill well drilling and tiebacks that



would in turn allow the Balloch field to continue producing. In this instance a cessation of production 

(COP) would be anticipated closer to the end of 2026 with the final date for COP dependent upon well 

performance. Assuming a COP at the end of 2026, high case production (P10) at the Balloch 

development is anticipated to be approximately 3.9 million m 3 of oil and 313 million m 3 of gas. By the 

end of 2019, 3.59 million m 3 of oil and 313 million m 3 of gas are expected to have been recovered. 

The anticipated P10 production profiles are presented in Section 2.8. 

2.1. NATURE OF THE RESERVOIR 

Two main factors dictate the way in which a hydrocarbon resource is developed; these are the nature 

of the reservoir (rock type, porosity and connectivity) and the type of fluids it contains (gas, oil, 

condensate and the composition of these). 

The Balloch field consists of an oil accumulation in the Upper Jurassic Piper sandstone and is located 

immediately below the Donan field. It is situated on the edge of the Fladen Ground Spur and Witch 

Ground Graben. 

The field comprises Upper Jurassic aged mid to upper shoreface sands, referred to as the Piper 

Sandstone Formation. The sands are believed to have been sourced from the Fladen Ground Spar to 

the north/northeast and subsequently transported and reworked along a northwest to southeast 

trending coastline. Transgression caused the shoreline to back‐step onto the Fladen Ground Spar. 

The sands were deposited regionally, so are normally well connected across the area. 

The Balloch field is a combined structural and stratigraphic trap and constitutes a tilted fault block 

(structural component). There may be erosion of the Piper at the top of the structure (stratigraphic 

component). The bounding faults juxtapose the Piper sandstone against chalks of the Valhall 

formations; this is expected to be the major sealing mechanism within Balloch. 

Oil in the Balloch field is sourced from the Kimmeridgian and Volgian age shales of the Kimmeridge 

Clay formation. The Kimmeridge Clay formation was mature for oil and gas generation in the Witch 

Ground Graben to the southeast of the Balloch field. 

The reservoir conditions expected for the Balloch field are provided in Table 2‐1. The Balloch field top 

reservoir map and cross‐sectional representation of the reservoir are shown in Figure 2‐3 and Figure 

2‐4. 

2‐3

2 ‐ 4 

Table 2‐1 Balloch reservoir conditions. 

Reservoir property Value 

Pressure 3647 psia 

Temperature 219 o F 

Gas/oil ratio (GOR) 490 scf/stb 

Gas gravity ( air = 1.000) 1.070 


Stabilised oil gravity at STP 0.8279 (39.41 o API) 

Saturation pressure 1625 psia 

Fluid density at saturation pressure 0.697 g/cm 3 

Entrained water content of stock tank liquid 0.01 wt% 

Figure 2‐3 Balloch reservoir as interpreted from seismic data. 

Section 2 Proposed Development



2.2. DEVELOPMENT OPTIONS 

Figure 2‐4 Cross section of the Balloch reservoir. 

The development concept for the Balloch field is a subsea tie back to the GPIII FPSO which currently 

serves the Donan and Lochranza fields. This is a viable option given the proximity of the Balloch field 

to the FPSO and the opportunity to combine the tieback with that of the Donan and Lochranza fields. 

A tieback of the Balloch field to other installations in the area would incur a greater use of resources 

and increased seabed impacts. 

Three initial development options, along with the do nothing option, were evaluated (Table 2‐2). 

Table 2‐2 Development options considered for Balloch. 

Development Options Summary 

Do nothing Drilling and subsea infrastructure not required. 

Subsea Options 

1 

Short (~80 m) step out from DC2 manifold with cooling spools to meet DC2 

design temperature requirements. 

2 Long (~1.7 km) step out from DC2 manifold with cooling spools. 

3 New Balloch template/flowline tied back to GPIII with new riser. 

The Options were compared using the following criteria: 

Value (NPV, CAPEX); 

Volumetric (Reserves, Shutdown losses); 

Schedule (First Oil, Impact to FPSO economic limit); 

Hazard (ALARP & regulatory compliance, Execution risk). 

Due to the socio‐economic benefits of the Balloch field development, including reducing UK imports 

of hydrocarbons and providing revenue to the Exchequer, the do nothing option was screened out at 

an early stage. Unlike option three, options one and two utilise the existing Donan DC2 production 

manifold and PL2662 13.5 ” production flowline. Brief summaries of the three options are provided 

below. 

2‐5

2 ‐ 6 



Option 1 ‐ Short (80 m) step out from DC2 with cooling spool to meet DC2 design temperature 

requirements 

Option 1 involves the Balloch fluids being commingled with that of Donan and Lochranza at the pre‐ 

existing DC2 production manifold. The fluids would then be transported to the GPIII FPSO via the 

existing PL2662 13½ ” production flowline. This option involves the smallest subsea infrastructure 

with an 80 m step out from the manifold. 

As Balloch has a higher reservoir temperature than Donan and Lochranza, a subsea cooling spool is 

required to allow the wells to be connected to DC2. A cooling spool will be installed for the first 

production well. In case of a second production well, a second cooling spool will be installed, which 

will also cover cooling requirements for a potential third production well. In order to minimise the 

subsea infrastructure, Option 1 entails directional drilling as the well is offset from the reservoir. 

Figure 2‐5 Balloch development Option 1.



Option 2 ‐ Long (~1.7 km) step out from DC2 with cooling spool 

Similar to Option 1, Option 2 involves the Balloch fluids being commingled with that of Donan and 

Lochranza at the existing DC2 production manifold. Again, the fluids will be transported to the GPIII 

FPSO via the existing PL2662 13½ ” production flowline. This option also involves the installation of 

subsea cooling spools. In this option the production wells would be located above the Balloch 

reservoir, approximately 1.7 km from the DC2 manifold (Figure 2‐6). This development option would 

facilitate any future tie‐in to any other Balloch flowline installed at a later date. 

Figure 2‐6 Balloch development Option 2. 

2‐7

Option 3 ‐ New Balloch template/flowline tied back to GPIII with new riser 

2 ‐ 8 



Option 3 requires the largest amount of subsea infrastructure to be installed. The Balloch wells would 

be tied back to the GPII FPSO but, unlike options 1 and 2, a new manifold would be installed and tied 

back to the FPSO via new 5.1 km production and gas lift lines and an umbilical (Figure 2‐7). This 

option does not require a cooling skid, as the Balloch fluids are commingled with the Donan and 

Lochranza fluids on board the FPSO. Two additional risers would need to be installed on the GPIII 

FPSO for the production and gas lift. 

Option 3 would require more subsea and FPSO infrastructure and was considered to have the biggest 

environmental and economic impact, hence it was screened out from further consideration. 

Conclusion of the Option Selection process 

Figure 2‐7 Balloch development Option 3. 

Option 1 will maximise production through existing facilities, with minimal requirement for new 

infrastructure. The developmental footprint of Option 1 is the smallest and requires the least amount 

of new infrastructure, thus it has minimal impacts associated with it. Option 1 is therefore considered 

to be the best developmental option in terms of both environmental and economic considerations.



2.3. SCHEDULE OF ACTIVITIES 

The proposed schedule of activities is shown in Table 2‐3. 

2.4. DRILLING 

Table 2‐3 Schedule for development of the Balloch field. 

Drilling and completion 

Subsea installation 

Commissioning 

First oil 

Activities Date 

November – December 2012 

January – April 2013 

April 2013 

Q3 2013 

The Balloch field will be developed by drilling one appraisal well and up to three production wells. 

The first production well will be a sidetrack off the appraisal well (appraisal/production well). The 

final number of production wells will depend on the amount of resources proven by the appraisal 

well. As a worst case the EIA considers the drilling of the initial appraisal/production well (Phase I) 

and two further production wells (Phase II). In addition, the EIA assumes the wells will be drilled 

during different drilling campaigns, i.e. the rig will go offsite between each well. 

2.4.1. DRILLING LOCATION AND SCHEDULE 

Drilling of the appraisal/production well is expected to commence in November 2012 and last for 

approximately 70 days. Any changes to the drilling schedule will be reflected in the subsequent 

PON15Bs. The surface location for the appraisal and production wells is expected to be 80 m from 

the existing DC2 manifold. Provisional surface location coordinates for the appraisal/production well 

are given in Table 2‐4. Surface locations for the second and third production wells have yet to be 

determined and will be decided following on from the results of the first appraisal/production well. 

Table 2‐4 Surface location coordinates for the proposed appraisal well and first production well. 

Well Number Latitude Longitude Northing Easting 

Appraisal well 58°22'18.035"N 0°53'03.319"E 6472 185N 376 245E 

The subsurface target locations for all the proposed Balloch wells are given in Table 2‐5. The locations 

given may be subject to minor variation, following detailed well planning. The order in which the 

second two wells will be drilled is also flexible and will depend on the outcome of the first well. 

Table 2‐5 Subsurface location coordinates for the proposed appraisal and three production wells. 

Well Number Latitude Longitude Northing Easting 

Appraisal well 58°22'37.800"N 00°54'14.355"E 6472 760N 377 418E 

Production well 1 58°22'48.562"N 00°53'40.344"E 6473 110N 376 876E 



2.4.2. DRILLING RIG 

Maersk Oil proposes to use the Noble operated NTvL semi‐submersible drilling rig to carry out the 

drilling of the initial appraisal/production wells (Figure 2‐8). The rig is designed for drilling operations 

in water depths up to 457 m and is rated to drill a well depth of up to 7,620 m. 

2‐9

2 ‐ 10 

Figure 2‐8 The NTvL semi‐submersible drilling rig. 



Should the second and third productions wells be required, Maersk Oil propose to use the 

Transocean‐operated Sedco 704 semi‐submersible drilling rig (Figure 2‐9). This rig is designed for 

drilling operations in water depths up to 305 m and, similar to the NTvL, is rated to drill a well depth 

of up to 7,620 m. 

Figure 2‐9 The Sedco 704 semi‐submersible drilling rig.



Total fuel capacity on the NTvL is 1,373 m 3 (8,642 bbls) and on the Sedco 704 is 1, 051 m 3 (6,610 bbls). 

As a worst case scenario, the spill modelling presented in Section 6 of this ES modelled the loss of 

diesel from the NTvL. 

The rig(s) will be towed to location with the assistance of three anchor handling vessels (AHVs), two in 

front and one to the rear. Semi‐submersible drilling rigs tend to have anchor facilities using 8 (e.g. 

Sedco 704 and NTvL) or 12 (e.g. NTvL) point chain wire mooring systems. For the purposes of this ES, 

the worst case scenario of 12 will be assumed. 

Whilst 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 rigs will be equipped with navigation lights, radar and radio communications. 

2.4.3. DRILL RIG AND SUPPORT VESSELS 

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

supply vessel and a standby vessel. Table 2‐6 summarises the drill rig and support vessel activity and 

fuel usage during the drilling of the proposed wells. It is possible that a reduced number of transit 

days will be required for the AHVs should the second two production wells be drilled consecutively, 

but as a worst case it is assumed that the rig will be moved off location between the drilling of these 

two wells. No additional guard vessel will be required as the guard vessel associated with the GPIII 

FPSO will meet the requirements of the drilling rigs. 

Table 2‐6 Fuel consumption of vessels associated with the drilling of the first Balloch well. 

Vessel type 1 

Duration (days) 

Working fuel 

consumption (te/d) 1 Total fuel use (te) 

Phase I (appraisal/ production well) 

3 x Anchor handling vessels (transit) 24 2 50 1,200 

3 x Anchor handling vessels (working) 6 5 30 

1 x Semi‐submersible drilling rig 70 10 700 

1 x Supply vessel (transit) 80 10 800 

1 x Supply vessel (working) 10 5 50 

Helicopter (5 hour return flight) 40 3 3 4 120 

Phase II (second and third production wells) 

3 x Anchor handling vessels (transit) 48 2 50 2,400 

3 x Anchor handling vessels (working) 12 5 60 

1 x Semi‐submersible drilling rig 140 10 1,400 

1 x Supply vessel (transit) 160 10 1,600 

1 x Supply vessel (working) 20 5 100 

Helicopter (5 hour return flight) 80 3 3 3 240 

Total 8,700 

1 Source: The Institution of Petroleum, 2000. 

2 Estimates it takes 4 days to transport rig to well location, therefore 2 x 4‐day trips per anchor vessel per well. 

3 Duration in hours. 

4 te/hr. 

2.4.4. BLOW OUT PREVENTER 

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

Out Preventer (BOP) stack while the Sedco 704 is fitted with a 15,000 psi BOP. The function of the 

BOP is to prevent uncontrolled flow from the well by positively closing in the well at the seabed, as 

2‐11

2 ‐ 12 



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 on the rig. 

2.4.5. WELL DESIGN 

A detailed well design and completion strategy has yet to be finalised for the Balloch production 

wells. However, each well is expected to follow the design outlined in Table 2‐7 and Figure 2‐10. 

Table 2‐7 Balloch well completion details. 

Hole section Depth (MDBRT in ft) Section length (m) Drilling fluid 

36” 815 71 Seawater with viscous sweeps 

17½” 3,092 694 Seawater with viscous sweeps 

12¼” pilot* 9,630 1,993 OBM 

12¼” 9,006 1,862 OBM 

8½” 9,220 61 OBM 

*The 12 ¼” pilot hole will only be drilled in the appraisal well / initial production well. 

The top hole section (36”) of the wells will be drilled with seawater and hi‐vis sweeps to an 

approximate depth of 815 ft measured depth below rotary table (MDBRT) and a 30” x 20” conductor 

will be set and cemented. The 17½" section of the well will be drilled directionally with seawater and 

hi‐vis sweeps, building to approximately 15 degrees inclination by total depth at 3,092 ft MDBRT. A 

13 3 /8 ” casing will then be run and cemented in place. 

A 12¼” appraisal pilot hole is planned from the 13 3 /8 ” shoe as part of the first production well. This 

will be drilled using +/‐ 11.4 ppg Versaclean Oil Based Mud (OBM) and logged. The well will be drilled 

to an angle of 38 degrees. Target depth (TD) of the pilot hole is currently planned at +/‐ 10,040 ft 

measured depth (MD). The pilot hole will then be abandoned before setting a kick off plug across the 

13 3 /8 ” shoe. 

The main target 12¼” hole section will be drilled using +/‐ 11.4 ppg Versaclean OBM and logged. The 

trajectory will gradually build angle, entering the top sand at 34 degrees at approximately 9,006 ft 

MDBRT. The section will be secured with 9 5 /8” casing. 

It is planned to continue drilling with +/‐ 10.9 ppg OBM and log with logging while drilling (LWD) in the 

8½” hole to TD at the currently planned +/‐ 9650 ft MDBRT. A 7” liner will then be cemented. 

It is intended to complete the well by perforating the 7” liner below a production packer tied back to 

the surface with 4½” x 5½” tubing. The well will be completed with a gauge mandrill, chemical 

injection feature, gas lift valve and sub‐surface safety valve (SSSV). Following completion, the well 

will be suspended as per industry best practice and will await hook up for production. At this time 

there are no foreseeable well interventions planned for the Balloch wells. 

The Balloch wells will be drilled and completed in accordance with Maersk Oil’s Well Operations 

Standards.



OPERATOR: 

MAERSK OIL & GAS NORTH SEA (U.K) LIMITED 

Figure 2‐10 Balloch completion design. 

DRILLING RIG: (BRT 106' ABOVE MSL) COMPLETION RIG: (RKB 106.0' ABOVE MSL) 

Noble NTVL Noble NTVL 

DIRECTIONAL DATA 

TUBULAR DATA 

WELLHEAD DATA 

KOP: 

1.50 deg @ 1,000 BRT Tubulars 

OD ID Weight Grade Thread TVD MD TOC TYPE Vetco SG-5 Horizontal 

MAX DEV: 34.00 deg @ 9,220 BRT 

WP 10,000 

DLEG SEV: 1.50 deg CONDUCTOR 30.000 28.750 133.00 X52 ST-2 815 815 

I.T.C No 

DEV AT PERFS 34.00 deg 

ITC Plug 

PROD CASING 13.375 12.347 72.00 L-80 Vam Top 3,000 3,092 1,592 Hanger No 

PROD LINER 9.625 47.00 L-80 Vam Top 7,350 8,300 6,800 Hanger Plug 

DRILLING / COMPLETION FLUID 

PROD LINER 7.000 29.00 L-80 Vam Top 8,216 9,220 8,300 Tree Ser No 

DRILLING FLUID: 11.4 ppg Versaclean OBM 

Tree I.D 

DRILLING FLUID: 10.9 ppg Versaclean OBM 

Tree Connector 18 3/4" 10K Colllet 

ELEVATIONS: WTR DE 475 

COMPLETION FLUID: 9.3 ppg NaCl Brine tbc TUBING 

5.500 4.917 17.00 

JFE-Bear BRT-TH HOP: OTHER: 

PACKER FLUID: 9.3 ppg NaCl Brine tbc TUBING 

4.500 3.958 12.60 

JFE-Bear BRT-MWL: 106.0 BRT-ML: 581 

WELLBORE SKETCH EQUIPMENT DESCRIPTION 

5" X 2" 5M HORIZONTAL SUBSEA 

DRAWING NOT TO SCALE 

BRT 

Sea Level 

30" x 20" Casing Shoe 

TRSSSV 

13-3/8" TOC 

Top of 9-5/8" Liner 

13-3/8" Casing Shoe 

7" TOC 

Top of 7" Liner 

9-5/8" Liner Shoe 

5" Mill Out Extension 

Wireline Entry Guide 

7" Liner Shoe 

CLAMPS: 

FIELD / WELL: 

Balloch 

BLOCK: 

5-1/2" Schlum MMRG-2-4 Side Pocket Mandrel c/w R20-PE GLV 1/4" Port 

9-5/8" TOC (tbc) 

4 1/2" Schlumberger BHP/BHT Gauge Mandrel c/w 1/4" Inc 825 

4-1/2" Chemical Injection Mandrel c/w 

7" Halliburton HHR Packer c/w L/H rotate out Ratch Latch 

4-1/2" Packer setting device (options) 

Perforations: (TBC) 

ID 

28.750 

WELL SKETCH: 

Proposed 

AFE NUMBER: 

OD 

30.000 

12.415 13.375 

TOTAL WELL DEPTH: 

PREPARED BY: 

KDH 

DEPTH 

TVD - BRT 

0 

106 

815 

3,000 

7,350 

DEPTH 

MD-BRT 

0 

106 

815 

TBC 

1,592 

2,972 

3,092 

TBC 

6,800 

8,180 

8,180 

8,300 

TBC 

TBC 

TBC 

TBC 

TBC 

TBC 

8,216 9,220 

8,221 9,225 

DATE: 

14-Nov-11 Rev 2 

2‐13

2.4.6. DRILLING MUD AND CUTTINGS 

2 ‐ 14 


During drilling, drilling fluids (mud) 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. 


The mud is pumped from drilling rig, down the drill stem to the bottom of the hole, past the drill bit 

and back up the annulus, BOP and marine risers before returning to the rig and passing through the 

mud recovery system which removes solids prior to reuse. 

Table 2‐8 summarises the Balloch well drill cuttings and mud masses for the appraisal/production 

well. It is assumed that drilling of the second and third wells will produce similar mud and cuttings 

volumes. 

WBM 

OBM 

Section 

diameter 

Table 2‐8 Cuttings and mud mass for the initial Balloch appraisal/ production well. 

Drilling 

fluid 

Mud system 

Mud volume 

(m 3 ) 

Cuttings 

mass (te) 

Fate of mud/ cuttings 

36” WBM Spud mud 52 120 Discharge to seabed 

17‐½” WBM Spud mud 118 276 Discharge to seabed 

Total 170 396 

12‐¼” pilot hole OBM VersaClean OPF 167 363 Rotomill TM 

12‐¼” side track OBM VersaClean OPF 156 389 Rotomill TM 

8‐½” OBM VersaClean OPF 2 6 Rotomill TM 

Total 326 758 

The 36” tophole and 17½” sections of the well will be drilled using water based mud (WBM) and the 

cuttings discharged to the seabed. Approximately 170 m 3 of WBM and 396 tonnes of cuttings will be 

discharged to the seabed from the drilling of the 36” and 17½” sections. A total volume of 326 m 3 of 

OBM will be used to drill the bottom hole sections and side track; this is expected to generate 

approximately 758 tonnes of cuttings. 

The cuttings from the lower sections will be recovered and processed using a Rotomill TM system. Use 

of the Rotomill TM 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 solids to 

landfill. Base oil will be recovered from the Rotomill TM and stored for reuse, while 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 or 

30 ppm oil in water. A skip and ship system will be in place as a contingency. 

Prior to drilling, PON 15B applications will be submitted to DECC detailing the final mud formulation 

and drilling chemicals to be used. 

2.4.7. CEMENTING CHEMICALS 

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

trees, as well as to isolate unstable formations and different formation fluids and to 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 mixed cement or mixwater. 

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

performance. Chemicals with substitution (sub) warnings will be avoided wherever technically 

possible. Any changes to chemicals or volumes listed will be detailed in the subsequent PON15B 

applications. 

2.4.8. OTHER RIG DISCHARGES 

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

chemicals resulting from small leaks or spills, as well as from 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 (to be 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. 

2.4.9. WELL CLEAN‐UP, TESTING AND COMPLETION 

Prior to production, each production well will be cleaned up to remove any waste and debris 

remaining in the well in order to prevent damage to the pipeline or topsides production facilities. 

The drilling mud will be displaced from the well by pumping clean‐out pills and a completion brine. 

The clean‐up train and associated interface liquids will be isolated for treatment by Rotomill TM , 

onshore treatment and disposal, as well as filtering the displacement brine prior to any disposal. 

All hydrocarbons produced during the well clean‐up and well testing operations will be flared. The 

volumes of hydrocarbons to be flared during well clean‐up and testing have yet to be determined; 

therefore, emission calculations have been undertaken (Section 5) based on a worst case of 2,000 te 

of oil per well, i.e. 6,000 te for the three production wells. No extended well testing is anticipated. 

To mitigate against fluid compatibility uncertainty, Balloch wells will be completed with downhole 

chemical injection. Following completion, the well will be suspended as per industry best practice 

and will await hook up for production. 

Further detail on well clean‐ups, testing and completions will be available nearer the time and 

presented within the subsequent PON15B and OPPC applications. 

2‐15

2.5. SUBSEA INFRASTRUCTURE 

2 ‐ 16 



This section details the installation of facilities required to transport the hydrocarbons from the 

production wells to the Donan DC2 manifold for onward transport to the GPIII. Table 2‐9 lists the 

infrastructure required should the three production wells be drilled. The surface location of the 

appraisal/production well will be approximately 80 m from the DC2 manifold. The exact location of 

the Phase II wells is not known, but it is expected they will be < 80 m from the manifold. As a worst 

case in this EIA they were assessed as also being 80 m from the manifold. 

Table 2‐9 Subsea infrastructure assuming three production wells. 

Equipment type Requirement 

Well heads and Xmas Trees 3 x well heads and Xmas trees 

Jumpers 3 x 80 m 6 ” production 

3 x 80 m 6 ” production (rated to 100 o C) 

6 x 80 m 3 ” lift gas 

3 x well set (chemical and controls) 

3 x 80 m control umbilical 

Tie‐In Spools 3 x production 

3 x lift gas 

Cooling spool 2 x cooling spool 

(maximum temperature 80 o C to DC2) 

Meters 3 x tree mounted production multiphase meter 

3 x drop down spool lift gas meter 

Controls Subsea control module (SCM) 

The surface locations for the Phase I wells and associated cooling spool are given in Table 2‐10. The 

surface location of the Phase II wells and the second cooling spool have yet to be determined. 

Table 2‐10 Location of subsea infrastructure for the proposed Balloch development. 

Subsea infrastructure 

Location 

Latitude Longitude Northing Easting 

Appraisal/production wells 58°22’18.035”N 0°53’03.319”E 6472 185 376 245 

Cooling skid 58°22’17.39”N 0°53’05.51”E 6472 164 376 280 

The DC2 manifold comprises eight available production slots, collects fluids into a single flowline and 

distributes gas‐lift to all wells tied to it. The Balloch wells will be tied back to these available slots 

slots or will replace high water content production wells. The hydrocarbons will be commingled with 

the Lochranza and Donan fluids before being flowed back to the GPIII FPSO. The top‐hole location for 

the proposed appraisal/production well is approximately 80 m from the DC2 manifold. The design life 

of the subsea infrastructure for the proposed Balloch development is 12 years. 

2.5.1. WELL HEADS AND TREES 

The Balloch wells will utilise standard Vetco‐supplied SG5 wellheads and MONS 5000 psig horizontal 

production trees. The trees will be provided with integral production and gas lift chokes, remotely 

operated from the GPIII via a subsea control system. The subsea control modules (SCM), required to 

interface control and monitor functionality, will be mounted on the tree. Installation will be done by 

divers during the installation and hook up phase of the project.



2.5.2. PIPELINE INSTALLATION 

The Balloch wells will be connected to the DC2 manifold via flexible jumpers for both production and 

gas lift. The jumpers will be installed in self supporting coils before being run out subsea. A Dive 

Support Vessel (DSV) will be used to install all jumpers. 

The production and gas lift jumper design parameters are summarised in Table 2‐11 and Table 2‐12 

respectively. 

Table 2‐11 Production jumper design parameters. 

Description Value 

Length (m) ~80 m 

Internal diameter (inches) 6 ” 

Design pressure 345 barg 

Design temperature (max/min) 130 / ‐20 o C 

Operating pressure 50 barg 

Operating temperature range 20 – 80 o C 

H 2S 50 ppm 

Table 2‐12 Gas lift jumper design parameters. 


Length (m) ~80 m 

Internal diameter (inches) 3” 

Design flow 5 mmscfd 

Operating flow 1 – 4 mmscfd 

Design pressure 345 barg 

Design temperature (max/min) 65/ ‐ 40 o C 

Operating pressure 180 barg 

Operating temperature range 5 o C 

H 2S 50 ppm 

Once the installation is complete, Balloch fluids will be commingled with Donan and Lochranza fluids 

at the manifold and transported to the GPIII FPSO via the existing PL2662 13½” production flowline. 

2.5.3. COOLING SPOOL 

As Balloch has a higher reservoir temperature than Donan, a subsea cooling spool is required to tie 

the Balloch wells into the DC2 manifold (Figure 2‐11). A cooling spool will be installed for the first 

production well. Should a second well be drilled at a later date, a second cooling spool will be 

installed which should also cover cooling requirements should the proposed third production well be 

drilled. The cooling spool for the first well is designed and sized for a 10 o C drop in temperature. The 

precise installation method for the cooling spools has yet to be finalised, but for the purposes of the 

EIA it was assumed that it will be piled using a subsea hammer. The cooling spool dimensions are 

approximately 6 m x 6 m x 3 m (length x width x height). The cooling spool has slots for four pin piles 

measuring 70 cm; if piling is used, these will be installed via a submersible hammer pile. The total 

piling time is estimated to be approximately six hours. The cooling spool will be “fishing friendly” and 

be designed in accordance with current North Sea practice. 

2‐17

2.5.4. METERING 

2 ‐ 18 

Figure 2‐11 Cooling spool assembly. 



Metering of Balloch production will be via dedicated tree‐mounted multiphase flow meters. The lift 

gas flow meter for Balloch will be installed on the drop down spools on the tree. Controls for these 

meters will be connected to the tree’s subsea control module. 

2.5.5. SUBSEA CONTROL, INSTRUMENTATION AND CHEMICALS 

The Balloch wells will require the following services: 

High pressure (HP) hydraulics (345 barg); 

Low pressure (LP) hydraulics (207 barg); 

Power and signal facilities; 

Chemical injection (methanol and scale inhibitor). 

The Balloch control will be delivered by a subsea umbilical. It is anticipated that chemicals currently 

deployed for Donan and Lochranza production fluids will also be suitable for Balloch production fluids. 

To mitigate against fluid compatibility uncertainty, the Balloch wells will be completed with downhole 

chemical injection. 

2.5.6. GAS AND CONDENSATE RE‐CIRCULATION SYSTEM 

Balloch gas is very rich (i.e. contains components such as butane and propane) and is anticipated to 

increase the loading on the current topside processing. Current practice relies on the condensate 

being cycled until it reaches equilibrium within the gas and oil export streams. Modelling of the 

process to demonstrate the extent to which this constraint will influence base production and exactly 

how much condensate will be generated has identified this as a potential variable. Flowing of the 

initial appraisal/production well will provide a more detailed understanding of this phenomenon as it 

is very much dependent on the exact composition of Balloch fluids and how they interact with Donan 

and Lochranza fluids. Models currently predict that the Balloch low to mid case profiles can be 

accommodated within existing processing capacities. There is some technical risk as to whether the 

high case can be accommodated, but the recently drilled L3Z well has gone some way to mitigating 

that risk by producing a spot rate of 32,000 bbl/d and an initial average of over 21,000bbl/d. 

Lochranza fluids are richer than those from Donan, which goes towards supporting the basis that the 

current GPIII condensate re‐circulation can be optimised and GPIII can handle richer gas throughputs 

to accommodate the Balloch fluids.



GPIII operations and production chemists will continually monitor this constraint and manage GPIII 

base production. Should this constraint become unacceptable, as part of the ongoing GPIII 

production management there are condensate handling mitigations that have been identified. De‐ 

bottlenecking options would be further pursued in the event they are required. 

2.5.7. ISOLATIONS AND HOOK‐UP 

Double block and bleed production isolations currently exist on the DC2 manifold. The Balloch wells 

can be hooked‐up to the DC2 manifold without the need for production shutdown or extensive 

flushing of production or lift gas flowlines. Flushing and isolation risk assessments will be prepared 

and detailed methodologies completed prior to operations. 

2.5.8. PIPELINE TESTING AND COMMISSIONING 

After pipe lay, the pipelines will be hydro tested prior to production to ensure they maintain pressure 

and do not leak. As part of this process, the pipelines will be flooded with potable water dosed with 

biocide, oxygen scavenger, dye and corrosion inhibitor. Following the leak test, the pipeline systems 

shall be de‐watered using dyed Monoethylene Glycol (MEG) and treated seawater. 

The potable water, along with chemical additives, may be discharged to the sea surface or processed 

through existing facilities and re‐injected with the produced water stream. The chemicals to be used 

for pipeline testing have yet to be finalised; however, the dose and quantities will be in accordance 

with the manufacturers’ specifications. 

For the purposes of this ES, it is assumed that all displaced water will be discharged overboard. 

Details of the disposal of pipeline testing chemicals will be provided in the subsequent PON15C. 

2.5.9. SUBSEA INFRASTRUCTURE PROTECTION 

Concrete mattresses and grout bags will be required to provide protection to the subsea 

infrastructure associated with the proposed Balloch development. It is estimated that a maximum of 

30 concrete mattresses and 15 grout bags will be required for the complete development, i.e. 

assuming three production wells. The mattresses will measure 6 x 3 x 0.15 m (L x W x H) and have a 

mass of 2.4 te each while the grout bags will measure 1 x 0.5 x 0.5 m (L x W x H) and have a mass of 

1 te each. 

2.5.10. SUBSEA INSTALLATION SUPPORT VESSELS 

Vessel type, duration and fuel usage for the installation of the subsea infrastructure are given in Table 

2‐13. 

Table 2‐13 Vessel use and fuel demand associated with the installation of the subsea infrastructure. 

Vessel type 1 

Phase I; appraisal/production wells 

Duration (days) 

Working fuel 

consumption (te/d) 1 

Total fuel use (te/d) 

Diving Support Vessel (transit) 8 22 176 

Diving Support Vessel (working) 30 18 540 

Phase II; second and third production wells 

Diving Support Vessel (transit) 2 16 22 352 

Diving Support Vessel (working) 60 18 1,080 

1 Source: The Institute of Petroleum (2000) 

2 It is assumed that the second and third wells will be drilled at different times, requiring the vessels to go offsite 

between the drilling of each well. Similarly it is expected that the DSV will go offsite between the drilling 

campaigns. 

2‐19

2 ‐ 20 



A DSV will be used to lay the jumpers, umbilicals and cooling spools. The mattresses and grout bags 

will also be put in place using the DSV. No additional vessels will be required as the support and 

guard vessels associated with the GPIII FPSO will meet the requirements of the DSV. 

2.5.11. FLOW ASSURANCE 

Flow assurance refers to the successful flow of hydrocarbons from the reservoir to the processing 

facilities. It involves effectively handling many solid deposits such as gas hydrates, scaling, sand, wax, 

etc. Flow assurance and operability are supported by methanol for the inhibition of hydrates at start 

up and shut down, by pipe insulation and chemical injection for the management of wax and by 

chemical injection for the management of other production chemistry issues. 

The chemical injection requirements for Balloch are the same as for Donan and Lochranza and are 

expected to include: 

Hydrate inhibitor Corrosion inhibitor 

Scale inhibitor Demulsifier 

Antifoam Deoiler 

Wax inhibitor Acetic acid 

Biocide (batch chemical) Anti asphaltene. 

There will be an incremental increase in chemicals used on the FPSO to process the Balloch 

hydrocarbons. Details of these will be provided in the subsequent PON15s and changes to the 

PON15D for the GPIII FPSO. 

2.6. FPSO FACILITY 

The GPIII FPSO is located approximately 2.5 km south west of the proposed Balloch development and 

currently handles production from the Donan and Lochranza fields. 

The GPIII has topside areas dedicated for future facilities and therefore little modification is needed to 

accommodate the proposed Balloch development. Details of the FPSO, including storage capacity, 

are provided in Table 2‐14. The vessel layout can be seen in Figure 2‐12. 

Storage Capacity 

Table 2‐14 Details of the GPIII FPSO. 


Length 200 m 

Beam 38 m 

Depth 23 m 

Draft 17 m 

Accommodation 95 personnel 

Crude oil 81,064 m 3 

Ballast 36,872 m 3 

Fuel oil 1,725 m 3 

Fresh water 430 m 3 

Slops 5,650 m 3



Figure 2‐12 FPSO layout. 

The proposed Balloch development will result in an increase in hydrocarbon production on board the 

FPSO compared to recent years. However, as Donan and Lochranza are nearing the end of field life 

the remaining anticipated production from these two fields combined with the anticipated production 

from the proposed Balloch development is not anticipated to exceed previous maximum production 

on the GPIII. 

As Balloch production fluids will be commingled subsea with Donan and Lochranza fluids at the 

existing DC2 manifold, no new tie‐ins to the FPSO are required. 

2.6.1. FPSO PROCESS FACILITIES 

The GPIII is moored to the seabed by a ten‐point turret mooring system. The FPSO’s turret and its 

transfer system will link the Balloch subsea facilities to the GPIII. Details of the FPSO swivel stack 

assembly are given in Table 2‐15. 

Table 2‐15 GPIII FPSO swivel stack assembly details. 

Section Description Design Pressure 

Production 

Water injection 

Gas lift / import 

Hydraulic Utility 

1 x 16” swivel/ 4 x 8” production path 

1 x 16” swivel/ 4 x 8” production path 

1 x 16” swivel/ 4 x 8” production path (spare) 

1 x 12” swivel/ 3 x 8” water injection path 

1 x 14” swivel/ 3 x 8” aquifer path (spare) 

1 x 6” swivel/ 1 x 6” gas lift path 

1 x 6” swivel/ 1 x 6” gas import/export path 

The hydraulic utility swivel has 12 flow paths for hydraulic fluid, 

methanol, chemicals, instrument air and vent gas 

220 

230 

220 

220 for chemicals 

Fire water 1 x 4” swivel for aerated seawater 17 

2.6.2. SEPARATION AND OIL PROCESSING 

The FPSO’s separation and crude stabilisation system consists of first stage pre‐heaters, two of three 

phase first stage separators, crude oil heaters, a three phase second stage separator and crude 

2‐21

2 ‐ 22 



transfer pumps The stabilisation system is designed to achieve a crude product specification of 25 m, while the de‐oiling package 

has been sized to achieve the regulatory



The proposed Balloch development will increase water production rates on GPIII; however, the new 

profiles will be within the FPSO’s capacity and therefore no PW plant modifications are required as 

part of the proposed development. Furthermore, to accommodate the PW from Balloch, higher 

water cut production from Donan and Lochranza may be choked back to optimise the production 

facilities. Overall, the water balance should remain stable and unaffected by the introduction of 

Balloch fluids. Recent disposal well interventions have increased well productivity significantly and 

overboard disposal is not envisaged. However, in an upset condition or well deterioration some 

overboard disposal may be required. 

No new sand management facilities are proposed as part of the Balloch development. Completion 

design will be optimised to minimise sand production. Sand production at the proposed development 

is likely to be at similar levels to the Donan and Lochranza wells. 

2.6.5. CONDENSATE AND GAS PRODUCTION 

The GPIII topsides have two design modes of operation for treating condensate, which are 

condensate re‐circulation and condensate extraction and export with gas. The latter has not been 

commissioned or implemented to date on the GPIII and is not envisaged to be required for Balloch 

production. This is due to the decline in Donan and Locharanza production relative to the phasing of 

Balloch wells. 

Balloch condensate, however, will result in the export gas becoming richer. For the Balloch high 

profiles, this condensate enrichment could result in exceeding agreed specifications, which are 

currently approaching their limit. A change in gas export specifications agreements will allow some of 

the excess condensate to be exported in the gas. Continuous future gas availability for fuel and start 

up of the GPIII FPSO is uncertain and dependent on the degree of future development. The gas export 

pipeline is scheduled to change service and become a gas import line as early as Q3 2013 in order to 

supply fuel gas to NSP and, at some point in the future, GPIII. 

Maersk Oil have carried out parallel studies on ongoing constraints imposed on current production on 

the GPIII and have identified strategies to de‐bottleneck any future processing constraints. 

2.6.6. UTILITY SYSTEMS 

The GPIII’s utility systems are summarised in Table 2‐16. 

2‐23

2 ‐ 24 

Table 2‐16 The GPIII’s utility systems. 

Utility System Description 



Power generation Two main generators (Alstom GT35), driven by dual fuel turbines (fuel gas or diesel) 

provide a total of approximately 32 MW. 

Four diesel generators each provide 4.2 MW. 

One emergency diesel generator rated at 1.7MW, 440v, 60Hz. 

Fuel gas The Fuel gas system is designed for 25 mmscfd and fuel gas is preferentially taken 

from downstream of the dehydration package. 

Flare system The HP Flare system is designed for 155 mmscfd with a minimum design temperature 

of –100°C. 

The LP Flare system is designed for 25 mmscfd with a minimum design temperature of 

–10°C. 

Heating Medium Heating medium is distributed to both the inlet and second stage heaters in the 

Separation package. 

There are two Waste Heat Recovery Units (WHRU), each designed to recover 15 MW 

of heat from the power generation exhaust gases. 

Chemical Injection The chemical injection package contains fourteen storage tanks and twenty‐two 

injection pumps. Swivel flowpaths are also provided for chemical injection. 

Seawater cooling Seawater cooling is provided to both the marine systems and topside users. The 

process cooling seawater system has a capacity of 1,866 m 3 /hr. 

Stream system Steam is produced in 2 x 100 % boilers, each capable of producing 10 tons/hr of steam 

at 8 barg. The steam is generated using dual fuel boilers and is supplied for heating to 

the cargo heaters, slop tank heaters, fresh water generation, lube oil tank/purifier 

heating, bilge holding tank heating, sea chests and hot water systems. 

Instrument & Plant Air Both instrument and plant air are supplied from the marine systems. 4 x 33 % 

compressors operate, each capable of delivering 1m170 Nm 3 /hr. 

2.6.7. POWER DEMAND 

On the GPIII the power demand for water injection and gas compression is high, in addition to 

variable demands from the FPSO thrusters and during offloading. The demand is satisfied by a 

combination of two 16 MW turbine generators and four 4.2 MW generators. Three of the 4.2 MW 

generators are dual fuel. Excluding periods of bad weather and cargo offload, the turbine generators 

are each nominally rated at 50 % of the total load. 

In addition to power generation, there is a 30 MW waste heat recovery system for process heating as 

well as other standard utility systems including emergency flare, fuel gas, chemical injection and 

drains systems. Waste heat recovery units (WHRUs) have been fitted to both turbines and again, 

each rated for 50 % of the peak heat duty. The heating medium is pressurised fresh water. 

Existing power generation facilities are expected to be sufficient to meet the power requirements of 

the proposed Balloch development. Fuel consumption on the GPIII in 2011 included 16,208 te of 

diesel and 27,578 te of gas. This fuel use was associated with the production shown in Table 2‐17. 

Production on the GPIII in 

2011 

Table 2‐17 Total GPIII production in 2011. 

Oil (m 3 ) Gas (m 3 ) Produced water (m 3 ) 

1,155,354 101,331,614 3,947,973 

It should be noted that in 2014, the year of anticipated maximum oil and gas production at the 

Balloch field, the P10 Balloch oil and gas production profiles are less than 8 % greater than the GPIII 

2011 profiles. Maximum water production at the Balloch field is associated with 2016 with an 

anticipated annual production of 1.26 million m 3 . This production is approximately 32 % of the PW 

volumes associated with the GPIII 2011 production. In Section 5, a conservative approach is applied 

to predict fuel use at the GPIII following the development of the Balloch field and assumes an increase



of 35 % on that used in 2011. Considering the oil, gas and PW production together, an estimated fuel 

increase of 35 % on 2011 is expected to over estimate the maximum annual fuel required for 

production of the Balloch fluids. 

2.6.8. VENTING AND FLARING 

The quantity of atmospheric gases vented from the GPIII is directly related to the volume of oil 

offloaded. This is because the tankers are filled with inert combustion gases that are vented as oil 

from the FPSO displaces them. In 2011 venting associated with the offloading of oil from the GPIII 

resulted in the production of 16 te of CH4 and 1,933 te of VOCs. It is possible to predict the CH4 and 

VOC emissions using factors provided in EEMS (2008). Predicted CH4 and VOC emissions associated 

with the offloading of the Balloch oil in 2014 (year of maximum Balloch production) are 21 te and 

2,488 respectively. 

Development of the Balloch field will not substantially increase flaring on board the GPIII. Section 

5.3.1 presents the 2011 flaring associated with the FPSO. 

2.7. CHEMICAL USE 

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 (Pose Little or No Risk to the environment) or are of a 

Hazard Quotient (HQ) 1, this 

indicates a possible risk of the discharge causing harm to the marine environment. This results in 

further investigation of the product to determine if there is an alternative product that can be used 

which produces a lower RQ or if the discharge can be diluted in order to reduce its RQ. 

Chemical usage or discharge is assessed via the appropriate PON15D prior to any activity taking place. 

Anticipated chemical requirements associated with the production of hydrocarbons from the Balloch 

field are listed in Section 2.5.11. 

2.8. PRODUCTION 

Maximum (P10) anticipated production profiles have been developed for the proposed Balloch 

development which forecast the likely volumes of oil, gas and water that will be produced from the 

reservoir. These production profiles are based on the drilling of three production wells. First oil is 

expected in Q3 2013 and production is expected to last 7 years, i.e. to the end of 2019. However, it is 

possible that production may continue after this date as it is planned to extend the life of the GPIII via 

infill well drilling and tiebacks that would in turn allow Balloch to continue producing. As a result, 

production profiles are presented assuming a cessation of production (COP) at the end of 2026. 

Assuming a COP at the end of 2026, high case production (P10) at the Balloch development is 

anticipated to be approximately 3.9 million m 3 of oil and 313 million m 3 of gas. By the end of 2019, 

3.59 million m 3 of oil and 313 million m 3 of gas are expected to have been recovered. 

Anticipated production profiles for the Donan and Lochranza fields are also presented in order that 

the impact of the proposed Balloch development on total production on the GPIII can be considered. 

P50 (i.e. medium case) production profiles are presented for these fields as production to date has 

been found to be more closely related to the calculated P50 profiles than to the P10 profiles. These 

P50 profiles assume the drilling of two further infill wells. 

2‐25

2.8.1. OIL PRODUCTION RATE 

2 ‐ 26 



Table 2‐18 and Figure 2‐13 show the anticipated P10 oil production profiles for the proposed Balloch 

development. 

Peak daily production at the Balloch field occurs in 2014, with a maximum production rate of 

3,408 m 3 /day. By 2019, oil production is anticipated to drop to 417 m 3 /day and to 42 m 3 /day by 

2026. When combined with the Donan and Lochranza production, 2014 is also the year of maximum 

oil production on the GPIII. 

Year 

Table 2‐18 Anticipated oil production profiles. 

Balloch (P10) 

Annual average oil production rate (m 3 /day) 

Donan & Lochranza 

(P50) 

GPIII production (i.e. 

Balloch, Donan & Lochranza) 

2012 ‐ 3,463 3,463 

2013 (Jan‐Aug) ‐ 1,730 1,730 

2013 (Sept‐Dec) 1,590* 1,730 3,320 

2014 3,408 1,013 4,421 

2015 2,845 636 3,481 

2016 1,544 402 1,946 

2017 861 242 1,103 

2018 578 162 740 

2019 417 119 536 

2020 301 87 388 

2021 217 63 280 

2022 156 46 202 

2023 113 34 147 

2024 81 25 106 

2025 58 18 76 

2026 42 1 43 

*2013 First oil at Balloch is anticipated in Sept 2013. Averaged over all of 2013, the mean daily rate of 

production is 530 m 3 /day.



2.8.2. GAS PRODUCTION RATE 

Figure 2‐13 Anticipated oil production profiles. 

Table 2‐19 and Figure 2‐14 show the anticipated P10 gas production profiles for the proposed Balloch 

development. 

Similar to the oil profiles, gas production is anticipated to peak in 2014, at a rate of 297,544 m 3 /day. 

In 2019, gas production from the Balloch field will have dropped to 36,408 m3/day while total gas 

production at the GPIII will be 125,213 m 3 /day. By 2026, average gas production at the Balloch field 

will be approximately 3,682 m 3 /day. 

2‐27

2 ‐ 28 

Year 

Table 2‐19 Anticipated gas production profiles. 

Balloch (P10) 


Annual average gas production rate (m 3 /day) 


(P50) 




2012 ‐ 361,349 361,349 

2013 (Jan‐Aug) ‐ 223,523 223,523 

2013 (Sept‐Dec)* 138,811 223,523 362,334 

2014 297,544 157,867 455,411 

2015 248,366 138,575 386,941 

2016 134,834 120,451 255,282 

2017 75,200 105,082 180,361 

2018 50,450 96,161 146,611 

2019 36,408 88,805 125,213 

2020 26,244 82,012 108,256 

2021 18,918 75,738 94,656 

2022 13,637 69,944 83,581 

2023 9,830 64,594 74,424 

2024 7,086 59,653 66,739 

2025 5,108 55,089 60,197 

2026 3,682 4,400 8,082 

*2013 First oil at Balloch is anticipated in Sept 2013. Averaged over all of 2013, the mean daily rate of gas production is 

46,270 m 3 /day. 

2.8.3. WATER PRODUCTION RATE 

Figure 2‐14 Anticipated gas production profiles. 

Table 2‐20 and Figure 2‐15 show the anticipated P10 PW production profiles for the proposed Balloch 

development. Peak water production at the Balloch field is expected in 2016 at a rate of 

3,454 m 3 /day and is expected to drop to 1,987 m 3 /day in 2019 and 624 m 3 /day by 2026. When 

combined with the Donan and Lochranza profiles, peak PW is anticipated in 2015 at a rate of 17,762 

m 3 /day with the Donan and Lochranza fields accounting for more than 80 %.



Year 

Table 2‐20 Anticipated produced water production profiles. 

Balloch (P10) 

Annual average water production rate (m 3 /day) 


(P50) 



2012 ‐ 13,079 13,079 

2013 (Jan‐Aug) ‐ 14,752 14,752 

2013 (Sept‐Dec)

2.9. PERMITTING 

2 ‐ 30 



The GPIII FPSO 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 Balloch development are provided in 

the subsequent sections. 

2.9.1. ATMOSPHERIC EMISSIONS 

Pollution Prevention and Control (PPC) Permit (Permit reference: PPC 17) 

The FPSO has an existing permit under the Offshore Combustion Installations (Prevention and Control 

of Pollution) Regulations 2001 (as amended). 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 no changes to the permit are expected to be required. 

EU Emissions Trading Scheme (ETS) (Permit reference: DTI 9700) 

The GPIII FPSO has an existing permit under the Greenhouse Gas Emissions Trading Scheme (ETS) 

Regulations 2005 (as amended). The Balloch development project will not result in an increase in 

power demand on the GPIII that will generate additional emissions above historic levels and the 

permit is not expected to be amended. It is also unlikely that the installation will be eligible to apply 

for CO2 allowances from the New Entrants Reserve (NER). 

2.9.2. DISCHARGES TO SEA 

Oil Pollution Prevention and Control (OPPC) (Permit reference: L00349.23) 

The GPIII has a permit for the discharge and re‐injection of PW from the Donan and Lochranza fields 

in accordance with the Petroleum Activities (Oil Pollution Prevention and Control) Regulations (OPPC) 

2005 (as amended 2011). As Balloch will be a new field and will result in an increase in the total 

volumes of PW discharged overboard and re‐injected, an amendment to the existing OPPC life permit 

will be applied for. 

Chemical Use (Permit reference PON15D/765/37(Version1) 

The GPIII has a current chemical permit and it is anticipated that there will be an increase in chemical 

usage as a result of the Balloch development. Maersk Oil will ensure that the relevant permits to use 

and discharge chemicals offshore will be applied for and that the chemical permit is updated in 

accordance with the Offshore Chemical Regulations 2002 (as amended 2011). 

2.10. DECOMMISSIONING 

At cessation of production, the well, 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 the decommissioning of 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 EIA will be required. 

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

appropriate times, dependent on the COP and the end of field life. The date of COP and the 

commencement of decommissioning of associated facilities will depend upon field performance, field 

economics, the production of other fields tied back to the GPIII FPSO 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. 

The marine licensing provisions in Part 4 replace the licensing and consent controls previously 

exercised under Part II of the Food and Environment Protection Act 1985 and Part II of the Coast 

Protection Act 1949. The considerations built into these regimes are merged into the new regime 

with some modifications. All activities associated with exploration or production / storage operations 

that are authorised under the Petroleum Act or Energy Act are exempt from the requirements of 

MCAA. Decommissioning operations are not exempt and will require a Marine licence for all 

operations, 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 piles by water jetting 

during abandonment operations. 

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

considered at the planning stage within the decommissioning schedule. 

2‐31

2 ‐ 32 



Section 2 Proposed Development


Section 3 Baseline Environment 

3. BASELINE ENVIRONMENT 

This section describes the baseline environment, that is, the current status of the proposed project 

area. 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 site‐specific survey data. Summaries of the data from these surveys have been included in the 

relevant sections of this report, with a synopsis of the general survey information provided in 

Section 3.2. 

3.1. THE SURROUNDING AREA 

The Balloch field is located in the Central North Sea (CNS) in Block 15/20a. It lies in water depths of 

approximately 140 m and is located approximately 225 km northeast of Aberdeen and 36 km west of 

the median line between the UK and Norwegian sectors of the North Sea (Figure 3‐1). 

3.2. SURVEY INFORMATION 

Figure 3‐1 Location of the Balloch development. 

The Balloch field is located within an area of past and current oil and gas activity. Several 

environmental surveys have been conducted in the Donan field (located above the Balloch field) and 

nearby areas prior to the exploration and production activities commencing. Consequently, there is a 

substantial amount of data which can be used to describe the environmental conditions in the area. 

The main surveys used in the environmental baseline are summarised in Table 3‐1. Sampling 

locations for the surveys are provided in Figure 3‐2. 

3 ‐ 1

3 ‐ 2 

Survey 

Reference 


Table 3‐1 Survey information sources in the Balloch development area. 

Title and Description 

BP (1990) Environmental site survey for exploration well 15/20a‐m. 

ERT (1998) 


Environmental decommissioning survey of the Donan field. Environmental survey 

carried out after the field infrastructure was removed. 

Gardline (2004) Donan to MacCulloch and Tiffany pipeline route survey in 2004. 

Fugro (2005) 

Fugro (2010) 

3.3. METOCEAN CONDITIONS 

Site survey of Block 15/20 for two proposed drilling locations. The survey comprised 

of a geophysical and environmental survey programme. The environmental survey 

consisted of a seabed investigation of six sampling sites. The survey was centred 

southeast of the Balloch location. 

Site survey of Block 15/20 comprising geophysical and environmental survey 

programme in 2009 for the proposed 15/20b‐r Dunglass ‐ Balloch Appraisal Well 

drilling location. The survey used single and multi‐beam echo sounders, sidescan 

sonar, a magnetometer, pinger, boomer, coring and Cone Penetration Testing (CPT) 

equipment to provide a detailed assessment of the area (Fugro, 2010). 

The habitat assessment and environmental baseline survey consisted of seabed 

imagery using a digital stills camera and video system, along with seabed sampling 

utilising a Day grab. Overall, eight sampling stations were analysed using a 0.1 m 2 Day 

grab. The samples obtained were used to undertake hydrocarbon analysis, heavy 

metals and particle size analysis and macrofaunal analysis. 

Figure 3‐2 Environmental sampling stations and seabed bathymetry. 

In order to design and operate offshore installations in a safe and efficient manner, it is essential that 

there is a good knowledge 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, discharges and releases 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. 

3.3.1. WATER MASSES, CURRENTS AND TIDES 

The Balloch development is situated within the CNS where the water depths gradually deepen from 

south to north. The major water masses in the North Sea can be classified as Atlantic water, Scottish 

coastal water, Northern North Sea (NNS) water, Jutland coastal water and Channel water (Turell, 

1992). The predominant regional current in the CNS originates from the vertically well‐mixed coastal 

water, the Atlantic inflow from the north and, to a lesser extent, the Fair Isle/Dooley current which 

enters the North Sea north of the Orkney Isles (Figure 3‐3). The residual flow in the CNS (associated 

with North Sea circulation patterns) is typically 0.2 m/s towards the south (DTI, 2001). Therefore, this 

pattern of water movement is likely to transport any discharges towards the south and southeast. 

However, it should be noted that this generalised pattern of water movement may be influenced by 

short‐ or medium‐term weather conditions, resulting in seasonal and annual variability. 

The Balloch development lies on the eastern edge of the anticyclonic system of the east of Shetland 

Atlantic inflow. Stratification of the water column in the development area is expected, due to the 

depth of the water column and the presence of two water bodies with differing temperatures and 

salinity profiles. A colder, denser water column originating from the depths of the Fladen Ground 

underlies a warmer water mass that originates from the east of Shetland Atlantic inflow. 

Figure 3‐3 A schematic diagram of the general circulation in the North Sea (EEA, 2002). 

Mixing in the water column intensifies with increased tidal current speed, which is influenced by 

weather and seasonal factors. Over most of the North Sea, the strength of 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, with surface current velocities for mean spring tides ranging from 0.2 ‐ 1.4 m/s. The 

velocity of current profiles decreases with increasing depth through the water column. 

Semi‐diurnal tidal currents are relatively weak in offshore NNS and CNS areas (DTI, 2001). 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 that are sufficient to cause sediment mobilisation (DTI, 2001). The maximum 50 year surge 

current in the region of the development is approximately 0.4 m/s (BODC, 1998). 

3 ‐ 3

3 ‐ 4 



During storms, the re‐suspension 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 0.75 – 1 m (BODC, 1998). Specific tidal 

data for the Balloch area is provided in Table 3‐2. 

Table 3‐2 Balloch tidal data. 

Tidal measurements Balloch data (m) 

Lowest Astronomical Tide (LAT) 0 

Mean low water spring tide 0.19 

Mean low water neap tide 0.51 

Mean low tide 0.8 

Mean high water neap tide 1.09 

Mean high water spring tide 1.38 

Highest Astronomical Tide (HAT) 1.54 

3.3.2. SEABED TOPOGRAPHY AND BATHYMETRY 

The Balloch field is located within an area of gently sloping relief, with water depth typically between 

139.3 m Lowest Astronomical Tide (LAT) in the northeast to 145.3 m LAT in the southwest. The 

seabed deepens gently towards the southwest (Figure 3‐2). In the immediate area of the proposed 

Balloch well, the seabed topography is generally flat and featureless (Fugro, 2010). 

3.3.3. 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 also by a large‐scale westerly air circulation, which 

frequently contains low pressure systems (OSPAR Commission, 2000). Air temperatures at sea tend 

to remain in the range of 0 ‐ 19 o C. An exception is when easterly winds occur for extended periods, as 

this can lead to extreme cold in winter and warm conditions in summer. The extent of this influence 

varies over time, as changes in the strength and persistence of 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 shows the occurrence of 

winds from all directions, with those from the south‐southwest 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) occurring during the winter months (November ‐ March). The major 

contrast between the NNS and the 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 of 

winds of Beaufort force 7 and above in January is >30 %, but falls to



3.3.4. WAVE HEIGHT 

Figure 3‐4 Annual wind rose for the proposed Balloch development area. 

W 

NW 

SW 

N % frequency 

18 

16 

14 

12 

10 

8 

6 

4 

S 

2 

0 2 

4 

6 

NE 

8 10 12 14 16 18 

E 

SE 

Legend 

0-2m/s 

2-4m/s 

4-6m/s 

6-8m/s 

8-10m/s 

10-12m/s 

12-14m/s 

14-16m/s 

16-18m/s 

18-20m/s 

20-22m/s 

22-24m/s 

24-26m/s 

26-28m/s 

28-30m/s 

Waves are the result of wind action on the sea surface; the size of the wave is dependent on the 

distance (fetch) over which the wind blows. The wave climate of the area is important in terms of 

physical energy acting on a structure, since this will have a large influence on the structural 

requirements of the design. Within the development area, significant wave heights of 3 m and 1 m 

are exceeded 10 % of the time and 75 % of the time respectively (BODC, 1998). The largest waves 

tend to occur from the north and east. Table 3‐3 shows the seasonal variation in wave height. 

3.3.5. TEMPERATURE 

Table 3‐3 Monthly mean significant wave height (BODC, 1998). 

Month 

Monthly mean significant 

wave height (m) 

January 3 ‐ 3.5 

February 2.5 ‐ 3 

March 2.5 ‐ 3 

April 2 ‐ 2.5 

May 1.5 ‐ 2 

June 1 – 1.5 

July 1.5 ‐ 2 

August 1.5 – 2 

September 2 – 2.5 

October 2 – 2.5 

November 3 – 3.5 

December 3 – 3.5 

Sea temperature affects both the properties of the sea water and the fates of discharges and spills to 

the environment. Sea surface temperatures (SSTs) in the northeast Atlantic and UK coastal waters 

have been rising since the 1980s, most rapidly in the Southern North Sea (SNS) and the English 

Channel. Average sea surface and seabed temperatures in the area of the Balloch field are provided 

in Table 3‐4 (BODC, 1998). 

3 ‐ 5

3 ‐ 6 


Table 3‐4 Average water temperature for the Balloch development (BODC, 1998). 


Location Mean temperature in winter ( o C) Mean temperature in summer ( o C) 

Sea surface 2.5 19.9 

Sea bottom 4.5 11 

During late spring, the water column begins to stratify due to increased solar radiation and calmer 

conditions. This 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 20 m to 50 m 

during summer (OSPAR Commission, 2000). In late August/early September, stratification begins to 

break down due to decreased solar heating and increased wind and wave action. Water temperature 

remains relatively uniform through the water column during the winter months (Doody et al., 1993). 

3.3.6. 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 salinity decreases. Salinity in the development area shows little seasonal 

variation, with water salinities of approximately 35 throughout the year (BODC, 1998). 

3.3.7. AMBIENT AIR QUALITY 

Air quality measurements are not measured on offshore sites; however, regular monitoring of 

onshore sites is carried out by local authorities in many rural areas. Air quality from rural locations 

can be used as an approximation of the air quality that is likely to apply in a nearby offshore location. 

As such, information for a rural Scotland location (Strath Vaich) has been used as a proxy for the 

Balloch location and is presented in Table 3‐5. 

Table 3‐5 Ambient concentration of NO 2 for Strath Vaich (AEA Energy and Environment, 2008). 

3.3.8. WATER QUALITY 

Averaging time µg/m 3 

Average 1.0 1 

98 th Percentile 7.5 

99.9 th Percentile 16.0 

100 th Percentile 16.8 

1 Converted assuming an ambient air temperature of 10 o C 

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 

that are subject to high industrial usage. Where concentrations of total hydrocarbons are found to be 

high offshore, this is normally in the immediate vicinity of installations. Concentrations generally fall 

to background levels within a very short distance of the point of discharge (CEFAS, 2001). 

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 is an exception as dissolved lead is quickly removed onto the surfaces of suspended 

particulate matter (SPM) which is relatively high in the coastal SNS area (apart from in the Dogger 

Bank region). It therefore does not get transported in the dissolved phase to the SNS by coastal



circulation patterns (CEFAS, 1998). Since lead from estuarine sources tends to be trapped in near‐ 

shore areas, atmospheric inputs of lead 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 biphenyl (PCB) concentrations in water are usually extremely low (< 1 ng/l) 

and difficult to detect. 

Typical concentrations of THCs (total hydrocarbons), PAHs, PCBs and heavy metals in the surface 

waters of the North Sea are shown in Table 3‐6. There was no monitoring of water contaminants and 

heavy metals as part of the Balloch environmental studies; only contaminants associated with the 

sediments were analysed and these are presented in Section 3.5.3. 

Table 3‐6 Summary of typical contaminant levels found in North Sea surface water (Sheahan et al., 2001). 

Location 

Oil and 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

3.4.1. HABITATS 

3 ‐ 8 



Of the habitat types listed in the Habitats Directive (Annex I) requiring protection, four 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 (e.g. pockmarks associated with Methane‐ 

Derived Authigenic Carbonate (MDAC)); 

submerged or partially submerged sea caves. 

Currently in UK offshore waters, a number of sites have been identified as requiring protection. Two 

of these sites, the Scanner pockmark and the Braemar pockmarks, lie within 80 km of the proposed 

Balloch location. The Scanner pockmark is in closest proximity to the proposed well location, lying 

approximately 10 km southeast of the development while the Braemar pockmarks are located 

approximately 75 km northeast of Balloch (Figure 3‐5). There are no other protected areas within 

150 km of the Balloch development. The closest SPAs are the internationally important seabird 

breeding colonies in the northeast of Scotland: Troup, Pennan and Lion’s Head and the Buchan Ness 

to Collieston Coast, both located over 200 km from Balloch. 

Figure 3‐5 Location of proposed development relative to protected areas.



Pockmarks identified within the Balloch development area 

Pockmarks are usually found in soft, fine‐grained seabed sediments, often post‐glacial sediments of 

the Witch Ground Formation or Flags Formation. The Balloch development is on the edge of the 

Witch Ground Basin, characterised by high densities of pockmarks of up to 40 per km 2 . 

Pockmarks are typically greater than 10 m across and several metres 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 MDACs ‐ mineral formations thought to be created by escaping methane. MDACs 

usually occur as a result of either microbial decomposition of organic matter (microbial methane) or 

the thermocatalytic destruction of kerogens (thermogenic methane) (Judd, 2001). 

Pockmarks alone are not considered to conform to any of the Annex I habitats; however, MDAC 

structures within pockmarks are often associated with the potentially important ‘submarine 

structures’ listed in Annex I. 

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 (Figure 3‐6). In addition, as a 

result of the seabed depression, currents are likely to be reduced within the pockmark and finer 

sediments with higher organic content are likely to accumulate. 

Figure 3‐6 Photograph of pockmark (with evidence of bioturbation) (Fugro, 2005). 

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 Thyasira 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). 

The Scanner pockmark is a large seabed depression measuring approximately 600 m by 30 m, with a 

depth of approximately 20 m below the surrounding sea floor. The area supports species associated 

with rock reef structures. Amongst the species to colonise the carbonate structures are anemones, 

squat lobsters and Astromonema southwardorum (a specialist in methane‐rich environments and 

unique to this site). 

The pockmarks in the Balloch area were initially identified during a seabed site survey in 1990 for the 

exploration well 15/20a‐m. They were found to be small and shallow, less than 50 m across and 

about 1 m deep (BP, 1990). This is in keeping with the trend for pockmark sizes to be smaller towards 

the ends of the Witch Ground Basin (Dando, 2001). The density of pockmarks in the 1990 survey was 

found to be 14 per km 2 . Photographs taken of the pockmarks, however, showed no unusual features 

or evidence of MDAC (BP, 1990). 

3 ‐ 9

3 ‐ 10 



The Fugro (2005) environmental survey which covered the area of the proposed Balloch well, but also 

an area to the south (Figure 3‐2), located a seabed depression measuring approximately 175 m by 

125 m and orientated approximately N‐SSW. The pockmark is situated over 1 km southwest of the 

proposed Balloch drilling location. The pockmark has previously been addressed in Environmental 

Impact Assessments (EIAs) for the Donan Phase II Development ES and subsequent PON15s. The 

depression showed one main pockmark running north to south with a second, considerably shallower 

pockmark to the south‐southwest. This depression was classified as a composite pockmark showing 

two pockmarks located within its limits. Photographs of the seabed location could not find evidence 

of the presence of MDAC. 

The environmental survey for the Balloch ‐ Dunglass appraisal well (Fugro, 2010) covered an area 

3 km to the west of the proposed Balloch well location (Figure 3‐2) and found nine large depressions 

greater than 20 m in diameter. The depressions were associated with steep gradients of up to 8° and 

depths of up to 2 m below the surrounding seabed. These depressions were identified as being 

potential seabed pockmarks, although previous surveys of the developmental area found no evidence 

of any leaking gases at these locations. 

A pipeline route survey undertaken to establish potential routes from Donan to MacCulloch identified 

numerous pockmarks. Most of these were small (



The contribution of existing protected area analysis; 

Contribution of other area‐based measures; and 

Contribution of least damage/more natural locations. 

At the time of writing (August 2012), the final list of MPAs had yet to be announced; however, the 30 

draft Scottish MPA search locations are shown in Figure 3‐7. The Balloch location is situated within 

the ‘East Scotland’ region, within which are three areas that have been identified as MPA search 

locations. The closest, situated approximately 30 km southeast, is the Norwegian Boundary Sediment 

Plain (NBSP). Other areas within the region include the East of Gannet and Montrose Fields (EGM), 

located approximately 130 km to the south of Balloch, and the Firth of Forth Banks Complex (FOF), 

situated over 260 km to the south west. 

Figure 3‐7 Scottish Marine Protected Area search locations with Balloch location (reproduced from SNH, 2011). 

Balloch 

A brief description of the nearest MPA search location, the Norwegian Boundary Sediment Plain (as 

described in SNH, 2011), is provided below: 

Norwegian Boundary Sediment Plain 

The MPA search features that occur within the NBSP search location include ocean quahog and 

offshore subtidal sands and gravels. Offshore subtidal sands and gravels occur across the majority of 

the search location and constitute shelf biotopes of this search feature, with ocean quahog records 

scattered throughout, except at the most northerly and western limits. The search location does not 

overlap with any key geodiversity areas or blocks. 

3.4.3. SPECIES 

The designation of fish species requiring special protection in UK waters is receiving increasing 

attention, with particular consideration being paid to large slow‐growing species such as sharks and 

rays. At a national level, the Wildlife and Countryside Act 1981 lists nine protected species of marine 

and estuarine fish (European sturgeon, allis and twaite shad, basking shark, angel shark, the whitefish 

Coregonus lavaretus, the short‐snouted seahorse, the giant goby and the couchs goby). Under the EC 

Habitats Directive, there are eight fish species (European sturgeon, allis and twaite shad, river and sea 

lamprey, salmon and Atlantic salmon and the whitefish Coregonus lavaretus) that are afforded 

protection. In addition, the International Union for the Conservation of Nature and Natural Resources 

3 ‐ 11

3 ‐ 12 



(IUCN) has assessed the conservation status of a limited number of fish groups and recommended 

that two North Sea inhabitants, the basking shark (Cetorhinus maximus) and the common skate 

(Leucoraja batis), be added to the IUCN 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 thus are not vulnerable to human activity in the area of Quadrant 15. 

Of the species listed, only the European sturgeon (which is relatively rare), the basking shark (UK 

Biodiversity Action Plan and 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 

(Rogers and Stocks, 2001). Although present within the North Sea, they are uncommon and widely 

dispersed; hence they 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). 

Of the four species listed above, only the harbour porpoise is a regularly occurring species in the 

region of the proposed development. 

The bottlenose dolphin and harbour porpoise are also classified as European Protected Species (EPS), 

along with all cetacean species 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 

potential offences to EPS species (Section 5.4.4). 

3.5. THE SEABED 

Through the processes of erosion, transport and deposition, seabed sediments are often in a state of 

dynamic equilibrium. Understanding the nature of the seabed sediments in the area of the Balloch 

development will help assess the potential for scouring in the area, as well as any impacts it may have 

on the proposed development. 

3.5.1. SEABED SEDIMENTS 

Seabed sediments comprising of mineral and organic particles occur commonly across the United 

Kingdom Continental Shelf (UKCS) 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 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 

3‐8.



Figure 3‐8 North Sea sediment distribution (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 nature of the local seabed sediments also plays a very important role in determining the flora and 

fauna present. Seabed sediments provide habitats and a food source for benthic infauna which in 

turn are preyed upon by other species such as fish and shellfish. Whilst gravely sediments are 

important to bottom spawning fish species, muddy sediments are favoured by burrowing shellfish 

species such as Norway lobster (Nephrops norvegicus). 

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, etc.) on the local seabed environment. 

Particles of various types and sizes, notably the silt/clay fraction, can absorb petroleum hydrocarbons 

from sea water. 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 that are adsorbed to sediment or organic matter is poorly understood. 

3.5.2. SEDIMENT CHARACTERISTICS 

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 gravely 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). 

3 ‐ 13

3 ‐ 14 



The Mapping European Seabed Habitats (MESH) project categorised seabed sediments in the UKCS 

area. From this, a predictive map of European sediment types was developed (Figure 3‐8). The 

sediments in the vicinity of the Balloch development are predominantly sublittoral mud and sandy 

mud. 

Within Block 15/20, very soft clays occur as pockets and ribbons up to about 1.5 m deep in some 

areas, with more extensive deposits also occurring. Sediments underlying the surface cover of sandy 

mud comprise the very soft clays of the Witch Ground Formation and the firmer clays of the 

Swatchway Formation. Superficial deposits in areas where the Witch Ground Formation is absent are 

underlain by the Swatchway Formation. Swatchway deposits are firmer silty or sandy clays that vary 

in thickness between about 7 m to 26 m (Fugro, 2010 and Gardline, 2004). 

Seabed sediments in the Balloch area were observed as relatively homogeneous across the site and 

consisting of very poorly sorted coarse silt, with a silt/mud component of 66.9 % (Fugro, 2010) (Figure 

3‐9). 

Figure 3‐9 Example seabed photographs from the Fugro (2010) site survey. 

Organic matter primarily comprising of detrital matter and naphthenic materials, i.e. carboxylic acids 

and humic substances, performs an important role in marine ecosystems by providing a source of 

food for suspension and deposit feeders which may then be predated by carnivores. This has led to 

the suggestion that variation in benthic communities is, in part, caused by the availability of organic 

carbon (Snelgrove and Butman, 1994). Organic carbon is also an important adsorber (scavenger) of 

heavy metals and may be of use when interpreting the distribution of metals (McDougall, 2000).



Total organic matter (TOM) ranged between 3.8 % (station 2) and 7.5 % (station 4) (Fugro, 2010). 

TOM levels at the majority of stations were higher than typical background levels found at 95 % of the 

stations in the CNS (4.48 %) (UKOOA, 2001). 

3.5.3. SEDIMENT CONTAMINANTS 

A summary of contaminant levels typically found in surface sediments of the North Sea is given in 

Table 3‐7. Across the North Sea, quantities of total hydrocarbons in sediments tend 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 (sands and gravels) due to their 

greater surface area and adsorptive capacity. Nevertheless, it should be noted 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 (CEFAS, 2001). 

For PAHs it is thought the same is true, with concentrations higher in the NNS relative to the SNS and 

total PAH concentration ranging between 0.02 µg/kg and 74.7 µg/kg at oil and gas locations. 

Table 3‐7 Contaminant levels typically found in surface sediments of the North Sea (Sheahan et al., 2001). 

Location 


Installations 

THC 

(µg/g) 

10‐450 

PAH 

(µg/g) 

0.02‐ 

74.7 

PCB 

(µg/kg) 

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 

Estuaries ‐ 0.2‐28 6.8‐19.1 ‐ ‐ ‐ ‐ ‐ 

Coast ‐ ‐ 2 ‐ ‐ ‐ ‐ ‐ 

Offshore 17‐120 0.2‐2.7 5000 m 

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 

Total Hydrocarbon Concentrations 

The stations surveyed by Fugro (2010) had relatively low levels of THCs. Levels varied from 2.8 µg/g 

dry weight to 6.6 µg/g at stations 4 and 6 respectively. These levels were higher than the 

concentrations recorded previously for the Donan field environmental survey (Fugro, 2005), but 

comparable to the published UKOOA (2001) mean background concentration of 9.51 µg/g. 

Carbon Preference Index (CPI) 

The Carbon Preference Index (CPI) is used to assess the relative contribution of petrogenic and 

biogenic sources in hydrocarbon samples and is determined by calculating the ratio of the sum of 

odd‐ to the sum of even‐carbon n‐alkanes. The range of n‐alkanes from nC21‐36 is of particular interest 

3 ‐ 15

3 ‐ 16 



as odd carbon n‐alkanes from terrestrial plants are removed in this region. Pristine sediments 

exhibiting a predominance of odd number biogenic n‐alkanes might be expected to have a CPI value 

greater than 2.0, while crude oil or refined products show no preference for odd or even n‐alkanes 

and achieve a CPI close to unity (1.0) (McDougall, 2000). 

The CPI ratio indicated that the Balloch survey area showed a dominance of odd‐numbered alkanes, 

with values relatively constant ranging between 2.05 and 2.39 throughout the survey area (stations 4 

and 2 respectively) (Fugro, 2005). High CPI ratios (>2) of longer chained (nC12‐36) alkanes are usually 

taken to indicate input of cuticular waxes from higher terrestrial plants. The CPI levels were higher 

than the UKOOA (2001) mean background levels for this region of the North Sea, indicating that the 

sediment is typical of the CNS as it does not show any evidence of point source contamination. 

Polycyclic Aromatic Hydrocarbons (PAHs) 

Polycyclic Aromatic Hydrocarbons (PAHs) are evident throughout the marine environment (Laflamme 

and Hites, 1978), with natural sources including plant synthesis and natural petroleum seepage. 

However, these natural inputs are dwarfed in comparison to the volume of PAHs arising from the 

combustion of organic material such as forest fires and the burning of fossil fuels (Youngblood and 

Blumer, 1975). These pyrolytic sources tend to result in the production of heavier weight 4‐6 ring 

aromatics (but not their alkyl derivatives) (Nelson‐Smith, 1972). 

Another PAH source is petroleum hydrocarbons, often associated with localised drilling activities. 

These are rich in the lighter, more volatile 2‐3 ring aromatics (NPD; naphthalene (128), phenanthrene, 

anthracene (178) and dibenzothiophene (DBT) with their alkyl derivatives). As the lightest and most 

volatile fraction, NPD is the dominant PAH in petrogenic hydrocarbons but is also the quickest to 

degrade and weather over time. 

The 2‐6 ring PAH concentrations ranged from 76 ng/g (station 4) to 289 ng/g (station 6). No spatial 

pattern of distribution was seen across the site. The mean total PAH concentration at all stations was 

higher than that found during the previous Fugro (2005) survey (33 ng/g). The majority of stations 

were marginally lower than the mean background levels for the CNS (233 ng/g, UKOOA, 2001), with 

the exception of station 6 (289 ng/g). Significant positive autocorrelations (p



the proportion of fine (

3 ‐ 18 



The composition and abundance of plankton communities vary 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). 

Plankton also includes the eggs, larvae and spores of non‐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 plankton community, although vulnerable to chemical or hydrocarbon releases to the sea, is less 

vulnerable to one‐off incidents than the benthos, because most phytoplankton have rapid maximum 

doubling times and there is a continual exchange of individuals with the surrounding waters (North 

Sea Task Force, 1993). A consequence of rapid doubling times is that when light and nutrient 

conditions are favourable, “blooms” of these organisms can develop. Although they are sometimes 

caused by anthropogenic pollution, plankton blooms occur naturally. These blooms have tended to 

occur each spring in the North Sea water with a smaller peak in the autumn. However, recent studies 

(FRS, 2007) indicate that the pattern has changed to a single bloom throughout the summer. 

Additionally, Harmful Algal Blooms (HABs) involving nuisance or noxious species can occur. These 

blooms can result in changes to the ecosystem causing discolouration, fish and marine organism 

mortality, deoxygenation and foam formation. The causes of HAB include rapid reproduction of a 

species, reduced grazing pressure or alterations in light, temperature, salinity and nutrients (Johns 

and Reid, 2001). 

3.6.2. BENTHOS 

Bacteria, plants and animals living on or within the seabed sediments are collectively referred to as 

the benthos. Species living on top of the sea floor may be sessile (e.g. seaweeds) or freely moving 

(e.g. starfish) and are collectively 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 sea bed. Benthic species may 

also be classified in terms of their size. Macrobenthos are organisms greater than 1 mm in size, 

microbenthos are smaller than 50 µm and the meiobenthos (50 µm to 1 mm) lie in between. These 

classifications, together with examples of representative groups, are shown in Table 3‐10.



Table 3‐10 Classification of benthic organisms based on size. 

Size categories Examples of representative groups Feeding notes 

Macrobenthos (>1 mm) 

Meiobenthos (50 µm to 

1 mm) 

Microbenthos (

3 ‐ 20 



Activities that result in the disruption of the seabed, such as the deposition of discharged drill 

cuttings, can affect the benthic fauna (Clark, 1996). It follows that the deposition of rock, subsea 

structures and pipes also have an effect. An ICES (International Council for the Exploration of the Sea) 

report on the structure and dynamics of the North Sea benthos (Rees, 2007) concludes that the 

ecological effects of anthropogenic influences arising from oil and gas installations and aggregate 

extraction were not identifiable on a large ICES Block scale and that there was no evidence of a 

footprint associated with clusters of installations, but rather that any variations identified were 

associated predominantly with natural forces. In addition, it concludes that the benthos are 

sufficiently resilient to accommodate the consequences of contemporary anthropogenic influences 

over large scales without significant degradation. 

Epifauna 

The seabed photos taken in the Balloch environmental surveys showed that the epifauna was sparsely 

distributed (Fugro, 2005 and 2010). The most prominent of the sessile epifauna was the seapen 

Virgularia mirabilis, which was present in photographs throughout the survey area (Fugro, 2010). A 

shoal of juvenile fish (Gadidae spp.) was observed at stations 7 and 8 in the Fugro 2010 survey. There 

was a lack of any hard substrate except epilithic (rock‐living) species. Other recorded epifauna 

included sea stars (Astropecten irregularis) and Norwegian lobsters (Nephrops norvegicus). Example 

photographs of the most prominent epifaunal and infaunal taxa are provided in Figure 3‐10. 

Figure 3‐10 Example epifauna that were captured during the Fugro 2010 survey. 

Plate 1: Seastar, Astropecten irregularis 

Plate 2: Sea pen, Virgularia mirabilis 

Plate 3: A shoal of juvenile gadoids 

Plate 4: A Norwegian lobster, Nephrops norvegicus, and carridean shrimps



Macrofauna 

The results of the macrofaunal survey (Fugro, 2010) suggest the community within the proposed 

Balloch development area is highly diverse with 152 discrete macrofaunal taxa (>0.5 mm) being 

represented in the samples collected within the survey area. These comprised of 70 annelid, 39 

crustacean, 36 molluscan and 3 echinoderm, along with 4 others belonging to other phyla. Annelids 

were dominant in the samples, representing 65.4 % of the fauna. 

The most abundant taxon recorded during the Fugro (2010) survey was the amphinomid polychaete 

Paramphinome jeffreysii, an almost ubiquitous member of CNS communities that frequently 

dominates the fauna in unimpacted areas. P. jeffreysii is a north Atlantic species generally found 

burrowing in mud and fine sands from the shallow sub tidal to depths of over 100 m. The second 

most numerically dominant species was a bivalve, the filter feeding Adontorhina similis, which is 

typically found in the North Sea (including around oilfields) in mixed sediments at water depths of 

between 85 m and 161 m. Levinsenia gracilis was the third most numerically dominant species. 

L. gracilis, from the Paraonidae family, is a deposit and filter feeding polychaete worm found in fine 

sediments including coarse silt and muddy sand from the lower shore to the deep sublittoral. The 

fourth and fifth most numerically dominant species (Galathowenia oculata agg. and Spiophanes 

kroyeri respectively) were found at similar levels across the survey area. These are both deposit 

feeding polychaetes. Both species are tube forming and G. oculata agg. is known to form dense worm 

colonies. Multivariate statistical analysis of the macrofaunal station data (0.3 m 2 ) identified two 

statistically significant clusters and a single outlying station. The outlying station was significantly 

different as a different taxa was observed to be dominating the fauna at this location. The same 

station was also identified as an outlier in the granulometric multivariate analysis due to the presence 

of higher proportions of very fine silt and clay, indicating that the sediment was a possible 

discriminating factor. The two clusters identified from the macrofaunal data were also very similar to 

the granulometry clusters, with just two stations switching from one cluster to the other. BIOENV 

calculations (which measure how close two sets of multivariate data are) supported the theory that 

sediment type plays a significant role in determining the macrofauna, with significant correlations 

found between the overall macrofaunal community composition and individual phi units. The 

physico‐chemical data showed little variation across the survey area and as a result there was only 

one statistically significant correlation between faunal community and the physico‐chemical 

parameters (mean particle size in µm). 

Collectively, the data suggested that the survey area is a relatively uncontaminated fine‐grained 

habitat and has a community structure typical for such a habitat in the CNS. 

Comparisons with the communities listed within The Marine Habitat Classification for Britain and 

Ireland, Version 04.05 (Connor et al., 2004) suggested that the closest biotope was ‘Levinsenia gracilis 

and Heteromastus filiformis in offshore circalittoral mud and sandy mud’ (SS.SMu.OMu.LevHet), an 

offshore mud and sandy mud biotope with a faunal community characterised by the polychaetes 

Levinsenia gracilis and Heteromastus filiformis. Other important taxa include Paramphinome 

jeffreysii, Nephtys hystricis and Spiophanes kroyeri among others (Orbinia norvegica, Thyasira 

equalis). This biotope has been previously identified in the CNS and NNS. 

3.6.3. FISH 

At present more than 330 fish species are thought to inhabit the shelf seas of the UKCS (Pinnegar et 

al., 2010) Pelagic species (e.g. herring (Clupea clupea), mackerel (Scomber scombrus), blue whiting 

(Micromesistius poutassou) and sprat (Sprattus sprattus) are found in mid‐water and typically make 

extensive seasonal movements or migrations. Demersal species (e.g. cod (Gadus morhua), haddock 

(Melanogrammus aeglefinus), sandeels (Ammodytes tobianus), sole (Solea solea) and whiting 

(Merlangius merlangus) live on or near the seabed and similar to pelagic species, many are known to 

passively move (e.g. drifting eggs and larvae) and/or actively migrate (e.g. juveniles and adults) 

between areas during their lifecycle. 

3 ‐ 21

3 ‐ 22 



Fish occupying areas in close proximity to offshore oil and gas installations will be exposed to aqueous 

discharges and may accumulate hydrocarbons and other contaminating chemicals in their body 

tissues. The most vulnerable stages of the life cycle of fish to general disturbances such as disruption 

to sediments and oil pollution are the egg and larval stages, hence recognition of spawning and 

nursery times and areas within a development area is imperative. 

Table 3‐11 shows approximate spawning and nursery times of some fish species occurring in or near 

the area of the proposed development. Spawning and nursery areas cannot be defined with absolute 

accuracy and are found to shift over time. 

Table 3‐11 Summary of spawning and nursery activity for commercial fish species found in area of the 

development (Coull et al., 1998). 

Month/Species J F M A M J J A S O N D Nursery* 

Norway pout 

Nephrops 

Blue whiting 

Spawning Peak Spawning Nursery 

*Nursery areas have been identified for the whole year and are not displayed by month. 

Figure 3‐11 and Figure 3‐12 show identified spawning and nursery grounds of some commercially 

important species occurring near the proposed development. Given that spawning and nursery 

grounds shift over time, it is worth noting that species including sprat and whiting have identified 

spawning grounds less than 70 km west of the proposed development area while nursery grounds for 

sprat and haddock have been identified less than 40 km to the west and 15 km to the east 

respectively. 

Shoals of adult and juvenile gadoid species (e.g. whiting, cod and haddock) were observed from the 

drop down cameras during the Fugro (2010) survey (Figure 3‐10). Ellis et al., (2012) also report 

spurdog, spotted ray, herring, cod, whiting, blue whiting, ling, anglerfish, sandeels, mackerel and 

plaice occurring in the area.



Figure 3‐11 Fish spawning grounds (Coull et al., 1998). 

Figure 3‐12 Fish nursery grounds (Coull et al., 1998). 

3 ‐ 23

Sharks, Rays and Skates 

3 ‐ 24 



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 (specifically common skate, long‐nose 

skate and angle shark) have been targeted by commercial fisheries and overfishing has significantly 

depleted the numbers in the North Sea. More recently, they tend to be taken as bycatch to such as 

extent that stocks are still depleting in UK waters. Work is underway to develop National Plans of 

Action for the conservation and management of Chondrichthyes. 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). 

The distribution of 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). 

Total numbers recorded for each of these species are low (Ellis et al., 2004). 

3.6.4. SEABIRDS 

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 can cause direct toxicity through ingestion and 

hypothermia as a result of the birds’ inability to waterproof their feathers. Birds are most vulnerable 

in the post‐breeding season when they become flightless during periods of moult, thus spending large 

amounts 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 from their coastal colonies and into 

offshore waters. At this time, high numbers of birds are particularly vulnerable to oil pollution. 

JNCC have produced an Offshore 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. This is due to seasonal fluctuations in the species and number of birds present in an area. The 

monthly OVI of Block 15/20 and its surrounding blocks is provided in Table 3‐12 and in Figure 3‐13 

and Figure 3‐14. The overall vulnerability of Block 15/20 and its surrounding blocks is provided in 

Figure 3‐15.



Table 3‐12 Monthly vulnerability of seabirds in the area of the Balloch field development (JNCC, 1999). 

Block 

OVI (monthly) 

J F M A M J J A S O N D All 

15/14 3 3 4 3 4 4 2 3 2 1 3 

15/15 2 2 4 3 4 4 2 3 2 1 3 

16/11 2 2 4 4 4 2 3 2 1 3 

15/19 3 3 4 3 4 4 2 3 2 1 3 

15/20 2 2 4 2 4 4 2 2 2 1 3 

16/16 2 2 4 2 4 4 2 2 2 1 3 

15/24 3 3 4 3 4 4 2 2 3 1 1 3 

15/25 2 2 4 2 3 4 2 2 3 1 1 3 

16/21 2 2 4 2 3 4 2 2 3 2 1 3 

Key 1= Very high 2= High 3= Moderate 4= Low Blank = No data 

Seabird vulnerability to oil pollution in the development block and the surrounding area is moderate 

overall. This varies throughout the year and is highest in November. Generally, seabird vulnerability 

decreases in offshore waters following the winter period when large numbers of seabirds leave the 

offshore waters and return to their coastal colonies for the breeding season. Species commonly 

found in and around this area include fulmars, gannets, shags, herring gulls, kittiwakes, arctic terns, 

guillemots, razorbills, black guillemots and puffins. Other species which are present but recorded in 

lower numbers include cormorants, arctic and great skuas, black headed gulls, common gulls, and 

greater and lesser black‐backed gulls (Stone et al., 1995). 

Figure 3‐13 Seabird Offshore Vulnerability Index during January to June (JNCC, 1999). 

3 ‐ 25

3 ‐ 26 



Figure 3‐14 Seabird Offshore Vulnerability Index during July to December (JNCC, 1999). 

Figure 3‐15 Average Annual Seabird Offshore Vulnerability Index (JNCC, 1999).



3.6.5. 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, hence routine offshore oil and gas 

activities do not directly affect these mammals. However, in cases of extreme oil spills where oil is 

washed ashore, the effects could be detrimental to some local populations which 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. 

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 grypu) 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. 

Common seals were shown to predominantly spend their time at or near haul out sites, with short 

trips to localised offshore areas. They were occasionally found 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 a 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 possibly made by 

only a few individuals (Hammond, 2000). Since the area of the development lies approximately 183 

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 offshore oil and gas industry have the potential to impact 

on cetaceans. Factors which could cause disturbance include noise or obstruction. The actual 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, 

2008). 

As marine mammals feed on fish and/or plankton, contamination of the water column affecting the 

food source could have a negative impact on cetaceans. Direct impacts could occur due to changes in 

prey availability 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 

oil and gas 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 the difficulties of species identification, has made it difficult to confidently 

assess cetacean population sizes. The JNCC has compiled an Atlas of Cetacean Distribution in 

Northwest European Waters (Reid et al., 2003). This resource provides an indication of types of 

3 ‐ 27

3 ‐ 28 



cetaceans and the 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: 

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 the 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 whales (sei, fin, pygmy sperm, Cuviers beaked, humpback and beaked) and dolphins 

(short beaked common dolphin, striped dolphin and Risso’s dolphins). Killer whales and long finned 

pilot whales have been sighted in higher numbers in the NNS, while large numbers of common 

bottlenose dolphins are to be found along the coastal regions of the UK (Reid et al., 2003). 

The CNS is home to relatively large numbers of minke whales, white‐beaked dolphins, Atlantic white‐ 

sided dolphins and harbour porpoises. A brief description of four key CNS cetacean species is 

provided in Table 3‐13. 

Table 3‐13 Overview of cetaceans found in high numbers in the offshore CNS area (Reid et al., 2003; 

JNCC, 2008). 

Species Description 

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, although 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, 

although 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 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 this species 

migrates. 

When estimating population sizes of cetacean species within the North Sea (SMRU, 2008), the region 

was divided into several areas as shown in Figure 3‐16 (JNCC, 2008). The Balloch development is 

located within area T but is reasonably close to area V. Estimated abundance and densities (animals 

per km 2 ) of cetaceans within the development area based on shipboard surveys are provided in Table 

3‐14. Harbour porpoise, minke whale, white‐sided and white‐beaked dolphins may occur in the 

development area, albeit in low numbers (SMRU, 2008).



Figure 3‐16 Chart showing how the North Sea was divided up during the SCANS II survey. 

Table 3‐14 Animal densities (animals/km 2 ) within the development area (SMRU, 2008). 

Species 

Animal 

abundance 

Area T Area V 

Animal density 

(per km 2 ) 

Animal 

abundance 

Animal density 

(per km 2 ) 

Harbour porpoise 23,766 0.177 47,131 0.294 

Minke whale 1,738 0.013 4,449 0.028 

White‐beaked dolphin and 

white‐sided dolphins 1 

12,627 0.094 6,460 0.04 

1 The data for white‐beaked and white sided dolphin is combined due to difficulty in distinguishing the two species in the field. 

3.7. 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. 

3.7.1. 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 location of major fishing grounds is therefore an important 

consideration when evaluating any potential environmental impacts from offshore developments. 

In terms of marine ecosystems, the International Council for Exploration of the Sea (ICES) 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 

3 ‐ 29

3 ‐ 30 



assessed by measuring the fishing effort, which can be defined as the number of days (time) x fleet 

capacity (tonnage and engine power). Due to the requirement of 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. It should be noted, however, that fishing effort may not be 

equally distributed across the entire area of a rectangle. 

The proposed development lies within ICES rectangle 45F0. The UK fishing effort within this area 

varies throughout the year but annually can be considered relatively low. Total fishing effort in ICES 

rectangle 45F0 represented 0.87 % of the 2011 total fishing effort in UK waters (Table 3‐15). The 

rectangle accounts for an average of 1 % of the UK total fishing effort over recent years (2009 – 2011) 

(Table 3‐15). 

Table 3‐15 Fishing effort in UK waters in ICES rectangle 45F0 (Scottish Government, 2012). 

Year 

Total fishing effort (days) in Balloch 

UK total 45F0 45F0 as % of UK 

2009 209,800 2,184 1.04 % 

2010 205,083 3,481 1.69 % 

2011 187,693 1,639 0.87 % 

ICES 45F0 is predominantly targeted for both demersal and shellfish species (Figure 3‐17), with live 

catch representing approximately 0.5 % of the total UK catch from 2009 ‐ 2011 (Table 3‐16). 

Figure 3‐17 Quantity of live catches within ICES rectangle 45F0 (Scottish Government, 2012).



Table 3‐16 Total landings by the UK fishing fleet in ICES rectangle 45F0 (Scottish Government, 2012). 

Year 

Total landings (tonnes) 

UK total 45F0 45F0 as % of UK 

2009 617,797 3,152 0.5 % 

2010 632,933 4,018 0.6 % 

2011 622,571 1,931 0.3 % 

3.7.2. SHIPPING 

The development lies within the SEA 2 area. Shipping traffic within this area of the North Sea is 

relatively moderate, with an average of between 1 and 10 vessels per day passing through these 

waters. The majority of shipping traffic comprises of 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 deadweight tonnage (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 3‐17 shows the shipping classifications for the CNS. 

Table 3‐17 Shipping classifications for the Central North Sea (Cordah, 2001). 

Shipping type Number of routes Total number of vessels Weight class (dwt) 

Merchant vessel 14 14,169 0‐1,499 

Supply vessels 20 8,564 0‐1,499 

Tankers 7 400 >40,000 

DECC use density to categorise shipping activities in the North Sea, ranking each block as having very 

low, low, moderate, high or very high shipping densities. Block 15/20 is classed as having a moderate 

level of shipping activity (DECC, 2012). 

The shipping routes in the vicinity of the proposed Balloch development were identified using 

Anatec’s ‘ShipRoutes’ software (Anatec, 2008). This data is continuously updated and takes into 

account changes to shipping routes necessitated by new and existing oil and gas installations. The 

database, however, does not include non‐fixed routes, i.e. movements of fishing vessels and traffic to 

mobile drilling units. 

The number of movements per year on routes passing through UK waters was estimated by analysing 

ship callings data at ports in the UK and Western Europe (ships greater than 100 tonnes). This 

included full details on the vessel characteristics, including type and size. Supplementary information 

was also obtained directly from ship operators, such as for passenger ferry and offshore support 

vessels. 

The routes taken by ships between ports were obtained from several data sources, including: 

Offshore installation, standby vessel and shore‐based survey data; 

Passage plans obtained from ship operators; 

Consultation with ports and pilots; 

Admiralty charts and publications. 

Overall, 22 routes passing within 10 nm of Balloch were identified (Figure 3‐18). These routes are 

trafficked by an estimated 1,990 vessels per annum, which corresponds to an average of 5 vessels per 

day. 52 % of the traffic is made up of cargo vessels (Figure 3‐19), 60 % of which have a dwt between 

1500 ‐ 5000 te. 

3 ‐ 31

3 ‐ 32 



This Anatec data is from 2008 and was collected for the development of the Donan field, which 

Balloch lies beneath, thus providing indicative data for the Balloch area. An additional Anatec 

Consent to Locate survey will be undertaken prior to operations. 

Figure 3‐18 Shipping routes within 10 nautical miles of Balloch. 

Balloch 

Figure 3‐19 Vessel type distribution within 10 nautical miles of Balloch. 

52% 

14% 

3.7.3. OTHER INDUSTRY STAKEHOLDERS OR DEVELOPMENTS 

Oil and Gas Industry 

1% 

33% 

Cargo 

Tanker 

Ferry 

Offshore 

The proposed development is within a well‐developed oil and gas area of the North Sea (Figure 3‐20). 

The Balloch field is located under the Donan field. The closest surface infrastructure to the 

development is the Maersk Oil‐operated GPIII FSPO, which the Balloch field will be tied back to, 

located approximately 3 km southwest of the proposed Balloch wells. The Miller to St Fergus pipeline 

(PL720) is located approximately 3.5 km west of the development location and the Donan gas export 

pipeline (PL2324) is approximately 2.5 km south‐southwest of the development. Neighbouring 

hydrocarbon fields are detailed in Table 3‐18.



Renewable energy 

Table 3‐18 Hydrocarbon fields within the vicinity of the development area. 

Hydrocarbon Field Distance from Balloch development 

Lochranza 3 km east 

Baldon 10 km southwest 

MacCulloch 11 km southwest 

Blenheim 13 km southeast 

Nicol 13 km south 

Figure 3‐20 Oil and gas infrastructure within the vicinity of the proposed development. 

There are no wind or wave energy harvesting installations in the area of the proposed Balloch field 

development. 

Submarine cables and pipelines 

Survey results indicate that the out of service Aberdeen to Bergen telegraph cable lies within the 

vicinity of the development (Fugro, 2010). Consultation of cable awareness charts (Kingfisher, 2011) 

revealed that there are no submarine cables in the vicinity of the Balloch development (Figure 3‐21). 

3 ‐ 33

Shipwrecks 

3 ‐ 34 



Figure 3‐21 Cables in the vicinity of the proposed development area (Kingfisher, 2011). 

Balloch 

An unknown wreck lies within the area surveyed during the Balloch ‐ Dunglass site survey (Fugro, 

2010). The wreck has dimensions of 26.6 m in length, 15.3 m in width and 1.6 m in height. It is found 

within an area of disturbed sediment, expected to have been caused when the vessel came to rest on 

the seabed (Fugro, 2010). 

Military exercise areas 

There are no known military exercise areas within the development area. 

3.8. OVERVIEW 

The Balloch field is located in the Central North Sea (CNS) in Block 15/20. It lies in water depths of 

approximately 140 m and is located approximately 225 km east of Aberdeen and 36 km west of the 

median line between the UK and Norwegian sectors of the North Sea. 

The predominant regional current in the area originates from the vertically well‐mixed coastal water 

and the Atlantic inflows from the north. Tidal currents over the proposed development area are 

relatively weak. The general pattern of water movement is likely to transport any discharges towards 

the south and southeast. 

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

the CNS. Although environmental surveys have shown pockmarks to be present in the area, these 

were considered to be small and inactive and representative of the area. Survey results from the 

development area identified no environmentally sensitive habitats that appear in Annex I of the EC 

Habitats Directive. 

The results of the environmental surveys indicate that the macrofauna community within the 

proposed Balloch development area is highly diverse, with over 152 macrofaunal taxa represented. 

The species communities present suggest that the survey area is a relatively uncontaminated fine‐ 

grained habitat and has a community structure typical for such a habitat in the CNS.



Fish species in the area are widely distributed. Spawning and nursery areas cannot be defined with 

absolute accuracy as they are found to shift over time. However, there is evidence of Norway pout 

and Nephrops spawning in the development area, while sprat and whiting have spawning grounds 

nearby. Juvenile Norway pout, Nephrops, and blue whiting use the area as a nursery ground, while 

juvenile haddock and sprat are found at relatively close distances (15 ‐ 40 km) to the development 

area. 

The Balloch field development is within an area of relatively low fishing effort, representing 

approximately 1 % of the total UK fishing effort over recent years. The area is predominately targeted 

for demersal and shellfish species. Landings within the area are also relatively low compared with 

other areas of the UK, representing less than 1 % of live catches over recent years. 

The overall seabird vulnerability to surface pollution is moderate and peaks during November. During 

the installation period for the well, the Offshore Vulnerability Index ranges from low to very high. 

A number of cetacean species frequent the development area, including white‐sided dolphin, white‐ 

beaked dolphin, minke whale, and harbour porpoise. Of the cetaceans sighted, the harbour porpoise 

is the only one protected under Annex II of the Habitats Directive. 

The Balloch development is situated in close proximity to approximately 22 vessel routes within 10 

nautical miles. These routes are trafficked by approximately 1,990 vessels per annum (approximately 

5 vessels per day). 

The Balloch field is located within a well‐developed oil and gas area of the Central North Sea, with 

many hydrocarbon fields and supporting infrastructure and pipelines in the area. Other types of 

subsea cables in the area include an out of service telecommunications cable. There are no known 

military exercise areas or renewable energy developments in the wider area. 

The Balloch development will contribute towards maintaining employment in local services and 

provide a valuable financial return to the exchequer. 

3 ‐ 35

3 ‐ 36 



Section 3 Baseline Environment


Section 4 Environmental Assessment Methodology 

4. ENVIRONMENTAL ASSESSMENT METHODOLOGY 

In order to determine the impact that the proposed Balloch development may have on the 

environment, an environmental impact assessment (EIA) was undertaken following a structured 

methodology for the identification of environmental impacts. The approach is generally qualitative, 

although estimates of some quantitative data such as atmospheric emissions are also provided in 

Section 5 and 6 which discuss the results of the EIA. 

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 EIA is discussed in Section 2. 

Potential effects are assessed in terms of: 

The duration of the activity (for planned events) or likelihood of occurrence (for unplanned 

events); 

The magnitude of the environmental impact; 

The overall environmental risk (low/moderate/high). 

Impacts assessed as having a high or moderate risk were considered further by the project team in 

order to identify additional mitigation and / or control measures. 

4.1. LIKELIHOOD 

The likelihood of the occurrence of each potential effect was given a score between one and five 

(Table 4 ‐ 1). A low score means that the likelihood of an aspect leading to an impact is low. 

Planned Activity 

Duration 

Table 4 ‐ 1 Likelihood of realisation of an impact. 

Likelihood of Accidental Event Likelihood Category 

One year to many years Likely: More than once a year 5 

One month to a year 

One week to a month 

One day to a week 

Less than a day 

4.2. CONSEQUENCE 

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 1 to 5, five being 

the most severe (Table 4 ‐ 2). Where magnitude appeared to fall within two categories, the higher 

category is selected to provide a worst case scenario for the purposes of assessment. 

4 

3 

2 

1 

4 ‐ 1

4 ‐ 2 

Level Definition 

Severe 

(5) 

Major 

(4) 

Moderate 

(3) 

Minor 

(2) 

Negligible 

(1) 

Table 4 ‐ 2 Definition of magnitude of environmental effects. 


Section 4 Environmental Assessment Methodology 

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. 

4.3. COMBINING LIKELIHOOD AND CONSEQUENCES TO ESTABLISH RISK 

The overall environmental risk of each environmental aspect/activity was assessed using the 

combination of the magnitude and likelihood scores in Table 4 ‐ 3 below. 

Likelihood of 

occurrence 

Table 4 ‐ 3 Environmental risk classification matrix. 

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 

This process was undertaken for all identified aspects with the results presented in Appendix B. For 

those aspects identified as being of moderate risk, additional mitigation measures were considered to 

demonstrate that the risk was as low as reasonably practicable (ALARP). Those aspects identified as 

moderate risk are discussed in Section 5.


Section 5 Assessment of Potential Impacts and Controls 

5. ASSESSMENT OF POTENTIAL IMPACTS AND CONTROLS 

This section presents the results from the Environmental Impact Assessment (EIA) process carried out 

for the proposed Balloch field development. The identification of potential impacts and the 

determination of their significance have been undertaken using the methodology outlined in 

Section 4. 

In the first instance, the information summarised in Sections 2 and 3 of the Environmental Statement 

(ES) was used to identify potential environmental hazards. These hazards were assessed and 

screened against the criteria set out in Section 4. Hazards that were assessed further to determine 

the significance of the impact and/or risk posed to the environment were those that: 

were subject to regulatory control; 

were found to pose a moderate or high risk to the environment; 

were raised during the consultation phase; 

or were identified as areas of public concern. 

Table 5‐1 summarises the results from the screening process and identifies the residual impact after 

mitigation measures or controls have been applied. All aspects/activities that had a moderate 

environmental risk were subject to an additional assessment and the results are summarised in this 

section. Section 6 describes the potential impacts of accidental spills resulting from a total loss of 

diesel from the drilling rig and an uncontrolled well blowout. Appendix B lists all activities associated 

with the proposed Balloch development and their potential environmental impacts. Where possible, 

mitigation measures to reduce these impacts have been identified. 

Table 5‐1 Issues identified as requiring further assessment. 

Phase/Issue Aspect/Activity 


risk (Screening) 

Residual impact 

(after Mitigation) 

Drilling Emissions to air from drilling rig and support vessels Low Low 

Subsea 

Installation and 

FPSO 

modifications 

Emissions to air from well clean‐up Low Low 

Discharge of mud to sea Moderate Low 

Discharge of chemicals to sea Moderate Low 

Physical disturbance from drilling rig Low Low 

Emissions to air from subsea installation vessels Low Low 

Discharges of chemicals from pipeline testing to sea Low Low 

Physical presence of subsea infrastructure Low Low 

Production Emissions to air Low Low 

Discharge of produced water Moderate Low 

Discharge of chemicals to sea Low Low 

Noise Vessels Low Low 

Wider 

development 

concerns 

Accidental 

events 

(Section 6) 

Installation of cooling spools Moderate Low 

Other offshore users (i.e. wind farms) Low Low 

Protected Areas/European Protected Species Low Low 

Transboundary impacts Low Low 

Subsea blowout High Low 

Loss of platform/pipeline Moderate Low 

Loss of diesel from the drill rig Low Low 

5 ‐ 1

5.1. DRILLING PHASE 

5‐ 2 



This section discusses the impacts associated with the drilling phase of the proposed development. 

These impacts are associated with emissions to air, discharges to sea and the physical presence of the 

drilling rig, vessels and anchors. Noise associated with drilling activities is discussed separately in 

Section 5.4. 

5.1.1. EMISSIONS TO AIR 

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 now strictly controlled under the Montreal Protocol). 

Atmospheric emissions associated with drilling were assessed as presenting a low environmental risk; 

however, as emissions to air are subject to regulatory control and could be considered an area of 

public concern they were further assessed. 

This section discusses the predicted emissions associated with the drilling of the Balloch wells. A 

worst case scenario of three production wells drilled during different drilling campaigns, i.e. the 

drilling rig leaves the site between wells, is assumed. In addition to assessing the emissions to air 

from the drill rig and associated vessels, this section also considers the emissions to air from well 

clean‐up operations. 

Exhaust emissions from the drilling rig, support vessels and helicopters 

Section 2 presents the maximum predicted duration of the drilling phase and the likely support 

vessels and helicopter flights required for the development. Predicted atmospheric emissions 

associated with the drill rig are given in Table 5‐2. These have been calculated using emission factors 

from the Environmental Emissions Monitoring System (EEMS) Atmospherics Calculations Issue 1.810a 

(EEMS, 2008). 

Table 5‐2 Emissions associated with drill rig while drilling the three proposed Balloch wells. 

Fuel use 

(te) 

Emissions (te) 

CO 2 NO x N 2O SO 2 CO CH 4 VOC 

Drill Rig (three wells) 2,100 6,720 125 0.46 8.4 33 0.38 4.2 

2009 total emissions from 

UKCS mobile sources 1 

Anticipated drill rig emissions 

from Balloch development as 

a % of 2009 UKCS total 

mobile rig emissions 

1 Source: EEMS 2009 data 

84,053 261,928 4,875 18 245 1,288 35 144 

2.6 2.56 2.56 3.43 2.56 1.1 2.9 

From Table 5‐2 it can be seen that, in the worst case scenario, the emissions associated with the drill 

rig amount to 2.6 % of CO2 generated by mobile drill rigs in UKCS waters in 2009. 

The atmospheric emissions from vessels and helicopters associated with the drilling activities are 

shown in Table 5‐3. These are further assessed in Section 5.2.1, where they are combined with 

emissions from vessels used during the subsea infrastructure installation phase and compared with 

the total domestic shipping emissions in UKCS waters.



Table 5‐3 Summary of emissions associated with the drilling support vessels assuming three production wells. 

Vessel type 

Fuel use 

(te) 



3 Anchor Handling Vessels 3,690 11,808 219 0.81 14.76 57.93 0.66 7.38 

Supply vessel 2,550 8,160 151.5 0.56 10.2 40.04 0.46 5.1 

Standby vessel 166 532 9.9 0.04 0.66 2.61 0.03 0.33 

Helicopter 360 1,152 21.4 0.08 1.44 5.65 0.06 0.72 

Total from vessels 6,600 21,120 392 1.45 26.40 103.62 1.19 13.20 

Emissions to air from well clean‐up and well testing 

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 begin. 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 during rig and vessel activities associated with drilling and completions. 

At the time of writing (August 2012), the volumes of hydrocarbons to be flared during well clean‐up 

and testing were not known. A worst case of 2,000 te of oil per well was therefore assumed. 

Atmospheric emissions resulting from the well test and clean‐up for the three proposed Balloch 

production wells have been calculated using the EEMS emissions factors (EEMS, 2008) and are 

presented in Table 5‐4. Total CO2 associated with flaring at the three wells equates to 0.49 % of that 

produced by similar activities in 2009 in UKCS waters. 

Table 5‐4 Summary of atmospheric emissions from the Balloch well clean‐up and well testing activities. 

Hydrocarbons 

flared (te) 



Oil 6,000 19,200 22.2 0.49 0.08 108 150 150 

2009 total hydrocarbon 

well testing emissions 

from UKCS offshore 

activities 1 

Anticipated well clean‐up 

& testing emissions as a % 

of the equivalent 2009 

UKCS emissions 

1 Source: EEMS 2009 data. 

3,931,850 3,022 113 219 10,300 15,706 11,394 

0.49 0.73 0.43 0.04 1.05 0.96 1.32 

Emissions from the well clean‐up and well test will be released approximately 225 km from the 

nearest coastline (UK). The prevailing winds from the south and southwest will carry the emissions 

away from the nearest coastline with very high dispersion and dilution of emissions occurring in the 

offshore environment (DTI, 2001). 

All relevant permits and consents (PON15B, OPPC and PPC) will be applied for to cover the clean‐up 

and well testing operations. 

Proposed control measures for impacts associated with emissions to air during the drilling phase 

Control measures to mitigate impacts from atmospheric emissions associated with drilling operations 

are presented below. 

5 ‐ 3

5‐ 4 



All impacts associated with atmospheric emissions during the drilling phase of the development are 

anticipated to be low. 


This section assesses the discharges to sea associated with the drilling phase of the proposed Balloch 

development. It assumes a worst case of three production wells. 

Discharge of drilling fluids and associated cuttings 

Proposed Control Measures 

The drilling rig will be subject to audits ensuring compliance with UK legislation. 

Support and standby vessel presence will be optimised, e.g. the GPIII standby vessel will 

serve as the standby vessel for the drilling rig. 

Flaring during well clean‐up will be undertaken using high efficiency burners. 

The tophole sections of the proposed Balloch wells will be drilled using WBM and each well will result 

in the discharge of approximately 396 te of cuttings and 170m 3 of WBM. 

The 12¼” and 8½” sections of the wells will be drilled using OBM and each well will use approximately 

326 m 3 of OBM and result in approximately 758 te of OBM contaminated drill cutting. All OBMs and 

associated cuttings will be processed using a Rotomill TM system. Similar amounts of cuttings and 

drilling mud are expected from any future additional wells. 

The treatment of drilling wastes using the Rotomill TM system will result in the generation of waste 

water, recovered oil and powder cuttings. The drilling oil will be re‐circulated into the drilling mud 

and the treated water and powder cuttings will be tested to ensure they meet acceptable 

hydrocarbon limits prior to overboard discharge. The level of retained hydrocarbons in the recovered 

solids is typically less than 0.1 % and the level of hydrocarbons in the recovered waste water is 

typically less than 20 ppm. Analysis of the waste streams produced by Rotomill TM will ensure they 

meet the regulatory limits, i.e. the hydrocarbons in the recovered water shall not exceed 30 ppm and 

those in the cuttings powder shall not exceed 1 % of hydrocarbons by dry weight. Powder samples 

will be taken every 2 hours and samples divided, with one portion retained for further analysis if 

required. Samples taken during each 12 hour period will be combined and an oil analysis performed. 

Estimates of the total quantity of OBM to be discharged on cuttings and in the water discharge 

streams will be provided in Section C of the PON15B and equivalent discharges will be provided in the 

chemical tables. 

WBM and cuttings, along with treated powder cuttings from the Rotomill TM , will be discharged 

overboard and will disperse rapidly in the water column. Upon discharge, the particles are expected 

to separate into distinct plumes, an upper plume of fine particles that will settle over wide areas and a 

plume lower in the water column containing cuttings and barite. The finer particles are expected to 

drift away and disperse, whereas the particles in the lower plume should settle to the seafloor much 

more rapidly and form a more concentrated pattern near the discharge point (Parker, 2003). Any 

soluble components of WBM will disperse into the water column without settling at all. The plumes 

of dispersed fines can cause a temporary localised increase in turbidity immediately following the 

discharge of a batch of WBM. 

As the seabed sediments are composed of fine grained materials and seabed currents are relatively 

weak, the deposition of a small cuttings pile at the Balloch well location cannot be ruled out, although 

like other wells in the area it is not expected to be visible after a couple of years (Fugro, 2010). 

Discharge of drilling mud and cuttings has been shown to smother the benthos in the immediate 

vicinity of the well, in addition to causing a temporary increase in the levels of barium in the 

sediment.



Daan and Mulder (1993) investigated the possible environmental effects of discharges of WBM 

cuttings from a single well site. This survey indicated that no adverse short‐term effects on the 

benthic community were observed from the presence of cuttings. A follow up study one year later 

revealed no adverse effects on the benthic community and further indicated that there was no 

change to the sediment characteristics beyond 1 m from the discharge point. These results are 

supported by a number of other studies, e.g. Hartley (1990), ERT (1999), ERT (2002) and Kingston 

(2002). 

Discharges of WBM are regulated under the Offshore Chemical Regulations 2002 (as amended 2010 

and 2011). As most WBM chemicals are PLONOR (Pose Little Or No Risk to the environment), the 

WBMs used are expected to disperse readily without any impact on the environment. 

The most common chemical effect of WBM discharge is a temporary elevation of barium 

concentrations in the sediment. This may extend up to 1 km from the drilling location along the 

predominant tidal axis. Barium is persistent in the sediment as barium sulphate or barium carbonate, 

both of which are essentially insoluble and therefore inert (CEFAS, 2001). These discharges are 

therefore expected to have only a localised and short‐term impact on the benthic fauna. 

The impact upon any benthic animals in the immediate drilling location is expected to be temporary. 

Any animals disturbed would be expected to re‐colonise from the surrounding area in a short 

timeframe, since the WBM used and discharged is of low toxicity and bioaccumulation potential. It 

can be expected that recovery of the seabed will start immediately once the deposition is finished. 

Therefore, no significant residual impacts are predicted. 

Flare dropout 

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. 

This could impact on the environment, particularly seabirds that may be using the area during the 

well clean‐up operations. Seabird data obtained from the area suggests that the density of seabirds 

ranges from low to very high throughout the year. 

In order to minimise the risk of flare drop‐out occurring, a green burner will be used on the drilling rig 

which is designed to burn at a greater efficiency and consequently reduce the risk of flare drop‐out. 

Flaring will not be continued if a significant sheen is observed. 

Proposed control measures for impacts associated with discharges to sea during the drilling phase 

Control measures to mitigate impacts from discharges to sea associated with drilling operations are 

presented below. 


Efficient use of WBM will be maximised. 

No OBM will be discharged to sea. 

OBM contaminated cuttings will be Rotomill TM treated before being discharged such that: 

Level of retained hydrocarbons in solids

5.1.3. PHYSICAL PRESENCE 

5‐ 6 



This section discusses the potential environmental impacts associated with the physical presence of 

the drilling rig and associated vessels, as well as the drilling rig’s anchors and chains. 

Rig and associated vessels 

The presence of a drilling rig and the increase in associated vessel movements has potential 

implications for other sea users, notably those involved in commercial fishing and shipping. 

Once in position, the drilling rig will have a temporary 500 m exclusion zone around it meaning that 

there will be no fishing or unauthorised vessels within that area. While the drilling rig is on station the 

GPIII’s guard vessel will serve the standby requirements of the drilling rig, thus minimising vessel use. 

Total fishing effort within the area of the development is approximately 1 % of total UK effort 

(Scottish Government, 2012). Shipping activity in the area is also considered to be moderate (DECC, 

2012). With mitigation measures in place, there are not expected to be any interactions between the 

rig and its associated support vessels and other vessels. 

Drilling rig anchors and chains 

The drilling rig will be held in place by an anchor mooring spread consisting of a maximum of 12 

anchors. The precise arrangement of the anchors around the rig will be defined by a mooring analysis 

which will be undertaken prior to bringing the rig into the field. This will take account of the water 

depth, tidal and other currents, prevailing wind conditions and any seabed features at the well 

location. Each anchor weighs approximately 12 te and will produce a linear scar of approximately 

50 m length during setting, before sinking into the seabed. The depth of penetration will be 

dependent on the shear strength and load bearing capacity of the seabed soils. 

Effects and their duration on the benthic community structure from disturbance caused by the 

anchors are related to individual species biology. As the majority of benthic species recorded on the 

European continental shelf have short life spans and relatively high reproduction rates, the effect of 

the anchors on the local benthic community is likely to be low. 

Proposed control measures for impacts associated with physical presence during the drilling phase 

Control measures in place to mitigate impacts from the physical presence of the drilling rig and 

associated vessels are presented below. 

In consideration of the control measures detailed above, the physical presence of the drilling rig and 

associated support vessels has been assessed as having a low/negligible impact. 

5.1.4. NOISE: DRILLING 

The impacts from noise generated by the support vessels and drilling rig are discussed in Section 5.4. 

5.2. INSTALLATION PHASE 


An exclusion zone will be established around the drilling rig, enforced by a standby vessel. 

Mooring analysis will determine rig anchor position. 

This section discusses the impacts associated with the installation of the subsea infrastructure. 

Emissions produced during subsea installation are primarily associated with vessel use. Subsea 

installation activities will cause disturbance to the seabed and could potentially interfere with other 

users of the sea. Underwater noise associated with the installation vessels and piling of the cooling 

spools is assessed in Section 5.4. This section considers the emissions to air produced by the vessels, 

physical presence of the subsea infrastructure, discharges associated with hydrotesting and the noise 

associated with piling of the manifold.




Details of the vessels required to complete the installation of the necessary infrastructure are given in 

Section 2.5.10, while the associated emissions are given in Table 5‐5. A worst case scenario whereby 

the development will include three production wells is assumed. To put these emissions into context, 

they are combined with those from the support vessels required during the drilling phase and are 

presented as a percentage of total UK domestic shipping emissions in 2009. 

Table 5‐5 Summary of emissions associated with subsea infrastructure installation vessels. 

Vessel type Fuel use (te) 1 Emissions (te) 


Vessels associated with 

installation of subsea 

infrastructure (DSV) 

Emissions from drilling 

support vessels (Table 5‐3). 

Total emissions from 

drilling support vessels and 

installation DSV 

2009 UK domestic shipping 

emissions 2 

2,148 4,852 85 0.31 5.73 22.48 0.26 2.86 

6,600 21,120 392 1.45 26.40 103.62 1.19 13.20 

25,972 477 1.76 32.13 126.1 1.45 16.06 

4,900,000 

% of UK total 0.53 % 

1 Fuel use assumes three production wells. 

2 Source: Department for Transport, 2011. 

Note: Atmospheric emissions have been calculated using emission factors from the EEMS Atmospheric 

Calculations Issue 1.810a (EEMS, 2008). 

From Table 5‐5 it can be seen that, in the worst case scenario, emissions associated with the drilling 

support vessels and the installation DSV amount to 0.53 % of CO2 generated by UK domestic shipping 

emissions in 2009. Given that the development is approximately 225 km from the nearest coastline 

and that the prevailing winds will result in very high dispersion and dilution of emissions produced, it 

can be concluded that the vessel emissions produced will resulting in no significant local air quality 

impact. In addition, the overall additive effect on climate change can be considered negligible given 

the very small portion these emissions form in relation to overall UKCS emissions. 

Proposed control measures for impacts associated with emissions to air during the installation 

phase 

Control measures to mitigate impacts from atmospheric emissions associated with installation phase 



Vessel use will be optimised, e.g. the GPIII standby vessel and supply vessel will serve 

these requirements for the installation DSV. 

Impacts associated with atmospheric emissions during the installation phase are anticipated to be 

low. 

5 ‐ 7


5‐ 8 



Routine discharges from vessels such as sewage are considered to have a negligible environmental 

impact and are therefore not considered here. Discharges assessed during the installation of the 

subsea infrastructure are associated with pipeline hydrotesting. 

Hydrotesting 

After installation and prior to being stabilised the lines will be flushed and hydrotested. It is 

anticipated that the lines will be tested using potable water and chemicals of the lowest possible 

Hazard Quotient (HQ). At the end of the testing operations, the hydrotest fluids will be discharged to 

sea. 

Concern over the impact of hydrotest water is due to the volume and types of chemicals discharged 

and the potential impact of chemicals on the marine environment. It is anticipated that only a single 

pipeline volume will be required for hydrotesting and, as such, chemical discharge will be a one‐off 

discharge; therefore, any effects from the discharge will be temporary. Based on the infrastructure 

listed in Table 2‐9 and assuming a tie‐in spool length of 20 m, a production spool inner diameter of 6” 

and a gas lift spool inner diameter of 3”,< 3m 3 of hydrotest water will be discharged during the testing 

operations of the production and gas lift jumpers and tie‐in spools at each well. 

The chemicals to be used are yet to be finalised; however, the dose and quantities will be in 

accordance with the manufacturer’s specifications and chemical permits will be sought prior to any 

chemical use or discharge using the relevant PON15 applications. Given the small volumes, the 

hydrotest fluids are expected to rapidly dilute in the marine environment. 

Proposed control measures for impacts associated with discharges to sea during the installation 

phase 

Control measures to mitigate impacts from discharges to sea associated with the installation phase 


5.2.3. PHYSICAL PRESENCE 

The physical presence of the subsea infrastructure was assessed as being of low environmental risk; 

however, given the potential for impacts on other sea users and the seabed it was further assessed. 

Section 5.1.3 discusses the potential environmental impacts associated with the physical presence of 

vessels on other sea users and the marine environment. This section will therefore concentrate on 

the physical impacts of the subsea infrastructure. 

Subsea infrastructure 


Chemicals of the lowest possible HQ will be used. 

Chemical use and discharge will be regulated under PON15C. 

The subsea infrastructure is likely to disturb the mobile benthic fauna and smother the mixed flora 

and fauna beneath. The structures could also cause a nuisance to fishing operations because of the 

potential snag risk. To mitigate against this, the X‐mas trees and cooling spools will be of a fishing 

friendly design. 

Table 5‐6 shows the area impacted by the subsea infrastructure using a worst case of three wells, 

with each at least 80 m from the DC2 manifold. The option chosen means that the area impacted is 

minimised as the only additional flow lines are the short jumpers required to connect the wellheads 

to the DC2 manifold. The maximum area impacted is anticipated to be 0.0008 km 2 .



Well heads and X‐mas Trees 

Table 5‐6 Total seabed footprint from subsea infrastructure. 

Requirement Number 1 Dimensions (L x W) (m) 

Total Footprint 

(m 2 ) 

Protective structures 3 3 x 3 27 

Jumpers 2 

6 ” production 3 80 x 0.45 108 

6 ” production (rated to 100 o C) 3 80 x 0.45 108 

3 ” lift gas 6 80 x 0.45 216 

Well set (chemical and controls) 3 80 x 0.45 108 

Control umbilical 3 80 x 0.45 108 

Tie‐in Spools 3 

Production 3 20 x 0.45 27 

Lift gas 3 20 x 0.45 27 

Cooling Spools 

Cooling spool (maximum temperature 80 o C to DC2) 2 6 x 6 72 

Total 801 

1 Number of structures assumes three production wells. 

2 For all jumpers, widths of 0.45 m have been assumed. 

3 For all tie‐in spools, lengths of 20 m and widths of 0.45 m have been assumed. 

Subsea infrastructure will be submitted for inclusion on the Admiralty Charts so that it may be 

identified by fishing vessels. It will also be entered into the FishSafe database, an industry‐sponsored 

computer system linked to vessel navigation systems that improves the ability to detect, identify and 

avoid potential hazards. 

As the benthic organisms likely to be impacted by the proposed development tend to have rapid 

reproductive cycles and widespread distributions, the impact caused by the physical presence of the 

infrastructure is not considered significant. In addition, as a result of the proposed notification 

measures the impacts on other sea users is considered low. 

Mattresses and grout bags 

The subsea infrastructure will be surface laid and will required some degree of protection; it is 

anticipated that a total of 30 mattresses and 15 grout bags will be used should the three production 

wells be required (Table 5‐7). The maximum footprint of these protective structures is 0.0005 km 2 . 

5 ‐ 9

5‐ 10 



Table 5‐7 Total seabed footprint from seabed protection structures. 

Structure Number 1 Dimensions (L x W) (m) Total Footprint (m 2 ) 

Mattresses 30 6 x 3 540 

Grout bags 15 1 x 0.5 7.5 

Total footprint 547.5 

1 Number of structures assumes three production wells. 

The mattresses and grout bags will result in a permanent change to the seabed habitat and associated 

benthic communities. It is possible that new colonising epifauna will, over time, start to colonise the 

mattresses and grout bags. However, the overall change that would be brought about by the creation 

of a relatively small area of hard substratum within a large expanse of soft sediment habitat is 

considered negligible. 

It is possible over time that, as well as becoming colonised by marine organisms, the mattresses and 

grout bags will be buried or partially buried under the soft sediments. 

5.2.4. NOISE 

The impacts from noise generated by the installation vessels and piling of the cooling spools are 

discussed in Section 5.4. 

Proposed control measures for impacts associated with physical presence during the installation 

phase 

The following control measures are proposed to minimise the impact associated with physical 

presence during installation. 

In consideration of the above control measures, the impact of the physical presence of the subsea 

infrastructure associated with the proposed development is not expected to be significant. 

5.3. PRODUCTION PHASE 

This section describes the environmental impacts associated with the production phase of the 

proposed Balloch development. It considers the environmental impact of the atmospheric emissions 

and PW discharges and lists proposed mitigation measures to limit their effect. 


Emissions from the production phase can primarily be divided into emissions associated with power 

generation and those associated with flaring, each of which are described here. 

Emissions from power generation 


Subsea infrastructure will be fishing friendly. 

Seabed infrastructure will be entered into Admiralty charts and the FishSafe system. 

The tieback option chosen minimises subsea infrastructure requirements. 

The main source of atmospheric emissions for the Balloch development will be from power 

generation at the GPIII, with the principle routine operational emissions including CO2, CO, NOx, SO2, 

CH4 and VOCs. As discussed in Section 2.6.7, the power requirements will be met by existing power 

generation facilities.



It is expected that production from the Balloch development will not result in a significant increase in 

power demand on the GPIII FPSO. However, for the purposes of this ES a worst case of a 35 % 

increase in power demand (relative to that required in 2011) was assumed. 

In 2011, total uses of diesel and fuel gas on the GPIII were 16,208 te and 27,578 te respectively (Table 

5‐8). The emissions generated from the additional power requirements of the proposed Balloch 

development (35 % increase) have been combined with the total emissions generated in 2011 to 

represent the potential worst case emissions associated with power generation on the GPIII following 

tieback of the Balloch field (Table 5‐9). 

Table 5‐8 Fuel used in power generation on GPIII FPSO. 

2011 GPIII fuel use (te) 

GPIII fuel use including 35 % 

increase associated with 

Balloch production (te) 

Anticipated increase 

associated with Balloch 

production (te) 

Fuel gas use 27,578 37,230 9,652 

Diesel use 

16,208 21,880 5,673 

Table 5‐9 Emissions from power generation on the GPIII including the Balloch development. 

Emissions (te) 1 


Annual emissions from GPIII (Donan and Lochranza) 2011 

Fuel Gas 78,873 168 6.07 0.35 82 25 0.99 

Diesel 51,866 963 3.57 65 254 2.92 32 

Total 130,739 1,131 9.64 65.35 336 27.92 32.99 

Annual emissions from GPIII including 35 % increase associated with Balloch production 

Fuel Gas 106,478 226 8.19 0.47 110 33 1.34 

Diesel 70,019 1,300 4.81 87 342 3.94 43 

Total 176,497 1,526 13 87.47 452 36.94 44.34 

Maximum Anticipated annual increase in emissions associated with Balloch production 

Fuel Gas 27,605 58 2.12 0.12 28 8.75 0.35 

Diesel 18,153 337 1.25 22 88 1.02 11.2 

Total 45,758 395 3.37 22.12 116 9.77 11.55 

1 Atmospheric emissions have been calculated using emissions factors from EEMS Atmospheric Calculations Issue 1.810a 

(EEMS, 2008). 

To put these emissions into context, Table 5‐10 shows the predicted emissions from the proposed 

Balloch development in relation to the UK total emissions in 2009. Emissions from the production of 

the Balloch liquids constitute a small portion of the UK total emissions, e.g. maximum CO2 emissions 

from the Balloch development represent < 0.2 % of the UK total CO2 emissions from offshore oil and 

gas installations, based on EEMS 2009 returns. 

5 ‐ 11

5‐ 12 



Table 5‐10 Balloch development production emissions as a percentage of total UK offshore installation 

emissions. 



2009 UK total emissions 

from offshore installations 

Balloch emissions 

15,354,696 44,096 972 1,875 22,717 51,352 56,918 

associated with power 

generation 

45,758 395 3.37 22.12 116 9.77 11.55 

Balloch emissions as % of 

UK 2009 total 

0.17 % 0.89 % 0.35 % 1.18 % 0.51 % 0.02 % 0.02 % 

1 

Atmospheric emissions have been calculated using emissions factors from EEMS Atmospheric Calculations Issue 1.810a (EEMS, 

2008). 

Emissions from venting and flaring 

In 2011, venting associated with the offloading of 1.155 million m 3 of oil resulted in the production of 

16 te of CH4 and 1,933 te of VOCs. Maximum Balloch production occurs in 2014 with an anticipated 

P10 of 1.026 million te (1.244 million m 3 ). It is possible to predict the CH4 and VOC emissions using 

factors provided in EEMS (2008). Predicted CH4 and VOC emissions associated with the offloading of 

the Balloch oil in 2014 are 21 te and 2,488 te respectively decreasing to 9.5 te and 1,127 te 

respectively in 2016. 

It is not anticipated that flaring will increase as a result of the proposed Balloch development and 

therefore current flaring emissions on the GPIII are expected to be representative of those when the 

Balloch development commences production. Total gas flared on the GPIII in 2011 was 22,941 te. The 

atmospheric emissions associated with this flaring load are presented in Table 5‐11. 

Table 5‐11 Flaring emissions associated with the GPIII. 

Total gas flared 

on the GPIII (te) 



Emissions associated 

with 2011 flaring on the 

GPIII 

22,941 64,236 27.53 1.86 0.29 154 229 229 

1 

Atmospheric emissions have been calculated using emissions factors from EEMS Atmospheric Calculations 

Issue 1.810a (EEMS, 2008). 

Proposed control measures for impacts associated with emissions to air during the production 

phase 

The following control measures are proposed to minimise the impact associated with atmospheric 

emissions during production.



Taking into account the above mitigation measures, 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 Balloch hydrocarbons will have a detrimental impact on the local environment. 


This section assesses the discharges to sea associated with the production of the Balloch 

hydrocarbons, i.e. the discharge of produced water (PW). During the screening phase of the EIA, in 

the absence of any mitigation measures, the discharge of PW and associated chemicals was assessed 

as being of moderate risk to the environment. 

Produced water discharges 


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: 

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. 

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 hydrocarbons flared. 

The discharge of PW to sea is one of the largest discharges associated with offshore oil and gas 

developments. 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, the 

dilution and the biodegradation of organic compounds. 

The PW system installed on the GPIII has been designed to treat PW for injection to disposal wells 

with PW reinjection (PWRI) being the base case for the proposed Balloch development. Discharge 

overboard is also available but as a secondary disposal route which is subject to the terms of the 

GPIII’s OPPC permit. The original development plan for the FPSO was for PWRI, but various issues 

since Donan first oil have prevented a high proportion of PWRI. PWRI has, however, been online 

since Q4 2010, with an injection rate of approximately 7,950 m 3 /day achieved whilst approximately 

3,180 ‐ 6,360 m 3 /day is discharged overboard. More recently, well intervention work has seen peak 

injection rates rise to nearly 15,900 m 3 /day. For the purpose of this ES, it has been assumed that the 

GPIII will have a PW handling capacity of 7,950 m 3 /day with any excess PW being treated and 

discharged overboard. 

P10 profiles indicate peak PW production from the Balloch field will occur in 2016 at a rate of 

3,454 m 3 /day (Table 2‐20), equating to an increase of approximately 27 % of that produced by the 

Donan and Lochranza fields in the same year. Combining Balloch production with that of Donan and 

Lochranza, maximum water production on the GPIII occurs in 2015 at a rate of 17,762 m 3 /day. This 

volume less a reinjection rate of 7,950 m 3 /day suggests a maximum discharge to sea of treated PW of 

9,812 m 3 /day. From 2022 no discharge of PW to sea is anticipated at GPIII with all PW being 

reinjected. 

In 2009, the total PW discharged to sea from offshore installations was 539,762 m 3 /day (DECC, 2011). 

In the absence of any PWRI facilities, the maximum water production at the Balloch field in 2016 

would equate to < 0.7% of total volumes discharged in 2009. 

5 ‐ 13

5‐ 14 



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 (OGP, 2005). Given the water 

depth and prevailing currents, PW will rapidly dilute. Any impact on water quality will be confined to 

the immediate vicinity of the discharge point, with levels of contaminants rapidly returning to 

background levels. 

Oil discharged with produced water 

In order to calculate the maximum weight of oil discharged with the PW, a discharge quality in line 

with regulatory requirements of 30 mg/l oil in water content was used. Table 5‐12 shows the 

maximum dispersed oil associated with PW from the Balloch field. For the purpose of the assessment 

it has been assumed, as a worst case, that all the PW from the Balloch development will be 

discharged to sea and that the oil in water content will be at the maximum permitted level of 30 mg/l. 

Typical oil in water content of PW discharged from GPIII since 2006 has been



With the identified control measures in place, combined with rapid dilution, it is expected that the 

discharge of PW from the Balloch field and associated oil and chemicals will not have a significant 

impact on the environment. 

5.4. NOISE 

It is recognised that there is the potential for shipping, drilling and piling noise to impact on the 

hearing structures of marine mammals and possibly fish. The environmental impact of noise 

associated with the proposed Balloch development is discussed in this section. 

5.4.1. VESSEL NOISE 

Vessel operations may be considered a potential source of noise disturbance to the local marine 

environment (Richardson et al., 1995), with vessel traffic being the largest contributor to 

anthropogenic ocean noise. As a result, the impacts of vessel activity associated with the proposed 

Balloch development are considered. 

The drilling rig will deploy anchors to remain on station during the drilling period and any underwater 

sound generated through its propulsion and transit to the drill centres will arise from the support 

vessels and DP anchor handling vessels. 

Minimal vessels will be used during the installation phase with the work being carried out from a Dive 

Support Vessel (DSV). It can be assumed that this vessel will be dynamically positioned (DP) and will 

therefore generate a relatively high noise output. No additional supply or guard vessels will be 

required during the installation period as those serving the GPIII will meet the requirements of the 

DSV. 

In terms of direct physical injuries to hearing structures in marine mammals and fish, it appears from 

the available data that 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. 

Short‐term behavioural effects may be observed amongst cetaceans and pinnipeds, but the overall 

impact of vessel noise from the proposed Balloch development is expected to be negligible. 

5.4.2. NOISE ASSOCIATED WITH THE DRILL RIG 


PWRI is the base case for the proposed Balloch development. 

Produced water treatment system is subject to an inspection and engineering 

maintenance strategy. 

GPIII OPPC permit is to be amended to capture additional water volume and oil 

discharged from the proposed development. 

Chemical usage will be minimised; those chemicals that will be used will be of the lowest 

toxicity HQ category. 

Chemical use will be captured in the PON15D. 

GPIII FPSO chemical control/spill measures include: 

Tanks are fitted with overflow alarms; 

Drums are stored in bunded areas (at skids or in storage areas); 

Equipment is provided with drip trays. 

There will be some noise and vibration associated with the drilling operations, which are expected to 

last for 70 days at each well location. 

Noise associated with the drilling operations will propagate from any rotating machinery such as 

generators, pumps and the drilling unit and risers (McCauley, 1998). 

5 ‐ 15

5‐ 16 



The noise from drilling has been found to be predominantly low frequency (less than 1,000 Hz) with 

relatively low source levels



Figure 5‐1 Sound Pressure Level plot for installation of a 600 mm pile at a manifold out to a distance of 30 km. 

The majority of the energy within a piling pulse is contained within the low frequency components 

2 kHz) have fallen below the normal background levels of 

noise, whereas the lower frequency components are still above ambient noise levels. This suggests 

that the piling signal for the cooling spool could be detected beyond a distance of 30 km (Figure 5‐2). 

It should be noted that prevailing ambient noise levels and weather conditions could influence the 

degree to which the sound could propagate (travel) through the water column. 

Figure 5‐2 Frequency output profiles for piling sound at source (1 m) and 30 km. 

Sound level dB 

270 

220 

170 

120 

70 

20 

10 100 1000 10000 100000 

Frequency Hz 

Predicted noise level 

Piling Source Level 

Ambient Noise 

5 ‐ 17

5‐ 18 



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 they 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 (Table 5‐13). These criteria are currently considered the best available and are based on 

quantitative sound levels 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 peak sound 

levels are not considered capable of causing a PTS to cetaceans, while a PTS may be caused to 

pinnipeds out to a short distance of 5 m. The range at which TTS extends to cetaceans and pinnipeds 

is approximately 1 m and 6 m respectively from the pile driver (Table 5‐13). 

Table 5‐13 Impact criteria for cetaceans and pinnipeds and the estimated ranges at which the auditory effects 

occur from the piling associated with the proposed Balloch development. 

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 Cetaceans ‐ Temporary Threshold Shift 224 dB re 1 µPa 1 

Injury to Pinnipeds (seals)‐ Permanent Threshold Shift 218 dB re 1 µPa 5 

Injury to Pinnipeds (seals)‐ Temporary Threshold Shift 212 dB re 1 µPa 6 

The diameter of the pile has been found to be the biggest influence on sound pressure levels 

generated from piling. The larger the pile to be installed, the larger the sound pressure levels which 

will be generated (Nedwell et al., 2007). The piles to be used for the Balloch subsea cooling spool are 

relatively small in diameter and are not expected to generate the high sound levels used for installing 

the larger diameter (>4 m) wind turbines. 

The only marine mammals that are considered to be at risk of PTS from pile driving activities are seals, 

but given the location of the Balloch development in the CNS the presence of any seals in the area is 

unlikely. It is also unlikely that any marine mammal species would be present in such close proximity 

to the pile driver (



Proposed control measures for impacts associated with underwater noise during the proposed 

Balloch development 

The following control measures are proposed to minimise the impact associated with underwater 

noise sources during all phases of the proposed development. 

The risk of noise associated with the vessels and drilling rig causing any significant impacts is low. 

Piling of the subsea cooling spool during the installation phase could cause relatively high sound 

levels. Providing the mitigation measures outlined above are followed, the impacts from underwater 

noise are assessed to be low. 

5.5. ACCIDENTAL EVENTS 

Uncontrolled hydrocarbon spills following an uncontrolled blowout at the proposed Balloch 

development location 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 Maersk Oil’s tiered response to 

respond to and mitigate such spills. 

5.6. WIDER DEVELOPMENT CONCERNS 

The potential of the proposed development to: 

Cause an offence to European Protected Species; 

Impact on protected areas; 

Impact on other sea users; 

Have a transboundary impact 

is discussed in this section. 

5.6.1. EUROPEAN PROTECTED SPECIES 


Both the number of vessels required and the length of time the vessels are on site will be 

minimised; 

The JNCC piling protocol will be followed including: 

Piling will commence using soft start; 

Piling will commence in hours of daylight and good visibility; 

A trained marine mammal observer (MMO) will be present during piling 

operations 

Following 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. 

This section assesses the impacts of noise on Marine European Protected Species (EPS) likely to be 

encountered in the area of the proposed development. EPS include all cetaceans, marine turtles and 

the Atlantic sturgeon. However, it is unlikely that marine turtles or Atlantic sturgeon will be found in 

the development area, therefore the assessment focuses on the cetaceans species likely to occur. As 

detailed in Section 3, there are several cetacean species distributed through the CNS that the EPS 

assessment should consider including harbour porpoise, minke whale, white‐beaked dolphin and 

white‐sided dolphin. 

The Offshore Marine Regulations 2007 (as amended 2010) contain a revised definition of 

‘disturbance’ to European Protected Species. The Offshore Marine Regulations extended the offence 

to areas of UK jurisdiction beyond 12 nautical miles (nm). It is now an offence under UK Regulations 

to deliberately disturb wild animals of a EPS in such a way as to be likely to: 

5 ‐ 19

5‐ 20 



(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 an EPS. Figure 5‐3 illustrates the suggested approach to a risk 

assessment for the offences of deliberate injury and deliberate disturbance. If there is a risk of 

causing an injury or disturbance to an EPS that cannot be removed or sufficiently reduced by using 

alternatives and/or mitigation measures, 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 5‐3 A suggested approach to risk assessment for offences of ‘deliberate injury’ and ‘deliberate 

disturbance’ (adapted from JNCC, 2010). 

The results from the underwater noise modelling carried out suggests permanent injury (i.e. PTS) to 

cetaceans is not anticipated, therefore no injury offence is expected. Given that the piling activity will 

only occur for a limited period of time, the activity is not expected to result in any significant 

displacement of marine animals. Any animals that are temporarily displaced are expected to return 

to the area after installation activities cease. Therefore, no disturbance offence is expected. 

The proposed mitigation measures that will be put in place during the subsea installation activities 

will further minimise the risk of causing an offence to EPS. Therefore, Maersk Oil believes that an 

application for an EPS licence is not required. 

5.6.2. PROTECTED AREAS 

The proposed Balloch development is located approximately 10 km southeast of the Scanner 

pockmark SAC. The discharge of WBM and cuttings during drilling operations may impact on 

pockmarks by smothering the benthic communities around the well, while anchors used to stabilise 

the drilling rig may disturb other small areas of seabed. Pipeline installation can also impact 

pockmarks through smothering. The effect of drilling a well at a distance greater than 1 km from an 

active pockmark has been assessed as not being significant (DTI, 2001; McQuillin et al., 1979); 

therefore, given their proximity to the Balloch development, no significant impacts are expected upon 

any marine protected areas. 

The pockmarks that have been identified in site surveys in the vicinity of the proposed Balloch 

development were found to not conform to the description of Annex I habitat ‘submarine structures 

made by leaking gas’. However, as good operating practice Maersk Oil will review any available



survey data in order to select a drilling location that will ensure that interactions with pockmarks or 

other types of seabed depressions within the area are avoided. 

5.6.3. OTHER MARINE USERS 

Potential impacts on other marine users include interference with commercial shipping, potential 

exclusion of fisherman from fishing grounds and damage to fishing gear. Operations will be 

undertaken in accordance with legal requirements and best practice to ensure that commercial 

operators and fishing vessels are aware of the location of the vessels and infrastructure. 

While on location, a 500 m exclusion zone will be in place around the drilling rig which may impact on 

the shipping and fishing activity in the area. However, these impacts on shipping are only associated 

with the drilling phase. During production, no additional vessels will be on location and the only 

additional vessel movements will be a small increase in tanker movements associated with offloading 

the oil. 

Although the Balloch field is within a relatively important area in terms of fishing effort (ICES 

rectangle 45F0, which has approximately 1 % of the UK fishing effort associated with it), once in the 

production phase the proposed development is not expected to impact further on the fishing industry 

given the minimal infrastructure associated with it. In addition, the wellheads and cooling spools will 

be of a fishing friendly design. 

Subsea infrastructure will be submitted for inclusion on the Admiralty Charts and the FishSafe 

database. 

There are no submarine cables or renewable energy installations in the area. 

5.6.4. TRANSBOUNDARY IMPACTS 

Given the distance of the Balloch field from the nearest transboundary line, i.e. 36 km from the 

UK/Norwegian median line, the impact assessment determined there would be no significant 

transboundary impacts as a result of the proposed planned activities, with atmospheric emissions and 

discharges to sea expected to disperse within a short distance from the development. 

Accidental events such as an uncontrolled blowout from the Balloch location has the potential to 

affect Norwegian, Danish, Dutch and German territorial waters. This is discussed further is Section 6. 

5.7. CUMULATIVE IMPACTS 

The cumulative impacts assessment has considered three environmental aspects: atmospheric 

emissions, discharges to sea and underwater noise. 

The Balloch development will contribute a CO2 increase of approximately 2.6 % to drilling emissions 

when compared with 2009 total rig emissions (Table 5‐2). Well clean‐up emissions are expected to 

contribute 0.49 % of CO2 emissions when compared to 2009 values from the UKCS (Table 5‐4). Vessel 

emissions are expected to contribute 0.53 % of the UK total from shipping emissions when compared 

to 2009 UK shipping emissions (Table 5‐5). Maximum annual energy emissions from the production 

of the Balloch hydrocarbons represents 0.17% of total emissions from installations in 2009 (Table 5‐ 

10). The generation of emissions will add to greenhouse gases in the atmosphere and hence 

marginally contribute to the effects of global warming. The emissions are not considered to be 

significant when considered in the context of total emissions from the UKCS oil and gas and shipping 

activities. Consequently, no significant cumulative impacts are anticipated. 

The PW from the Balloch field increases as the reservoirs are depleted; the maximum volume of oil in 

water is 38 tonnes, which is produced in 2016 (Table 5‐12). When these discharges are compared to 

the oil in water discharges arising from the UKCS sector as a whole, they represent an increase of 

1.3 %. Increases in oil in water levels as a result of the Balloch development are not anticipated to 

result in any adverse cumulative impacts. 

5 ‐ 21

5‐ 22 



The impacts of underwater sound have been receiving increased scientific attention, with potential 

cumulative impacts raised as a potential cause for concern for acoustically sensitive marine life 

(OSPAR, 2009). There will be an increase in local sound levels associated with the Balloch 

development. Few practical measures exist to minimise the sound from vessels on a project basis and 

they are more appropriately dealt with by international collaboration within the shipping industry and 

regulatory bodies. The loudest sound levels are expected to arise during the piling activity. Maersk 

Oil will reduce the risk of underwater noise to animals by implementing JNCC guidelines when piling. 

No significant cumulative or residual impacts as a result of the underwater noise levels associated 

with the proposed Balloch development are anticipated.


Section 6 Accidental Spills 

6. ACCIDENTAL SPILLS 

As part of the EIA process, it is necessary to consider the effects of an unplanned hydrocarbon spill on 

the environment. DECC issued new advice on their requirements relating to oil pollution emergency 

preparedness on 23 rd December 2010 (updated 21 st July 2011 and 20 th September 2011) (DECC, 

2010). This section aims to satisfy these requirements. 

In the event of a hydrocarbon spill at the Balloch field, there is the potential to impact the waters and 

coastline 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 

(Reed et al., 1995; Reed et al., 1996; 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. 

subsea 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 the 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 uses three‐dimensional currents and two‐ 

dimensional winds to predict the movement of oil and incorporates an oil properties database that 

supplies physical, chemical and biological parameters including evaporation data, emulsification, 

sediment partitioning and decay processes. The version of OSCAR used was that contained within the 

Marine Environmental Modelling Workbench Version 6.1. 

Three hydrocarbon release scenarios are presented; these are: 

Uncontrolled well blowout from a subsea release; 

Uncontrolled well blowout from a surface release for the first 2 days, followed by a 

continuation of the release subsea. This scenario represents a blowout that occurs initially 

through the semi‐submersible drill rig; 

Instantaneous release of the diesel inventory from the drill rig. 

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 have failed. 

For each spill scenario, both stochastic and deterministic analyses were carried out as per the DECC 

guidance. 

6.1. OIL SPILL REGULATIONS AND RISK 

6.1.1. REGULATORY CONTROL ON THE UKCS 

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 operators have a 

formally approved Oil Pollution Emergency Plan (OPEP) in place for each offshore operation or 

agreed grouping of facilities; 

The Offshore Installations (Emergency Pollution Control) Regulations 2002 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; 

The EC Directive 2004/35 on Environmental Liability with Regard to the Prevention and 

Remedying of Environmental Damage enforces strict liability for prevention and remediation of 

6 ‐ 1

6 ‐ 2 



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. LIKELIHOOD OF A BLOWOUT SCENARIO 

The International Association of Oil & Gas Producers has issued datasheets (OGP, 2010) on the 

likelihood of blowouts for offshore operations of ‘North Sea Standard’. The North Sea Standard refers 

to operations that are performed with the Blowout Preventer (BOP) installed (including shear ram), as 

well as where the ‘two barrier principle’ to stopping a potential release is followed. The dataset is 

derived from the International SINTEF blowout database. Blowout frequencies have been calculated 

per well drilled in the North Sea and are not annual frequencies. Table 6‐1 indicates that for gas high 

pressure/high temperature (HP/HT) reservoirs, the likelihood of a blowout is higher in than in oil 

reservoirs such as Balloch. 

Table 6‐1 Blowout and well release frequencies for offshore operations of North Sea Standard (OGP, 2010). 

Operation Category Gas Oil Unit 

Development drilling (Oil) Blowout ‐ 4.8 x 10 ‐5 

Development drilling (HP/HT) Blowout 4.3 x 10 ‐4 

Development drilling shallow gas (topside) Blowout 4.7 x 10 ‐4 

Development drilling shallow gas (topside) Blowout 7.4 x 10 ‐4 

Per well drilled 

‐ Per well drilled 



Tina Consultants Ltd (2010) report that in 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 oil based mud (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 diesel and the other 36 % relating to condensates, hydraulic oils, oily waters and 

others. 

Spilled amount (tonnes) 

900 

800 

700 

600 

500 

400 

300 

200 

100 

0 

1991 

1992 

Figure 6‐1 Volume of spilled oil and number of spills in UKCS waters. 

1993 

1994 

1995 

1996 

1997 

1998 

1999 

2000 

Year 

2001 

Total amount spilled (tonnes) Total number of oil spill reports 

2002 

2003 

2004 

2005 

2006 

2007 

2008 

2009 

500 

450 

400 

350 

300 

250 

200 

150 

100 

50 

0 

Number of spills



6.1.3. HISTORIC DIESEL SPILLS FROM DRILLING RIGS IN THE UKCS 

Historical data collected since 1975 indicate that mobile offshore drilling rigs account for 23 % of all 

diesel spills. The majority of these spills are caused by hose failure and drain overflows and the 

releases are relatively small, generally

6 ‐ 4 



1. The first time the reservoir is penetrated is while drilling the 12¼” hole. If the well were to 

flow at this stage, for instance because a large hydrocarbon influx has entered the well, it is 

possible that hydrocarbons may reach the surface. However, as the wellbore pressures in 

the 12¼” 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/weeks. 

2. Similarly, during the drilling of the 8½” reservoir hole section it is possible that hydrocarbons 

may reach the surface. Hole collapse and plugging would be expected within a couple of 

weeks if a blowout were to occur while the reservoir was being drilled. 

3. Once the sand screens have been installed and before the completion is run, there is a full 

steel‐lined conduit in place from reservoir to surface with an 8½” 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 once the well is 

completed. This scenario constitutes the worst case blow out event for the spill modelling. 

4. During the completion phase, hydrocarbons are purposely introduced into the wellbore 

during the production clean‐up. Although this would appear to introduce more blowout risk 

than in any drilling scenario, there are several 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 test tree and the surface test tree 

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 then the subsurface test tree and 

SSSV will close automatically and shut in the well. This blowout 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 subsurface 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. 

A scenario where a well being drilled intersects with a completed producing well at a relatively 

shallow depth 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 (well blow out) which is considered the worst case 

scenario and extremely unlikely. As required by DECC, the modelling assumes no intervention, i.e. 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. In this sense, the modelling gives a pessimistic outcome. 

6.2.2. LOSS OF FUEL INVENTORY FROM NTVL. 

The appraisal/production well will be drilled from the Noble Ton van Langeveld (NTvL) semi‐ 

submersible drilling rig. Any additional wells are likely to be drilled by the Sedco 704 semi‐ 

submersible drilling rig. The inventory for the diesel stored on the NTvL is 8,642 bbls and on the 

Sedco 704 is 6,610 bbls. Spill modelling was carried out on a total loss of fuel inventory from the NTvL 

to represent a worst case. 

6.3. HYDROCARBON SPILL MODELLING 

This section summarises the input data and assessment methods used to model the loss of inventory 

from the drilling rig and the blowout scenarios. For each spill scenario, both stochastic and 

deterministic analyses were carried out as per the DECC guidance. 

The “SNORRE B” oil type was chosen from the model database to represent the closest oil type to the 

Balloch oil. The parameters used to make this assessment were the API and the pour point of the



Balloch fluid. The API and pour point of the SNORRE B oil type is 39.8 and ‐6 o C while those of the 

Balloch oil are 40 and ‐6.1 o C respectively. 

Bathymetry data is based on the Sea Topo 8.2 and IBCAO databases (Jakobosson et. al., 2008) which 

are built into the OSCAR model. 

Representative water column current data from 1990 and 1991, supplied by SINTEF for modelling in 

the North Sea and northeast Atlantic areas, was used. This data covers currents varying over 16 

layers in the water column up to 400 m water depth. Representative 2‐dimensional wind data from 

1990 and 1991 supplied by SINTEF was also used. 

Given the relatively shallow waters of the North Sea, the travel time between seabed and surface is 

short. Because of this, salinity and temperature variation with depth have not been included as they 

are not considered to have a significant effect on the predictions. 

Model runs were undertaken 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) that is capable of producing a visible sheen 

(Table 6‐4). BAOAC states that oil films below ≈ 0.04 µm thickness are considered invisible. Recent 

research by O’Hara and Morandin (2010) suggests that a thickness between 0.04 µm and 0.1 µm is 

also the point at which there is noticeable uptake of oil into bird plumage. 

Code Description ‐ Appearance 

Table 6‐4 Bonn Agreement Oil Appearance Code. 

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 

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 50 ppb 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 (e.g. EU, 2003 and ECHA, 2008). This is a very conservative approach 

since this treats all the oil as the most toxic component. Following OSPAR recommendations 

sediment concentrations of 50 mg/kg are used as the threshold 

For the blowout from the Balloch well, the model was run to incorporate an area of ≈ 900,000 km 2 

that included UK, Danish and Norwegian coastlines. A small fraction of oil (< 5 %) was found to have 

moved outside these areas, at extremely low concentrations. 

A release diameter of 9 5 /8” was assumed. The diameter of production tubing is 8 1 /2”; at the surface 

this opens out to 9 5 /8”. The modelling parameters used are summarised in Table 6‐5. A surface spill 

blowout was modelled for 2 days and then followed by a release for the remainder of the blowout 

period from the seabed. 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 quickly detach from the well location. It was assumed a period of 90 days would be required 

to arrest the blowout by drilling a relief well and the model was run for an additional 30 days to track 

the fate of the hydrocarbons following cessation of the spill. 

For the diesel inventory loss, the model was run to incorporate an area of ≈ 360,000 km 2 and included 

UK and Norwegian coastlines. No diesel was found to have moved outside these areas. A total loss of 

inventory from the rig was assumed to occur in one hour, with the fate of the diesel being tracked 

over the next 30 days. 

6 ‐ 5

6.3.1. STOCHASTIC MODELLING 

6 ‐ 6 



Stochastic modelling involves using a variety of wind and current data to simulate the most realistic 

probability outcomes of a spill event. For the blowout scenario the stochastic models were run for 

the time it is expected to take to drill a relief well (90 days), with an additional 30 days added in order 

to model the fate of the oil after the spill has been controlled (total = 120 days). 

A stochastic analysis of the uncontrolled flow rate during the two blowout scenarios and loss of diesel 

inventory was undertaken by modelling 40 scenarios utilising a broad range of weather and current 

data. Table 6‐5 shows the locations and main parameters for modelling undertaken at each of the 

drilling locations. 

Table 6‐5 Main parameters used for modelling of oil spills. 

Scenario Coordinates Volume Gas:Oil Ratio API 

Diesel 

inventory 

loss 

Balloch well 

blowout 

58 o 22’18.035’’N 

00 o 53’03.319’’E 

58 o 22’18.035’’N 

00 o 53’03.319’’E 

6.3.2. DETERMINISTIC MODELLING 

8,642 bbls 

(in 1 hour) 

124,000 

bbl/d 

Release diameter 

(inches) 

‐ 36.4 ‐ 

87.3 scm/scm 40 9 5 / 8 

In addition to the stochastic analysis, a deterministic analysis was also undertaken for the worst case 

scenario of oil beaching identified in the stochastic modelling, in order to gain a more detailed insight 

into the fate of oil and to understand the water column and sediment distribution of the oil. 

Additionally, the fate of hydrocarbons in the presence of unvarying offshore and onshore winds at 

30 knots was modelled for both cases to determine the fate of each spill, according to DECC 

requirements. Air and water temperatures from January were assumed in order to represent worst 

case parameters. 

6.3.3. IMPACT ASSESSMENT CRITERIA 

The environmental resources within the vicinity of the Balloch field have been identified and assessed 

for their susceptibility to oil spills. Seabirds and fisheries are not normally affected by routine 

offshore oil and gas operations, but are among the environmental aspects most at risk in the unlikely 

event of an oil spill. The overall impact of spilt oil on the marine environment will vary seasonally due 

to variations in species abundance and behaviour. Potential effects on fish populations from spilt oil 

will be greatest during periods of fish spawning. In the event of a very large oil spill, fisheries may be 

closed as a result of fish ‘tainting’. Seabirds spending time on the sea surface are also vulnerable to 

oiling following a spill. Cetaceans passing through the area may also be vulnerable to oil spills. 

Drilling of the Balloch well is currently scheduled to begin in Q4 2012. Environmental sensitivities 

noted within the block during this time are: 

Fish nursery/spawning periods for Nephrops, Norway pout and blue whiting; 

The Offshore Vulnerability Index (OVI) for seabirds in the area is very high in 

November. 

The assessment criteria used to evaluate the environmental sensitivities in this section are 

outlined in Table 6‐6 and Table 6‐7.



Table 6‐6 Oil spill assessment criteria (based on Patin, 2004). 

Spatial scale Temporal scale 

Local Area impacted ranges 

from 100 m 2 to 1 km 2 

Confined Area impacted ranges 

within 1 – 100 km 2 

Subregional Area impacted is more 

than 100 km 2 

Regional Area impacted spreads 

over shelf region 

Short term From several minutes to several days 

Temporary From several days to one season 

Long term From one season to one year 

Chronic More than one year 

Assessment Criteria (based upon the Oil and Gas UK Environmental Assessment Criteria) 

Severe 

Moderate 

Slight 

Insignificant 

Change in ecosystem or activity over a wide area leading to medium 

term (> 2 years) damage but with a likelihood of recovery within 10 

years. Possible effect on human health. Financial loss to users or 

public. 

Change in ecosystem or activity in a localised area for a short time, 

with good recovery potential. Similar scale of effect to existing 

variability but may have cumulative implications. Potential effect on 

health but unlikely, may cause nuisance to some users. 

Change which is within scope of existing variability but can be 

monitored and/or noticed. May affect behaviour but not a nuisance to 

users or public. 

Changes which are unlikely to be noticed or measurable against 

background activities. Negligible effects in terms of health or standard 

of living. 

Table 6‐7 Risk Assessment Matrix. 

Short term Temporary Long term Chronic 

Local Insignificant Insignificant Slight Moderate 

Confined Insignificant Slight Moderate Moderate 

Subregional Slight Moderate Severe Severe 

Regional Moderate Moderate Severe Severe 

6.4. MODELLING RESULTS 

This section presents the results from the stochastic and deterministic modelling carried out for the 

three scenarios; total subsea blowout at the well location, two day surface followed by an 88 day 

subsea release and loss of rig diesel inventory. 

6.4.1. SCENARIO 1: UNCONTROLLED WELL BLOWOUT FROM A SUBSEA RELEASE 

Surface oil model outputs 

The model outputs are summarised in Figure 6‐2. In general, much of the oil from the surface release 

travels in an easterly direction towards Norway. Norwegian waters would be at risk with an oil slick 

highly likely (100 % probability) to be present at some time during the period modelled. A very small 

percentage of the release is predicted to travel northwards, outwith the modelled area. The slick also 

travels in a southeast direction, putting Danish waters at a moderate risk (50 % probability) of a slick 

being present at some time. There is a low risk (1 ‐ 10 % probability) of a surface slick occurring in 

German or Dutch waters. The rate of subsea release from the well has been modelled at a constant 

6 ‐ 7

6 ‐ 8 



output of 19,700 m 3 /day; this is a worst case assumption as the flow rate is expected to decline with 

time. 

Shoreline oil modelled outputs 

There is a possibility of hydrocarbons beaching on Shetland, Orkney, mainland UK, Norway and 

Denmark following a 90 day subsea release. This is summarised in Figure 6‐3. A maximum of 1,986 

tonnes of oil is predicted to reach the coastline, which could represent 9,930 tonnes of emulsion 

(based on 80 % water content predicted by the weathering analysis). The minimum time to reach 

shore is 20.7 days. The hydrocarbons reaching the Norwegian coastline are more likely to be in the 

form of dispersed oil in the water column, rather than a surface slick. The graphs in Figure 6‐3 show 

the amount of oil beached and the time it takes to beach, as well as the cumulative percentage of 

scenarios in which this happens. 

Water column and sediment modelled outputs 

The water column and sediment concentration outputs are summarised in Figure 6‐4. Water column 

and sediment concentrations are not expected to exceed 50 ppb beyond approximately 450 km from 

the release, except very locally around patches of surface oil. Sediment concentrations of around 

1170 mg/kg (peak) and 200 mg/kg are predicted. Water column levels below 50 ppb are not 

expected to have a significant acute toxic effect while the sediment levels are higher than the 

50mg/kg OSPAR recommendation for oil in sediment. 

Fate of oil and fixed wind analysis 

The fate of the hydrocarbons associated with a 90 day subsea blowout is shown in Figure 6‐5. This 

shows that 30 days after the release has been controlled, approximately 50 % has decayed, 10 % has 

evaporated, 30 % is in the sediment and less than 15 % is dispersed in the water column. 

Fixed wind analyses predict that in the presence of 30 knot offshore winds (east to west), 

hydrocarbons will cross the UK ‐ Norwegian median line in 3.5 days and in 6.5 days in the presence of 

30 knot onshore winds (west to east). The surface slick would still cross the UK‐Norwegian median 

line in the onshore wind scenario, albeit in a longer time period, as a result of the prevailing water 

currents. The outputs are summarised in Figure 6‐5. 

Typical manifestation of oil during release 

Figure 6‐6 presents instantaneous snapshots of the appearance of the surface slick and water column 

plume. The surface example is chosen to represent a period of relatively calm winds that allow oil to 

accumulate on the surface, which in this scenario occur on day 84, i.e. it is a relatively pessimistic 

prediction as to the extent of the surface slick. The water column example is chosen as being at the 

end of the release period, after which concentrations would be expected to decline. 

The cross‐section image shows the oil accumulating in the water column above the release site on the 

seabed. Oil does not appear in the entire water column as it moves rapidly up towards the surface 

after release from the well, where it then accumulates.



Figure 6‐2 Surface slick summary outputs for a well blowout at subsea. 

Volume released m 3 

19,700 m 3 Probability of visible surface oil at any time 

Oil type SNORRE B Release position 

1,773,000 Release duration 

Rate of release 

/ day 

Median lines crossed % likelihood 

Mass balance (tonnes) 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

40000 

30000 

20000 

10000 

0 

5°00'W 

5°00'W 

200 km 

Blowout ‐ subsea release 

0°00'E 

0°00'E 

5°00'E 

5°00'E 

Entire at seabed 

Norway Faeroes Denmark Germany Neth's 

100% 0% 50% 1 ‐ 10 % 1 ‐ 10 % 

Typical mass of oil on surface over time 

10°00'E 

Statistical Map: Surface: Probability of contamination above threshold (0.000 mm) [%] 

10°00'E 

90 days 

0 20 40 60 80 100 120 140 

Time (days) 

Surface 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

6 ‐ 9

6 ‐ 10 


Figure 6‐3 Shoreline summary outputs for a well blowout at subsea. 



Probability of oil reaching shoreline 

Max. Shoreline Shetland Orkney UK main. Norway Faeroes Min time to beach 20.7 days 

probability (%) 1‐10 % 1‐10 % 1‐10 % 30‐40 % 0% 

Maximum mass oil beached 1,986 tonnes Max. mass emulsion beached 9,930 tonnes 

% of scenarios 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

5°00'W 

5°00'W 

200 km 

0°00'E 

0°00'E 

0 500 1,000 1,500 2,000 2,500 

Mass of oil beaching (tonnes) 

5°00'E 

5°00'E 

Mass reaching shore distribution (tonnes) Time to reach shore distribution 

Oil to shore statistics 

10°00'E 

Statistical Map: Shoreline: Probability of contamination [%] 

% of scenarios 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

10°00'E 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

0 50 100 150 

Time ashore (days)



Figure 6‐4 Water column and sediment summary outputs for a well blowout at subsea. 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

5°00'W 

5°00'W 

200 km 


Probability of oil exceeding 50 ppb (dissolved + droplets) 

5°00'W 

5°00'W 

200 km 

0°00'E 

0°00'E 

0°00'E 

0°00'E 

Concentration of oil in sediments 

Maximum sediment conc'n 117 g/m 2 

Equivalent conc'n over 5cm* 1170 mg/kg 

Typical sediment conc'n** 20 g/m 2 


** representative of larger affected areas * 5cm used as a typical sediment mixing depth 

5°00'E 

5°00'E 

5°00'E 

5°00'E 

10°00'E 

Statistical Map: Water-Column: Probability of contamination above threshold (50 ppb of tot.conc.) 

10°00'E 

10°00'E 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

120:00:00 

10°00'E 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

6 ‐ 11

58°45'N 

58°30'N 

58°15'N 

58°00'N 

57°45'N 

6 ‐ 12 

Mass balance 

0°00'E 

0°00'E 

40 km 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

0°30'E 

0°30'E 


Figure 6‐5 Fate of oil and fixed wind analysis for a well blowout at subsea. 

1°00'E 

1°00'E 

1°30'E 

1°30'E 


Figure space 

0 

5 

10 

15 

20 

25 

30 

35 

40 

45 

50 

55 

60 

65 

70 

75 

80 

85 

90 

95 

100 

105 

110 

115 

120 

Fate of oil over time (example) 

2°00'E 

2°00'E 

2°30'E 

6:12:00 

2°30'E 

Time (days) 

Onshore wind 30 knots (090°) Offshore wind 30 knots (270°) 

Fixed wind analysis 

Oil reaches median line: YES Oil reaches median line: YES 

Time taken: 6.5 days Time taken: 3.5 days 

58°45'N 

58°30'N 

58°15'N 

58°00'N 

57°45'N 

58°40'N 

58°20'N 

58°00'N 

0°00'E 

0°00'E 

50 km 

1°00'E 

1°00'E 


2°00'E 

2°00'E 

Evaporated 

Surface 

Dispersed 

Sediment 

Stranded 

Decayed 

3:12:00 

58°40'N 

58°20'N 

58°00'N



Figure 6‐6 Momentary slick and plume illustration for a well blowout at subsea. 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

5°00'W 

5°00'W 


0°00'E 

0°00'E 

5°00'E 

5°00'E 

10°00'E 

83:18:00 

10°00'E 

Momentary surface slick example for low wind conditions T = 84 days 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

200 km 

5°00'W 

5°00'W 

200 km 

0°00'E 

0°00'E 

5°00'E 

5°00'E 

10°00'E 

Concentration of oil in the water column (dissolved + droplets) T = 55 days 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

55:09:00 

10°00'E 

6 ‐ 13

6 ‐ 14 



6.4.2. SCENARIO 2: UNCONTROLLED WELL BLOWOUT FROM A SURFACE RELEASE FOR THE FIRST TWO DAYS, 

FOLLOWED BY A CONTINUATION OF THE RELEASE SUBSEA 

This scenario represents a blowout that occurs initially through the semi‐submersible drill rig. 

Surface oil modelled outputs 

The model outputs are summarised in Figure 6‐7. In general, much of the oil from the surface release 

of the diesel travels in an easterly direction towards Norway. Norwegian waters are at high risk 

(100 % probability) of an oil slick being present at some time during the period. A very small 

percentage of the release is predicted to travel northwards outwith the modelled area. The slick also 

travels in a southeasterly direction putting Danish waters at high risk of a slick (60 ‐ 70 % probability) 

being present at some time. German and Dutch waters are at a low risk (10 % probability) of a 

surface spill being visible. The flow of hydrocarbons from a Balloch well blowout when the entire 

release is from the seabed is 19,700 m 3 /day. This is a worst case scenario as it is expected that the 

flow of oil would decline over time. 

Shoreline modelled outputs 

There is a possibility of hydrocarbons beaching on Shetland, Orkney, mainland UK, Norway and 

Denmark following a 90 day subsea release. 3,285 tonnes are predicted to reach the coastline, which 

could represent 16,425 tonnes of emulsion (based on 80 % water content predicted by the 

weathering analysis). The minimum time to reach shore is 11.8 days. The hydrocarbons reaching the 

Norwegian coastline are more likely to be in the form of dispersed oil in the water column rather than 

a surface slick. The graphs in Figure 6‐8 show the amount of oil beached and the time it takes to 

beach, as well as the cumulative percentage of scenarios in which this happens. They also provide a 

summary of the modelled outputs. 


Water column concentrations are not expected to exceed 50 ppb beyond approximately 450 km from 

the release, except very locally around patches of surface oil. Sediment concentrations of around 

1700 mg/kg (peak) and 30 mg/kg are predicted, which again could be higher locally. 

Oil is predicted to deposit into sediments where there is dispersed oil in the water column in contact 

with the seabed, according to partitioning algorithms in the model. Consequently, oil is predicted to 

deposit in sediments in the shallow water either side of the deep trench near Norway but not actually 

within this trench, as shown in Figure 6‐9. 


The fate of the hydrocarbons associated with a 2 day surface release and subsequent 89 day 

subsurface release is shown in Figure 6‐10. This shows that 30 days after the release has been 

controlled, approximately 45 % has decayed, 25 % has evaporated, 25 % is in the sediment and less 

than 5 % is dispersed in the water column. 

Fixed wind analyses predict that in the presence of 30 knot offshore winds, hydrocarbons will cross 

the median line in 1.125 days and in 9 days in the presence of 30 knot onshore winds. The outputs 

are summarised in Figure 6‐10. 

Typical manifestation of oil during release 

Figure 6‐11 presents instantaneous snapshots of the appearance of the surface slick and water 

column plume. The surface example is chosen to represent a period of relatively calm winds that 

allow oil to accumulate on the surface, which in this scenario occur on day 60, i.e. it is a relatively 

pessimistic prediction of the extent of the surface slick. The water column example is chosen at the 

end of the release period, after which concentrations would be expected to decline. 

The cross section image shows the oil accumulating in the water column above the release site on the 

seabed. Oil does not appear in the entire water column upon release from the well; it moves rapidly 

up towards the surface where it then accumulates.



Figure 6‐7 Surface slick summary outputs for a well blowout for 2 days at the surface and the remainder at 

subsea. 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

Blowout ‐ 2 day surface release + 89 day subsea release 

Probability of visible surface oil at any time 

Oil type SNORRE B Release position Surface (2d) + Seabed (89d) 

1,773,000 

19,700 m 3 Volume released Release duration 


/ day 



120000 

100000 

80000 

60000 

40000 

20000 

0 

5°00'W 

200 km 

5°00'W 

0°00'E 

0°00'E 

m 3 

5°00'E 

5°00'E 

Norway Faeroes Denmark Germany Neth's 

100% 0% 60 ‐ 70 % 1 ‐ 10 % 1 ‐ 10 % 

Typical mass of oil on surface over time 

10°00'E 


10°00'E 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

90 days 

0 20 40 60 80 100 120 140 

Time (days) 

Surface 

6 ‐ 15

6 ‐ 16 



Figure 6‐8 Shoreline summary outputs for 2 days at the surface and the remainder at subsea. 

Max. Shoreline 

probability (%) 

Maximum mass oil beached 

% of scenarios less than 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

5°00'W 

200 km 

5°00'W 


0°00'E 

0°00'E 

5°00'E 

5°00'E 

Probability of oil reaching shoreline 

Shetland Orkney UK main. Norway Faeroes Denmark Min time to beach 

1‐10% 1‐10% 1‐10% 100 0% 30 ‐ 40% 11.875 days 

0 1,000 2,000 3,000 4,000 

Mass of oil beaching (tonnes) 

3,285 tonnes Max. mass emulsion beached 16,425 

Mass reaching shore distribution (tonnes) Time to reach shore distribution 

Oil to shore statistics 

10°00'E 

Statistical Map: Shoreline: Probability of contamination [%] 

% of scenarios less than 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

10°00'E 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

tonnes 

0 20 40 60 80 100 

Time ashore (days)



Figure 6‐9 Water column and sediment summary outputs for 2 days at the surface and the remainder at 

subsea. 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

62°00'N 

60°00'N 

58°00'N 

56°00'N 


5°00'W 

200 km 

5°00'W 

Probability of oil exceeding 50 ppb (dissolved + droplets) 

5°00'W 

200 km 

5°00'W 

0°00'E 

0°00'E 

0°00'E 

0°00'E 

Concentration of oil in sediments 

Maximum sediment conc'n 170 g/m 2 


Typical sediment conc'n** 3 g/m 2 


** representative of larger affected areas * 5cm used as typical sediment mixing depth 

5°00'E 

5°00'E 

5°00'E 

5°00'E 

10°00'E 

Statistical Map: Water-Column: Probability of contamination above threshold (50 ppb of tot.conc.) [%] 

10°00'E 

10°00'E 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

120:00:00 

10°00'E 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

6 ‐ 17

59°00'N 

58°30'N 

58°00'N 

57°30'N 

57°00'N 

6 ‐ 18 



Figure 6‐10 Fate of oil and fixed wind analysis for 2 days at the surface and the remainder at subsea. 

Mass balance 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

0°00'E 

50 km 

0°00'E 


0 6 13 19 25 31 38 44 50 56 63 69 75 81 88 94 100106113119 

1°00'E 

1°00'E 

2°00'E 

2°00'E 

3°00'E 

3°00'E 

Fate of oil over time (example) 

4°00'E 

4°00'E 

Time (days) 

Onshore wind 30 knots Offshore wind 30 knots 


Oil reaches median line: YES 

Oil reaches median line: YES 

Time taken: 9 days Time taken: 1.125 days 

9:00:00 

59°00'N 

58°30'N 

58°00'N 

57°30'N 

57°00'N 

59°00'N 

58°30'N 

58°00'N 

57°30'N 

57°00'N 

0°00'E 

50 km 

0°00'E 

1°00'E 

1°00'E 

2°00'E 

2°00'E 

3°00'E 

3°00'E 

Evaporated 

Surface 

Dispersed 

Sediment 

Stranded 

Decayed 

4°00'E 

4°00'E 

1:03:00 

59°00'N 

58°30'N 

58°00'N 

57°30'N 

57°00'N



Figure 6‐11 Momentary slick and plume illustration for 2 days at the surface and the remainder at subsea. 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

62°00'N 

60°00'N 

58°00'N 

56°00'N 


5°00'W 

200 km 

5°00'W 

Momentary surface slick example for low wind conditions T = 60 days 

5°00'W 

200 km 

5°00'W 

0°00'E 

0°00'E 

0°00'E 

0°00'E 

5°00'E 

5°00'E 

5°00'E 

5°00'E 

10°00'E 

60:12:00 

10°00'E 

10°00'E 

90:00:00 

10°00'E 

Concentration of oil in the water column (dissolved + droplets) T = 90 days 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

62°00'N 

60°00'N 

58°00'N 

56°00'N 

6 ‐ 19


6.4.3. SCENARIO 3: INSTANTANEOUS RELEASE OF THE DIESEL INVENTORY FROM THE DRILL RIG. 

A worst case diesel inventory loss of 8,642 bbls over a one hour period was modelled. 

Surface oil modelled outputs 

6 ‐ 20 


In general, the diesel from the surface release travels in every direction from the source of the 

discharge. Norwegian waters are at low risk (1 ‐ 10 % probability) of a visible surface spill. No other 

countries are at risk of a surface spill entering their waters. The outputs are summarised in Figure 

6‐12. 

Shoreline modelled outputs 

No European shorelines are at risk from the diesel spill. 


Following a loss of diesel inventory from the drill rig, water column concentrations are not expected 

to exceed 50 ppb beyond approximately 35 km from the release, except very locally around patches 

of surface oil. 

Sediment concentrations of around 3 mg/kg (peak) and 2 mg/kg are predicted in small, isolated areas, 

which could be higher locally. This average value is considerably below the 50 mg/kg OSPAR 

recommendation for oil in sediment. 


The fate of the diesel associated with loss of inventory from the drilling rig is shown in Figure 6‐13. 

This shows that after 30 days approximately 45 % has decayed, 45 % has evaporated and the 

remaining 10% is in the sediment. Evaporation and decay are the main factors at work reducing 

diesel in the environment. At the end of the simulations, a small percent of the oil is still present in 

the water column, dispersed over a wide area. 

Fixed wind analyses predict that in the presence of 30 knot offshore and onshore winds, 

hydrocarbons will not cross the median line. The outputs are summarised in Figure 6‐13.



Figure 6‐12 Surface slick summary outputs for diesel inventory loss. 

Diesel release 

Oil type 

Probability of visible surface diesel at any time 

Marine Diesel (IKU) Release position 

Volume released 8,642 bbls Release duration 


Total inventory 



60°00'N 

59°00'N 

58°00'N 

57°00'N 

56°00'N 

1400 

1200 

1000 

800 

600 

400 

200 

0 

2°00'W 

100 km 

2°00'W 

0°00'E 

0°00'E 

2°00'E 

2°00'E 

4°00'E 

4°00'E 

Norway Faeroes Denmark Neth's 

1 ‐ 10% 0% 0% 0% 

Typical mass of diesel on surface over time 

6°00'E 


6°00'E 

Surface 

31 days 

0 5 10 15 20 25 30 35 

Time (days) 

Surface 

60°00'N 

59°00'N 

58°00'N 

57°00'N 

56°00'N 

6 ‐ 21

59°00'N 

58°30'N 

58°00'N 

57°30'N 

57°00'N 

6 ‐ 22 

Mass balance 

1°00'W 

50 km 

1°00'W 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

0°00'E 

0°00'E 


Figure 6‐13 Fate of oil and fixed wind analysis for diesel inventory loss. 

Diesel release 

0 1 2 3 5 6 7 8 9 10111214151617181920212324252627282930 

1°00'E 

1°00'E 

2°00'E 

2°00'E 

Fate of diesel over time (example) 

3°00'E 

3°00'E 

4°00'E 

4°00'E 

Time (days) 

Onshore wind 30 knots Offshore wind 30 knots 


Oil reaches median line: NO Oil reaches median line: NO 

Time taken: days Time taken: 

days 

0d 09:00 

59°00'N 

58°30'N 

58°00'N 

57°30'N 

57°00'N 

59°00'N 

58°30'N 

58°00'N 

57°30'N 

57°00'N 

1°00'W 

50 km 

1°00'W 

0°00'E 

0°00'E 

1°00'E 

1°00'E 

2°00'E 

2°00'E 


3°00'E 

3°00'E 

4°00'E 

4°00'E 

Evaporated 

Surface 

Dispersed 

Sediment 

Stranded 

Decayed 

0d 15:00 

59°00'N 

58°30'N 

58°00'N 

57°30'N 

57°00'N



6.4.4. CONCLUSIONS OF MODELLING 

Uncontrolled blowout scenario 1: Subsea release 

The probability of a surface spill crossing into the European countries waters are as follows: 

Norwegian (100 %), Danish (50 %), German (1 ‐ 10 %) and Dutch (1 ‐ 10%). 

The probabilities of oil reaching the following shorelines are as follows: Shetland (1 ‐ 10 %), 

Orkney (1 – 10 %), UK mainland (1 ‐ 10 %) and Norway (30 ‐ 40 %). 

Minimum time to beach 20.7 days. 

Maximum mass of oil beached 1,986 tonnes. 

Maximum emulsion beached 9,930 tonnes. 

Sediment concentration average 200 mg/kg. 

In an offshore wind the surface slick could cross the UK ‐ Norwegian median line in 3.5 days, 

but 6.5 days in an offshore wind. 

Uncontrolled blowout scenario 2: Surface release followed by subsea release 

The probability of a surface spill crossing into the European countries waters are as follows: 

Norwegian (100 %), Danish (60 ‐ 70 %), German (1 ‐ 10 %) and Dutch (1 ‐ 10%). 

The probabilities of oil reaching the following shorelines are as follows: Shetland (1 ‐ 10 %), 

Orkney (1 ‐ 10 %), UK mainland (1 ‐ 10 %), Norway (100 %) and Denmark (30 ‐ 40 %). 

Minimum time to beach 11.8 days. 

Maximum mass of oil beached 3,285 tonnes. 

Maximum emulsion beached 16,425 tonnes. 

Sediment concentration average 30 mg/kg. 

In an offshore wind the surface slick could cross the UK‐Norwegian median line in 1.1 days, 

but 9 days in an offshore wind. 

Summary of blowout scenarios 

In the event of a blowout it is likely that oil will cross into Norwegian waters, with a moderate/high 

probability of oil entering into Danish waters and a low probability of oil entering into German and 

Dutch waters. There is a marginally greater probability of oil entering into Danish waters in the 

surface blowout scenario. In both scenarios there is a low probability of oil beaching anywhere in the 

UK, although there appears to be a greater probability of oil beaching in Norway and Denmark for the 

surface release scenario. 

The surface blowout scenario would result in a shorter duration for an oil spill to reach the shore 

(11.8 days) compared to the 20.7 days for the subsurface release. The surface blowout is expected to 

result in a greater maximum mass of oil beached (3,385 tonnes), in comparison to the subsurface 

blowout (1,986 tonnes). 

A subsea blowout could cause elevated hydrocarbon levels in the sediments with typical 

concentrations of 200 mg/kg; this is far greater than the 30mg/kg that is expected for the surface 

blowout. The time taken to cross the UK‐Norway median line is shorter for the surface blowout spill. 

Instantaneous Release of the Diesel Inventory from the Drill Rig. 

The loss of the diesel inventory does not result in a large or significant impact: 

The probability of a surface spill crossing into Norwegian waters is low (1 ‐ 10 %); 

Diesel will not reach any European coastline; 

The typical sediment would be 2 mg/kg; 

In an offshore and onshore wind the surface slick is not expected to cross the UK‐Norwegian 

median line. 

6 ‐ 23

6.5. ENVIRONMENTAL RISKS ‐ FATE OF OIL IN THE MARINE ENVIRONMENT 

6 ‐ 24 



When crude oil is spilled on the surface of the sea it is subjected to a number of processes. These 

include 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. This is taken into account in the modelling scenarios. 

The physico‐chemical changes to which the oil is subjected vary depending on oil type, volume spilled 

and the prevailing weather and sea conditions. Some of these changes can lead to its disappearance 

from the sea surface while others, for example emulsification, may cause it to persist. 

Evaporation and dispersion are the two main mechanisms that act to remove oil from the sea surface. 

Evaporation is the main mechanism by which the mass of oil is reduced immediately after a spill. It 

also causes considerable changes in the density, viscosity and volume of the spill over time. The light 

fractions of the oil (aromatic compounds such as benzene and toluene) evaporate quickly. 

Substances like diesel (the most likely type of hydrocarbon to be spilled) have a greater percentage of 

light hydrocarbon fractions and will therefore evaporate relatively quickly in comparison with heavier 

oils. A large proportion of even a very large spill of diesel will evaporate within the first 24 hours of 

release. Evaporation is enhanced by warm air temperatures and moderate winds. The oil remaining 

in the slick will have a higher viscosity and specific gravity. The processes of dissolution, dispersion 

and photo‐oxidation will also act to break down the oil. The aromatic compounds of diesel can be 

toxic to planktonic organisms in the vicinity of the spill. 

Figure 6‐14 Fate and behaviour of spilled oil at sea (adapted from Koops, 1985). 

After the light fractions have evaporated from the slick, the process slows down and natural 

dispersion becomes the dominant mechanism in reducing the slick volume. This process is dependent 

upon sea surface turbulence, which in turn is affected by wind speed. Water‐soluble components of 

the oil mass will dissolve in the seawater and the immiscible components will either emulsify and



eventually disperse as droplets, or aggregate into a viscous mass. The rate of emulsification is 

dependent upon the oil type and sea state. In certain sea states, emulsions may increase in volume, 

containing up to 70 ‐ 80 % water depending on the oil type, and form a thick layer on the sea surface 

reducing slick spreading and natural dispersion. By diminishing the amount of surface area available 

to be weathered and degraded, these emulsions can be difficult to break up using dispersants and 

some mechanical recovery devices. The light oil encountered in this project is unlikely to form 

emulsions. Emulsions normally require the presence of long chain molecules known as asphaltenes. 

The impacts of oil spills on marine organisms are well documented. A synopsis of potential impacts 

from the proposed operations is summarised in the following sections. 

6.6. SUMMARY OF ENVIRONMENTAL SENSITIVITIES AND POTENTIAL IMPACTS 

This section provides a summary of key relevant data on the environmental sensitivities and potential 

impacts of an oil spill at the Balloch location. Full details of environmental sensitivities can be found 

in Section 3 of this ES. Table 6‐8 provides a summary of the risk assessment of the environmental 

sensitivities within the Balloch location; these have been derived following the assessment criteria 

detailed in Table 6‐6 and Table 6‐7. 

Table 6‐8 Summary of risk assessment of environmental sensitivities within the vicinity of the proposed 

Balloch location. 

Feature Key Sensitivities 

present 

Impact of Small 

Spill 

(Tier 1) 

Impact of Medium Spill 

(Tier 2) 

Impact of Large Spill 

(Tier 3) 

Plankton Low vulnerability Insignificant Insignificant Slight 

Benthic 

communities 

Fish 

Marine 

Mammals 

Offshore 

Seabirds 

Protected 

Sites and 

Shore Birds 

Commercial 

fisheries 


operations 

Shipping 

Tourism 

6.6.1. PLANKTON 

Low / moderate 

sensitivity, species 

specific. 

Spawning and 

nursery for some 

species in winter / 

spring 

Low/moderate 

abundance in area 

Overall Moderate 

vulnerability 

184 km from 

nearest shoreline 

(UK) 

Some commercially 

important species 

present 

Nearest are 

MacCulloch FPSO 

Northern Producer 

FPU and Balmoral 

FPSO 

Moderate area of 

activity 

184 km from 

nearest shoreline 

(UK) 

Insignificant Slight Moderate Severe 

Slight Slight Moderate 

Insignificant Insignificant 

Slight 

(cetaceans) 

Moderate 

(seals) 

Slight Moderate Slight Moderate Moderate Severe 

Insignificant Slight Moderate Moderate Severe 

Insignificant Slight Moderate 

Insignificant Insignificant Slight 

Insignificant Insignificant Slight 

Insignificant Insignificant Moderate 

Although low concentrations of hydrocarbons (

6 ‐ 26 



vulnerable to oil during laboratory experiments. Any changes in the distribution and abundance of 

plankton communities could result in secondary effects on organisms that depend on the plankton as 

a food source, including commercial fish species and marine mammals. There is also the possible 

accumulation and bioaccumulation up the trophic levels of pollutants ingested by plankton (SAHFOS, 

2001). However, the plankton community is generally less vulnerable to one‐off incidents such as 

crude oil or marine gas oil spills than continuous releases, as many species have the capacity to 

recover quickly due to the continual exchange of individuals with surrounding waters (North Sea Task 

Force, 1993). 

As a result, in the unlikely case of a spill occurring, any immediate potential impacts to plankton 

associated with the proposed drilling operations are likely to be short‐term (1 ‐ 2 years). The overall 

impact on phytoplankton populations from a tier 3 spill is expected to be slight. It is recognised that 

there is potential for longer term variation in populations of organisms at higher trophic levels if a 

very large spill over a long period (e.g. >4 months) were to occur, which could affect the spring 

plankton bloom. 

6.6.2. BENTHIC COMMUNITIES 

Oil has been reported to reach the seabed from blowouts (e.g. substantial water column oil 

contamination has been reported following the Deepwater Horizon incident, as well as after the 

Ekofisk blowout). Thus far this has been without recorded biological effect (DTI, 2001), although 

future studies from the Gulf of Mexico may change this view. Investigations into the fate of oil from 

the Braer grounding on Shetland in 1993 concluded that less than 1 % was carried ashore to beaches, 

14 % evaporated and 85 % went into the water column; subsequently, approximately 30 % of the oil is 

believed to have deposited in the seabed sediments, including an area to the southeast of Shetland 

some 30 km from the release (Topping et al., 1997). The nature of the oil, partially biodegraded in the 

reservoir, meant that further biodegradation rates were low and over 3 years of monitoring no 

significant reduction in the deposited oil concentrations was observed, although there was some 

redistribution of the oil vertically downwards into the sediment. Some decline in polycyclic aromatic 

hydrocarbons (PAHs) , some of the more harmful components, was observed over this period, but this 

was not observed at all locations. 

Therefore, in the unlikely case of a very large spill occurring from the proposed operations, it is 

recognised that there is potential for moderate/severe benthic impacts. Sediments could potentially 

become locally contaminated with high levels of hydrocarbons for long periods of time, which in turn 

could cause toxic impacts to the benthic communities. 

6.6.3. FISH 

Several fish species have been recorded across the North Sea; 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 3‐12. 

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. 

Fish are not generally affected by oil slicks on the sea surface and mature fish of most species can 

tolerate water‐soluble oil fraction concentrations of about 10 mg/l. Some species can survive much 

higher concentrations unless whole oil or dispersed oil droplets coat the gills and cause asphyxiation. 

Adult fish are generally more resistant than other marine organisms to oil because their surfaces are 

coated with an oil‐repellent mucus, but they can be affected through the gills, by ingestion, or by 

eating oiled prey (USCG, 2006). Although various developmental disorders may occur to some degree 

under oil slicks, as well as mortalities, so far it has proved impossible to detect consequential effects 

on adult populations. Potential sub‐lethal effects of spilled oil on fish include impairment of 

reproductive processes and increased susceptibility to disease and predators. In fish life cycles, it is



the egg and juvenile stages that are the most vulnerable to spilt hydrocarbons. An oil spill could 

potentially result in the tainting of fish and a reduction of its commercial value. 

Therefore, in the unlikely event of a very large spill occurring from the proposed operations, it is 

recognised that there is some potential for a moderate impact on certain fish species, though the 

scale of this will be dependent upon the size and duration of the spill. 

6.6.4. SEABIRDS 

The effects of oil on birds have been widely studied and include both immediate chronic impacts 

which can cause mortality and 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 

determining the likely impact on birds from a release of oil, the JNCC has produced an Offshore 

Vulnerability Index (OVI) from which it is possible to indicate the sensitivities of birds at different 

times of the year (Section 3.6.4). The OVI of seabirds within each offshore licence block in the vicinity 

of the Balloch development is shown in Table 3‐12 as well as Figure 3‐13, Figure 3‐14 and Figure 3‐15. 

The JNCC has ranked the blocks on a four point scale using the OVI criteria as detailed in Section 3.6.4. 

Seabird vulnerability for the entire year is classified as moderate and there is a degree of monthly 

variability in the sensitivity of seabirds to surface pollution. Generally, seabird vulnerability decreases 

after the winter period when large numbers leave offshore waters to return to their coastal colonies 

for the breeding season. Species commonly found in and around the Balloch area include fulmars, 

gannets, shags, herring gulls, kittiwake, arctic terns, guillemot, razorbills, black guillemots and puffins. 

Other species which are present but recorded in lower numbers include cormorant, arctic and great 

skuas, black headed gulls, common gulls and greater and lesser black‐backed gulls (Stone et al., 1995). 

Seabirds are vulnerable to surface oil that can coat feathers, thereby reducing buoyancy, or be 

ingested through preening, causing illness and other sub‐lethal effects. Seabirds that encounter oil 

slicks either offshore or deposited on the coastline would be expected to have a reduced rate of 

survival. A long term blowout with a large surface slick under calm weather conditions could have a 

significant impact upon seabirds (moderate/severe impact). The degree of any impact is dependent 

upon the season and the extent of offshore areas and coastline impacted. Seabirds that are oiled in 

the coastal area could be caught and rehabilitated. The likelihood of successful treatment is 

dependent upon a number of factors including the degree of oiling and local wildlife response 

capabilities. 

6.6.5. MARINE MAMMALS 

Marine mammals are generally less vulnerable than seabirds to fouling by oil (Geraci, 1990). 

However, they are at risk from hydrocarbons and other chemicals that may evaporate from the 

surface of an oil slick at sea within the first few days of a spill (Gubbay and Earll, 2000; SMRU, 2001). 

The fur of young seal pups may become contaminated by oil, lowering their resistance to cold. The 

loss of insulation properties is not considered a significant risk for adult seals and cetaceans that have 

relatively little fur. Where oil does come into 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 liver and kidneys. If inhaled, hydrocarbons 

can impact the respiratory system. Section 3.6.5 summarises the marine mammals associated with 

the area of the development. The main marine mammals occurring in the area are cetaceans, 

although there is a slight risk expected to these only in a tier 3 spill. Marine mammals most at risk 

from a prolonged blowout are seals, especially those present in coastal regions where oil could beach. 

Oil that beaches at known seal colonies, especially during periods of haul‐out, breeding or pupping, 

would be expected to increase the magnitude of any impacts. 

6.6.6. SOCIO‐ECONOMIC IMPACTS 

In the event of a major release, there would probably be an exclusion of commercial fishing from the 

area until it could be determined that oil levels had diminished and the absence of taint had been 

6 ‐ 27

6 ‐ 28 



confirmed. This would probably be in the order of weeks following the end of such an incident, given 

the nature of the oils involved. However, precautionary closures might last for months if sediments 

were also contaminated, i.e. following a prolonged blowout. With regard to the fishing value of the 

ICES rectangle in the immediate vicinity of the well that would be most affected, rectangle 45F0 has a 

large shellfish fishery (as illustrated in Figure 3‐17 in Section 3.7.1). 

Oil and gas operations are unlikely to be directly impacted by a tier 3 spill. However, following on 

from such an event they may be subjected to increased regulator/public scrutiny of the operations, 

which could lead to changes and/or delays to planned activities. 

The development is in a moderate area for shipping; a large tier 3 spill is only expected to cause a 

slight temporary impact to shipping. 

Tourism is not expected to be impacted, with the exception of a tier 3 spill where there is the 

possibility of oil reaching the shorelines. Oil is likely to be finely dispersed and unlikely to be visible or 

detectable. Should oil beach on the coastline, this could have a negative impact upon local tourism 

industries. 

Summary of impact assessment 

Potential impacts on various environmental and economic receptors need to be considered in relation 

to the likelihood of a spill occurring. In the case of a significant uncontrolled blowout, the likelihood 

of this happening is remote. The impacts from a significant spill could be ranked as moderate/severe 

for a number of environmental and socio‐economic receptors. However, the overall environmental 

risk should be considered as tolerable given the procedures in place to minimise the likelihood of tier 

3 spills. Prevention and contingency measures are discussed in more detail in the next section. 

6.7. SPILL PREVENTION AND CONTINGENCY PLANNING 

Maersk Oil currently has an approved offshore Oil Pollution Emergency Plan (OPEP) that covers the 

Donan and Lochranza fields that are processed at the GPIII FPSO. This OPEP will need to be updated 

to include the Balloch development. 

Maersk Oil’s commitments to ensuring the protection of the environment are set out in the corporate 

HSE policy, a copy of which is provided in Appendix C. Maersk Oil has an externally verified (certified 

to ISO 14001) Environmental Management System (EMS) which will apply to all phases of the Balloch 

Project. 

Oil spills can occur at any phase of a project, including drilling, completion, production and export. A 

particular focus of the recent DECC guidance relates to well control during the drilling and completion 

stages; 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 consequences of a failure 

of well control. 

The wells and completions are designed to Maersk Oil’s internal technical practices. During 

well operations, the primary well control barrier is weighted drilling 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; 

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; 

Maersk Oil will enter into contracts with the drilling contractor to ensure that appropriate 

control measures are in place; 

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 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 Oil procedures detail action to be taken in response to a well control event and 

define the roles and responsibilities for all responders. Technical and operational support 

details are included for different scenarios; 

The proposed measures will be documented in the OPEP for approval by the authorities prior 

to the operation; 

If primary and secondary well control is lost and oil flows uncontrollably from the well to the 

environment (blowout) then a relief well may be required to stop the flow of oil and bring 

the well back under control; 

Maersk Oil are signatories to the OSPRAG capping device; 

Maersk Oil currently has a contract in place with Wild Well Control Inc (WWC) for provision 

of specialist well control advice, personnel, debris clearance and equipment, including a 

commercial agreement gaining access to the WWC UK capping device and related equipment 

(located in Peterhead, UK). 

6.7.1. EMERGENCY PREPAREDNESS AND RESPONSE 

Maersk Oil has a number of arrangements in place to ensure appropriate response to any spill 

scenario. 

Maersk Oil is supported by Oil Spill Response Limited (OSRL), an industry recognised company who 

provide expertise in the containment and management of hydrocarbons accidentally released into the 

environment. Access to competent personnel and equipment is available at short notice for 

mobilisation to the site of any spill to assist in the remedial containment and subsequent clean‐up 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 statutory oil spill response exercises. 

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 also 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. 

Proposed control measures for impacts associated with the accidental release of hydrocarbons 

Maersk Oil has processes in place to reduce the risk of accidental spills 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 assessments form a 

component part of individual OPEPs. Procedures for emergency preparedness and response for 

drilling are detailed in Maersk Oil OPEP (DRL‐PLN‐1034) and the offshore asset‐specific OPEP (OPS‐ 

PLN‐1008). These procedures apply for all spills of hydrocarbons and chemicals to sea. Control and 

mitigation measures are identified below. 

6 ‐ 29

6.7.2. TRANSBOUNDARY CONSIDERATIONS 

6 ‐ 30 




Offshore crews and supervisory teams are trained and competent. 

Approved OPEPs are in place prior to any activities being undertaken and OPEP 

commitments (training, exercises, etc.) are captured in the environmental audit 

programme. 

Well specific control measures include: 

Robust BOP pressure and functional testing regime; 

Routine Remotely Operated Vehicle (ROV) inspections of the BOP on the seabed, 

as well as visual integrity checks whenever BOPs are recovered to the surface; 

Appropriate mud weights are used to ensure well control is maintained; 

Higher hazard and risk awareness and understanding in light of lessons learned 

from the Deepwater Horizon incident. 

Operations specific control measures include: 

Platform import and export facilities are secured by a combination of topside 

Emergency Shut Down Valves (ESDV) and Subsea Isolation Valves (SSIV); 

Export is ceased from the oil export line from the GPIII following a low pressure 

indication on the export line or following a report of a spill at sea which would 

prompt a controlled shut down; 

Balloch pipelines are protected by pressure indicators and leak detection system. 

An uncontrolled blowout from the Balloch location has the potential to affect Norwegian, Danish, 

Dutch and German territorial waters. International agreements are in place to ensure a suitable 

response to such scenarios. 

The UK and Norway have an agreement in place known as the “NORBRIT Agreement” which details 

counter pollution measures between the two countries. Germany, Denmark, the Netherlands and the 

UK are all signatories to the Bonn Agreement. 

These agreements ensure intergovernmental cooperation in dealing with pollution, including aerial 

surveillance and other response measures. It is the responsibility of the authorities for the territorial 

waters within which a major oil spill occurs to immediately notify the authorities of the other 

territories if their waters are threatened.


Section 7 Conclusions 

7. CONCLUSIONS 

A detailed Environmental Impact Assessment (EIA) of the proposed Balloch development has been 

carried out in order to determine its potential impacts on the environment and their significance. 

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 

guidance from DECC. The EIA process will continue throughout the project with the incorporation of 

commitments made in this ES into the design process and construction, ultimately affecting the way 

in which the field is produced. 

7.1. ENVIRONMENTAL EFFECTS 

The development area is considered to be a typical Central North Sea (CNS) offshore environment 

where there are no biological or physical features that are particularly sensitive to the type of 

development proposed. The Balloch project may impact very briefly upon fisheries in the area during 

the installation period. No protected areas or Annex I habitats are present within the vicinity of the 

development. The area is already well developed with a number of oil and gas installations in the 

vicinity of the project. 

The potential impacts on the environment from all phases of the project were assessed. The 

environmental aspects of each of the key activities for each phase of the development were identified 

and the potential effects quantified in terms of their likelihood, potential significance and magnitude. 

The screening results were assessed on the basis of the risk posed to the environment and were 

summarised as being of low, moderate or high risk. 

The initial screening assessment showed that the majority of the proposed activities are of low risk. 

The only activities screened as high risk were associated with unplanned accidental events resulting in 

an uncontrolled well blowout. The likelihood of a subsea blowout is very remote, with the likelihood 

being further reduced by the control procedures that Maersk Oil will have in place. 

Five aspects were assessed as being of moderate risk. The discharge of drilling muds and chemicals to 

sea was assessed as being moderate risk. Underwater noise from piling was also found to be a 

moderate risk, as was the discharge of produced water at the GPIII FPSO. 

Following the identification of suitable control and mitigation measures, an additional assessment 

was undertaken for activities that were initially assessed as being moderate or high risk. Following 

implementation of identified mitigation and control measures, all residual risks to the environment 

are considered to be low. 

7.2. MINIMISING ENVIRONMENTAL IMPACT 

The execution of the proposed Balloch development, following the incorporation of the control 

measures identified in this ES, is not expected to have a significant impact on the environment. 

7.2.1. COMMITMENTS 

Project specific commitments and mitigation measures to minimise the impact of the development on 

the environment have been highlighted throughout the ES and are summarised in relation to the 

phases of the project (drilling, subsea installation and production). These commitments will be 

captured in Maersk Oil’s action tracker, Pride Synergi. 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. 

7 ‐ 1

Drilling 

Atmospheric emissions 

Physical presence 

Subsea Installation 

Physical presence 

7 ‐ 2 



1. The drilling rig will be subject to audits ensuring compliance with UK legislation. 

2. Support and standby vessel presence will be optimised, e.g. the GPIII standby vessel will 

serve as the standby vessel for the drilling rig. 

3. Flaring during well clean‐up will be undertaken using high efficiency burners. 

Discharges to sea 

4. Efficient use of WBM will be maximised. 

5. No OBM will be discharged to sea. 

6. OBM contaminated cuttings will be Rotomill TM treated before being discharged such that: 

Level of retained hydrocarbons in solids



Production 

Atmospheric emissions 

18. 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: 

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. 

19. 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 hydrocarbons flared. 

Discharges to sea 

20. PWRI is the base case for the proposed Balloch development. 

21. Produced water treatment system is subject to an inspection and engineering 


22. GPIII OPPC permit is to be amended to capture additional water volume and oil 

discharged from the proposed development. 

23. Chemical usage will be minimised; those chemicals that will be used will be of the lowest 

toxicity HQ category. 

24. Chemical use will be captured in the PON15D. 

25. GPIII FPSO chemical control/spill measures include: 

Tanks are fitted with overflow alarms; 

Drums are stored in bunded areas (at skids or in storage areas); 

Equipment is provided with drip trays. 

Noise (during all phases) 

26. Both the number of vessels required and the length of time the vessels are on site will be 

minimised; 

27. The JNCC piling protocol will be followed including: 

Piling will commence using soft start; 

Piling to commence in hours of daylight and good visibility; 

A trained marine mammal observer (MMO) will be present during piling 

operations. 

Following 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. 

7 ‐ 3

Hydrocarbon Spills 

7 ‐ 4 


28. Offshore crews and supervisory teams are trained and competent. 


29. Approved OPEPs are in place prior to any activities being undertaken and OPEP 

commitments (training, exercises, etc.) are captured in the environmental audit 

programme. 

30. Well specific control measures include: 

Robust BOP pressure and functional testing regime; 

Routine Remotely Operated Vehicle (ROV) inspections of the BOP on the seabed, 

as well as visual integrity checks whenever BOPs are recovered to the surface; 

Appropriate mud weights are used to ensure well control is maintained; 

Higher hazard and risk awareness and understanding in light of lessons learned 

from the Deepwater Horizon incident. 

31. Operations specific control measures include: 

Platform import and export facilities are secured by a combination of topside 

Emergency Shut Down Valves (ESDV) and Subsea Isolation Valves (SSIV); 

Export is ceased from the oil export line from the GPIII following a low pressure 

indication on the export line or following a report of a spill at sea which would 

prompt a controlled shut down; 

Balloch pipelines are protected by pressure indicators and leak detection system. 

7.3. OVERALL CONCLUSION 

Following the implementation of the mitigation and control measures identified, the long term and 

cumulative environmental impacts associated with the proposed Balloch development are considered 

to be acceptable.


Section 8 References 

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Section 8 References


Appendix A – Review of 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 (as 

amended 2007) 

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

Offshore Marine Conservation (Natural Habitats, &c.) Regulations 2007 (as amended 2012) 

Offshore Combustion Installations (Prevention and Control of Pollution) Regulations 2001 (as amended 2007) 

Offshore Chemicals Regulations 2002 (as amended 2011) 

Offshore Installations (Emergency Pollution Control) Regulations 2002 

Greenhouse Gases Emissions Trading Scheme Regulations 2005 (as amended 2011) 

Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 (amended 2011) 

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) (as amended by EC Directive 97/11) 

Directive 2000/60 (the Water Framework Directive) 

Directive 2001/80 (the Large Combustion Plants Directive) 

Directive 2004/35 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). 

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Pollution Prevention 

and Control 

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MARPOL: 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 Pollution 

from Ships 

Directive 2008/1/EC on Integrated 

Pollution Prevention and Control (IPPC) 

(as amended) 

Pollution Prevention and Control Act 

1999 (as amended 2000) 

Territorial Waters Territorial Sea Act 1987 (as amended 

2002) 

Territorial Waters Order 1964 

Control Oil Pollution Act 1974 

Public Participation EC Directive 2003/35 on Public 

Participation 


Liability 

EC Directive 2004/35 on Environmental 

Liability with Regard to the Prevention 

and Remedying of Environmental 

Damage 

The Environmental Liability (Scotland) 

Regulations 2009 (as amended 2011) 



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 are required and these special areas are provided with a higher level of 

protection than other areas of the sea. 

Directive 2008/1 replaces Directive 96/61 concerning integrated pollution prevention and control. 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. 

The Directive is implemented into UK law by the Pollution Prevention and Control Act. The provisions of this act are 

enforced through: 

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

The Offshore Chemicals Regulations 2002 (as amended) 

The Offshore Combustions Installations (Prevention and Control of Pollution) Regulations 2001 (as amended) 

Defines the territorial waters of the UK. 

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. 

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. 

EC Directive 2009/31 on the geological storage of carbon dioxide amends the following directives to include CCS: 

85/337/EC



Environmental Damage (Prevention and 

Remediation) Regulations 2009 (as 

amended 2010) 

The Environmental Damage (Prevention 

and Remediation) (Wales) Regulations 

2009 

Environmental Liability (Scotland) 


Marine Management EC Directive 2008/56 (the Marine 

Strategy Framework Directive) 

The Marine Strategy Regulations 2010 

2000/60/EC 

2001/80/EC 

2004/35/EC 

2006/12/EC 

2008/1/EC 

The Environmental Liability (Scotland) Amendment Regulations 2011 amend the 2009 regulations in accordance with EC 

Directive 2009/31 and came into force in June 2011. 

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 2011 amendments amend the Regulations in accordance with EC Directive 2009/31 

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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A ‐ 4 

Marine and Coastal Access Act 2009 (as 

amended 2012) 

Marine (Scotland) Act 2010 (as amended 

2011) 



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. The marine licensing provisions in Part 4 

replace the licensing and consent controls previously exercised under Part II of the Food and Environment Protection Act 

1985 and Part II of the Coast Protection Act 1949. The considerations built into these regimes are merged into the new 

regime, with some modifications. The export of cuttings or produced water to another site for reinjection continues to 

be licensed under FEPA Part II. All activities associated with exploration or production / storage operations that are 

authorised under Petroleum Act or Energy Act are exempt from the requirements of MCAA. Specifically, 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 

Decommissioning operations are not exempt and will require a Marine licence. 

MCAA includes navigational provisions, but as described above, virtually all activities associated with exploration or 

production/storage operations will not require Marine licences. Therefore the provisions of the Coast Protection Act 

were transferred to the Energy Act 2008 Part 4A via the MCAA to cover navigation considerations relating to exploration 

or production/storage operations. 

Licences will be valid for a maximum period of one year however; applications for licence renewals can be made.



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: 

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Field Development 

Plan 

Pipeline Works 

Authorisation 

A ‐ 6 

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 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 when 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 when seeking a chemical permit during workover/well intervention operations 

Petroleum Act 1998 Regulator: DECC 

Operators are required to submit plans for development of field to DECC for approval. 

Petroleum Act 1998 Regulator: DECC 

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 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 

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A ‐ 8 



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 

consent of 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); 

Seabed lease Crown Estate Act 1961 Regulator: Crown Estate Commissioners 

Minute of agreement required for occupation of seabed. 

Location of 

structures 

Energy Act 2008 Regulator: DECC 

A 'consent to locate' was previously issued under the Coast Protection Act 1949 Section 34, Part II. It is now issued under 

Part 4 of the Energy Act 2008, which was implemented through the MCAA. 

Separate applications for consent are submitted to the Environmental Management Team in DECC’s Offshore 

Environment and Decommissioning Directorate. 

Continental Shelf Act 1964 

The Continental Shelf (Designation of 

Areas) (Consolidation) Order 2000 (as 

amended 2001) 

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



Well consent 

Licensing 

Planning 

Petroleum Act 1998 

Petroleum Operations Notice No 4 

(revised May 2012) 

Petroleum Licensing (Production) 

(Seaward Areas) Regulations 2008 (as 

amended 2009) 

Marine Coastal Access Act 2009 (as 

amended 2011) 

Marine (Scotland) Act 2010 

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 CO 2 storage activities which will remain with DECC 

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A ‐ 10 

Drilling 


Rig Movements HSE Operations Notice 6 Reporting of 

Offshore Installation Movements 

HSE Operations Notice 3 Liaison with 

other bodies 

HSE Operations Notice 14 on Coastal 

Protection Act. 

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) (as 

amended by the Energy Act 2008 

(Consequential Modifications) (Offshore 

Environmental Protection) Order 2010) 

(replacing Prevention of Oil Pollution Act 

1971 (as amended)) 



Under Operations Notice 6 a rig warning communication must be issued at least 48 hours before any rig movements 

Notice 6 should be read in conjunction with Operations Notice 3 Liaison with other bodies and Operations Notice 14 

Guidance on Coast Protection Act ‐ consent to locate and the marking of offshore installations. 

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. 

Although the discharge of drilling muds and cuttings is exempt from FEPA/MCAA, the export of drilling cuttings and 

produced water for re‐injection still requires a FEPA licence. 


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



Offshore Chemicals Regulations 2002 (as 

amended 2011) (as amended by the 

Energy Act 2008 (Consequential 


Protection) Order 2010) 

PON 15b Implementing the requirements 

of OSPAR Decision 2000/2 on a 

Harmonised 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 

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 permit 

under the Offshore Chemicals 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 an offshore chemical and a new definition of “release” has been inserted which catches all other emissions 

(regulation 4(a) and (h) of the amendments). 

Under the 2011 amendments, well suspension and abandonment also requires a formal permitting process and will 

usually require approval under the MCAA licensing regime. Both of which are administered by DECC’s Environmental 

Management Team. These requirements are in addition to the PON15 consent to abandon a well. 

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 

A ‐ 11

Rig Stabilisation Offshore Petroleum Production and 






Order 2010) 

Offshore Petroleum (Conservation of 

Habitats) Regulations 2001 (as amended 

2011) 

Dangerous Goods The Merchant Shipping (Dangerous 

Goods and Marine Pollutants) 


Chemical data sheets 

and labelling 

A ‐ 12 

The Chemicals (Hazard Information and 

Packaging for Supply) Regulations 2002 

(as amended 2008) (revoked by the 

Chemicals (Hazard Information and 

Packaging for Supply) Regulations 2009) 

EC Regulation 1907/2006 (REACH) 

REACH Enforcement Regulations 2008 SI 

2852 

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. 

The 2009 regulations, CHIP4, consolidate all amendments made to the Chemicals (Hazard Information and Packaging for 

Supply) Regulations since 2002. 

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.



Vessels 


Rock dumping and 

other deposits of the 

seabed 

Fisheries liaison Model Clauses of Licence 

HSE Offshore Safety Division Operations 

Notice 3 

The Petroleum Act 1998 Regulators: DECC supported by Marine Scotland and CEFAS and within territorial waters Scottish Government Marine 

Directorate 

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. 

A ‐ 13

Machinery space 

drainage from 

shipping 

Waste from vessels 

and construction 

A ‐ 14 

The Merchant Shipping (Prevention of Oil 

Pollution) Regulations 1996 ( as amended 

2005) (as amended by the Merchant 

Shipping (Implementation of Ship‐Source 

Pollution Directive) Regulations 2009) 



Regulator: Maritime and Coastguards Agency 

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 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 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 Merchant Shipping (Prevention of 

Pollution by Sewage and Garbage) 


Sewage from vessels MARPOL 73/78 Annex IV Regulations for 

the Prevention of Pollution by Sewage 

from Ships 


Pollution by Sewage and Garbage) 


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 

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 force in September 2003 and the revised annex entered into 

force in 2005 

This does not apply to offshore installations as defined in the Petroleum Act 1998. 


Atmospheric MARPOL 73/78 Annex VI the Prevention Regulator: Maritime and Coastguard Agency 

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

emissions from 

vessels 

A ‐ 16 



of Air Pollution from Ships Annex VI is concerned with the control of emissions of ozone depleting substances, NOx, SOx, and VOCs and require 

ships (including platforms and drilling rigs) to be issued with an International Air Pollution Certificate following survey. 

The Annex includes a global sulphur limit of 4.5% for heavy fuel oil burned by ships. MARPOL also allows for the 

establishment of Sulphur Oxide (SOx) Emission Control Areas with more stringent controls on Sulphur emissions. The 

North Sea was adopted as a SOx Emissions Control Area in 2005 and consequently the Sulphur content of fuel oil must 

not exceed 1.5wt%. In 2015 this will be reduced further to 0.1wt% Sulphur. 

No new installations containing ozone‐depleting substances are permitted, with the exception of HCFCs which are 

permitted till 1 January 2020. 

NOx emissions from diesel engines are to be limited by the implementation of NOx technical code. 

No incineration of contaminated packing materials or PCBs onboard ships. 

Annex VI only applies to diesel engines over 130 KW and does not apply to turbines. 

Emissions arising directly from the exploration, exploitation and associated offshore processing of seabed mineral 

resources are exempt from Annex VI, including the following: 

Directive 1999/32 relating to a reduction 

in the sulphur content of certain liquid 

fuels and amending Directive 93/12/EEC 

The Merchant Shipping (Prevention of Air 

Pollution from Ships) Regulations 2008 

(as amended 2010) 

Emissions resulting from flaring, burning of cuttings, muds, well clean‐up emissions and well testing; 

Release of gases entrained in drilling fluids and cuttings; 

Emissions from treatment, handling and storage of reservoir hydrocarbons; and 

Emissions from diesel engines solely dedicated to the exploitation of seabed mineral resources. 

In addition, Regulation 13 concerning NOx does not apply to emergency diesel engines, engines installed in lifeboats or 

equipment intended to be used solely in case of emergency. 

The EU Directive (1999/32/EC) regarding the sulphur content of diesel fuels sets sulphur limits for certain fuels within 

Community territory. In the case of marine gas oil for vessels in the North Sea this is set at 0.1wt%. It also cites sulphur 

limits for inland heavy oil fuels and gas oils, but not for marine heavy fuel oils. A new amending Directive is being drafted 

that would align the provisions of Directive 1999/32/EC with the revised Annex VI to MARPOL (as discussed above) (see 

pending legislation). 

The Merchant Shipping (Prevention of Air Pollution from Ships) Regulations 2008 implements Annex VI of MARPOL into 

UK law. UK ships (including offshore installations and drilling rigs) are surveyed by an internationally agreed standard to 

demonstrate they are in compliance with Annex VI. 

The Regulations aim to reduce air pollution from shipping. This will be achieved through controls on emissions of 

Nitrogen Oxides, Sulphur Oxides, Volatile Organic Compounds and Ozone Depleting Substances, which are not 

Greenhouse Gases (GHGs). Additionally elements of the Regulations limit the sulphur content of marine fuels and



Antifouling coating 

on vessels 

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 

Discharges The Offshore Petroleum Activities (Oil 



(as amended by the Energy Act 2008 



(replaced the Prevention of Oil Pollution 

Act 1971) 





Protection) Order 2010) PON 15c 

require a register of local marine fuel suppliers. 

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 

A ‐ 17

Vessel Movements International Regulation for Preventing 

Collisions at Sea 1972 (COLREGS) (as 

amended 2007) 

A ‐ 18 

The Merchant Shipping (Distress Signals 

and Prevention of Collisions) Regulations 

1996 

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: 

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 implements 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 

Commissioning and Operations 


Discharges of linefill 

and hydrotest fluids 

The Petroleum Act 1998 Regulator: DECC supported by Marine Scotland and CEFAS and within territorial waters Scottish Government Marine 

Directorate 

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.



Displacement water The Offshore Petroleum Activities (Oil 






Chemical use and 

discharge 


amended 2011) 




PON 15 c, d and f 

Dangerous goods The Merchant Shipping (Dangerous 

Goods and Marine Pollutants) 

Regulations 1997 

Chemical data sheets 

and labelling 

The Chemicals (Hazard Information and 

Packaging for Supply) Regulations 2002 

(as amended 2008) (revoked by the 

Chemicals (Hazard Information and 

Packaging for Supply) Regulations 2009) 

Machinery space The Merchant Shipping (Prevention of Oil Regulator: Maritime and Coastguards Agency 


The discharge of oil requires an OPPC permit which are issued by DECC. The 2011 amendments to the regulations extend 

permit 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 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. 

A ‐ 19

drainage from 

shipping 

A ‐ 20 

Pollution) Regulations 1996 (as amended 

2000 and 2005) (as amended by the 

Merchant Shipping (Implementation of 

Ship‐Source Pollution Directive) 

regulations 2009) 

Radioactive sources Radioactive Substances Act 1993 (as 

amended 2011 (Northern Ireland and 

Scotland only)) 

Produced water The Offshore Petroleum Activities (Oil 








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. 

Regulator: SEPA or Environment Agency (EA) 

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. 

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 came 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. 


Discharge limits under OPPC are: 

A monthly average oil‐in‐water concentration of 30mg/l; 

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.



Hazardous and non‐ 

hazardous drainage 

(excluding 

machinery space 

drainage) 

Well workover, 

intervention and 

service fluid 

discharges 

Maintenance and 

cleaning discharges 

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 from 

Offshore Installations (as amended by 

Recommendation 2011/8) 





















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 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. 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. Permits extend to both installations and pipeline under the Offshore Petroleum Activities (Oil Pollution 

A ‐ 21

Other minor oily 

discharges 

A ‐ 22 










Oily sand and sludge The Offshore Petroleum Activities (Oil 






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) Regulations 2007 (as amended 

2012) 

The Pollution Prevention and Control 

(Scotland) Regulations 2000 (as amended 



Prevention and Control) (Amendment) 2011. 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 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. 


permits now extend 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. 


permits now extend 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 (as amended) 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.



CO 2 Combustions 

Sources and 

Emissions 

2011) These were extended by the Environmental Permitting (England and Wales) (Amendment) (No.2) Regulations 2012 which 

aim to simplify the permitting process and came into force April 6 th 2012. 

The regulations require operators to apply for a permit for new offshore combustion processes which are to be 

permanently installed 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: 

Offshore Combustion Installation 

(Prevention and Control of Pollution) 


EC Directive 2003/87 establishing a 

scheme for greenhouse gas emission 

allowance trading with the community 

(as amended by EC Directive 2009/29) 

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 CO 2 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 amended by three subsequent acts: 

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Greenhouse Gas Emissions Trading 

Scheme Regulations 2005 (as amended 

2011) 

The Greenhouse Gas Emissions Data and 

National Implementation Measures 


CRC Energy Efficiency Scheme Order 

2010 (as amended 2011) 






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% 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, MODU are exempt from this scheme. 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). 

The CRC Energy Efficiency Scheme Order 2010 (as amended 2011) is a mandatory scheme designed to promote energy 

efficiency and reduce carbon emissions.



Ozone Depleting 

Substances 

EC Regulation 842/2006 

Fluorinated Greenhouse Gases 

Regulations 2009 (as amended 2012 

(Northern Ireland only)) 

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) 


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 (as amended) 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. 

These Regulations also give effect to the following EC Regulations relating to certain fluorinated GHGs: 

- EC Regulation 1493/2007 









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 


The 2011 regulations revoke and replace the previous regulations. The regulations enforce the provisions of EC 

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(revokes and replaces the Environmental 

Protection (Controls on Ozone Depleting 

Substances) Regulations 2002 (as 

amended 2008) 

Ozone Depleting Substances 

(Qualifications) Regulations 2009 



Regulation 1005/2009 which controls the production, impact, export, placing on the market, recovery, recycling, 

reclamation and destruction of substances that deplete the ozone layer. 

The 2009 regulations take into account changes made by the Fluorinated Greenhouse Gas Regulations 2009 (as amended 

2012), revoking and replacing the 2006 regulations. The purpose of these Regulations is to specify the minimum 

qualification requirements for persons handling ozone depleting substances. It includes minimum qualifications for 

persons carrying out work which involves recovering, recycling, reclaiming and destroying controlled substances; and 

preventing and minimising the leakage of controlled substances. 

Flaring and Venting Model Clauses of Licences Regulator: DECC 

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. 

Nearshore 

Discharges 

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 2003 

The Water Resources Act 1990 

(superseded by the Water Resources Act 

1991) (as amended 2009 (England and 

Wales)) 

Implemented in Scotland by: 

Water Environment and Water Services 

(Scotland) Act 2003 

the Water Environment (Controlled 

Activities) (Scotland) Regulations 2011 

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 

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.



Sewage from 

installations 

Food and Environment Protection Act 

1985 (as amended) 

Deposits in the Sea (Exemptions) Order 

1985 

the Deposits in the Sea (Exemptions) 

(Amendment) (England and Wales) Order 

2010 (extends to England and Wales 

only) 

Waste Directive 2008/98/EC on Waste (the 

Waste Framework Directive) 

National Waste Strategy 2000 (as 

amended 2007) 

MARPOL Annex V: Prevention of 

pollution by garbage from ships 


Pollution by Sewage and Garbage from 

Ships) Regulations 2008 (as amended 

2010) 

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 

Commits the UK to a target of cutting landfill of biodegradable waste by two thirds by 2020. 


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) supersedes 

Merchant Shipping (Prevention of Pollution by Garbage from Ships) Regulations 1998 and brings the previous 

implementing regulations into line with the current version of Annex V. 

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) 

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Environmental Protection (Duty of Care) 


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) 




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 2009 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 

Decommissioning 


Chemical use and Offshore Chemicals Regulations 2002 (as Regulator: DECC



discharge amended 2011) (as amended by the 




PON 15e 

Preliminary 

discussions 

Decommissioning 

proposals 

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 the 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 2008 (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 

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Stabilisation 

Materials 

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Offshore Petroleum Production and 






Order 2010) 

Pipelines Safety Regulations 1996 (as 

amended 2003) 

OSAPR Recommendation 2006/5 on a 

management scheme for offshore 

cuttings piles 


amended 2011) 



amended 2011) 


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 an EIA at the decommissioning stage, the decommissioning 

programme should be supported by an 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



Power Generation Offshore Combustion Installations 

(Prevention and Control of Pollution) 





The Greenhouse Gas Emissions Trading 

Scheme Regulations 2005 (as amended 

2011) 

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(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. 

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. 

Accidental Events 


Oil pollution 

emergency planning 

International Convention on Oil 

Pollution, Preparedness, Response and 

Co‐operation (OPRC) 1990 

The Merchant Shipping Act 1995 

The Merchant Shipping (oil pollution 

preparedness, response and co‐ 

operation) Regulations 1998 

BONN Agreement Oil Appearance Code 

(BAOAC) 

Offshore Pollution Liability Agreement 

4 th September 1974 (as amended) 

Petroleum (Production) (Seaward 

Areas) Regulations 1988 (as amended 

1996) 

Oil pollution Offshore Installations (Emergency Regulator: DECC 

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 operators have a formally approved Oil Pollution Emergency Plan 

(OPEP) in place for each offshore operation, or agreed grouping of facilities. 

The aims of this convention are enforced through national legislation such as the Merchant Shipping Act 1995 and the 

Merchant Shipping (oil pollution preparedness, response and co‐operation) Regulations 1998. 

This code was adopted following the BONN Agreement for co‐operation in dealing with pollution of the North Sea. The 

code gives a standard format to quantify the amount of oil that is polluting a body of water. 

All offshore operators currently active in exploration and production on the UKCS are party to a voluntary oil pollution 

compensation scheme which is known as the Offshore Pollution Liability Association (OPOL). 

These regulations relate to applications for offshore petroleum exploration and production licences and the clauses to be 

incorporated in such licences. It gives effect to certain model clauses such as Model Clause 23(9) which requires offshore 

facilities to have a liability regime where there is a risk of discharging oil causing pollution damage. 

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(Installations) 

A ‐ 32 

Pollution Control) Regulations 2002 (as 

amended by the Energy Act 

(Consequential Modifications) 


Order 2010) 

Offshore Chemical Regulations 2002 

(as amended 2011) (as amended by the 

Energy Act (Consequential 

Modifications) (Offshore 


Offshore Petroleum Activities (Oil 


Regulations 2005 (as amended 

2011)(as amended by the Energy Act 

(Consequential Modifications) 


Order 2010) 



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. 

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 

Oil pollution The Merchant Shipping EC Directive 2005/35 on ship‐source pollution and on the introduction of penalties for infringements states that ship‐




(shipping) 

(Implementation of Ship‐Source 

Pollution Directive) Regulations 2009 

The Merchant Shipping (Oil Pollution 

Preparedness, Response and Co‐ 

operation) Regulations 1998 (as 

amended 2001) 

source polluting discharges constitute in principle a criminal offence. According to the Directive this relates to discharges 

of oil or other noxious 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 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 EU 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 (as amended 2004) 

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. 

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Pipeline emergency 

prevention 

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Pipelines Safety Regulations 1996 (as 

amended 2003) 

Spill reporting Model Clauses of Licence 

PON 1 

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. 


All oil spills must be reported to DECC, the nearest HM coastguard and JNCC using a PON 1. 

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) 

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 Directive provides a framework for the conservation and management of, and human interactions with, wild birds in 

Europe. It sets broad objectives for a wide range of activities, although the precise legal mechanisms for their 

achievement are at the discretion of each Member State (in the UK delivery is via several different statutes). 

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 Birds Directive is implemented nationally for the offshore marine environment by The Offshore Petroleum Activities



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 (as amended 

2012) (The Conservation of Species and 

Habitats Regulations 2010 (as amended 

2012) consolidate all amendments 

made to the 1994 regulations) 

The Offshore Marine Conservation 

(Natural Habitats, &c) Regulations 2007 

(Conservation of Habitats) Regulations 2001 (as amended), the Conservation of Habitats and Species Regulations 2010, 

the Conservation (Natural Habitats, & c.) Regulations 1994 and the Offshore Marine Conservation (Natural Habitats, &c.) 

regulations 2007 (as amended). 

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 at a favourable conservation status, introducing robust 

protection for those habitats and species of European importance through the designation of Special Areas of 

Conservation (SACs). In applying these measures Member States are required to take account of economic, social and 

cultural requirements and regional and local characteristics. 

The Habitats Directive is implemented nationally for the offshore marine environment by The Offshore Petroleum 

Activities (Conservation of Habitats) Regulations 2001 (as amended), the Conservation of Habitats and Species 

Regulations 2010, the Conservation (Natural Habitats, & c.) Regulations 1994 and the Offshore Marine Conservation 

(Natural Habitats, &c.) regulations 2007 (as amended). 

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 (and all amendments) transpose the Habitats and Birds 

Directive into UK Law. These Regulations provide for the designation and protection of 'European Sites'. The protection 

of 'European Protected Species' (EPS)and the adoption of planning and other controls for the protection of European 

Sites only as far as the limit of territorial waters (12nm from the coastline). 

The Conservation of Habitats and Species Regulations 2010 (as amended 2012) consolidate all amendments made to the 

1994 regulations in England and Wales. Whereas, in Scotland, the Habitats and Birds Directives are transposed through a 

combination of the 2010 and 1994 regulations. The Conservation of Habitats and Species Regulations 2010 also 

implement aspects of the Marine and Coastal Access Act (2009). 

These Regulations are the principal means by which the Birds and Habitats Directives are transposed in the UK offshore 

marine area (i.e. outside the 12 nm territorial limit) and in English and Welsh territorial waters. 

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(as amended 2012) 

Offshore Petroleum (Conservation of 

Habitats) Regulations 2001 (as 

amended 2007) 

The Petroleum Act 1998 

Birds Convention on Wetland of 

International Importance Especially as 

Waterfowl Habitats 1971 (The Ramsar 

Convention) 

Cetaceans Agreement on the Conservation of 

Small Cetaceans of the Baltic and North 

Seas 1991 (ASCOBANS) and 2008 

amendments 



The Regulations apply the Habitats Directive and the Wild Birds Directive in relation to oil and gas plans or projects, and 

under the Energy Act 2008 (Consequential Modifications) (Offshore Environmental Protection) Order 2010, CCS plans and 

projects, wholly or partly on the United Kingdom’s Continental Shelf and superjacent waters outside territorial waters 

(‘the UKCS’) (i.e. outside the 12 nm territorial zone). 

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. 

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 be managed centrally by 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 2008 

Climate Change (Scotland) Act, 2009 

The Climate Change Act intends to introduce powers to combat climate change by setting targets to reduce CO 2 

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 CO 2 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.



Chemical Discharges 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 

Produced Water Draft OSPAR Recommendation on 

Produced Water Management 

EC Directive 1999/32 A new amending Directive is being drafted that would align the provisions of Directive 1999/32/EC with the revised 

Annex VI to MARPOL (2008). 

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 has been 

developed. It involves 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. 

The draft OSPAR Recommendation suggests that a risk based approach (RBA) should form the basis of produced water 

management methods within each OSPAR contracting party. The goal of the Draft Recommendation is to establish a 

methodology to assess the environmental risk of PW discharges to the marine environment and to ensure that operators 

take suitable measures to prevent or mitigate any identified environmental risks. The RBA will be additional to existing 

legislation, and if agreed, the measures are expected to enter into force in January 2012.Once in force, participants must 

demonstrate a RBA approach to PW handling along with complying with the 30 mg/l monthly discharge requirements. 

A ‐ 37


Appendix B ‐ Environmental Assessment 

APPENDIX B – ENVIRONMENTAL ASSESSMENT 

Potential impacts for each key project and associated environmental effect before and after mitigation measures. 

Drilling Phase 

Key 

High Moderate Low 


Source 

Aspect 

Emissions to air Exhaust emissions 

from drilling 

operations 

Well clean up and 

testing 

Exhaust emissions 

from support vessels 

and helicopter 

transfers 

Discharge of CFCs 

and HCFCs 

Activity 

Description 

Generation of power during 

the proposed drilling 

operations will result in 

emissions of various 

combustible gases. 

Well test flaring will result in 

the emissions of various 

combustible gases. 

Support vessels consist of 

anchor handling vessels, supply 

vessel, standby vessel. 

Traditionally CFCs have been 

utilised as a coolant medium in 

refrigeration units 

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). 

Likelihood Consequence Risk 

5 1 Low 



(VOC, NOx & particulates) 


5 1 Low 





5 1 Low 

CFCs contribute to ozone depletion and are regarded as 

greenhouse gases. 

In 2010, the NTvL resulted in approximately 0.23 tonnes of 

HCF refrigerant R422D, which is relatively low 


Mitigation of impacts and actions 

to address concerns 

Audit to ensure rig complies with 

UK standards, engines are 

maintained and operated 

correctly. 

Residual impact and/or 

concern 

Contributes to 

greenhouse gases. Low 

impact. 

Use of low sulphur diesel in 

vessels. 

No extended well test. Contributes to 


impact. 

Minimise vessel travel times, 

number of vessels required and 

length of time vessel remains on 

location. 

Drilling rig contractors are phasing 

out the use of HCFCs in 

compliance with legal 

requirements. 



impact. 

None envisaged as the 

development should not 

lead to any release. 

Negligible impact. 

B ‐ 1

B ‐ 2 

Halocarbon release 

during emergency 

events 

Discharges to Sea Deliberate discharges 

from drilling 

operations 

Contained and 

treated drilling fluids 

Contained and 

treated drainage 

water 

Liquid waste 

(domestic sewage) 

Fire fighting systems can be 

designed to release harmful 

halocarbons 

WBM and cuttings, 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. 

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). 

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 

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. 



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. 

Brine contaminated with oil to be 

shipped to shore for treatment 

and disposal 

Use of PLONAR chemicals (i.e. low 

toxicity chemicals). 

All OBM’s will be processed using 

Rotomill % of oil on cuttings 

discharged < 0.1% 

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 NTVL. 

Sewage treatment unit on board 

rig (MARPOL) and vessels to 

reduce BOD prior to discharge, 

this will aid biological breakdown 

on release. 


None envisaged as the 

development should not 

lead to any releases. 


Minimal discharge of 

WBM to sea with only 

localised temporary 

effects on the water 

column and seabed. Low 

impact. 

No detectable increase in 

the water column or 

sediments of any the 

OBM drilling fluids or 

chemicals discharged. 

Low impact. 

Good working practice 

will minimise any 

potential spillage. 


Negligible impact.



Disposal to land General waste from 

drilling operations 

and support vessels. 

Physical presence Installation of rig and 

presence of vessels 

Drilling rigs and support vessels 

generate a number of wastes 

during routine operations 

including waste oil, chemical & 

oil contaminated water, scrap 

metal domestic wastes etc. 

Positioning of semi‐sub rig at 

wells using anchors (12) and 

chains 

Support vessel e.g. anchor 

handling vessels & tug vessel, 

movements. 

Under water noise Noise and vibration Sources include 

semi‐sub drilling operations & 

support vessels 

Minor accidental 

events 

Chemical spills Chemical storage‐ accidental 

spills, leaks, containment 

damage. 

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 

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 

May result in a variety of impacts including increased 

chemical or biochemical oxygen demand, toxicity, persistence, 

bioaccumulation in animals 


2 2 Low 

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. 

The rig will be present for as short 

a time as possible. 

Rig moves will be minimised. 

Other users of the area will be 

notified. 

Use of vessels kept to a minimum. 

The rig will be present over a 

relatively short period of time. 

Minimise rig movements. 

Optimised quantities procured & 

stored. COSHH, Task Hazard 

Assessments are completed and 

MSDS sheets are available. 

Transfer operations suspended in 

rough weather. Bulk hoses and 

connections inspected before and 

after use by competent personnel. 

Hoses on bard the NTVL are 

replaced annually. 

OPEP procedures followed 

Contribute to landfall 

waste. Low impact. 

Short term and very 

localised impact . 

No long term impacts to 

other sea users. 

Low impact 

Contribute to increase in 

ambient noise levels. Low 

impact. 

Mitigation measures will 

ensure risk of chemical 

spill are within tolerable 

risk levels. Low impact. 

B ‐ 3

B ‐ 4 

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 

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. 

Minor spillage that would impair water quality and marine life 

in immediate vicinity of discharge. 


2 2 Low 

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. 

Affect also on amenity value, property (e.g. vessels in 

marinas) & commercial interests. 


2 1 Low 

Impact dependent on spill volume and weather conditions. 






2 2 Low 


Trained personnel undertake 

decanting operations. 

OPEP is implemented in the event 

of a spill as per Emergency 

Response Process. Oil spill 

modelling completed as an 

integral part of the OPEP. 

Trained personnel involved in fuel 

transfer. Diesel storage tanks and 

transfer hoses are subject to 

inspection & engineering 

maintenance strategy. Bunded 

storage tanks. 



Response 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. Maersk are members 

of OSRL (OSRL are on standby to 

provide oil spill clean‐up when 

required). Tanks have a spill over 

area. 



ensure risk of chemical / 

oil spill are within 

tolerable risk levels. Low 

impact. 

Diesel should rapidly 

evaporate and disperse, 

diesel evaporates 

contribute are a form of 

greenhouse gases 


ensure risk of a spill are 

within tolerable levels. 

Low impact. 

Spills may cause local 

elevation of hydrocarbon 

levels and contamination 

and toxic effects. 


ensure actual risk of a 


levels.



Major accidental 

events 

Installation Phase 

Loss of well control 

/fire explosion. 

Uncontrolled subsea 

blowout 


Source 

Aspect 

Emissions to air Exhaust emissions 

associated with 

installation of subsea 

infrastructure e.g. 

infield pipe‐lines, 

cooling spool, 

concrete mattresses 

Exhaust emissions 

from support vessels 

Loss of control of well resulting 

in release of oil and or subsea 

blowout. Two subsea blowout 

scenarios are assessed in 

Section 6. 

Activity 

Description 

Subsea wellheads will be fixed 

in position on the seabed 

surface. All infield pipelines will 

be covered with concrete 

mattresses and grout. Due to 

its minimal nature, subsea 

installation will require a diving 

support vessel only. 

During pipe lay opera‐ tions a 

survey vessel will ensure the 

line is laid in accordance with 

the selected route plan. 

Additional surveying activities 

will be commissioned as 

necessary . The survey vessel 

will have associated exhaust 

emissions. 

Damage to commercial fisheries, sediment and water quality 

impairment and release of atmospheric emissions. 


1 5 High 






5 1 Low 





5 1 Low 

Inspection &engineering 

maintenance strategy based on 

preventative maintenance. 

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. 



Minimising operations through 

design. 

Post and pre‐installation surveys 

will be carried out during periods 

of good weather 




and toxic effects and 

socio‐economic impacts 

to fishing, and tourism. 

Oscar modelling of a 

blowout indicates a high 

risk of oil beaching on 

Norwegian coastlines. 




levels. 


concern 



impact. 



impact. 

B ‐ 5

Discharges to Sea Discharge from 

pipeline pressure 

testing 

B ‐ 6 

Discharge of fluid 

from the open 

subsea control 

system 

Disposal to land General waste from 

pipelay, installation 

of infield infra‐ 

structure and 

support vessels 

After installation pipelines 

need to be pressure tested. 

The lines are to be filled with 

potable water, dosed with 

biocide, oxygen scavenger, dye 

& corrosion inhibitor. The 

displaced water, along with 

chemical additives may be 

discharged to the sea surface 

or processed through existing 

facilities & reinjected with the 

produced water stream. 

Hydraulic control of subsea 

facilities. 

Control systems use water 

based hydraulic fluid in an 

open system. 

Pipelay and installation 

generate a number of wastes 

during routine operations 

including waste oil, scrap metal 

and domestic wastes 

Localised effect on water quality associated with discharge to 

sea of seawater 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 


5 1 Low 


the nature of the site or process. Landfills – land take, 


on future land use. Treatment plants‐ nuisance, atmospheric 



5 1 Low 

Physical presence Installation vessels Presence of installation vessels. Shipping and commercial fishing vessels are prohibited from 

entering the safety zones around installation vessels. 


5 1 Low 


Use of chemicals will be kept to a 

minimum & will be of as low a 

hazard quotient as practicable. 

Discharge of fluids, if required, 

will be carried out in a manner 

which will minimise 

environmental impact. 

All chemicals will be risk assessed 

as part of Offshore Chemical 

Regulations requirements and 

reported in PON 15C. 

Use of chemicals will be kept to a 

minimum & will be of as low a 

hazard quotient as practicable 

Discharge of fluids, if required, 

will be carried out in a manner 

which will minimise 

environmental impact 

Wastes will be minimised by use 

of appropriate procurement 

controls. 

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 vessel presence 

and vessel movements 


Rapid dispersion and 

dilution will occur in close 

proximity to the discharge 

point. Low impact. 

Water based hydraulic 

fluid that has will rapidly l 

disperse in close 

proximity to the discharge 

point. Low impact. 

Contribute to pressures 

on land based waste 

disposal. Balloch 

associated wastes 

predicted to have a Low 

impact. 

Only a temporary physical 

obstruction to other sea 

users. 

Low impact.



Noise Noise from 

installation. 


event 

Infrastructure All infield subsea infrastructure Mattresses may cause smothering of benthos and alter the 

habitat type, thus affecting communities in the area. 

Potential impacts to fishing activities. 

Surface & subsea noise 

produced during operations, of 

which piling of the cooling 

spool is likely to be the 

dominant sound 



damage 


oil spills 








sea 


5 1 Low 

Generates elevated sound levels which can affect the 

behaviour of fish and marine mammals in the area. 


5 3 Moderate 


chemical or biochemical oxygen demand, toxicity, persistence, 

bioaccumulation in animals 


2 2 Low 




2 1 Low 

Minimisation of foot‐ print 

through design. 

Optimisation of pipeline route. 

Impact area is expected to rapidly 

restore/ recolonise. 

JNCC piling protocol followed. 




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. 


decanting operations. Storage 

tanks and hoses are subject to an 

inspection and engineering 




Response Process. 

Temporal physical 

disturbance effect on 

local benthic communities 

recovery expected with 

time. Hard structures will 

act as attract different 

species. Low impact. 

Short term impact upon 

sensitive species, no 

impacts beyond the 

installation activities . 

Low impact. 

None envisaged. 


B ‐ 7

Production Phase 


Aspect 

Source 

Emissions to air Flaring of Balloch 

reservoir fluids 

B ‐ 8 




Activity 

Description 

Flaring occurs during 

emergencies and blowdowns. 

No increase in flaring is 

anticipated with the additional 

production on the GPIII FPSO 

Venting Increased venting required as 

Balloch will result in increased 

production and frequency of 

tanker offloading. The exhaust 

gases are diverted into the fuel 

tanks prior to loading with oil. 








2 1 Low 


Flaring may contribute to climate change (CH4, CO2), 

acidification effects (SOx, NOx) and potential localised smog 

formation (VOC, NOx and particulates). 


2 1 Low 

Releases greenhouse gases into the environment, these gases 

were derived from combustion gases (CO2). Venting gases 

contribute to greenhouse warming. 


4 1 Low 


Trained deck operations 

personnel. Diesel storage tanks 

and transfer hoses are subject to 



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. 



Rapid dispersion and reduction to 

background levels. 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. 

Engines are maintained properly 

to ensure optimal fuel 

combustion for venting gases and 

minimise release of gases with a 

high global warming potential 

such as methane. 


None envisaged diesel 

should rapidly evaporate 

and disperse, diesel 

evaporates contribute are 

a form of greenhouse 

gases. 


concern 

None envisaged as 

contribution of emissions 

to worldwide levels is 

negligible when 

compared to other 

industrial sources. 

Increase global 

greenhouse emissions. 

Low impact.



Discharges to Sea Produced Water 

Discharge 

Power requirement Balloch will result in a 

maximum increase in power 

demand of approximately 30%. 

However, existing spare 

capacity will be utilised. 

Therefore, no new power 

generation equipment will be 

installed. 

Produced water is treated to 

reduce discharge of oil in 

water comprising condensed 

and formation water. 

It is planned for produced 

water to only be released 

when produced water 

injection facilities are not 

operational. 

Produced Sand Discharge of small quantities 

of produced sand. 


effects (SOx, NOx) and potential localised smog formation 

(VOC, NOx). 


5 1 Low 

Detrimental impact on water quality and marine flora and 

fauna, potential local toxic effects of dissolved chemicals and 

substances entrained within produced water. 


5 2 Moderate 

Rapid dispersion and reduction to 


Fuel gas system is subject to an 



Compliance with EUETS 

requirements. 

Average discharge of oil per 

annum is low. PW is treated by 

desanding and de‐oiling 

hydrocyclone packages to remove 

solids down to 5 microns and oil 

to 30mg/l. 

Rapid dilution at the platform 

given the water depth and 

prevailing currents. Any effect on 

water quality will be confined to 

the immediate vicinity of the 

discharge point, with levels of 

contaminants rapidly returning to 


PW treatment system is subject 

to an inspection & engineering 


Water quality impact & impact on marine flora and fauna. Follow procedures in place for 

disposal of small quantities of 

Likelihood Consequence Risk sand. 

4 1 Low 

Increase global 

greenhouse emissions. 

Low impact. 

Majority of produced 

water will be reinjected. 

Volume of balloch 

produced water and 

associated oil in water 

are relatively minor. Low 

residual impact. 


B ‐ 9

B ‐ 10 

Drainage water Discharge of oily drainage 

water to sea. Open drains 

collect spills & drainage from 

all hazardous and non‐ 

hazardous areas of the FPSO. 

These drains feed into the 

drainage caisson which 

provides oil & water 

separation. 

No increase in drainage water 

is expected as a result of the 

production covered in this ES. 

Chemical discharges Discharge of chemicals. 

There will be a increase in 

chemical use associated with 

the Balloch development, this 

will not result in any increases 

in chemical discharges at the 

FPSO as chemicals will be 

transported entrained within 

reservoir hydrocarbons. 

Cooling water Seawater is utilised to cool the 

cooling medium (70% water 

and 30% TEG) and used to cool 

the heat exchangers. This 

result sin an increase in the 

temperature of the seawater 

returned and small amounts of 

glycol are released into the 

sea. 

Oil in water can result in narcotic, toxic, teratogenic impacts 

and enrichment etc. 


5 1 Low 


chemical or biochemical oxygen demand, toxicity, 

persistence, bioaccumulation in animals. 


5 1 Low 

High concentrations of glycol are toxic to marine life, elevated 

water temperatures may be intolerable to marine life not 

observable increase in water column temperature beyond 

immediate zone of discharge. 


5 1 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. Given the prevailing 

current speeds, dilution will be 

rapid with no perceptible effect 

on water quality with the except‐ 

ion of the immediate vicinity of 

the discharge. 

Maersk 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. 

No new equipment required on 

the GPIII therefore no changes to 

cooling demand or volume of 

water discharged. 



Low impact. 

Negligible impact.



Waste Liquid Waste 

(domestic sewage 

and food waste). 

Discharge of sewage (grey & 

black water macerated to 

Physical presence Oil and gas 

infrastructure 

B ‐ 12 

General waste Onshore disposal of solid 

waste e.g. bin bags, scrap 

metal, plastics etc. 

Physical presence of subsea 

infrastructure e.g. pipeline, 

well, etc. Apart from minor 

topside modifications the 

surface infrastructure will not 

change as a result of the 

development 


the nature of the site or process. Landfills ‐ land take, 


on future land use. Treatment plants ‐ nuisance, atmospheric 



5 1 Low 

May conflict with other users e.g. fishing, shipping. Attraction 

of birds and fish shoals to the structure. Biofouling of 

structure. 


5 1 Low 


Maersk has a Company Policy to 

minimise waste. Optimisation of 

quantities of materials ordered. 

Waste segregated by personnel at 

source of generation and 

manually handled to the 

appropriate labelled waste 

receptacle until transferred 

ashore for disposal. Waste 

Management Procedure is 

implemented. Monthly reporting 

of waste returned to shore. 

Recycling and reuse of wastes as 

defined by the Waste 

Management Procedure. 

Physical presence of subsea 

infrastructure minimised through 

design. 

500m exclusion zone around the 

FPSO to mitigate against collision 

& hence prevent damage to 

vessels and the FPSO platform. 

The location is marked on charts. 

Loss of small area (500m radius 

around the FPSO) compared to 

available fishing area. Protective 

structures on pipeline etc. to 

prevent interaction with fishing 

gear. 



Balloch development will 

not generate significant 

volumes of general 

waste. 

Negligible impact.




events 



damage 


oil spills 








sea 





chemical or biochemical oxygen demand, toxicity, 

persistence, bioaccumulation in animals 


1 2 Low 




2 2 Low 








2 1 Low 




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. 

Contaminated chemical spill kits 

are generally disposed of 

onshore. 


decanting operations. Storage 

tanks and hoses are subject to an 


maintenance strategy. Oil Spill 

Contingency Plan is implemented 

in the event of a spill as per 

Emergency Response Process. Oil 

spill modelling completed as an 

integral part of the OPEP, this 

indicates that there would be no 

shoreline impact. 

Trained deck operations 

personnel. Diesel storage tanks 

and transfer hoses are subject to 



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 

evaporate and disperse, 

diesel evaporates 

contribute are a form of 

greenhouse gases. 

B ‐ 13

Major accidental 

events 

Other environmental 

aspects 

B ‐ 14 

Oil spills Loss of hydrocarbon 

containment. 

Produced water spills Accidental discharge of 

produced water above 

regulatory limits of 30mg/l. 

Failure of flow‐ 

lines/loss of well 

control /fire 

explosion / loss of 

FPSO/ rupture in 

offloading line 

Consumption of 

materials 

Loss of platform, process plant 

or well control resulting in 

release of gas and condensate 

which may be ignited. 

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 infrastructure. 

Impact dependent on spill volume and weather conditions. 






2 2 Low 

Oil in water can result in narcotic, toxic, teratogenic impacts 

and enrichment etc. 


3 2 Low 

Atmospheric emissions contribute to global warming, acid 

deposition and ozone depletion. Damage to commercial 

fisheries. Sediment and water quality impairment. Potential 

discharge of hydrocarbons and various chemicals and gases 

into the environment. Fire‐fighting system comprises of CO2, 

water and foam (no halons released). Physical disturbance to 

other sea users. 


1 4 Moderate 


Procedures in OPEP are 


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. 

Procedures in the OPEP are 


Inspection &engineering 

maintenance strategy based on 

preventative maintenance. 

Dispersant on board standby 

vessel available for local 

response. Maersk has 

membership 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. 

Snap locks on transfer lines 

Use of non‐renewable resources. Maersk has an expectation to 

recognise the limitations of 


resource availability. Company 

Policy to minimise waste. This 

1 2 Low 

includes reducing the quantity of 

materials used. 


Low impact. 





and toxic effects and 

socio‐economic impacts 

to fishing, and tourism. 




levels. 

Materials used on the 

platform indirectly 

impact natural resources. 

Low impact.


Appendix C HSSE Policy 

C‐1

Environmental Statement - Maersk Oil

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