Breagh Development - RWE.com

Breagh Development 

Phase I 

Environmental Statement 

June 2010

Standard Information Sheet 

Breagh Environmental Statement 

Non Technical Summary 

Project name Environmental Statement for the Breagh Development 

Development Location Block 42/13 

Licence No. P1230 

Project reference number D/4037/2008 

Type of project Field development 

Undertaker RWE Dea UK SNS Ltd. 

4th Floor 

90 High Holborn 

London 

WC1V 6LJ 

Licensees/owners RWE Dea UK SNS Ltd. (70%) 

Sterling Resources Limited (30%) 

Short Description The Breagh field is a gas field located in UKCS block 42/13 of the 

Southern North Sea (SNS). It lies 50km to the north east of the UK 

coast and 200km to the west of the median line between the UK 

and Dutch sectors. RDUK intends to develop the Breagh field by 

installing one Normally Unmanned Installation (NUI) over the 

Breagh Field, drilling 7 wells and laying c. 100km of pipeline 

between the Breagh Field and Teesside to transport hydrocarbons 

to the UK. The Breagh NUI will be based on the standard SNS 

design. Breagh gas will be metered on the Breagh NUI before being 

exported to the Teesside Gas Processing Plant for processing. 

Key dates NUI installation: Q3 & Q4 2011 

Pipeline installation: Q1 – Q3 2011 and Q2 2012 

First gas: Q2 2012 

Significant environmental None identified 

effects identified 

Statement Prepared by Genesis Oil and Gas Consultants Limited 

6 Albyn Place 

Aberdeen 

AB10 1YH 

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[This Page is Intentionally Blank]




The undeveloped Breagh gas field is located in block 42/13, to the North of the UK Southern 

North Sea (Figure 1). It lies 50km to the north east of the UK coast and 200km to the west of 

the median line between the UK and Dutch sectors in approximately 61m of water. 

The Phase I development of the Breagh Field is expected to result in the recovery of 15.4 

BNm 3 of gas. The field development will start at the beginning of 2011 with a production 

start planned for Q2 2012. The Phase I project will yield an average yearly gas production 

stream of approximately 530 NMm 3 /year for the period of production from 2012-2040 

including onshore compression start up in 2016. Development of the Breagh field will entail 

the construction of a production hub through which gas from the surrounding fields and 

prospects is likely to be exported The Phase 1 development will consist of: 

• Normally Unmanned Installation (NUI) at West Breagh 

• Seven wells drilled 

• 100km 20” pipeline back to a beach crossing at Coatham Sands 

• 9km of onshore pipeline to, and modifications of, the Teesside Gas Processing Plant 

(TGPP) before delivery of gas into the National Transmission System (NTS) 

This Environmental Statement (ES) assesses all offshore surface and sub sea structures, the 

drilling of the wells and the pipeline from Mean Low Water Springs (MLWS) to the offshore 

installation. 

Figure 1: Breagh Field Location and Proposed Pipeline Route 

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Scope 

The scope of the Environmental Impact Assessment (EIA) and this resultant ES includes all 

offshore activities associated with the development of the Breagh field including drilling 

activity. The proposed scope of the development is the completion of the Breagh wells, the 

installation of the Breagh A NUI, installation of approximately 100 km of 20” production 

pipeline and 100 km of 3” MEG pipeline and Fibre Optic cable between the Breagh field and 

MLWS at Teesside, testing and commissioning of the facilities and production of gas and 

condensate. A separate environmental statement has been submitted for onshore planning 

application (Figure 2, below). 

Figure 2: Environmental Statement Demarcation 

Summary of Onshore Environmental Statement 

The EIA conducted for the onshore ES concludes: 

• The majority of the chosen pipeline route will be situated within the ‘Development 

Limits’, coincidental to established industrial areas, therefore will minimise 

environmental impact; 

• The proposed development is feasible with little or no adverse effects on land and 

water quality, both during construction and operation; 

• A range of mitigation measures is proposed to minimise dust generation and 

emissions to air from construction traffic, and the adoption of these mitigation 

measures will ensure that there are no significant impacts as a result of emissions 

during construction. 

• No effects on features of cultural or archaeological heritage are expected during 

construction of the pipeline or works 

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• No significant impacts on protected mammals or fauna are predicted, and no 

significant impacts on birds are predicted. 

• The proposed pipeline route is predominantly located within an established 

industrial area therefore it is not predicted to result in any noise impacts to 

residential receptors. 

Environmental Management and Mitigation 

RWE Dea UK SNS Ltd. (hereafter referred to as RDUK) is the Licensed Operator for the 

Breagh field. RDUK is fully committed to conducting its activities in accordance with all 

applicable legislation and operates a Health, Safety & Environmental Management System 

(HS&EMS). The system provides the framework for managing HS&E issues within the 

business to ensure compliance with company policy. The HS&EMS was assessed in August 

2008 by an accredited third party certification body, Lloyd's Register Quality Assurance 

(LRQA) and verified as meeting Environmental Management System (EMS) requirements set 

out in the OSPAR Recommendation and Department of Environment and Climate Change 

(DECC) Guidance. This verification is to be repeated every 2 years and is scheduled to be re 

verified during August 2010 as part of the biennial cycle. 

The proposed development is not expected to have a significant impact on the environment. 

Notwithstanding this, there are a number of associated mitigation measures listed in section 

5 of this ES that will ensure environmental impacts are minimised wherever possible. The 

commitments made within the ES will be tracked to completion by the RDUK Environmental 

Team. 

The HSE policy is outlined in Appendix D. 

Development Concept 

RDUK’s proposal for the development of the Breagh Field will enable the economic recovery 

and export of gas. The NUI will be installed over the exploration wells and the exploration 

wells completed and hooked up to manifolds on the NUI platform. From here the gas will be 

transported to the TGPP through a 20” production pipeline. The controls and chemicals for 

the Breagh development will be supplied from shore. It is proposed to provide MEG mixed 

with corrosion inhibitor via a separate 3” line laid adjacent to the gas export pipeline. 

Environmental and Socioeconomic Development 

The flora and fauna in the area of the proposed development are typical of those found over 

wide areas of the Southern North Sea. During the consultation phase of the EIA, discussions 

were held with DECC, the Joint Nature Conservation Committee (JNCC), Natural England 

(NE), Marine Management Organisation (MMO), National Federation of Fisherman’s 

Organisation (NFFO) and Centre for Environment, Fisheries and Aquaculture Science 

(CEFAS), North Eastern Sea Fisheries Committee (NESFC) and no major issues were raised. 

The development area lies within the vicinity of spawning and/or nursery grounds for Cod, 

Herring, Lemon Sole, Mackerel, Sprat, Sandeel, Plaice, Haddock, Nephrops and Whiting. 

Spawning for these species takes place over large areas of the North Sea, and as such, they 

are unlikely to be significantly affected by the development. 

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Marine and Fisheries Agency 1 

data (Marine and Fisheries Agency, 2008) shows that the 

fishing effort within both the development area and the pipeline route is relatively low. 

Fishing effort is directed predominantly at demersal species within the development area 

while demersal and crustaceans are targeted along the pipeline route. 

The Breagh A NUI location does not lie within an important area for sea-birds. However, 

migrant species are known to pass through the development area and migrant and 

wintering wildfowl are dispersed within the vicinity of the development. The highest seabird 

vulnerability in block 42/13 occurs during January and February and September through to 

November (Very High). 

Low densities of cetaceans have been recorded in the area (Reid et. al., 2003). Sightings 

suggest that the harbour porpoise is the most frequently recorded cetacean, with low 

numbers occurring throughout the year. Low numbers of minke whales have been sighted 

in the summer months and white beaked dolphin during the winter and spring. 

This area of the Southern North Sea is of low to moderate commercial fishing value in 

comparison to other areas of the North Sea. 

Otters are unlikely to be sighted within the development area given the distance of the 

Breagh field from shore and the low number of otter ranges along the coastline adjacent to 

the Breagh field. 

Common and grey seal breeding colonies are present on the coastline adjacent to the 

development. Given the feeding patterns of common and grey seals and the fact that the 

Breagh field lies 50 km from shore it is unlikely that common seals will be sighted at the 

development site while grey seals may be sighted occasionally. 

The Petroleum (Conservation of Habitats) Regulations 2001 and amendments 2007 

implement the requirements of the Habitats Directive for oil and gas developments and 

extend the protection of marine habitats and species beyond the 12 nautical mile zone to all 

oil and gas developments either partly or wholly on the UKCS. These sites are referred to as 

Special Areas of Conservation (SAC). At the moment there are thirteen 

candidate/draft/possible SACs on the UKCS. New projects/developments must demonstrate 

that they will not significantly disturb a European protected habitat or species in a way that 

will affect: 

• The ability of the species to survive, to breed or rear or nurture their young 

• The local distribution or abundance of any protected species 

either alone or in combination with other plans and projects. 

Of the thirteen candidate/draft/possible SACs, only one is located within 40 km of the 

development; The Dogger Bank dSAC, which at its nearest is 34 km from the Breagh 

development well and export pipeline. This feature contains Annex I habitat: 

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• Sandbanks which are slightly covered by seawater at all times 

1 

The Marine and Fisheries Agency merged with a number of other bodies to form the Marine 

Management Organisation (MMO) on the 1 st April 2010.



Due to the proximity of this site benthic sampling has been conducted throughout the 

development area. The area was found to be typical of the SNS. No other Annex I seabed 

features were identified within the area which will be impacted upon by the development. 

The Saturn Reef and North Norfolk Bank pSACs are located to the South East of the Breagh 

Field. A number of designated areas are located on the English coast within the vicinity of 

the development area and/or the pipeline approach to landfall including: Teesmouth and 

Cleveland Coast Ramsar Site and SPA; Flamborough Head SAC and SPA; Humber Flats, 

Marshes & Coast Phase 1 Ramsar Site and Humber Estuary SPA. 

The impact assessment has not identified any significant impact. The main impact upon 

these sites results from the presence of the pipeline installation vessels. The installation 

vessels will only be present for a short period of time and the waterfoul resident at 

Teesmouth and Cleveland Coast Ramsar Site and SPA are already subject to considerable 

interaction with shipping vessels in the area. Flamborough Head SAC and SPA and Humber 

Flats Marshes and Coast Phase 1 Ramsar Site and Humber Estuary are located at least 40 km 

and 95 km respectively from any part of the development respectively and are therefore 

unlikely to be impacted upon by the development. 

The development area is considered to be typical of the Southern North Sea offshore 

environment and there are no biological or other features identified that are thought to be 

particularly sensitive to the type of activities being undertaken. 

The full results from the EIA identified no ‘high’ risks; however a number of ‘moderate’ risks 

requiring additional assessment were identified. Further assessment of these, and planned 

mitigation measures, demonstrated no remaining moderate risks. 

Teesside Offshore Windfarm 

Northern Offshore Energy Ltd., which is part of the EDF group, was granted permission to 

construct and operate a 30 turbine windfarm at Redcar, Teesside. The site lies within a 

10km 2 trapezoidal box located 1.5km offshore from Coatham Sands, Redcar and Cleveland. 

The turbines will be constructed in 3 rows of 10 turbines. The spacing between the rows will 

be 600m with the spacing between turbines within each row approximately 300m. The tip 

height of the windturbines will be in the range of 110m to 132m. 

The windfarm will be connected to shore by three underground cables which will be laid in a 

single trench. The cables will come ashore through the dunes of South Gare before linking 

to a sub-station in Warrenby. Figure 3 below shows the proposed windfarm and associated 

infrastructure within the landfall of the Breagh pipeline. 

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Figure 3 Teesside Offshore Windfarm, CATS Pipeline and Proposed Pipeline Route (South) 

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Pipelaying activities for the Breagh development will take place to the south of windfarm 

during Q1 to Q3 2011 and Q2 of 2012, and will take place in a controlled construction 

corridor. In consideration of the works undertaken as part of the Teesside Offshore 

Windfarm and the infrastructure present in the area, the presence of the 20” production 

pipeline and 3” MEG pipeline do not represent a significant cumulative impact. 

Summary of Environmental Effects 

The EIA process used a standard, structured approach for the identification of environmental 

hazards. This involved breaking down the development option into individual phases (e.g. 

subsea installation and production) and key activities. For each key activity the 

environmental aspect was identified and the potential effects identified and quantified. 

Potential effects were assessed both in terms if their likelihood (how often they occur) and 

their significance (their magnitude). 

The full results from the EIA have been assessed within the ES identified no ‘high’ risks, 

however a number of ‘moderate’ risks requiring additional assessment were identified. 

Further assessment of these, and planned mitigation measures, demonstrated no remaining 

moderate risks. Table 1, below, displays issues identified as requiring further assessment as 

detailed in Appendix B, and addressed within section 5. 

Table 1: Issues identified as requiring further assessment 

Phase / Issue Aspect / Source 

Surface Installation Exhaust emissions from NUI installation vessels 

Phase 

Physical presence of HLV anchors 

Noise associated with piling activities 

Accidental events 

Drilling Phase Atmospheric emissions from drilling operations 

Discharge of WBM 

Physical presence of the drill rig on seabed 

Noise associated with drilling activities 


Subsea Installation Exhaust emissions from subsea installation and commissioning 

and Commissioning vessels 

Phase 

Discharge of hydrotest fluids 

Physical presence of pipelay vessel anchors 

Physical presence of 20” production pipeline 

Physical presence of trenching and associated deposits 

Physical presence of rockdump and mattresses 

Noise associated with subsea installation and commissioning vessels 


Production Phase Physical presence of the NUI 


Wider Development Noise 

Concerns 

Protected species 

Transboundary impacts 

Cumulative impacts 

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Main Conclusions 

The proposed development will not result in any significant long-term environmental, 

cumulative or transboundary effects. The identified discharges and emissions will be 

minimised by the mitigation measures in place and are likely to be dispersed rapidly in the 

immediate environment. 

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Glossary 



Acute Of Short duration 

Annulus The ring shaped cavity between 2 concentric tubes, e.g. inner and outer 

strings of casing, or between casing, or drill pipe, and the well borehole. 

Appraisal well A well drilled to confirm the size or quality of a hydrocarbon discovery. 

Before development, a discovery is likely to require at least 2 or 3 of such 

wells. 

Barite A very heavy substance used as a main component of drilling mud to 

increase its density and counter balance down-hole pressures. 

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. 

Biocide A chemical toxic or lethal to living organisms. 

Biogenic Produced by the action of living organisms 

Biomagnify Increase in toxicity within a species 

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

companies for exploration and production rights. A UK block is 

approximately 200 – 250km 2 . 

Casing Steel lining used to prevent caving of the sides of a well, to exclude 

unwanted fluids and to provide a means to control well pressures and oil 

and gas production. 

Cetacean Aquatic animals comprising porpoises, dolphins and whales. 

Choke An aperture restricting flow in a well or flowline. 

Christmas Tree An assembly of isolation valves, chokes and gauges installed at the top of 

a well to control the flow of oil and gas once a well has been completed. 

Condensate Light hydrocarbon fractions produced with natural gas which condense 

into liquid at normal temperatures and pressures associated with surface 

production equipment. 

Cuttings pile Pile of primarily rock chips deposited on the seabed as a result of drilling 

activities. 

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 for use in one. 

Dynamic Positioning Use of thrusters to maintain a vessels’ position without the use of 

anchors. 

Environmental aspect An activity that causes an environmental effect. 

Environmental effect Any change to the environment or its use. 

Flagellae A long projection from a unicellular or multicellular body that aids the 

movement of the organism. 

Flowline Pipe through which produced fluids travel 

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

carbon dioxide and methane. 

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

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

atmosphere. 

Infauna Benthic organisms that live within the sediment. 

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

ISO 14001 International management system standard. 

Macrofauna Larger bethic organisms. 

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

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

collected into one. 

Meiofauna Benthic organisms sized between 50µm and 1mm. 

Microfauna Benthic organisms sized less than 50µm. 

Oxygen scavenger Chemical used to remove oxygen. 

Pelagic Organisms inhabiting the water column of the sea. 

Phytoplankton Free floating microscopic plants. 

Pig Piece of equipment inserted into a pipeline and carried along by the flow 

of oil and gas to clean or monitor the internal condition of the pipeline. 

Ramsar The Convention of Wetlands of International Importance especially as 

Waterfowl Habitat. 

Riser A pipe which connects a rig or platform to a subsea wellhead or pipeline 

during drilling or production operations. 

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

equipment. 

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

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

reservoir from an existing wellbore. 

Special Area of 

Conservation 

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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. 

Sublittoral Below the level of low tide. 

Thermocline Pronounced temperature incline. 

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

production by fitting a wellhead. 

Zooplankton Free floating microscopic animals. 

Acronyms 

ALARP As Low as Reasonably Practicable 

API The standard unit adopted for measuring the density of a liquid, 

(especially hydrocarbons) expressed in degrees. 

Bbl Barrels 

bcf Billion Cubic Feet 

BERR Department for Business Enterprise and Regulatory Reform 

BOP Blow Out Preventor 

BP British Petroleum 

Bpd Barrels Per Day 

Bscm Billion Standard Cubic Metres 

C Carbon 

°C Degrees Celsius 

CATS Central Area Transmissions System 

CCLS Combined Control and Safety System



CEFAS Centre for Environment Fisheries and Aquaculture Science 

CGR Condensate Gas Ratio 

CHARM Chemical Hazard and Risk Management 

CITHP Closed In Tubing Head Pressure 

CMACS Centre for Marine and Coastal Studies 

Cm/s Centimetre per second 

CO2 

Carbon Dioxide 

COPA Crude Oil Pipeline Agreement 

COWRIE Collaborative Offshore Wind Research Into The Environment 

CPA Closest Possible Approach 

CRA Corrosion Resistant Alloy 

cSAC Candidate Special Area of Conservation 

dB Decibels 

DECC Department of Energy and Climate Change 

DEME Dredging, Environmental and Marine Engineering 

dSAC Draft Special Area of Conservation 

DP Dynamic Positioning 

DSV Dive Support Vessel 

DTI Department of Trade and Industry 

E East 

EAC Ecological Assessment Criteria 

EC European Commission 

EDF EDF Energy (Northern Offshore Wind) Ltd 

EEC European Economic Community 

EEMS Environmental Emissions Monitoring System 

EIA Environmental Impact Assessment 

EMS Environmental Management System 

ENV Environmental station 

ES Environmental Statement 

ETS Emissions Trading Scheme 

EU European Union 

°F Degrees Fahrenheit 

FO Fibre Optic 

FRS Fisheries Research Services 

ft Feet 

FWHP Flowing Well Head Pressure 

FWHT Flowing Well Head Temperature 

GBS Gravity Based Structure 

GDT Gas down to 

HAB Harmful Algal Blooms 

HIPPS High Integrity Pressure Protection System 

HLV Heavy Lift Vessel 

HP High Pressure 

hr Hour 

HSE Health Safety & Environmental (Management System) 

HQ Hazard Quotient 

H2S Hydrogen Sulphide 

ICES International Council for the Exploration of the Sea 

INCA Industry Nature Conservation Association 

IPPC Integrated Pollution Prevention and Control 

ISO International Standards Organisation 

IUCN International Union for the Conservation of Nature 

JNCC Joint Nature Conservation Committee 

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Juv Juvenile 

km Kilometres 

KP Kilometre Point 

kw Kilowatt 

l Litre 

LAT Lowest Astronomical Tide 

LTOBM Low Toxic Oil Based Mud 

LP Low Pressure 

LSA Low Specific Activity 

Ltd Limited 

LWMS Low Water Mean Spring [Tide] 

m metres 

MAOP Maximum Allowable Operating Pressure 

MARPOL International Convention for the Prevention of Marine Pollution from 

Ships 

MEG Monoethylene Glycol 

MeOH Methanol 

MESH Mapping European Seabed Habitats 

MLWS Mean Low Water Springs (Tide) 

mm Millimetre 

MMO Marine Mammal Observer 

m/s Metres per second 

MMscf Million Standard Cubic Feet 

MMscf/d Million Standard Cubic Feet per Day 

MoD Ministry of Defence 

Msm 3 Million Standard Metres Cubed 

MW Megawatt 

N Nitrogen 

NFFO National Federation of Fishermen’s Organisations 

ng Nanograms 

Nm Nautical Mile 

NMm 3 Normal Metres Cubed 

NNW North Northwest 

NTS National Transmission System 

NUI Normally Unmanned Installation 

OBM Oil Based Mud 

OCNS Offshore Chemical Notification Scheme 

OD Outside Diameter 

OPPC Oil Pollution Prevention and Control 

OSIRIS Osiris Hydrographic & Geophysical Projects Ltd 

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

East Atlantic 

OVI Oil Vulnerability Index 

PAH Polycyclic Aromatic Hydrocarbon 

PCB Polychlorobiphenyls 

PLONOR Poses Little Or No Risk to the environment 

PON Petroleum Operations Notice 

PPC Pollution Prevention and Control 

ppm Parts Per Million 

psi Pounds per Square Inch 

Psia Pounds per Square Inch Absolute 

pSAC Possible Special Area of Conservation 

PVT Pressure Volume Transducer 

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RAMSAR RAMSAR Convention on Wetlands 

ROV Remote operated Vehicle 

RQ Risk Quotient 

SAC Special Area of Conservation 

S Seconds 

SCANS Small Cetacean Abundance in the North Sea 

scf/hr Standard Cubic Feet per Hour 

SEA Strategic Environmental Assessment 

SG Specific Gravity 

SIMOPS Simultaneous Drilling and Production 

SIWHP Shut In Well Head Pressure 

Sm 3 /d Standard Meters Cubed per day 

SNS Southern North Sea 

SPA Special Protection Area 

Spp Species 

SOPEP Ship Oil Pollution Emergency Plan 

t Tonnes 

t/d Tonnes per day 

TGPP Teesside Gas Processing Plant 

THC Total Hydrocarbon Content 

TOC Total Organic Carbon 

TOM Total Organic Matter 

TVD True Vertical Depth 

TVDSS True Vertical Depth Subsea 

µg micrograms 

UK United Kingdom 

UKCS United Kingdom Continental Shelf 

UKOOA United Kingdom Offshore Operators Association 

UPS Uninterrupted Power Supply 

UTM Universal transverse Mercator 

V Vaults 

VHF Very High Frequency 

VOC Volatile Organic Compound 

WBM Water Based Mud 

WHSIP Well Head Shut In Pressure 

WUP Water up to 



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Table of Contents 

Standard Information Sheet .............................................................................................. i 

Non Technical Summary .................................................................................................. iii 

Scope ..................................................................................................................................... iv 

Summary of Onshore Environmental Statement .................................................................. iv 

Environmental Management and Mitigation ........................................................................ v 

Development Concept ............................................................................................................ v 

Environmental and Socioeconomic Development ................................................................. v 

Teesside Offshore Windfarm ................................................................................................ vii 

Environmental Effects ........................................................................................................... ix 

Main Conclusions.................................................................................................................... x 

Glossary.......................................................................................................................... xi 

Acronyms ...................................................................................................................... xii 

Introduction ................................................................................................................. 1-1 

Aim of the Project ............................................................................................................... 1-2 

Purpose of the Environmental Statement .......................................................................... 1-2 

Requirement for an Environmental Statement .................................................................. 1-2 

Scope of the Environmental Statement ............................................................................. 1-3 

Legislative Overview ........................................................................................................... 1-3 

Environmental Management .............................................................................................. 1-6 

Areas of Uncertainty ........................................................................................................... 1-6 

Consultation Process .......................................................................................................... 1-7 

Proposed Development ................................................................................................. 2-1 

Introduction ........................................................................................................................ 2-1 

Nature of the Reservoir ...................................................................................................... 2-2 

Development Options ........................................................................................................ 2-4 

Schedule of Activities ......................................................................................................... 2-7 

Breagh Alpha NUI Design .................................................................................................... 2-8 

Subsea Design ................................................................................................................... 2-13 

Drilling............................................................................................................................... 2-20 

Production ........................................................................................................................ 2-29 

Environmental Performance ............................................................................................ 2-31 

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Permitting ......................................................................................................................... 2-32 

Decommissioning ............................................................................................................. 2-34 

Teesside Gas Processing Plant .......................................................................................... 2-37 

Baseline Environment ................................................................................................... 3-1 

Physical Environment ......................................................................................................... 3-3 

Biological Environment ..................................................................................................... 3-16 

Socio-Economic Environment ........................................................................................... 3-49 

Overview ........................................................................................................................... 3-60 

Environmental Assessment Methodology ...................................................................... 4-1 

Likelihood ........................................................................................................................... 4-1 

Consequence ...................................................................................................................... 4-1 

Combining Likelihood and Consequence to Establish Risk ................................................ 4-2 

Assessment of Potential Impacts and Control Measures ................................................. 5-1 

Surface Installation Phase .................................................................................................. 5-2 

Drilling................................................................................................................................. 5-5 

Subsea Installation and Commissioning ........................................................................... 5-10 

Production ........................................................................................................................ 5-17 

Wider Development Concerns ......................................................................................... 5-18 

Conclusions .................................................................................................................. 6-1 

Environmental Effects ........................................................................................................ 6-1 

Minimising the Environmental Impact ............................................................................... 6-1 

Overall Conclusion .............................................................................................................. 6-3 

References .................................................................................................................... 7-1 

Appendix A Register of Environmental Legislation ......................................................... A-1 

Appendix B Environmental Assessment ........................................................................ B-1 

Appendix C Chemical Register ....................................................................................... C-1 

Appendix D Environmental Management System .......................................................... D-1 

Appendix E Survey Data ................................................................................................ E-1 

Appendix F Oil Spill Modelling ....................................................................................... F-1 

Appendix G Drawings ................................................................................................... G-1 

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1. Introduction 


Section 1 - Introduction 

The Breagh gas field is located in Block 42/13 of the northern reaches of the UK Southern 

North Sea (SNS) (Figure 1-1). It lies 50 km to the north east of the UK coast and 200 km to 

the west of the median line between the UK and Dutch sectors in approximately 62 m of 

water. Block 42/13 is owned by RWE Dea SNS Limited (RDUK) (70%) and Sterling Resources 

(UK) Limited (30%). 

Figure 1 - 1 Breagh Field 

The Breagh field development concept comprises the installation of up to two Normally 

Unattended Installations. A first NUI, Breagh A, will be installed on the west side of the field 

(West Breagh) in Phase 1. In Phase 2 a second NUI, Breagh B, will be installed on the east 

side of the field. 

The scope of this ES is limited to Phase 1 activities. The activities associated with Phase 2 

will depend on the success of Phase 1 and will be the subject of a future submission. 

1-1



1.1. Aim of the Project 

The purpose of the project is to develop the Breagh field in order to deliver hydrocarbons to 

the UK and to install a gas export route from Block 42/13 to the Teesside Gas Processing 

Plant (TGPP) for future developments. 

1.2. Purpose of the 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 RDUK’s project 

requirements. 

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

(Assessment of Environmental Effects) (Amendment) Regulations 2007. 

The ES reports on the conclusions from the EIA, which investigated and evaluated routine 

and non-routine environmental impacts associated with the development, specifically: 

atmospheric emissions, physical presence of installation vessels, impacts of drilling and 

testing the new wells and installation of the export pipeline. The presence of permanent 

new subsea infrastructure and the fate of potential hydrocarbon spills from all stages of the 

project were also included. 

1.3. Requirement for an Environmental Statement 

The ES documents the results from the Environmental Impact Assessment (EIA) of the 

proposed project. The EIA was carried out to ensure that the environmental impacts 

associated with the project were identified and their significance assessed, and that 

appropriate mitigation and control measures are implemented. 

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

Amendment) Regulations 2007 requires: 1) evaluation of projects likely to have a significant 

effect on the offshore environment; and 2) formal public consultation on the resulting ES. 

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

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

(Conservation of Habitats) Regulations 2001, SI 2001 No. 1754 and the EU Birds Directive 

79/409/EEC. 

RDUK has an HSEQ-EMS in place which ensures that: 

1. There is an effective management organisation in place to plan operations to 

minimise the impact to the environment by identifying and managing the relevant 

risks. 

2. Environmental issues are considered from the outset when planning operations, to 

reduce waste, the consumption of resources and prevent damage to wildlife 

habitats. 

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1.4. Scope of the Environmental Statement 



The scope of the EIA and this resultant ES includes all activities associated with the Phase 1 

of the offshore development of the Breagh Field up to the landfall at the Mean Low Water 

Springs (MLWS) line. 

The proposed scope of the offshore Phase 1 development is to: 

• Install the Breagh A NUI; 

• Drill 7 target wells (including re-drilling in two existing wells at the platform 

location); 

• Install approximately 100 km of 20” export pipeline, 3” MEG line and fibre optic 

cable between Breagh A and the landfall at Teesside; 

• Test and commission all the facilities; 

• Produce gas and condensate. 

The landfall and terminal impacts are considered under a separate submission as required 

under the Town and Country Planning Act (Figure 1-2). 

Figure 1-2 Environmental Statement Demarcation 

1.5. Legislative Overview 

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

legislation is included in Appendix A of the ES. 

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

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

impact. Strands of both primary and secondary legislation, voluntary agreement, and 

conditions in consents granted under the petroleum licensing regime and international 

conventions have also contributed. 

1-3



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 (Amendment) 

Regulations 2007 and accompanying Guidance Notes for Industry) (DECC, 2009). 

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

(Amendment) Regulations 2007, hereafter referred to as ES 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 to this 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; 

• Where designated archaeological features are present and may be damaged or 

disturbed; 

• Areas which are subject to high seasonal environmental sensitivities and/or within 

herring or sandeel spawning grounds or important fisheries; 

• 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 which have been 

enacted in the UK by the following legislation: 

• Conservation (Natural Habitats, &c.) Regulations 1994 (as amended 1997 and 2000); 

• Conservation (Natural Habitats, &c.) Amendment (Scotland) Regulations 2007; 

• Conservation (Natural Habitats, &c.) (Amendment) Regulations 2007; 

• Offshore Petroleum Activities (Conservation of Habitats) Regulations 2001 and 2007 

amendment; 

• The Offshore Marine Conservation (Natural Habitats &c.) Regulations 2007; 

• The Offshore Marine Conservation (Natural Habitats, &c.) (Amendment) Regulations 

2009; 

• The Conservation of Habitats and Species Regulations 2010. 

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

when their scope was extended to include the offshore with the Offshore Regulations being 

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

developments must demonstrate that they are not “likely to have a significant impact on the 

integrity of the conservation objectives for the protected site” or “significantly disturb 

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

1-4



The disturbance of European protected species has been further defined by the 2009 

Regulations where it is an offence to: 

“Injure or kill an animal” 

“deliberately disturb wild animals of any such species in such a way as to be likely to 

significantly to affect— 

- the ability of animals of that species to survive, breed, or rear or nurture their 

young; or 

- The local distribution or abundance of that species… 

…disturbance of animals includes in particular any disturbance which is likely – 

to impair their ability- 

- to survive, to breed or reproduce, or to rear or nurture their young; 

- in the case of animals of a hibernating or migratory species, to hibernate or 

migrate; or 

- to affect significantly the local distribution or abundance of the species to which 

they belong.” 

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

chemicals (OSPAR Decision 2000/2 on a Harmonised Mandatory Control System for the Use 

and Reduction of the Discharge of Offshore Chemicals). This decision operates in conjunction 

with two OSPAR Recommendations; OSPAR Recommendation 2000/4 on a Harmonised Pre- 

Screening Scheme for Offshore Chemicals; and OSPAR Recommendation 2000/5 on a 

Harmonised Offshore Chemical Notification Format (HOCNF). 

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

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). 

The offshore industry is also operating the European Union Emissions Trading Scheme (EU 

ETS) enacted in the UK via the Greenhouse Gas Emissions Trading Scheme Regulations 2005 

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

(Amendment) Regulations 2007 (Statutory Instrument 2007 No. 465). This scheme is one of 

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

targets for UK industry. 

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

requirements to reduced the permitted average monthly oil in produced water discharge 

concentration to 30mg/l. 

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

produced water from 2006 measured against a 2000 baseline; controlled by the issue of 

permits to each installation. 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. 

1-5



1.6. Environmental Management 

All projects undertaken by RDUK follow the RDUK Health, Safety and Environmental 

Management System (HS&EMS). The system provides the framework for managing HS&E 

issues within the business to ensure compliance with company policy (provided in Appendix 

D) and legislation. Additionally it ensures clear assignment of responsibilities, efficient and 

cost-effective planning and operations, effective management of HS&E risks and continuous 

improvement. The RDUK HS&EMS applies at all levels within the RDUK organisation, 

including all subsidiary companies. 

The HS&EMS is based on the requirements of the Company HS&E Policy Statement. It has 

been developed in accordance with current UK environmental legislation and health & 

safety legislation, including The Health & Safety at Work etc. Act (HSWA) and various 

Regulations made under HSWA. 

The content and structure of the HS&EMS have also been based on: 

• principles in the Health and Safety Executive publication HS(G)65 ‘Successful Health 

and Safety Management’; 

• OHSAS 18001 ‘Occupational Health & Safety Management Systems – Specification’; 

• BS EN ISO 14001 standard for Environmental Management Systems. 

The HS&EMS is not certified for compliance with ISO14001 or OHSAS18001 standards. The 

HS&EMS was, however, assessed in 2008 by an accredited third party certification body 

(LRQA) and verified as meeting EMS requirements set out in the OSPAR Recommendation 

and DECC Guidance. The EMS is scheduled to be re-assessed in August 2010 as part of the 

two year cycle. 

More details on the HS&EMS are included in Appendix D along with a copy of the company 

environmental policy. 

1.7. Areas of Uncertainty 

1. The exact co-ordinates of the well locations of the Breagh field are still to be 

finalised, these will be provided in the subsequent PON15B application; 

2. Production profiles (based on models) have a degree of uncertainty associated with 

them. The profiles contained within the ES are based on the P10 (high) case; 

3. At the time of writing, the contract for pipelaying was still out to tender. As such it 

is possible that a DP pipelay vessel or anchored lay barge may be used to lay the 20” 

production pipeline. In addition the temporary dump sites for sediments excavated 

from the pipeline trenches will not be known until the contract is awarded and a 

method statement defined. 

The assumptions detailed in Table 1-1 were made for the purposes of conducting the EIA 

and preparing this ES. 

1-6



Table 1-1 Uncertainties and Assumptions 

Subject Assumption 

Trenching 

Backhoe and suction hopper trencher width of impact is 30 m including 

sediment redeposit 

NUI Feet Feet of NUI are 51 m 2 each 

Pipelay barge 

anchors 

Anchors have to be reset every 2.5km (40 times along route) 

Rockdumping 1 tonne of rock dump impacts on 1 m 2 of seabed 

HLV Consumes 55 tonnes of diesel per day 

20" production 

pipeline 

Assumed width of impact on seabed is 0.5 m 

Piling Assumed maximum diameter of NUI piles is 2.4 m 

1.8. Consultation Process 

During the process to assess the environmental impact of the development a number of 

organisations were consulted (Table 1-2). The process of consultation will continue 

throughout the project. 

Table 1- 2 Consultation Process 

Consultees and 

Dates 

DECC & JNCC 

March 2010 

Natural England 

April 2010 

NFFO 

March 2010 

Issue/Concerns 

DECC identified the need for RDUK to consult with 

Natural England with respect to the environmental 

surveys undertaken for the nearshore (shoreline 

out to 12 Nm) section of the pipeline route to 

shore. RDUK subsequently provided survey 

information to Natural England for review. 

RDUK sent an information pack to NE in March 

2010 containing all environmental survey 

information collected to date. NE requested that: 

• Options assessment was detailed and cross 

referenced to survey data where 

appropriate; 

• Methods to minimise impacts on sensitive 

species identified are provided; 

• Offshore pipeline construction and 

onshore construction works are linked to 

minimise disturbance to designated 

species and sub-features at the beach 

landing area. 

RDUK held a meeting with NFFO in March 2010 to 

discuss the project. NFFO feedback was as follows. 

NFFO identified the main fishing types within the 

project area and the pipeline route to shore. It was 

recognised that there will need to be a clearly 

defined work corridor within which there is 

sufficient space during all construction activities. 

Good liaison with fisheries throughout 

Where Addressed 

in the ES 

3 

2, 3 

3, 5 

1-7



Marine 

Management 

Organisation 

(Formerly the 

Marine Fisheries 

Agency) 

March 2010 

North Eastern 

Sea Fisheries 

Committee 

March 2010 

JNCC 

January 2009 

CEFAS January 

2009 

1-8 

construction will be necessary. Agreed to use 

guard vessels to patrol the working corridor and 

ensure smaller fishing vessels deploying static gear 

observe the designated work corridor. NFFO 

preference is for trenched and buried pipelines. 

Q3/Q4 2010 RDUK and NFFO shall start working on 

a collaboration/co-operation plan for liaison with 

local fisherman during pipeline construction 

activities in 2011. 

RDUK contacted three groups within the MMO 

• North Shields District Inspector; 

• Grimsby District Inspector; 

• Marine Consents (North Shields). 

RDUK sent a short project briefing and a summary 

of the meeting with NFFO for review and comment 

to the MMO. Response was as follows: 

The MMO agreed with the actions identified during 

the NFFO consultation. The MMO expressed a 

desire for smaller fishing businesses which may not 

be members of the NFFO to be included in the 

consultation/collaboration plan. 

The NESFC requested that: 

• Near shore fishing activities were 

accurately identified; 

• Consult DECC and DEFRA data regarding 

near shore fishing activities; 

• Consider undertaking beam trawls as part 

of the near shore survey. 

Baseline survey to be undertaken and any potential 

impacts addressed. 

CEFAS did not comment on the proposed 

development but requested that a copy of the ES 

be distributed to the OCNS team. 

3, 5 

3, 5 

3

2. Proposed Development 

2.1. Introduction 


Section 2 – Proposed Development 

The Breagh gas field is located in Block 42/13 of the Southern North Sea UKCS. RDUK plan 

to develop the Breagh field and export the gas to shore by the installation of an export 

pipeline to the existing Teesside Gas Processing Plant (TGPP). It is proposed to develop the 

field by the installation of two offshore platforms, both of which would be Normally 

Unmanned Installations (NUI). The project is split into two phases, outlined below. The 

offshore elements of Phase 1 (from the offshore NUI location up to the shoreline at the 

Mean Low Water Springs (MLWS) are subject to this ES. 

Phase 1: 

• Installation of a NUI on the west side of the field (Breagh A); 

• Installation of the export pipeline from Breagh A to TGPP and a 3” MEG pipeline and 

fibre optic cable from TGPP to Breagh A; 

• Drilling and connection of seven target wells (12 slot template); 

• Commissioning of the infrastructure; 

• Production from the wells. 

The exact scope and nature of the Phase 2 development will depend on the production 

results of Phase 1, ongoing Breagh Field appraisal, the surrounding area exploration success 

and possible third party business. However, it is currently envisaged to include the 

following: 

Phase 2: 

• Installation of a NUI on the east side of the field (Breagh B); 

• Drilling and tieback of additional wells; 

• Commissioning of the infrastructure; 

• Production from the wells. 

An overview of the Breagh Development concept is shown in Figure 2-1. 

Figure 2-1 Overview of the Breagh development 

Onshore Landfall 

Offshore 

TGPP 

Processing 

Phase 1 

Phase 1 Phase 2 

Breagh A 

NUI 

(West) 

Phase 2 

Breagh B 

NUI 

(East) 

2-1



It is anticipated that gas flow for the Phase I development will peak at 1,588 Msm 3 per year 

(annual average). The recoverable reserves for the Phase I development are estimated at 

15.4 Bscm. It is expected that no sand will be produced with the gas, however it is 

anticipated that condensate and water will be produced with the water content peaking in 

2013 before falling for the remainder of the field life. 

In summary, the development programme considered within this ES comprises: 

• Installation of the Breagh A NUI; 

• Installation of approximately 100km of 20” pipeline, 3” MEG line and fibre optic (FO) 

cable between the Breagh A NUI and Mean Low Water Springs (MLWS) at Teesside; 

• Drilling of 7 production wells; 

• Commissioning of the wells and facilities; 

• Production of gas and condensate. 

This ES addresses those activities regulated by the Department for Energy and Climate 

Change under The Offshore Petroleum Production and Pipe-lines (Assessment of 

Environmental Effects) Regulations 1999 and the Offshore Petroleum Production and Pipelines 

(assessment of Environmental Effects (Amendment) Regulations 2007, that is namely 

those associated with the offshore aspects of the Breagh development up to MLWS. 

2.2. Nature of the Reservoir 

The Breagh Gas Field is located in the UKCS Southern North Sea gas basin (Block 42/13) 

some 50 km from the North East coast of England. The field was discovered by exploration 

well 42/13-2 drilled in 60 m of water by Mobil in 1997. The well tested gas from sandstones 

of Visean age (Lower Carboniferous) below the Base Permian Unconformity between 7,300 

and 7,650 ft TVD. Table 2-1 shows the Breagh discovery and appraisal well history. 

Table 2-1 Well history in the Breagh field 

Well Operator Spud Date Well Type Status 

42/13-1 BP 29 Jun 1968 Exploration P&A 

42/13-2 Mobil 12 Jul 1997 Exploration P&A (discovery well) 

42/13-3 Sterling 28 Sep 2007 Appraisal Suspended 

42/13-4 Sterling 18 Aug 2008 Exploration/ Appraisal Suspended 

42/13-5 Sterling 12 Nov 2008 Appraisal Abandoned 

42/13-5z Sterling 24 Dec 2008 Appraisal Suspended 

Note: P&A – Plugged and Abandoned 

The Breagh gas reservoir, shown in Figure 2-2, is a carboniferous reservoir. The structure is a 

four way dip enclosure mapped at Base Zechstein. The gas is reservoired within stacked 

fluvial channel sands in two discrete intervals. These sands are interpreted to be the 

deposits of large scale braided fluvial channels anastomosing from north to south within a 

channel belt many kilometres in width. Recoverable reserves from the Phase I development 

are estimated at 15.4 Bscm. Table 2-2 gives the reservoir conditions and fluid properties. 

Table 2-3 shows the composition of the Breagh gas. 

2-2

Figure 2-2 Breagh reservoir depth map 

Table 2-2 Initial Reservoir conditions and fluid properties 



Reservoir Property Measurement 

Reservoir Fluid Type Gas 

Reservoir Pressure @ 7250’ TVDSS 3750 psia 

Reservoir Temperature @ 7920’ TVDSS F (88 o C) 

Condensate to Gas Ratio 2-2.5 bbl/MMscf 

Max CITHP c. 3162 psia 

Max FWHT F (≤ 55 o C) 

Reservoir Water saturation 30% 

Gas SG 0.62 

Design Temperature (well completion) 176°F (80°C) 

Design Temperature (platform piping, 

risers and pipeline) 

149°F (65°C) 

2-3



Table 2-3 Gas Compositional Analysis (Separator Gases from PVT Analysis) 

2-4 

Gas Compositional Analysis mol % 

Well 42/13-2 Well 42/13-3 

C1 91.27 92.31 

C2 2.10 2.12 

C3 0.46 0.49 

iC4 0.08 0.07 

nC4 0.13 0.12 

iC5 0.08 0.04 

nC5 0.06 0.04 

C6 0.08 0.06 

C7 0.17 0.03 

C8 0 0.03 

C9 0 0.02 

C10 0 0.02 

C11+ 0 0.04 

H2 0 0 

CO2 3.08 2.37 

N2 2.54 2.23 

H2S < 1 ppm < 3 ppm 

2.3. Development Options 

Prior to RDUK becoming operator of the Breagh field in mid 2009, the previous operator, 

Sterling Resources (UK) Limited, undertook a preliminary evaluation of export routes from 

the Breagh field. The options under consideration at that time included pipeline routes to 

the following locations: 

• ConocoPhillips (CMS, Murdoch), approximately 120 km; 

• Perenco (Tyne/Trent), approximately 80 km; 

• BP Cleeton, approximately 60 km; 

• Centrica (Rough), approximately 85 km; and 

• Teesside Gas Processing Plant (TGPP), approximately 100 km offshore section and 10 

km onshore to the existing facility. 

These export options are schematically represented in Figure 2-3 below.

Figure 2-3 Breagh Export Route Options 



Initial requests for host infrastructure service were sent out covering all options in the area 

in May 2008 (by Sterling Resources). In the case of ConocoPhillips (CMS), Perenco 

(Tyne/Trent) and Centrica (Rough) the response indicated that either capacity was not 

available or that capacity would have to be bid for against other fields. 

BP made an indicative offer of capacity at Dimlington terminal with access via Cleeton 

platform or via a hot-tap into the Cleeton-Dimlington pipeline (nominally at 1 km from the 

Cleeton facility). Teesside Gas Processing Plant (TGPP) offered capacity in their terminal that 

was being made available by the end of 2008 following the end of an existing contract. 

Subsequent to the initial exercise in 2008, RDUK in its role as Operator of the Breagh 

development instigated a competitive bidding process in September 2009 to identify the 

optimal export route for the Breagh Field. With consideration of the responses to the 2008 

process of approaching hosts, a revised Statement of Requirements was issued to three 

prospective hosts in September 2009 with a request for responses by the end of October 

2009. This process recognised the potential for additional equity gas from the Greater 

Breagh Area and third party business. 

The three routes under evaluation were: 

• Teesside Gas Processing Plant (TGPP); 

• Central Area Transmission System (CATS) terminal in Teesside (adjacent to the 

TGPP), who were not approached in the 2008 process; and 

• Southern North Sea Pipeline System (Dimlington). 

2-5



RDUK received processing offers from TGPP and Dimlington. The CATS (working through the 

substitute commercial operator – BG) did not respond to the request. 

The main uncertainties associated with the Cleeton/Dimlington options related to (i) 

throughput capacity, i.e. modifications required to the Dimlington facility in order to achieve 

the production rates from Breagh, (ii) hydrate/corrosion inhibitor issues, i.e. delivery of 

these production chemicals in the volumes required to the Breagh facility, and (iii) offshore 

pipeline pressure protection (it was considered possible that a HIPPS would be required to 

protect the Southern North Sea Pipeline System from the high reservoir pressure at Breagh). 

In comparison, the options for dealing with these issues were relatively well defined within 

the TGPP option. Additionally, TGPP was able to offer up to 400 mmscfd throughput 

capacity versus a maximum rate of 200 mmscfd at Dimlington. 

The technical uncertainties associated with the Dimlington option coupled with the lower 

throughput rates meant that TGPP became a favoured option for both technical and 

economic reasons, particularly with one of the key aspects of the bidding process being the 

potential for additional equity gas from the Great Breagh Area and third party business. 

As such, export to TGPP via landfall at Teesside was the selected option. 

Subsequent to the selection of the TGPP export route, various sub-options were examined 

to identify the preferred route, pipeline installation method and type of NUI. A breakdown 

of each of these sub-options with a brief justification for selection or rejection is given 

below. 

2-6



Preferred Route 

South of the CATS pipeline No requirement for crossing the CATS pipeline and associated 

complications. 

Minimise length of pipeline. 

Minimise impact on windfarm. 

North of the CATS pipeline Avoid static fishing grounds. 

Avoid rocky out crop south of the CATS pipeline. 

Avoid harder substrate which impedes trenching. 

20” Export Pipeline Installation 

Trench and bury the 

pipeline along the entire 

route 

Coat the line with concrete 

to add stability and lay on 

the seabed (with trenching 

along the final 12 km to 

shore) with a fishing 

friendly design. 

Adds stability to the pipeline and reduces the required 

concrete thickness. Would increase the installation duration 

and number of vessels required. 

Increase area of seabed disturbed during the installation. 

Removes the requirement for trenching the majority of the 

line. 

Minimises the number of vessels required for the installation. 

Minimises the impact on the seabed during the installation. 

Type of NUI 

Sea Harvester design The Breagh topsides would be larger and heavier than any currently 

installed to date. Similarly it would be in water depths greater than 

that of any currently installed to date - all of which would add 

complications to the design. Due to the heavy topsides a heavy 

lifting vessel would be required for the installation. 

Standard design Likely to be heavier than the Sea Harvester design. Fully proven 

design for similar applications in the North Sea. Due to the heavy 

topsides a heavy lifting vessel would be required for the 

installation. 

Self-installing design No requirement for the heavy lifting vessel and requires minimal 

hook-up. 

The following options were selected for the development of the Breagh field: 

• Preferred Route: The route south of the CATs pipeline is preferred as it eliminates 

the need to cross the CATs pipeline and reduces the overall length of the pipeline; 

• Pipeline Installation: Surface lay pipeline (20”) to minimise the duration of the 

installation period and the impact on the seabed. The 20” pipeline will be trenched 

and buried from 12 km offshore to the landfall. Trench and bury the 3” MEG 

pipeline and fibre optic cable along their entire length; 

• Type of NUI: Standard design NUIs to ensure that there is sufficient space available 

for the required operations. 

2.4. Schedule of Activities 

Installation activities are scheduled between Q4 2010 and Q1 2012 with the first gas in Q2 

2012. The schedule of activities is shown in Figure 2-4. 

2-7



Figure 2-4 Schedule of activities 

2010 2011 

2012 

Activity 

20" Production pipeline installation and testing 

3" MEG pipeline installation and testing 

Optical fibre installation 

Breagh A NUI Jacket transportation and installation 

Breagh A NUI Topsides transportation and installation 

Breagh A NUI hook-up and commissioning 

Drilling 

Onshore construction, commissioning and testing 

Start-up and first gas 

Production 

O N D J F M A M J J A S O N D J F M A M J J A S O N D 

2.5. Breagh Alpha NUI Design 

During Phase 1 of the development a Normally Unmanned Installation (NUI) will be installed 

over the Breagh Field. The NUI will be based on a SNS ‘minimum facilities’ design 

(Figure 2-5) and will be a fixed steel platform with a jacket weight of approximately 2,000 

tonnes and topsides weight of approximately 1,000 tonnes. The facilities will be capable of 

at least 60 days and up to 100 days unattended operation 1 

. The platform will be designed to 

achieve a production uptime of 97% during unattended operation (not including planned 

shut downs) and will be remotely controlled from shore via a fibre optic link (or telemetry 

backup). The design life of the platform will be 20 years for the topsides and 40 years for 

the jacket. It will contain the following facilities: 

• Helideck (suitable for operation with the AW-139 aircraft); 

• 10 tonne diesel driven crane; 

• Corrosion and hydrate inhibitor injection package; 

• Methanol storage and injection for hydrate control at well start-ups; 

• Simple vent line for maintenance venting; 

• Dual system, closed HP/LP hydraulic control package for topsides and subsurface 

safety valves; 

• Wellheads (hydraulically operated); 

• 12 well slots; 

• 7 production gas wells each with wet gas metering on flowlines; 

• Gas production manifold; 

• Up to seven risers (including future expansion): 

o 20” pipeline to shore; 

o 3” MEG pipeline from shore and future 3” from Breagh B; 

o Future pipeline from Breagh B; 

o Possible future pipeline to Breagh B; 

o Two 8” pipelines for third party gas. 

• Permanent automatic pig launcher; 

• Communication links with the shore; 

• Lifeboat, life rafts and safety equipment; 

• Equipment Room; 

• Battery room; 

• Emergency Overnight Accommodation for 12 people; 

1 This is the maximum planned period of autonomy. In practice it is likely that visits will be 

undertaken every 6-8 weeks for several days at a time to carry out planned maintenance. 

2-8 

Project Activities 

Production



• Heating and ventilation for Local Equipment Room and Emergency Overnight 

Accomodation; 

• Power generation (400V) by air cooled diesel generators with suitable fuel and 

bunkering provision; 

• Diesel storage for up to 6 months supply (25 tonnes); 

• Freshwater storage and bunkering, for washdown and sanitary purposes; 

• Topsides piping and export pipeline fully rated for CITHP; 

• Closed drains and hazardous open drains systems; (no non-hazardous drains); 

• Combined Control and Safety System (CCSS); 

• Uninterruptible Power Supply (UPS); 

• Navigation aids; 

• VHF/UHF radio. 

Figure 2-5 Breagh SNS “minimum facilities” NUI 

The Breagh A NUI will be set by the location of the suspended wells 42/13-3 and 42/13-5z. 

Table 2-4 provides the coordinates of the 42/13-3 and 42/13-5z wells. 

Table 2-4 Well 42/13-3 and 42/13-5z coordinates 

Well Latitude/Longitude Easting/Northing 

42/13-3 

54° 35’ 44.148” N 

0° 26’ 00.931” E 

6,052,949.75 N 

334,193.73 E 

42/13-5z 

54° 35’ 44.073” N 

0° 26’ 00.981”N 

6,052,947.39 N 

334,194.55 E 

Installation 

The Breagh A template, docking piles, jacket, topsides and main piles will be loaded onto a 

transportation barge and towed by tug from the manufacturing site to the installation site 

over the Breagh Field where the barge will rendezvous with the Heavy Lift Vessel (HLV) 

which will also be towed to the installation site by tug. 

2-9



The HLV will moor at the installation site using up to 8 anchors which will be managed by up 

to two anchor handling vessels. The template will be lifted from the barge and lowered into 

position over the pre drilled wells and the two docking piles installed. After the docking piles 

have been installed the template will be recovered to the surface. 

The jacket will then be lifted from the barge and lowered into position over the pre-drilled 

wells guided by the docking piles. Each leg of the jacket will be secured to the seabed. A 

platform foundation assessment has been undertaken to identify the most suitable method 

(Senergy Ltd, 2008). Four methods were considered; pile driven, drilled and grouted piles, 

gravity based structure (GBS) and suction piles. Of these methods suction piles are not 

considered feasible due to the presence of chalk as water ingress through fractures in the 

chalk make it difficult to generate enough suction in the pile to penetrate it through the hard 

chalk. Difficulties associated with drilled and grouted piles and GBS lead to driven piles 

being the preferred option with up to 8 piles being required as a worst case option. A site 

specific geotechnical survey and test programme has been undertaken by Fugro in April 

2010 to establish the seabed strength. 

The HLV will commence piling activities which are expected to last up to a maximum of 10 

days. Piling activities will be initiated using the soft start method to minimise impact upon 

cetaceans in the area. An Marine Mammal Observer (MMO) will be present during piling 

activities. Once the piles are driven to a sufficient depth to secure the jacket to the seabed 

the piles will be grouted to the jacket sleeves. The size of the piles which will be required to 

secure the Breagh A NUI to the seabed have not been defined but are not likely to be 

greater than 2.44 m in diameter. 

Upon completion of piling the HLV will lift the topsides into position on the jacket and the 

topsides welded to the top of the jacket legs. In total, installation activities will be 

approximately 44 days. Table 2-5 details installation vessel requirements assuming no 

weather delays. 

Table 2-5 Summary of vessel requirements for installation of the NUI 

Vessel Type Duration (Days) 

Working Fuel 

Consumption (t/d) 

Total Fuel Use (t) 

Barge - na - 

Tow Tug 44 18 792 

Heavy lifting Vessel 23 55 1,265 

HLV Tug 23 18 414 

Anchor Handling Tug 

(x2) 

16 18 288 

Standby Vessel 23 2 (idle) 46 

Guard Vessel (NFFO) 44 3 (idle) 132 

TOTAL 209 - 2,937 

Process Description 

There will be no separation or processing of produced water on Breagh A. The Breagh 

hydrocarbons will be metered and sent via export pipeline to TGPP Onshore Terminal for 

processing and metering prior to passing to the National Transmission System (NTS). 

Individual metering of wells for reservoir monitoring will be installed. The design capacity of 

2-10



Breagh A will be 225 mmscfd (6.37 million sm 3 /d) with a maximum flowrate per well of 50 

mmscfd (1.42 million sm 3 /d). 

Production System 

The production systems will consist of dry Xmas-trees, production piping including chokes 

and a manifold. High CO2 content dictates that as a minimum the pipework will be duplex 

stainless up to the export pipeline inlet. Thereafter the carbon steel will be protected by 

continuous injection of corrosion inhibitor. Figure 2-6 shows a flow diagram of the Breagh 

Facilities. 

The combined gas and produced fluids will flow from the Xmas-trees via the flowlines to the 

production manifold. A manually set choke valve on each flowline will control the flow rate 

from each well. The choke valve internals will be designed for minimum maintenance with 

maximum resistance to sand and other solids in the well stream. 

Sand production is not predicted. Online non-intrusive sand detection instrumentation will 

be provided in each well flowline. 

Gas and produced fluids will pass from the production manifold into the export riser and on 

to the onshore processing facility. Production will normally be maximised with chokes fully 

open since the export pipeline is fully rated for closed in tubing head pressure. 

MEG mixed with corrosion inhibitor shall be continuously injected after the production 

manifold to mitigate corrosion and hydrate formation in the riser and export pipeline. This 

will be delivered from the onshore processing plant via a subsea pipeline with sufficient 

pressure for injection into the production header. 

Methanol will be injected whilst wells are shut-in and also after wells are restarted to 

prevent the formation of hydrate. Only methanol is stored in bulk on the topsides as MEG 

and Corrosion Inhibitor are supplied by pipeline from shore, it will be transferred out on the 

supply vessel and stored on the NUI. 

Production fluids (gas, condensate and water) from all wells will be metered before passing 

to the onshore processing facility for metering and processing. Condensate and produced 

water treatment facilities will not be provided on Breagh A. 

Figure 2-6 Flow diagram of the Breagh A facilities 

MeOH 

Typical 

Wellhead 

MEG and Corrosion Inhibitor 

NUI 

Subsea export 

Terminal: 

Teesside Gas 

Processing 

Plant 

2-11



Vent System 

As the topsides piping will be designed for pressures in excess of CITHP there will be no 

requirement for full flow relief. 

An atmospheric vent system will be provided for venting from topsides process piping, pig 

trap, sample connections and Xmas tree annulus vents. The vent will discharge to a safe 

area which will be determined from a dispersion study. The volume of gas vented during 

blowdown of the topsides facilities on the Breagh A NUI is 6,883 Sm 3 of gas. Export pipeline 

depressurising will take place at the onshore processing facility. 

Power Generation 

The Breagh A NUI will provide utilities, e.g. power, control systems etc to support up to 10 

production wells (although seven are currently planned) and associated ancillaries. Power 

generation will comprise up to 3 self-contained, air-cooled diesel generator sets, configured 

in a duty/auto-standby arrangement, running efficiently at platform base load. The exact 

number of generators shall be determined during the course of engineering development. 

The base case is for two generators however for the purpose of environmental assessment it 

has been assumed that Breagh A will have three diesel generators. This is based on RDUK’s 

operational experience of similar assets which indicates that three generators may be 

preferable on Breagh A to allow for more frequent maintenance activities. It is assumed 

that all three units will be rated at 47kW. Fuel consumption, based on current operational 

experience and with allowances for additional manned maintenance activities is estimated 

to be 50 tonnes per year. Fuel capacity and bunkering provisions will be provided with the 

fuel supply based on a gravity feed to avoid the requirement for diesel circulation pumps. 

Diesel Fuel 

Diesel will be stored on Breagh A to power the diesel generators. It will be delivered by 

supply boat and bunkered to the platforms. Bunded storage facilities will be provided for 

the storage of diesel. The storage capacity will be designed for 6 months supply (25 tonnes) 

to allow maximum operation flexibility. 

Aviation Fuel 

There will be no aviation fuel stored on the Breagh A facility. 

Drains 

The drain system will maximise the use of open drains and piping systems to maximise selfdraining. 

Hazardous drains will drain the methanol skid, diesel system and vent knockout 

drum pot to a hazardous drains tank and the collected inventory removed by tote tank and 

supply boat. Open drains and the overflow lines from the hazardous open drains tank shall 

be routed overboard. Small volumes of sewage will be discharged to sea during the 

maintenance visits. 

2-12

Discharges Overboard 



There will be no processing undertaken on Breagh A, all processing will be carried out on 

shore at the Teesside Gas Processing Plant. As such there will be no routine discharges. The 

discharges that will occur have been described in the preceding sections and include: 

• Discharge from non hazardous drains. This will comprise mostly rain water with 

occasional accidental release of contaminants from possible spills during 

maintenance visits; 

• Small volumes of sewage only during maintenance visits; 

• Accidental spills during bunkering of diesel or methanol (only methanol is stored in 

bulk on the topsides as MEG and Corrosion Inhibitor are supplied by pipeline from 

shore). 

2.6. Subsea Design 

Export Pipeline, MEG Line and Fibre Optic Cable 

Hydrocarbons from the Breagh A NUI will be exported through a 20” export pipeline of 

approximately 110 km to TGPP. The 20” export pipeline will be made with carbon steel API 

5LX 65 and coated with concrete ranging in thickness from 40 mm to 110 mm. A 3” MEG 

pipeline from TGPP will be laid along the route parallel to the main pipeline to provide 

hydrate and corrosion inhibitor which will be pumped from TGPP. A fibre optic control cable 

required for communications and control purposes will be laid with the 3” MEG pipeline. 

The pipeline systems will be designed for full CITHP. Table 2-6 shows the design conditions 

of the 20” production pipeline and the 3” MEG pipeline. 

Table 2-6 Pipeline design conditions 

Section Insulated MAOP (Barg) C) 

Pipelines No 217 65 

Riser Tie-in Spools No 217 65 

MeOH/MEG Pipeline No 250 20 

Pipeline trenching 

For the majority of the pipeline route, the 20” 

production pipeline will remain untrenched on 

the seabed. From a distance of around 12 km 

offshore to shore, the 20” production pipeline 

will be trenched. The length of trench in the 

immediate nearshore area will be excavated 

using a backhoe dredger (Figure 2-7). A trailing 

suction hopper dredger (Figure 2-8) will be 

used to trench the 20” production pipeline 

route from deeper waters to around 12 km 

offshore from where the 20” production 

pipeline will remain untrenched. Sediment 

removed from the seabed by the back hoe 

dredger and suction hopper dredger will be 

deposited adjacent to the trench (up to 3 km) 

for storage prior to backfilling. 

Figure 2-7 Backhoe Dredger (DredgingToday, 

2-13



Figure 2-8 Trailing Suction Dredger (DEME, 2010) 

The 3” MEG pipeline and FO cable 

will be laid separately from the 

production pipeline at a distance 

of approximately 50 m and will be 

trenched along their entire length 

to offer dropped object and fishing 

gear protection. The trench, which 

will be allowed to naturally backfill, 

may be cut with a plough or a 

water jet trencher. Of these two 

options the plough has a larger 

subsea footprint. From a distance 

of 12 km offshore to landfall the 3” 

MEG line and FO cable will be 

trenched following the same methodology utilised for the 20” production pipeline. Table 2- 

7 summarises the area impacted by the trenching operations. 

Table 2-7 Subsea footprint associated with trenching 

3” MEG 

Pipeline & 

FO cable 

20” 

Production 

pipeline 

2-14 

Trench Section 

Distance 

(km) 

Width of seabed 

impacted (m) Subsea 

footprint (km 2 ) 

Trench Storage 

Nearshore trench 12 30 30 0.72 

Offshore trench 88 20 1.76 

Nearshore trench 12 30 30 0.72 

TOTAL 112 - 3.2 

Two cables must be crossed by the pipeline en-route to TGPP (Figure 2-9). Prior to pipelay, 4 

mattresses measuring 2 x 5 m will be installed at each cable crossing. Post lay protection will 

be provided by rockdump or mattress laying. If mattress laying is required for protection an 

additional 4 mattresses will be laid at each crossing location. If rockdumping is required 200 

tonnes of rock will be dumped per crossing. The footprint of each cable crossing will be 

approximately 200 m 2 . Figure 2-10 illustrates a typical crossing protected by rockdump.

Figure 2-9 Pipeline route elevation and cable crossings 

Cantat 3 Telecoms cable 

Note: KP – Kilometre Point from proposed NUI location 

Figure 2-10 Typical crossing site 

EXISTING TELECOM CABLE 

Pangea N Telecoms cable 



Initial engineering studies have shown that rockdumping will not be required. However, for 

the purposes of environmental assessment it has been assumed that it will be required up to 

500 m from the platform to stabilise the hot end of the 20” production pipeline. 

Approximately 1,500 m 3 of rock is estimated to be required for this purpose which will have 

a subsea footprint of 1,500 m 2 . 

Sections with rocky outcrops, where trenching might not be feasible, could require 

rockdumping as protection / stabilisation. Rock dump may be required to mitigate the risks 

of upheaval or lateral buckling but this has not been developed yet in any detail. Worst case 

estimates indicate that 1,500 tonnes of rock will be required for these purposes along the 

pipeline route. Table 2-8 details the rockdump and mattress requirements. 

2-15



Table 2-8 Rockdump and mattress laying requirements 

2-16 

Purpose 

Mass of 

rock (t) 

Subsea 

footprint 

(m 2 ) 

Number of 

mattresses 

Subsea 

footprint 

(m 2 ) 

Total subsea 

footprint 

(m 2 ) 

Stabilise 500m hot 

end of pipeline 

1,500 1,500 - - 1,500 

CANTAT Cable 

crossing 

PANGEA 

200 200 8 160 200 

Cable 

Crossing 

200 200 8 160 200 

CANTAT Cable 

crossing 

PANGEA 

200 200 8 160 200 

Cable 

Crossing 

200 200 8 160 200 

Postlay rock dump 1,500 1,500 - - 1,500 

TOTAL 3,800 3,800 - - 3,800 

3” pipeline 

20” pipeline 

The contract for the installation of the pipeline has not yet been awarded. However, from 

RDUK’s experience it is anticipated that the vessels detailed below will be required for the 

installation of the 20” production pipeline, 3” MEG pipeline and FO cable. The total 

duration 2 

and fuel use for the vessels required for the pipeline installation are shown in 

Table 2-9. The pipeline installation vessels are split into four categories: 

• Those used exclusively for the landfall works; 

• Those used exclusively for the installation of the 20” production pipeline; 

• Those used exclusively for the installation of the 3” MEG pipeline; 

• Those used for the installation of both the 20” and 3” pipelines. 

The following will be used exclusively for the landfall works are: 

• Backhoe dredger; 

• Crawler cranes; 

• Piling hammer; 

The following will be used exclusively for the installation of the 20” production pipeline: 

• Pipelay barge. 

The following vessels will be used exclusively for the installation of the 3” MEG pipeline and 

fibre optic cable: 

• Reel-lay vessel; 

It is anticipated that the following vessels will typically be used for activities common to both 

the 20” production pipeline, the 3” MEG pipeline and the fibre optic cable: 

• Split barge (backfill and rockdumping); 

2 Total duration of vessel requirements are shown in Table 2 -9 for overall impact assessment, 

however, pipeline construction is currently planned to be undertaken over two campaigns (see 

section below for further explanation).

• Survey vessel (pre and post lay surveys); 

• Trenching support vessel; 

• Split barge for backfilling and rockdumping; 

• Trailing suction hopper dredger; 

• Wire lay barge; 

• Personnel supply vessel; 

• Shallow water lay barge; 

• Pipelay support vessel for pipe supply; 

• Anchor handling tugs; 

• Diving support vessels; 

Table 2-9 Pipeline installation vessels 

Landfall 

20” 

pipelay 

3” pipe and fibre 

optic cable lay 

20” and 3” pipelay 

Vessel Type Duration (Days) 



Working Fuel 

Consumption 

(t/d) 

Total Fuel Use 

(t) 

Backhoe 

dredger 

90 2 1 180 

Crawler Cranes 90 5 450 

Piling Hammer 90 5 450 

Pipelay barge 3 60 34 2 2,040 

Reel lay vessel 30 25 2 (DP) 750 

Split barge 60 12 720 

Pre and post lay 

surveys 

180 17 2 (DP) 3,060 

Trenching 

support vessel 

45 20 2 900 

Trailing suction 

hopper dredger 

30 25 2 750 

Wire lay barge 30 12 360 

Personnel 

supply vessel 

90 20 2 1,800 

Shallow water 

lay barge 

30 12 2 360 

Pipelay supply 

vessel 

90 20 2 1,800 

Anchor handling 

tugs 

90 18 2 1,620 

DSV 60 20 2 1,200 

TOTAL 1,065 - 16,440 

2-17



Note 1: Based on a 12 hour working day 

Note 2: Based on a 24 hour working day 

Note 3: A pipelay vessel may be used instead of a pipelay barge. The pipelay barge constitutes the worst case 

in terms of fuel consumption and seabed impact therefore it is assumed that a pipelay barge will be used in order 

to provide a worst case assumption for the purposes of assessment. 

Pipeline Installation 

For the shore approach and pull-in, the laybarge will back in to a water depth of 20 m LAT. 

The pipeline will be assembled on board and pulled in from the stern using shore based 

winching equipment. The pipeline will be buried along this part of the route with burial 

performed by the landfall contractor via the use of dredging equipment. This section of the 

trench will also be backfilled. 

In order to comply with mitigation measures applied to onshore pipeline construction 

activities in sensitive areas (i.e. the crossing of the Coatham Common), the landfall section of 

pipeline (20”, 3” and fibre optic) shall be laid in August to October 2011 (site set up on the 

beach shall commence earlier, expected to be in March 2011). It is envisaged that the 

landfall sections shall be constructed out to approximately 3 km offshore within the 

construction window in 2011. The remainder of the offshore pipeline construction shall be 

undertaken as soon as weather permits, currently estimated March – May 2012. The barge 

will continue laying away from 3 Km offshore towards the completion at the platform in 

water depth 63 m LAT in early 2012. 

The pipelay barge will deploy an anchoring system to maintain station and pull itself along 

the pipeline route. It is likely that up to 14 anchors will be deployed for this purpose. Figure 

2-11 shows a semi-submersible 

Figure 2-11 Pipelay barge (Eni Saipem, 2010) 

pipelay barge typical of that 

expected to be used for the 

Breagh development. 

For the landfall approach, a 

300/500 ton pull-in winch will 

be installed on the beach, with 

a pull-in cable of 

approximately 1,000 m. To 

protect the trench in the tidal 

zone, and to create access at 

the tie in point, a cofferdam 

will be prepared at this 

location. Length of the 

cofferdam is yet to be 

determined, but shall be 

sufficient to protect the trench 

and tie-in point for the 

duration of construction 

activities. As detailed above, 

these activities are subject to a construction window of August to October in the Coatham 

Common area (which is adjacent to the beach landing site) 

2-18

The shallow water section 

of the pipelines will be 

installed by a lay barge. To 

establish a limited pull-in 

load, and to have full 

control over the pull-in 

operation, in front of the 

cofferdam, some access 

dredging may be 

performed. This access 

dredging will be sufficient 

to create access for the 

barge including supply 

boats to come alongside 

for pipe discharge. 



After pre-dredging and 

installation of the pull-in 

cable on the seabed, the lay barge will position itself just in front of the cofferdam. The 

winch installed on the beach will perform the pull-in. After a successful pull-in and following 

ROV survey of the installed pipeline, backfilling can be initiated. The whole process will be 

continuously monitored to ensure the correct shore approach of the pipeline. Figures 2-12 

and 2-13 show a cofferdam and shore based winch similar to that which will be installed as 

part of the Breagh development. 

Figure 2-13 Shore based winch arrangement (Tideway, 2010) 

Pipeline Testing and Commissioning 

Figure 2-12 Cofferdam (Tideway, 2010) 

Upon completion of laying, the 20” production pipeline will be flooded with predominantly 

70,000 m 3 of treated seawater, gauged and hydrotested. As part of the hydrotest the 20” 

production pipeline will be raised to a pressure of 272 bar for 24 hours to ensure mechanical 

integrity. A subsequent leak test shall be performed after tie-in at each end at 10% above 

2-19



design pressure. The hydrotest fluids have not been defined but are likely to include 

corrosion inhibitor, oxygen scavenger, biocide and fluoroscene dye. Following the hydrotest 

a quantity of the contents will be released to sea on relaxation of the pipeline pressure to 

ambient pressure. The pipeline will remain flooded with inhibited water at static pressure. 

Discharge during blowdown will take place offshore. 

The 3” MEG pipeline will be subject to a hydrotest upon completion of laying activities. 

Approximately 500 m 3 of hydrotest fluid will be pumped into the pipeline at a pressure of 

313 barg. Hydrotest fluids have not yet been determined but are likely to include corrosion 

inhibitor, oxygen scavenger, biocide and fluoroscene dye. Discharge will take place at the 

platform. Following testing the 3” pipeline will remain flooded for tie-in to the jacket. 

The short sections of the landfall pipelines (to 3 km offshore) laid in 2011 (Aug – Oct) may 

undergo some preliminary hydrotesting prior to being left over the winter. 

Full details of the pipeline testing and commissioning and chemical use and discharge will be 

addressed in the subsequent PON 15C which will be submitted prior to these activities 

taking place. 

2.7. Drilling 

Drilling will commence once the Breagh A platform is installed. A SIMOPS (simultaneous 

drilling and production) philosophy will be employed and it is expected that production will 

commence after the first two wells have been drilled. 

Drilling Rig 

The contract for the drilling rig has not yet been awarded however, it is expected that a jackup 

cantilever drilling rig will be mobilised to allow the wells to be drilled through the Breagh 

A Platform. Details of the drilling rig will be included in the subsequent PON 15B application. 

However, for the purpose of 

Figure 2-14 Ensco 102 

assessing the environmental 

impacts from drilling activities, 

details of a jack-up rig that is of 

similar size to the one required for 

the Breagh wells has been 

described below and the 

environmental impacts assessed 

accordingly in Section 5.2. In this 

case, the ENSCO 102 has been 

identified as a rig that would be of 

similar size to the rig required for 

the Breagh wells and is utilized for 

the purposes of assessment. 

2-20 

The Ensco 102 (Figure 2-14) is a 

three-legged jack-up rig with a 

cantilever drilling derrick. It has 

accommodation facilities for a 

crew of 122 people. The rig is 

designed to operate in water



depths up to 120 m, and can drill wells of up to 9,144 m. The Ensco 102’s operational 

equipment comprises: 

• A cantilever deck to position the derrick over the well; 

• A 52 m high derrick for suspending tubulars in the hole; 

• A 3,000hp draw-works, brake, and cable for moving the tubulars into and out of the 

hole; 

• A Varco TDS 4H top drive for rotating the drillstring; 

• Storage for tubulars in the derrick and on the deck; 

• Tanks for storage of 763 m 3 drilling mud and three National Oil well 14-P-220 7,500 

psi mud pumps to circulate drilling mud through the hole; 

• Four NOV Brandt VSM 300 shale shakers to remove drilled solids from the circulating 

mud. 

• Storage for 500 m 3 bulk powdered chemicals used in drilling fluids and cement in Ptanks, 

for 653 m 3 drill water, and a sack store; 

• Safety features like a Shaffer 18 3/4” 15,000 psi 4 ram BOP; 

• Space for third party equipment such as cement units and logging units. Utilities 

include the generation of power (Ensco 102 has six Cat 3516-B engines rated at 

1,855 HP (2,150 kW) each and one Cat 3512-B emergency engine rated at 1,476 

(1,030 kW)), provision and storage of 801 m 3 of fuel oil, mechanical workshops, a 

mud laboratory, two cranes to receive materials in containers from supply vessels 

and a helideck to enable crew exchange by helicopter. 

The Ensco 102 comprises a flat bottomed hull with three vertical legs fitting through 

openings on the outer hull. The legs are raised and lowered by a jacking mechanism on the 

deck that usually employs a hydraulic or electric rack and pinion arrangement. Prior to 

drilling, the legs are jacked down onto the seabed with the hull raised on its legs above the 

water providing a stable platform. Excessive penetration by the legs into soft seabed is 

prevented by large round feet called “spud cans” or at the bottom of the legs measuring 18 

m in diameter. As the legs are pulled out they may leave scars and/or sediment mounds. The 

impacts of rig installation are discussed further in section 5.2. 

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 rig will be equipped with navigation lights, radar 

and radio communications. A stand-by vessel will patrol the 500 m zone while the rig is on 

location. 

Drilling is scheduled to start in October 2011. The drilling, logging and completion program is 

estimated to take a total of 455 days. 

Various support vessels will be associated with the drilling of the field. The drilling rig will 

have a supply vessel requirement of around 152 return trips totalling 303 days sailing during 

the drilling period. A standby vessel will be on location for the entire drilling phase, 

estimated at 455 vessel days. 

Table 2-10 shows the drilling rig and support vessel activity and fuel usage during the drilling 

programme. The support vessels are assumed to run on marine gas oil and the drilling rig to 

be powered by diesel generators. 

2-21



Table 2-10 Activity and fuel usage associated with drilling and completion of wells 

2-22 

Source 

Activity Level 

(days) 

Fuel 

Consumption 

Rate (t/day) 

Fuel Consumed 

(t) 

Rig (on location) 455 10 4,550 

Supply Vessels 303 10(load) 3,030 

Standby Vessel 455 3 (idle) 1,365 

Total 1,213 - 8,945 

Well Design 

The base case is to design the well utilising the conventional programme employing a 30inch, 

20-inch, 13 ⅜ inch and 9 ⅝ inch string. The reservoir section will be drilled in 8 ½-inch 

hole size and 7-inch liner however if problems are experienced in the overburden the 

reservoir may have to be drilled in 6-inch hole. At present a cemented and perforated liner 

will be utilised. The reservoir penetration will be drilled between 65 and 90 degrees angle. It 

is anticipated a 4½-inch production tubing string will be employed. 

Figure 2-15 shows a schematic for a generic Breagh well.

Figure 2-15 Schematic of a generic Breagh well 

30" Conductor 500ft 

Chalk Group 

Cromer Knoll 

Group 

20" Surface Casing 2200ft 

Jurassic 

13 3/8" Intermediate Casing 3900ft 

Zechstein 

Bacton Group 

Zechstein 

9 5/8" Production Casing 10000ft 

Carboniferous 

7" Production Liner 17300ft 



2-23



Drilling Fluids and Chemicals 

The Offshore Chemical Notification Scheme (OCNS) requires that hazard assessments be 

undertaken for chemicals that are used offshore. Chemicals are assessed using the CHARM 

model and awarded a ranking from purple to gold with gold representing those chemicals 

with the lowest environmental hazard. Those chemicals which cannot be assessed through 

the CHARM algorithms (inorganic substances, hydraulic fluids or chemicals used only in 

pipelines) are awarded an OCNS grouping from A-E with E being used to represent those 

chemicals with the lowest environmental hazard. 

The selection of chemicals is made according to the technical requirements for the mud and 

the environmental credentials of the chemical. The well will be drilled with a mixture of 

water based mud (WBM) and low toxicity oil base mud (LTOBM) as shown in Table 2-12 

below. The drilling mud is specially formulated for each section of the well to suit the 

pressure and temperature conditions downhole and the lithology being drilled. 

The majority of the chemicals which will be used during the drilling of the Breagh wells are 

PLONOR, i.e., they are not considered to have a significant impact on the marine 

environment due to their low toxicity. Of those chemicals that are not considered to be 

PLONOR, all but 3 have been rated “Gold” following assessment through CHARM or awarded 

an “E” OCNS grouping, that is they fall into the category of lowest environmental hazard. 

None of the 3 chemicals expected to be used which are not rated PLONOR or classified in the 

lowest category of environmental hazard will be discharged into the marine environment. 

They will be contained within the mud system and shipped to shore for treatment and 

disposal. The 3 chemicals not rated PLONOR or classified in the lowest category of 

environmental hazard are detailed in Table 2-11. 

Table 2-11 Chemicals not classified as PLONOR or in category of lowest environmental 

hazard 

Chemical 

Estimated 

Hole Estimated Use 

Hazard 

Formulation Function 

Discharge 

Section (tonnes) 

Quotient 

Group 

(tonnes) 

Drilling 

Chemicals 

2-24 

TRUVIUS Viscosifier 8½” 7 0 D 

Versaclean FL Emulsifier 8½” 10 0 B 

Versaclean VB Emulsifier 8½” 10 0 B 

Once each section of the well has been drilled, the drill string shall be lifted and a steel lining 

(casing), is lowered into the hole. The casing is then cemented into place. The cement is 

formulated specifically for each section of the well, of the appropriate materials that will 

seal the well casing in place against the well bore. The cement is mixed into a slurry on the 

rig and is then pumped down the string and forced up into the space between the well bore 

and the casing. To ensure that sufficient cement is in place and that a good seal is achieved, 

a certain amount of extra cement is pumped and some of this may find its way to the 

seabed. 

Other contingency chemicals may be required if problems or emergencies are encountered 

during drilling or cementing operations. These contingency chemicals will be included within 

the PON15B for the drilling of the wells.



All LTOBM used will be contained, and will be skipped and shipped to shore at the end of 

drilling for oil recovery and waste disposal. LTOBM will not be discharged into the sea. 

Treatment and Disposal of Mud and Cuttings 

Where water based drilling fluid is being used the cuttings and any remaining attached mud 

will be discharged directly to sea on a continuous or batch basis. The short, top-hole section 

will be drilled open to the seabed and the cuttings generated whilst doing so will be will be 

swept out of the hole using seawater. These will be deposited around the drill hole at the 

seabed. 

For subsequent sections the well will be cased and drilled whilst circulating drilling mud to 

remove cuttings, to condition the well bore and provide weight down the hole. Whilst 

drilling the well, a riser will be set between the wellhead and the rig, with a blow-out 

preventer fitted at the top of the riser. The mud and cuttings will be returned to the rig 

where they pass through the cleaning system. This reduces the amount of drilling fluid 

retained on the cuttings to between 5-10 percent. On the rig the cleaned mud’s composition 

will be monitored and its contents adjusted to ensure that its properties remain on 

specification and it will be recycled through the well. 

The mud and suspended cuttings are passed over screens (shale shakers) to maximise 

recovery of the mud. Most of the drilling mud and chemicals will be recovered from the 

shakers but some mud discharge to sea is inevitable. ‘Spent mud’, where water based, will 

be discharged on site. The cuttings will be collected from the shakers and discharged to the 

seabed. 

Where oil based mud is used (8½” sections) the mud and cuttings will be collected in skips 

and shipped to shore for onshore treatment and disposal. This will require the transport of 

approximately 242 m 3 of OBM and 102 m 3 of cuttings. Table 2-12 shows the volume of mud 

and cuttings (including 25% contingency) associated with each section of the well. 

Table 2-12 Breagh well mud programme 

Hole size 

(inches) 

Mud system 

Fluid volume 

per section 

(m 3 ) 

Cutting 

volume (m 3 ) 

Cuttings handling 

36” 

Seawater with 

viscous sweeps 

125 125 

Continuous discharge 

to seabed 

26” 

Bentonite 

mud/KCL Glycol 

287 223 

Continuous and batch 

discharge to seabed 

17 ½” KCL Glycol 231 101 



12 ¼” 

KCL salt 

saturated 

290 178 



8 ½” LTOBM 242 102 Skip and ship to shore 

The 7 wells in the Breagh field are all gas wells and it is not anticipated that there will be any 

significant hydrocarbon contamination of the cuttings generated. Therefore, an OPPC permit 

for discharge of the cuttings will not be required. 

2-25



Cementing Chemicals 

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

subsequent casing strings as well as isolate unstable formations, different formation fluids 

and separate different wellbore pressure regimes. Each steel casing will be cemented into 

place to provide a structural bond and an effective seal between the casing and formation. 

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

in the same way as WBM and discharged to sea. It is anticipated that all cement will be 

mixed as required and as a result there should be limited operational discharge of any mixed 

cement or mixwater. 

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

environmental performance. Chemicals with subwarnings will be avoided where technically 

possible. The drilling and cementing chemicals to be used have not yet been finalised. 

Details of the drilling and cementing chemicals will be included in the PON 15B application. 

Contingency Chemicals 

In the event of problems associated with the drilling operations there may be a need to drill 

contingency sidetracks or pilot holes. The majority of contingency chemicals which will be 

used during the drilling of the Breagh wells are PLONOR, i.e., they are not considered to 

have a significant impact on the marine environment due to their low toxicity. Of those 

chemicals that are not considered to be PLONOR all but 2 have been rated “Gold” following 

assessment through CHARM or awarded an “E” OCNS grouping, that is, they fall into the 

category of lowest environmental hazard. None of the contingency chemicals which may be 

used and are not rated PLONOR or classified in the lowest category of environmental hazard 

are expected be discharged into the marine environment. They will be contained within the 

mud system and shipped to shore for treatment and disposal. The 2 chemicals not rated 

PLONOR or classified in the lowest category of environmental hazard are detailed in Table 2- 

13. 

Table 2-13 Contingency chemicals not classified as PLONOR or in lowest category of 

environmental hazard 

Contingency 

Chemicals 

2-26 

Formulation 

Chemical 

Function Group 

Estimated Use 

(t) 

Estimated 

Discharge 

(t) 

Hazard 

Quotient 

SWA-EH OPF Additive 2 0 D 

Versapac 

Fluid loss control 

chemical 

6 0 B 

Contingency chemicals required for unplanned events will be assessed prior to any drilling 

operations and reported to the regulatory bodies. A list of chemicals identified for such 

contingencies will be given in the appropriate PON15B application.

Solid wastes from drilling 



Careful consideration is given to minimising the amount of waste generated and controlling 

its eventual disposal. Experience has shown that typically, 24 tonnes of waste are generated 

per month from a single well drilling programme. Bulk wastes (e.g. garbage, scrap, etc.) 

generated on the drilling rig will be segregated by type and stored in covered, four tonne 

capacity skips. Periodically these will be transported to shore and the waste recycled or 

disposed of in a controlled manner through authorised waste contractors. RDUK will ensure 

that a waste management programme is implemented to minimise the amounts generated 

and to ensure material such as scrap metal, waste oil and surplus chemicals are correctly 

segregated and sent for re-cycle or re-use as far as practicable. Other waste will be sent to 

authorised landfills or incineration facilities, depending on its precise nature. 

Well Clean-up and Testing Operations 

Prior to production, any waste and debris remaining in the well will have to be removed to 

prevent damage to the pipeline or topside production facilities. There is an established 

process for determining the best way of cleaning up the well so as to minimise damage to 

the environment. 

For each of the Breagh wells it is estimated that up to 0.8 Mscm of gas may be produced 

along with up to 10 m 3 of condensate. The clean up operations are likely to take place on 

the rig and will be restricted to 24 hours in duration during which time the produced 

hydrocarbons will be flared. The requirement for well testing will depend upon the log data 

gathered during drilling and if there is a requirement to gather further data. 

Atmospheric Emissions from drilling 

Atmospheric emissions during drilling operations arise from diesel combustion for power 

generation for the drill rig and associated standby and supply vessels and from well clean up 

and testing. 

Well cleanup will take 24 hours and will produce 0.8 Mscm of gas and approximately 10 m 3 

of condensate per well. From these, approximately 11,948 tonnes of CO2 will be emitted 

during well clean up activities for the seven wells. 

A standby vessel will be present during drilling operations and a generic figure of 3 tonnes 

per day of diesel use has been used. The vessel is assumed to be on site for the entire 

duration of drilling operations, logging and completion i.e. 455 days, therefore using 1,365 

tonnes of diesel producing 4,368 tonnes CO2. A supply vessel will also be required for 

normal supplies and to transport the OPF mud and cuttings in skips for onshore disposal. As 

a worst case this vessel is assumed to be in service for 303 days and to use 10 tonnes of 

diesel per day therefore 3,030 tonnes of diesel producing 9,696 tonnes of CO2. 

During 2007 – 2009 the Ensco 102 used an average of 8.8 tonnes of diesel per day. 

Assuming a worst case fuel consumption rate of 10 tonnes of diesel per day, the Ensco 102 

will consume 4,550 tonnes of diesel throughout the drilling programme producing a total of 

14,560 tonnes of CO2 (Table 2-14). 

2-27



Table 2-14 Predicted atmospheric emissions from drilling and related activities (tonnes) 

Activity CO2 NOx N2O SO2 CO CH4 VOC 

Drilling 14,560 270.27 1.001 18.20 71.44 0.819 9.10 

Well clean 

up 

11,948 5 0 0 29 192 21 

Standby 

vessel 

4,368 81.08 0.300 5.46 21.43 0.246 2.73 

Supply 

vessel 

9,696 179.98 0.667 12.12 47.57 0.545 6.06 

Total 40,572 536 1.968 35.83 169.03 193.63 39.23 

Breagh East Appraisal Well 

An appraisal well may be drilled in the eastern side of the Breagh field in late 2010/early 

2011 as part of the Breagh full field concept evaluation. Existing survey data within the area 

does not indicate the presence of any sensitive habitats. The drilling plan has not yet been 

confirmed and RDUK do not envisage significant environmental impacts from this activity. 

This will be confirmed following RDUK completing an environmental survey that will be 

included within the PON15B application for this activity. 

2-28

2.8. Production 



Total recoverable reserves from the Breagh field Phase I Development are estimated to be 

15.4 Bscm of gas. The expected production rates over the life of the field are discussed 

below and summarised in Table 2-15. 

Table 2-15 Anticipated Maximum Phase I Production Figures (Maximum Case, P 10) 

Year 

Gas Rate 

(Mscm/year) 

Condensate Rate 

(m 3 /year) 

Water Rate 

(m 3 /year) 

2012 677 9,301 8,009 

2013 1,588 21,797 18,770 

2014 1,208 16,585 14,281 

2015 976 13,397 11,536 

2016 1,116 15,318 13,190 

2017 947 13,005 11,199 

2018 833 11,442 9,853 

2019 747 10,261 8,836 

2020 679 9,315 8,022 

2021 617 8,472 7,295 

2022 564 7,741 6,665 

2023 518 7,107 6,119 

2024 479 6,573 5,660 

2025 441 6,059 5,218 

2026 409 5,615 4,835 

2027 380 5,214 4,489 

2028 355 4,870 4,193 

2029 329 4,519 3,891 

2030 307 4,216 3,631 

2031 287 3,935 3,388 

2032 269 3,688 3,176 

2033 251 3,445 2,966 

2034 235 3,230 2,781 

2035 221 3,033 2,612 

2036 208 2,860 2,462 

2037 195 2,684 2,311 

2038 184 2,529 2,178 

2039 174 2,385 2,053 

2040 164 2,258 1,944 

Gas Production Rate 

The expected gas production rate, presented in Figure 2-16, shows peak production rate in 

year 2 at 4.3 Mscm/d based on an annual average production profile. 

2-29



Figure 2-16 Maximum case gas profile, Phase I development 

NMm3/year 

Condensate Production Rate 

The initial Condensate is anticipated to be 25 tonnes/day based on a annual average 

production profile. Condensate production peaks in year 2 before decreasing (Figure 2-17). 

Figure 2-17 Maximum case condensate profile, Phase I development 

Tonnes/year 

2-30 

1,800 

1,600 

1,400 

1,200 

1,000 

800 

600 

400 

200 

- 

25,000 

20,000 

15,000 

10,000 

5,000 

- 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

2023 

2024 

2025 

2026 

2027 

2028 

2029 

2030 

2031 

2032 

2033 

2034 

2035 

2036 

2037 

2038 

2039 

2040 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

2023 

2024 

2025 

2026 

2027 

2028 

2029 

2030 

2031 

2032 

2033 

2034 

2035 

2036 

2037 

2038 

2039 

2040



Water Production Rate 

Water production peaks in year 2 at a rate of 51 m 3 /day before falling throughout life of field 

(Figure 2-18). There will not be any produced water discharges from the Breagh A NUI. 

Figure 2-18 Maximum case water production profile, Phase I development 

M3/year 

20,000 

18,000 

16,000 

14,000 

12,000 

10,000 

8,000 

6,000 

4,000 

2,000 

2.8.1. Maintenance Visits 

As previously stated, the Breagh A will be designed for operation in unattended mode for 

periods of up to 100 days. It is anticipated that the platform will normally operate 

unattended for periods of approximately 6 to 8 weeks, at which point an intervention team 

will visit the platform for periods of around 4 to 5 consecutive days. The visits will allow for 

the following: 

• Planned maintenance; 

• Replenishing the supply of fuel, water, methanol and other consumables; 

• Well sampling and meter calibration; 

• Statutory inspections and surveys. 

Less frequently planned shut downs will allow for well interventions and major maintenance 

of the platform. 

2.9. Environmental Performance 

Atmospheric Emissions 

Combustion 

- 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

2023 

2024 

2025 

2026 

2027 

2028 

2029 

2030 

2031 

2032 

2033 

2034 

2035 

2036 

2037 

2038 

2039 

2040 

The power for the installation will be supplied by three air-cooled diesel generator sets. In 

addition, diesel will be required to power the crane. The fuel use under normal operation is 

anticipated to be 50 tonnes/year for the generators and up to 5 tonnes per year for the 

crane. 

2-31



Venting 

There will be no routine venting from the installations. The topsides piping will be designed 

for pressures in excess of the closed-in wellhead pressure. There will, however, be a venting 

system for the topsides piping depressurising. This will include gas from the well annulus, 

production header, pig launcher and well flowline, as required for maintenance purposes. 

The export pipeline will be depressurised to shore. 

Chemical Use and Discharges to Sea 

RDUK are committed to try and minimise the effect of the chemicals used and discharged 

during any operation. As such there will be no routine discharges from the NUI. The volume 

of chemicals to be used will comply with all UK rules and regulations. As such, and as part of 

the chemical permitting process, RDUK will strive to reduce the number of chemicals used 

with a substitution warning and/or product warnings. Wherever possible, chemicals will be 

chosen which are either PLONOR (Poses Little or No Risk to the environment) or of a Low 

Hazard Quotient, HQ

2.10. Permits and Consents 



RWE will create and maintain a permitting and consents register for the Breagh Phase I 

project which will capture all permits and consents relevant to the development. A 

summary of the main offshore permits and their relevance to the Breagh Phase I project is 

given below. 

Pollution Prevention and Control (PPC) Permit 

The total thermal capacity of Breagh A will be less than the 50MW thermal trigger threshold 

of the Offshore Combustion Installations (Prevention and Control of Pollution) Regulations 

2001. Therefore Breagh A will not need a PPC permit. 

EU Emissions Trading Scheme (EU ETS) 

As for PPC, the total thermal capacity of the combustion equipment on Breagh A will be less 

than the 20MW thermal trigger threshold of the EU Emissions Trading Scheme (EU ETS). 

Additionally, there will be no flare. Therefore, Breagh A will not need to join the EU ETS. 

That said, the fuel use and associated emissions will be reported through the Environmental 

Emissions Monitoring System (EEMS). 

Oil Pollution, Prevention and Control (OPPC) 

Discharges of oil to sea need to be permitted under The Petroleum Activities (Oil Pollution, 

Prevention and Control) Regulations 2005 (OPPC). There will be no processing on Breagh A 

therefore there will be no permit required for the discharge of produced water. However, 

there will be discharge of open drains to sea and this will need to be permitted. Produced 

water will be monitored for LSA scale and a permit applied for under the Radioactive 

Substances Act 1993. 

Chemical Use and Discharges to Sea 

The relevant permits to use and discharge chemicals offshore will be applied for, in 

accordance with the Offshore Chemical Regulations 2002. All offshore activities are covered 

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

pipelines and discharges made during decommissioning. Applications for requesting a 

chemical permit under these Regulations are made using Petroleum Operations Notice 

(PON) 15 documents: 

• PON 15B – Drilling activities; 

• PON 15C – Pipeline operations; 

• PON 15D – Production operations; 

• PON15E – Decommissioning; 

• PON 15F – Workovers/well intervention operations. 

2-33



Radioactive Substances 

This is controlled under the Radioactive Substances Act 1993 and is regulated by 

Environment Agency (EA) and is compulsory for all new installations. A certificate is required 

for any radioactive substances brought onto installations as a result of project and will be 

issued by EA. The application must refer to all temporary or permanent radioactive sources 

taken offshore. SEPA require a 4 month statutory consultation time for this application. 

OPEP 

An OPEP is required for all oil and gas operations that have the potential to release 

hydrocarbons to the UKCS. When developing a field OPEPS can be submitted separately for 

each activity or as one main production OPEP with drilling appendices, but the production 

plan must reference that it also covers drilling and the interface between the plans must be 

made clear. Plans are approved by DECC and are also issued for comment to a number of 

statutory consultees. DECC require a 3 month consultation time for this application. 

Pipeline Works Authorisation (PWA)/ Deposit Consent (DEPCON) 

A PWA is the governing permit for the installation and use of offshore pipeline in the UKCS, 

however the PWA should accompany the PON15C (pipeline chemical permit) and the PWA 

will not be approved until the PON15C has been assessed and approved. 

A DEPCON is required under FEPA Part II and is a consent for the allow the use of rockdump 

and mattresses in order to prevent damage to pipelines. 

2.11. Decommissioning 

The Breagh A NUI and subsea facilities will have a design life of 20 years for the topsides and 

40 years for the jacket. At cessation of production, the wells, subsea structures, associated 

pipelines and facilities will be decommissioned in accordance with statutory requirements in 

force at that time. 

Where possible the ease of decommissioning and removal has been taken into account 

during the design phase, for example, by minimising the subsea infrastructure. However 

there are a variety of effects relating to decommissioning the subsea infrastructure and 

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

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

dependent on the decommissioning strategy selected. 

The pipeline decommissioning options likely to be available at cessation of production 

include: 

• Re-use in situ; 

• Leave as is; 

• Full recovery. 

Discharge chemicals during decommissioning operations require a licence and if and 

discharges are envisaged during decommissioning RWE will submit the relevant PON15D 

application. 

2-34

Re-use in situ 



Whether or not the 20” production pipeline can be re-used in situ will be determined by a 

number of factors including: 

• The requirement for an export pipeline from the development area to shore; 

• The condition of the pipeline; 

• The suitability of the pipeline specifications with regard to export requirements; 

• The cost of redeveloping the pipeline to meet new export requirements. 

Re-use of the pipeline would prolong the operational lifetime of the pipeline and reduce the 

lifecycle impact of pipeline fabrication and installation. Activities to redevelop the 20” 

production pipeline for reuse would result in a number of environmental impacts for 

example, atmospheric emissions, aqueous discharge to the marine environment and 

disturbance to the marine environment in the vicinity of the pipeline. 

Activities to prepare the 3” MEG pipeline for reuse would involve similar environmental 

aspects to those regarding the 20” production pipeline, namely atmospheric emissions, 

aqueous emissions and disturbance to the marine environment in the vicinity of the 

pipeline. 

Leave in place 

For the main part, there are no technical challenges associated with leaving a pipeline in 

place. All preparation and implementation operations are either routine activities or use 

well established methodologies and techniques that have been employed in the North Sea 

for many years. 

Following an operational life of 25-30 years the 20” export pipeline, which for the most part 

lies on the seabed, will become integrated with the marine environment in terms of marine 

growth and sea life. Leaving the pipelines in place would minimise disturbance to the 

marine habitat around both the 20” export pipeline and the 3” MEG pipeline, which will be 

buried for its entire length. Although not significant, leaving the pipelines in place would 

also reduce atmospheric emissions compared to removal, through reduced vessel activity 

and energy associated with recycling. 

Leaving the pipeline in place would represent the lowest cost option to full recovery. There 

may, however, be a need to undertake inspection surveys of the pipelines although it is 

envisaged that the inspection frequency would be likely to reduce providing stability is 

maintained. Leaving in situ may also have an ongoing financial liability for any snagging or 

damage to other users of the sea in the unlikely event of this occurring. 

Full recovery 

Whether or not a pipeline can be recovered, in part or in full, is determined by a number of 

site specific factors such as: 

• The extent to which the pipeline is buried; 

• The environmental impacts of local site disturbance; 

• Onshore landfill requirements; 

• Risks that leaving them unburied would pose to other users of the sea; 

• The depth of the water; 

2-35



• Size and service of the pipeline; 

• Safety considerations; 

• Risks posed by decommissioning to other pipelines and cable crossings; 

• The risk of a pipelines movement over time. 

The preferred method of pipeline recovery is by reverse lay. Recovery of flexible pipelines 

via reverse lay using a reel-lay vessel is common place on the UKCS. The 3” MEG pipeline is a 

rigid steel pipeline but it has a certain amount of flexibility so it is anticipated that it could be 

recovered by reeling without any need for excavation along the route. Any associated 

structures could be removed via reversal of standard construction techniques. Recovery of 

the 3” MEG pipeline would disturb the seabed but the area impacted is unlikely to be 

significant and experience has shown that benthic community recovery times are short. 

Reverse lay of rigid pipelines via S-lay or J-lay recovery is fraught with a greater number of 

challenges due to the high stresses associated with recovering this type of pipeline. Given 

the water depth along the Breagh pipeline route it is likely that the 20” production pipeline 

would be recovered via reverse S-lay recovery. 

However due to uncertainty regarding the future condition of the concrete coating and the 

pipeline, the high stresses associated with this method means that it involves a degree of 

technical risk and risk to the personnel involved in any recovery operation. Spalling of 

concrete during the lifting process and the potential for the pipeline to shear as it is pulled 

onto the vessel may result in injury from flying material and the loss of concrete and pipeline 

lengths to the seabed. Removal of rockdump would require disturbance of the existing 

marine habitat. 

Recovery of the 20” export pipeline using hydraulic shears and cutting on the seabed is also 

possible but would be very time consuming and diver intensive resulting in increased risk to 

personnel. In addition, transfer of the pipeline sections to the vessel has similar risks to 

those described for removal by reverse lay and does not significantly reduce the risk of loss 

of material on transfer. 

If the 20” export pipeline were recovered the majority of it would go to landfill. Experience 

has shown that the process of removing concrete and epoxy coatings from pipeline, 

necessary for the recovery of the steel is a difficult and labour intensive process. Crushing 

the pipeline to remove the concrete may be possible providing that LSA scale is not present. 

Full recovery of the pipelines is likely to result in the highest cost of the available options but 

future financial liability would be eliminated and there would be no requirement for 

continued monitoring. 

Well abandonment 

A drill rig or intervention vessel will be required to plug and abandon the production wells. 

Cement plugs will be set across the reservoir sections, across casing shoes and in the 

conductor casing. The conductor casing will be cut below the seabed. The abandonment 

will follow current legislation (UKOOA, 2001), or to guidelines applicable at the time. 

2-36

NUI removal 



It is expected that the decommissioning of the NUI will be undertaken in reversal of the 

installation procedures. That is, the topsides will be separated from the jacket and lifted by 

crane onto a transport barge for transportation to shore for recycling and onshore disposal. 

Similarly the jacket legs will be severed below the seabed and the jacket lifted by crane onto 

a transport barge for transport to shore for recycling and onshore disposal. 

A detailed decommissioning plan will be submitted to DECC. The date of cessation of 

production and the commencement of decommissioning of associated facilities will depend 

upon field performance, field economics and host facility operating costs. 

2.12. TGPP 

The Teesside Gas Processing Plant commenced operation in 1992. The plant was constructed 

to process gas from the Everest and Lomond fields transported via the Central Area 

Transmission System (CATS) for use as a fuel for the then newly constructed 1,875 megawatt 

(MW) Teesside Power Station. The TGPP subsequently expanded, with the construction of a 

second train in 1994. Train 2 was commissioned in 1996 and was initially used to process 

gas from the Andrew field with the processing of J-block gas commencing in 1997. The gas 

processing and transportation services have continued to be expanded to respond to more 

recent gas importation projects including Excelerate’s LNG Gasport facility on the River Tees. 

A 10 km onshore section of 20” export pipeline (Figure 2-19) will connect with the 20” 

offshore export pipeline at the beach valve house to transport the Breagh gas to TGPP for 

processing and export. 

2-37



Figure 2-19 Onshore pipeline and TGPP 

A number of modifications will be required to TGPP to receive the Breagh gas. Construction 

activities are expected to last 18 months and include: 

• Ground clearance and site preparation; 

• Piling installation; 

• Concreting; 

• Structural steel erection; 

• Process plant construction; 

• Excavation and groundworks; 

• Building erection; 

• On site works e.g. tank fabrication; 

• Main Plant Items installation, piping, valves and instruments; 

• Pre-commissioning works; 

• System pre-conditioning tests and handover. 

It is not anticipated that there will be any new sources of emissions to air associated with 

the operation of the additional plant. Similarly, there will be no new discharges to water 

from the operation of the additional plant. Waste water arising from glycol recovery and 

regeneration unit will be taken off-site via tanker (RWE, 2010). 

2-38



Solid waste arising as a result of the operation of the additional plant will be managed 

according to the existing procedures implemented at the TGPP to facilitate the appropriate 

management, storage and disposal of waste. The existing TGPP is operated according to the 

limits and conditions specified in an Environmental Permit issued by the Environment 

Agency. An application will be made to the Environment Agency for a variation to that 

permit to encompass the operation of the new plant. 

The construction and laying of the landfall section of the export pipeline from MLWS to the 

beach valve house, the construction of the onshore 20” export pipeline, modifications to the 

TGPP and the operation of the plant are assessed under a separate EIA and associated ES as 

required under the Town and Country Planning Act. 

2-39

3. Baseline Environment 


Section 3 - Baseline Environment 

In this section we describe the baseline environment, that is, the current nature and status 

of the relevant offshore development area and the pipeline route which has been assessed 

from the Breagh A installation to Mean Low Water Springs (MLWS) at the landfall. This 

information will provide a basis for assessing the potential interactions of the proposed 

development with the environment. 

The section has been prepared with reference to available literature (referenced), expertise, 

previous experience and survey data. A total of seven surveys have been undertaken to 

support the Breagh Development consisting of pipeline route surveys and well site/rig site 

surveys. These are: 

Pipeline Route Surveys 

• ‘Phase I’ Inshore Pipeline Route survey (ORISIS), completed Sep/Oct 2009, (Ref C9031). 

• ‘Phase II’ Inshore survey (OSIRIS), completed April 2010, (Ref C10003) 

• ‘Phase I’ Offshore Pipeline Route Survey (Breagh East to Teesside Pipeline Route Survey 

UKCS Quads 40, 41 and 42) (Gardline), completed Jul/Aug 2009, (Ref 8120) 

• ‘Phase II’ Offshore Pipeline Route Survey (Breagh East to Teesside Pipeline Route Survey 

UKCS Quads 40, 41 and 42) (Gardline), completed Feb 2010, (Ref 8272) 

Well Site/ Rig Site Surveys 

• Debris Clearance Survey UKCS Block 42/13 Proposed Location 42/13-3 Breagh West 

(Fugro),completed June 2008, (Ref 9664.2) 

• UKCS 42/13 –D, Breagh East Rig Site and Environmental Baseline Survey including a 

herring spawning ground survey (Gardline), completed May/June 2008, (Ref 7629) 

• UKCS 42/13 – A, Site Survey and Environmental Baseline Survey including a herring 

spawning ground survey (Gardline), completed March/April 2006, (Ref 6723) 

A summary of the survey results are given below, with specifics included within the relevant 

sections describing the baseline environment. Further survey details are available in 

Appendix E. 

3-1


Section 3 - Environmental Baseline 

Breagh Site Surveys 

The site surveys found the depth of the water to vary between 59.3m LAT and 62.3m LAT 

with the average gradient across the site being



The tidal currents are reported to be up to 1.4 knots in the area and therefore just below 

that necessary for successful Herring spawning. 

3.1 Physical Environment 

The physical condition of the environment influences the type and distribution of marine life 

in the area, helps set the design parameters for offshore facilities and influence the 

behaviour of emissions and discharges from offshore facilities. 

3.1.1. The Surrounding Sea 

The proposed ‘Phase I’ Breagh A NUI is in UKCS Block 42/13 of the Southern North Sea (SNS). 

It lies in water depths of approximately 62m, 50km north east of the UK coast and 200km 

west of the median line between the UK and Dutch sectors (Figure 3 - 2). The proposed 

pipeline route will pass through UKCS blocks 42/12, 42/11, 41/15, 41/14, 41/13, 41/12, 

41/11 and 40/16, the maximum water depth along the pipeline route is 81.5m. 

Figure 3-1 Survey area 

3-3



Figure 3- 2 Location of development 

Currents and Tidal Streams 

The speed and direction of water currents have a direct effect on the transport, dispersion 

and ultimate fate of any discharges from an installation. In regions where strong directional 

water currents occur, greater dispersal of discharges will occur. Mixing in the water column 

intensifies with increased tidal current speed. 

Over most of the North Sea, the strength of the tidal streams are generally less than 0.51m/s 

even at mean spring tide. Tidal currents over the proposed development area are relatively 

weak between 0.2m/s and a maximum of 1.3m/s (British Oceanographic Data Centre, 1998) 

(Noble Denton, 2008). 

The general, near-surface pattern of water movement in the proposed development area is 

variable and wind driven. The predominant direction of the currents within the area is 

south to south easterly (Figure 3 – 3) and have a uniform speed between the surface and 

midwater reducing towards the seabed. 

3-4

Figure 3 - 3 Schematic diagram of the general circulation in the North Sea 



Table 3 – 1 shows that the surface and seabed currents likely to be exceeded once per year 

are 1.3m/s and 0.8m/s respectively (Noble Denton, 2008). 

Table 3 - 1 Maximum currents 

1 Year 10 Year 

Current Direction Velocity cm/s Velocity cm/s Velocity cm/s Velocity cm/s 

(From) 

Surface Seabed Surface Seabed 

North 1.3 0.8 1.4 0.8 

Northeast 0.5 0.2 0.5 0.3 

East 0.5 0.2 0.5 0.3 

Southeast 1 0.6 1.1 0.6 

South 1 0.6 1.1 0.6 

Southwest 0.5 0.2 0.5 0.3 

West 0.5 0.2 0.6 0.3 

Northwest 1.3 0.8 1.4 0.8 

3-5



Wave Height 

Waves are the result of wind action on the sea surface and wave size is dependent on the 

distance or fetch over which the wind blows. The wave climate of the area is important in 

terms of the physical energy acting on structures, since this will have a large influence on the 

structural requirements of the design. The wave climate of the North Sea has changed in 

recent years, with a tendency towards increasing wave height. Within the development 

area, the significant wave height of 3m is exceeded 10% of the time and 75% of the time for 

heights greater than 1m (British Oceanographic Data Centre, 1998). Table 3 - 2 shows the 

extreme wave conditions in the development area. The largest waves tend to occur from 

the north and northwest. 

Table 3 - 2 Maximum extreme wave conditions (Noble Denton, 2008) 

Waves Return Period 

1 Year 10 Years 50 Years 100 Years 

Max Height (m) 13.0 16.0 18.0 18.9 

Time period between 

wave crests (s) 

3-6 

11.6 12.8 13.6 14.0 

Salinity 

Like temperature, salinity affects marine organisms and the properties of seawater. 

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. As salinity decreases, the solubility of effluents increases. In general, the salinity 

of the southern North Sea is lower than in the central/northern North Sea as a result of 

greater freshwater inflow from rivers. 

A slight seasonal variation in the surface salinity of the water exists in the development area, 

34.75 in the summer and 34.60 in winter (British Oceanographic Data Centre, 1998) with the 

average salinity being in the region of 34.70 (Figure 3 – 4). In the region of the development 

the trend over the last few years has been one of increasing salinity, however some coastal 

areas which are influenced by increase river inputs have been observed to have a decreased 

salinity.



Figure 3 - 4 Average Winter Bottom salinity calculated from the ICES International Bottom 

Trawl Survey Quarter 1 for 1971-2000 (Marine Scotland, 2007). 

Temperature 

The temperature of the sea affects both the properties of the sea water and the fate of 

discharges and spills to the environment. 

Average sea surface temperature in the area of the development throughout the year range 

from 5.5 o C in winter and 14.5 o C in summer. The water temperature at the sea bed is similar. 

It ranges between 6 o C in the winter and 12-14 o C in the summer (British Oceanographic Data 

Centre, 1998). Mean water temperatures in the vicinity of the Breagh Development are 

shown in Table 3 - 3 and Figure 3 - 5. The trend over the last few years has been for 

increasing temperature in the North Sea. 

Table 3 - 3 Mean water temperature for the Breagh development area (British 

Oceanographic Data Centre, 1998) 

Locations Mean temperature in winter ( o C) Mean temperature in summer ( o C) 

Sea surface 5.5 14.5 

Sea bottom 6 12-14 

3-7



Figure 3 - 5 Average Winter Bottom temperature calculated from the ICES International 

Bottom Trawl Survey Quarter 1 for 1971-2000 (Marine Scotland, 2007) 

During late spring a thermocline forms in the water column, separating a warmer and less 

dense surface layer of water from the rest of the water column, where winter temperature 

remains. The thermocline increases in depth between May and September, and is typically 

between 50m to 20m deep during August and September (OSPAR, 2000). During autumn, 

the variable weather conditions and seasonal cooling at sea surface result in the mixing of 

the surface and bottom layers and the disruption of the thermocline. Water temperature 

remains relatively uniform through the water column during the winter months (Doody et. 

al., 1993). 

The likelihood of the sea to layer in this way can be estimated from the water depth (H) and 

the maximum tidal stream velocity at the surface (U) as log10 (h/U3). If the answer is 

greater than 2 then it is likely that a thermocline may form in the summer months. The 

development area has a value of approximately 2 therefore there may be some layering in 

the summer months. 

Water Quality 

Regional inputs from coastal discharges in the North Sea and localised inputs from existing 

oil and gas development in the area may affect water quality. Typical concentrations of 

heavy metals in the water column of the SNS are shown in Table 3 -4. Generally, higher 

levels of contaminants are found in the SNS than the NNS, for example lead, copper, iron 

and vanadium. This is attributed to the lower salinity and the higher inputs of fresh water 

from river sources in the SNS (SEA 2001). 

3-8



The impacts of contamination on marine organisms are primarily in two mechanisms: 

• Passive diffusion or active uptake is associated mostly with the contaminants in 

the water column and thus on pelagic species. 

• Absorption from the gut is associated mostly with the contaminants in the 

sediments and thus on benthic species. 

Elevated levels of contaminants can affect the organisms in a variety of ways (UK Marine 

SACs Project, 2001): 

Heavy Metals 

Heavy metals are toxic at low concentrations and bioaccumulate in aquatic organisms. The 

impacts can, therefore, affect humans from consumption of contaminated fish. Table 3 -4 

shows typical concentrations of heavy metals within the SNS. 

Total Hydrocarbons (THCs) 

The effect of elevated concentrations of hydrocarbons is very dependent of the type of 

hydrocarbon. The potential effects include impacts on the reproductive, development and 

behavioural process. 

PAHs 

Polyaromatic Hydrocarbons (PAHs) generally absorb to particulate matter/suspended solids 

as they have low water solubility and are hydrophobic. Background concentrations of PAHs 

are usually found at levels below the limit of detection and Polychlorinated biphenyls (PCBs) 

are typically less than 1ng/l. 

The primary risk from PAHs is that some are carcinogenically active metabolites with the 

impacts including acute toxicity, liver neoplasm and other abnormalities. As with heavy 

metals the risks associated with elevated PAH concentrations are to both aquatic organisms 

and humans as a result of consuming contaminated fish and shellfish (MPMMG , 1998). 

PCBs 

PCBs will usually be found in the sediment rather than the water column as they are likely to 

absorb to particulate matter and have relatively low water solubility. 

They have been identified as endocrine disruptors and have been shown to be toxic to 

aquatic organisms at a range of concentrations between 12µg/l to 10mg/l, however the 

main concern with PCBs is their potential to bioaccumulate. 

3-9



Table 3 - 4 Concentration of dissolved heavy metals and organics in the SNS (British 

Oceanographic Data Centre, 1998) (Sheahan. et al., 2001) 

Compound Concentration 

3-10 

PAHs 

Seabed Sediments 

Overview 

Mercury 4ng/l 

Manganese 1.0µg/l 

Zinc 2µg/l 

Nickel 0.25 µg/l 

Copper 0.4 µg/l 

Cadmium 0.050 µg/l 

THC 0.5-0.7 µg/l 

Benzo[a]pyrene 0.002-0.004 ng/l 

Fluoranthene 0.104-0.264 ng/l 

Benzo[b]fluoranthene 0.003-0.009 ng/l 

Indeno[1,2,3]pyrene 0.006-0.012 ng/l 

PCB



referred to as ‘ageing’, and is especially important for sediments with historic contamination 

such as prolonged discharge of drill cuttings or produced water. 

Sediment Characteristics 

A summary of the sediment characteristics identified in the seven Breagh surveys are given 

in Table 3 - 6. Further details of the surveys are provided in Appendix E. 

Table 3 - 6 Summary Sediment Characteristics from Surveys 

Survey Area Surveyed Single and 

Multibeam echo 

Inshore 

pipeline 

Survey 

‘Phase I’ 

Inshore 

Pipeline 

Survey 

‘Phase II’ 

Offshore 

Pipeline 

Survey 

‘Phase I’ 

and 


Debris 

Clearance 

UKCS 

43/12-D 

Breagh 

East Rig 

Site 

Survey 

UKCS 

42/13-A 

Site 

Survey 

KP 84.915 to 

landfall at KP 

103.958 

KP99.5 to 

KP103.5 

KP0.00 to 

approximately 

KP101.00 

1km by 1km 

centred on 


location 

334193.73mE 

6052949.75mN 

2km by 2km 

centred on 

Breagh East 

Location 

337166e 

6050324 

2km by 2km 

centred on 


Location 

334184.9E 

6052960.0N 

sounders 

Sands or silty 

sands with 

variable gravel 

and bedrock 

Predominantly 

sand 

Seabed 

sediments 

predominantly 

comprise sand 

with components 

of gravel and silt 

Silty sand with 

numerous 

patches of gravel, 

cobbles and 

boulders 

Fine sand with 

areas to the west 

with exposed 

underlying chalk 

and clay to the 

east. 

Silty sand with 

patches of gravel, 

cobble and 

boulders. 

Note: KP is a Kilometre Point from the Breagh A NUI. 

Camera Imagery Particle 

Distribution 

Analysis 

N/A N/A 

Sand Predominantly fine 

to very fine sand 

Fine sand in the 

outer regions, 

increasing gravel 

and shell debris 

closer to shore. 

Boulders fields of 

varying size are 

also present 

throughout 

majority of route 

Varied throughout 

pipeline route, see 

pipeline reports 

- See Breagh A Rig 

Site Survey 

Fine sand seabed Wentworth 

Classification – fine 

sand 

Modified Folk 

Classification - 

Fine or silty sands 

with some areas 

of visible shell 

content and the 

occasional 

coble/exposed 

rock. 

Sand 

Wentworth 

Classification – fine 

sand 

Modified Folk 

Classification - 

Sand 

3-11



Note: The Breagh East rig site survey described above is at a different location to the planned Breagh East 

Appraisal well (late 2010/early 2011) and shall be subject to a separate survey prior to submission of a PON15B 

application. 

The site surveys found fairly uniform sediment distribution within the development area 

characterised by fine sand with gravelly patches. Generally, these sands are likely to be 

organically deficient and are unlikely to absorb petroleum hydrocarbons and have elevated 

levels of heavy metals associated with them. This, in combination with the currents in the 

area, indicates that it is unlikely that contaminants will build up in the area. 

The sediment along the pipeline route predominantly comprises of sand and gravel. Boulder 

fields of varying density are present through much of the pipeline route, more details are 

found in Appendix E. 

Sediment Contaminants 

The general trend in hydrocarbon concentration is a gradient; higher in the SNS to lower in 

the NNS with the contamination being largely localised to the installation/activity either drill 

location or the discharge point (Sheahan et. al., 2001). This is attributed to the sediment 

type rather than water depth or sediment mobility (Gatliff, 1994). 

For PAHs there is some evidence that the concentration is higher in the NNS than the SNS. 

Table 3 -7 shows the background concentrations to heavy metals, PAH’s and PCB’s in the 

southern North sea (Sheaham et, al., 2001). 

Table 3 - 7 Concentration of heavy metals and organics in the sediment of the Southern 

North Sea (Sheahan et. al., 2001) 

Compound Concentration (mg/kg) 

Mercury 0.1 

Manganese - 

Zinc 200 

Nickel 40 

Copper 40 

Cadmium 0.4 

THC - 

Benzo[a]pyrene



hence the discharge is not anticipated to have any significant effect upon the surrounding 

environment. The OBM will not be discharged into the marine environment, it will be 

contained and then skipped and shipped to shore for disposal. 

Table 3 - 8 Summary table of sediment chemical analysis (mean and standard deviation for 

site survey) 

Compound Breagh East Rig 

Site Survey 

PAHs 

(mg/kg) 

Breagh A Rig Site 

Survey (mg/kg) 

Mercury BDL BDL 

Manganese NT NT 

Zinc 23+/-5 15+/-2 

Nickel 3.8+/-2.1 3.2+/-0.2 

Copper 0.8+/-0.2 1.6+/-0.1 

Cadmium 0.04+/-0.02 13+/-1 

THC 2.7+/-0.5 1.4+/-0.1 

Benzo[a]pyrene - - 

Fluoranthene - - 

Benzo[a]fluoranthene - - 

Indeno[1,2,3cd]pyrene - - 

Total PAHs 0.127+/-0.05 0.085+/-0.024 

PCB NT NT 

BDL = Below detection limit NT = not tested 

OSPAR has developed and adopted ‘Ecological Assessment Criteria’ (EAC) as a method of 

assessing the degree of contamination in sediment (Table 3 - 9). EAC are defined as the 

‘Concentration level of a specific substance above which concern is indicated’ (OSPAR, 

2000). 

Table 3 - 9 Ecological Assessment Criteria for Sediment 

Compound Concentration (mg/kg dw) 

Mercury 0.05-0.5* 

Manganese - 

Zinc 50-500* 

Nickel 5-50* 

Copper 5-50* 

Cadmium 0.1-1* 

THC - 

Benzo[a]pyrene 0.1-1* 

Fluoranthene 0.5-5* 

Benzo[a]fluoranthene nd 

Indeno[1,2,3cd]pyrene nd 

PCB 

* = These values are provisional 

0.001-0.01* 

nd = no data available or insufficient data available 

nr = not relevant 

PAHs 

3-13



In general the concentration of heavy metals and organic matter in the SNS and with the 

Breagh area are below the values which raise concern in line within OSPAR‘s EAC. 

The results of the Total Organic Matter (TOM) and Total Organic Carbon (TOC) analyses were 

low and consistent across the site survey area, Table 3 - 10. Generally speaking, sands and 

coarser grained materials are often organically deficient. Strong currents have a tendency to 

resuspend fine materials and their associated organic matter. 

Table 3 - 10 Summary of Total Organic Matter and Total Organic Carbon in sediments from 

the site survey areas 

Survey Total Organic Matter (TOM) Total Organic Carbon (TOC) 

UKCS 42/13A Site Survey 0.5 - 0.9% 0.3% 

UKCS 42/13D Site Survey 0.5 - 0.7% 0.3 - 0.4% 

The pipeline route surveys showed that concentrations of metals, TOC’s, TOM’s increase 

towards land. The results therefore showed that contaminant concentrations were 

terrestrially influenced and the strength of this influence increased as distance to land 

decreased. Further details of concentration levels of contaminants along the pipeline route 

can be found in Appendix E. 

3.1.2. Offshore Climate 

The North Sea is situated in temperate latitudes with a climate that is strongly influenced by 

the inflow of oceanic water from the Atlantic Ocean and by the large-scale westerly air 

circulation, which frequently contains low pressure systems. The extent of this influence 

varies over time. As a result the North Sea climate is characterised by large variations in 

wind direction and speed, a high rate of cloudiness and relatively high precipitation. 

Wind 

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. 

Historic data from 54.0N – 55.9N, 2.0E – 3.9E (Figure 3- 6) shows that westerly winds are 

most frequent although the direction is variable, with north-easterly and south-westerly 

winds being most common during winter and summer and south-westerly and westerly 

winds being most common from July to September. The calmest months are May to August 

and the windiest months are December and January with wind speeds of greater than 

Beaufort Force 7 one to three days a month and six to ten days a month, respectively. 

3-14



Figure 3- 6 Wind roses for the area 54.0N – 55.9N, 2.0E – 3.9E (Korevaar, 1990) 

Ambient Air Quality 

Ambient air quality data is not gathered offshore, therefore information for rural Scotland 

(Strath Vaich, 1997) is assumed for the North Sea and is presented in Table 3 – 11 (AEA 

Energy and Environment). 

Table 3 – 11 Ambient concentration of NO2 for Strath Vaich 

Averaging Time µg/m 3 

Average 1.0 

98 th Percentile 7.5 

99.9 th Percentile 16.0 

100 th Percentile 

Converted assuming an ambient air temperature of 10 

16.8 

o C 

Closest statistic to 99.8 th Percentile available, which is a conservative assumption 

3-15



3.2. Biological Environment 

3.2.1. Benthos 

Overview 

The organisms living near, on or in the seabed are collectively called the benthos. Various 

terms are used in order to distinguish different benthic species in terms of their life habits. 

Species living within the sediment are termed infaunal species (e.g. burrowing clams). 

Epibenthic species such as seaweeds live with either all or most of their bodies out of the 

sediment, the term epifaunal being used in the case of animals, e.g. limpets. Semi-infaunal 

animals, including sea pens, live in the sediment/water interface zone (Levington, 1995). 

However, benthic species may also be classified in terms of their size. Macrobenthos are 

organisms greater than 1mm in size, microbenthos are smaller than 50µm and the 

meiobenthos (50µm to 1mm) lie in between. These classifications, together with examples 

of representative groups, are shown in Table 3 - 12. 

Table 3 - 12 Categories of Benthic Organisms 

Examples of Representative 

Size Categories 

Groups 

Macrobenthos (>1mm) 

Meiobenthos (50µm to 

1mm) 

Microbenthos (



Benthic animals display a variety of feeding methods. Suspension and filter feeders capture 

particles which are suspended in the water column (sea pens) or transported by the current 

(e.g. mussels). Deposit feeders ingest sediment and digest the organic material contained 

within it. Other benthic species can be herbivorous, such as sea urchins, carnivorous or 

omnivorous. Bacteria and benthic organisms play a major role in the decomposition of 

organic material that originates from primary production by phytoplankton is surface water 

and settles on the seabed (North Sea Task Force, 1993). Bacteria degrade hydrocarbons 

through its utilization as a food source (Clark, 1996). 

Seabed sediments provide a habitat and a food source for many species. Infaunal species 

are particularly vulnerable to external influences, which alter the physical, chemical or 

biological community of the sediment. Such infaunal organisms are largely sedentary and 

are thus unable to avoid unfavourable conditions. Each species has its own response and 

degree of adaptability to changes in the physical and chemical environment. Consequently 

the species composition and relative abundance in a particular location provides a reflection 

of the immediate environment, both current and historic (Clark, 1996). Surveys of the North 

Sea show that the benthic fauna is characterised by water depth and seabed type (Figure 3 - 

7, (MESH 2004)) with depth mainly influencing epifauna, whilst sediment characteristics are 

more important for the infauna (Basford et. al., 1990) 

The recognition that aquatic contaminants may alter sediment characteristics, together with 

the relative ease of obtaining quantitative samples from specific locations, has led to the 

widespread use of infaunal communities in monitoring the long-term impact of disturbance 

to the marine environment. 

Activities that result in the disruption of the seabed such as the deposition of discharged drill 

cuttings can affect the benthic fauna (Clark, 1996). 

In the SNS the diversity and species abundance are generally low, since the physical 

parameters cause disturbance to the sediment and inhibits the development of more 

diverse fauna. 

3-17



Figure 3- 7 Benthic community distributions in the North Sea (Mesh 2004) 

Benthic Surveys 

Benthic surveys have been undertaken in the development area and along the proposed 

pipeline route. All analysis was undertaken following standard methods. Details of these 

can be found in the relevant survey reports. 

The results of this analysis are summarised below with more detail about the surveys given 

in Appendix E. 

Overall, the fauna community was largely uniform within the site surveys, with low numbers 

of both taxa and individuals spread largely evenly across both sites. The most dominant 

taxa, polycaetes, are generally typical of the region, water depth and sediment type. 

Multivariate analysis carried out on the samples from both surveys showed there to be a 

high level of similarity between samples indicating that the community found across the 

area is highly uniform which is indicative of a relatively stable environment that has not 

been subject to a recent significant point source anthropogenic contamination. The ten 

most common taxa found from the two rig site surveys are listed in Table 3 - 13. 

3-18 

Breagh Field



Table 3 - 13 Most common taxa found by the macrofaunal analysis in the site surveys 

Rank Breagh East Rig Site Survey Breagh A Rig Site Survey 

1 Bathyporeia elegans Paramphinome jeffreysii 

2 Echinocyamus pusillus OPHIUROIDEA spp. (juv.) (Brittle Stars) 

3 Corymorpha nutans Chaetozone christiei 

4 Nuculoma tenuis NEMERTEA spp. 

5 Owenia fusiformis Owenia fusiformis 

6 Scoloplos armiger Scoloplos armiger 

7 Sthenelais limicola Spiophanes bombyx 

8 Goniada maculate Eudorellopsis deformis 

9 Urothoe elegans Mysella bidentata 

10 Abra prismatica Goniada maculata 

The benthic community along the pipeline route generally appeared diverse and free from 

pollution impact across the proposed route (Gardline, 2009). Species present were 

characteristic of the associated sediment types and spread evenly across the various taxa. 

There was generally no clear dominance of any one particular species at any station. 

The variability in benthic community across the proposed route was controlled by the 

corresponding changes in physico-chemical properties of the sediment, which appeared 

predominantly natural and were generally due to changes in the physical environment. The 

elevated THCs at Stations ENV11 and ENV13, where evidence of petrogenic contamination 

was found, were associated with subtly impacted communities. Likewise the elevated THCs 

at Stations ENV22 and ENV24 resulting from a terrestrial influence, were also associated 

with subtly impacted communities. The communities associated with elevated metal 

concentrations, which were predominantly caused by terrestrial influence, displayed no sign 

of being impacted (Figure 3 – 8). 

3-19



Figure 3 - 8 Contributions of five gross taxonomic groups (individuals) according to station 

(Gardline, 2009) 

Note: 

- ENV 1 – 24 are environmental sampling stations selected between KP00.00 and KP95.00 

- It was not possible to use day grabs at ENV3, 4, 10, 12, 20 and 23, due to the rocky and gravel content of the 

substrate 

- Stations ENV14, ENV16 and ENV17 were excluded as they were not complete in time for inclusion in report 

On behalf of OSIRIS an inshore survey was undertaken by CMACs, encompassing a corridor 

of seabed from the shallow subtidal to a point four kilometres from the coast. A total of 903 

individuals from 53 unique taxa were recorded in the eight analysed grab sample replicates. 

The samples became progressively richer with increasing distance from the coast with just 

two taxa in sample 1C (approximately 0.25km from shore) and 36 in 4A (approximately 4km 

from shore) (Figure 3 - 9). Table 3 – 14 lists the top ten taxa found during the sampling. 

Figure 3 – 9 Number of species and taxa found at the inshore sampling stations 

40 

400 

35 

350 

30 

300 

25 

250 

20 

200 

15 

150 

10 

100 

5 

50 

0 

0 

1B 1C 2A 2B 3A 3C 4A 4B 

1B 1C 2A 2B 3A 3C 4A 4B 

Number of taxa 

3-20 

Sample 

Number of individuals 

Sample



Table 3 – 14 A list of the ten most abundant species found in marcofauna analysis (CMACS, 

2010) 

Species Name Type of Organism No. of No. of Samples 

Individuals Containing Species 

Chaetozone christei Annelida 332 7 

Bathyporeia elegans Crustacea 101 5 

Magelona filiformis Annelida 61 6 

Tanaissus lilljeborgi Crustacea 51 6 

Bathuporeia guillamsoniana Crustacea 49 3 

Magelona johnstoni Annelida 43 4 

Ophiuridae sp. Juv. Echinodermata 24 5 

Chrysallida sarsi Mollusca 20 3 

Nucula sp. Juv. Mollusca 19 4 

Pontocrates arenarius Crustacea 16 6 

The seabed immediately to the south of the proposed pipeline route between KP99.5 and 

KP103.5 was predominantly sand with a small proportion of silt and gravel at certain 

stations. The fauna was dominated by cirratulid, magelonid polychaetes and pontoporeiid 

amphipods indicating a community of small, short-lived organisms. In addition, there were 

occasional larger longer-lived taxa such as terebellid and capitellid polychaetes. Following 

any local disturbance event is expected that recruitment from the surrounding sediment 

would be rapid (CMACS, 2010). 

In addition, an extensive benthos and epibenthos survey was undertaken in July 2004 in 

support of the Teesside windfarm development (EDF Energy (Northern Offshore Wind) Ltd, 

2004), which is located immediately north of inshore section of the pipeline route. Fortyfour 

sites were sampled using a 0.1m 2 grab sampler. The samples were all within 6km of the 

shore and a summary of the top ten taxa found is shown in Table 3 – 15. 

Table 3 – 15 A list of the ten most abundant taxa found in marcofauna analysis (EDF, 2004) 

Species Name Type of Organism No. of 

No. of Samples 

Individuals Containing Species 

Sabellaria spinulosa Polychaete worm 2440 4 

Abra nitida Bivalve 6992 46 

Nucula nitidosa Bivalve 430 37 

Abra albe Bivalve 403 25 

Magelona johnstoni Polychaete worm 336 48 

Veneridae jux. Bivalve 245 46 

Ensis spp. Juv Bivalve 177 48 

Chaetozone setosa Polychaete worm 154 46 

Bathyporeia elegans Bivalve 148 42 

Mysella bidentata Bivalve 111 4 

The highest number of individuals identified during the EDF survey was Sabellaria spinulosa, 

however it was only found in high numbers at two of the stations, although from the report 

it was not clear if these were found as solitary individuals within the grab samples or 

aggregated into a mat or ‘reef like’ structure. The two stations recording the high numbers 

of S. spinulosa, are situated approximately 2km southeast of the proposed pipeline route. 

3-21



In the UKCS 42/13A site survey uninhabited S. spinulosa tubes were found in 9 samples, no 

other Sabellaria structures were observed during either the site or pipeline route survey 

samples. 

The Ross worm S. spinulosa is a sedentary, epifaunal polychaete worm, which builds rigid 

tubes from sand or shell fragments. It is a suspension feeder primarily found in the shallow 

sublittoral and is abundant in English waters as solitary or low-lying aggregations (Hayward 

& Ryland, 1990). S. spinulosa is not an obligatory reef building species and is often widely 

scattered as a minor component of the biota (Limpenny, et al 2010). It should be noted, 

however, that dense aggregations of this species do not necessarily correspond to the 

occurrence of a visible reef (Foster-Smith & Hendrick, 2003). S. spinulosa may also form thin 

crusts which, although extensive in some cases, are ephemeral in nature. Strong winter 

storms may cause the disappearance of these crusts with rapid recolonisation taking place 

during calmer conditions. Such crusts do not form a stable biogenic habitat and 

establishment of a rich associated community does not occur. They are therefore not 

considered to be true S. spinulosa reefs (Foster-Smith & Hendrick, 2003). 

Sabellaria spinulosa reef, in the context of the Habitats Directive, is considered to be an area 

of S. spinulosa which is elevated from the seabed and has a large geographic extent. 

Colonies may be patchy within an area defined as reef and show a range of elevations 

(Gubbay, 2007). In UK waters elevations created by Ross worm tubes of up to 30cm have 

been recorded and geographic extents of more than 1km (Gubbay, 2007). 

Table 3 - 16 Threshold ranges proposed for the reef characteristics elevation, spatial extent 

and coverage, which could be used in combination to determine whether an area might 

qualify as a S. spinulosa reef (Gubbay, 2007). 

Elevation (cm) 

(average tube 

height) 

3-22 

Not a reef 

Extent (m 2 ) 1,000,000 

Coverage (%) 30 

Note: The figures above are not fully agreed thresholds and intended for guidance, as an indication of the 

starting point to reef identification. 

Neither crusts or any ‘reef’ like structures were encountered in the Breagh site or pipeline 

route surveys. 

3.2.2. Plankton 

Planktonic organisms live freely in the water column, drifting with the water currents, 

unable to swim against them. Phytoplankton are the primary producers of organic matter in 

the marine environment and form the basis of marine food chains. They are grazed on by 

zooplankton and larger species such as fish, birds and cetaceans are ultimately dependent



upon them. Therefore, the distribution of plankton directly influences the movement and 

distribution of other marine species. 

The composition and abundance of plankton communities varies throughout the year and is 

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 nonplanktonic 

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. Table 3 – 17 summaries the most 

dominant plankton species in the SNS, (SEA 2001). 

Table 3 - 17 most abundant phytoplankton and zooplankton species in the SNS 

Phytoplankton Zooplankton 

Ceratium fusus Total copepods 

Ceratium furca Echinoderm larvae 

Ceratium tripos Para-Pseudocalanus spp. 

Chaetoceros (Phaeoceros) spp. Acartia spp. 

Chaetoceros (Hyalochaete) spp. Temora longicornis 

Ceratium macroceros Evadne spp. 

Thalassiosira spp. Pseudocalanus adult. 

Protoperidinium spp Oithona spp. 

Ceratium horridum. Calanus traverse 

Ceratium longipes Podon spp. 

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 doubling times and there is continual exchange of individuals with the 

surrounding water (North Sea Task Force, 1993). A consequence of rapid doubling times is 

that when light and nutrient conditions are favorable, “blooms” of these organisms can 

develop. Although they are sometimes caused by anthropogenic pollution, algal blooms can 

occur naturally. These blooms occur each spring in the North Sea water with a smaller peak 

in the autumn. 

Additionally, Harmful Algal Blooms (HAB) involving nuisance or noxious species can occur at 

other times of the year. These blooms can result in changes to the ecosystem causing 

discolouration, fish and marine mortality, deoxygenation and foam formation. 

The causes of the HAB include rapid reproduction of a species reduced grazing pressure or 

alterations in light, temperature, salinity and nutrients (Johns & Reid, 2001). 

3.2.3. Fish 

Various fish species in the North Sea are exploited by the UK and other EU country fishing 

fleets. This section details the important species encountered in the vicinity and outlines 

their life cycles. 

3-23



Fish congregate around offshore platforms (Patin, 1999) with the platforms and pipelines 

providing a habitat for certain species. Fish in these areas will be exposed to aqueous 

discharges and may accumulate hydrocarbons and other contaminating chemicals in their 

body tissues. Furthermore, depending on the time of year, spawning and nursery areas for 

juvenile fish may be sensitive to oil and gas activities including discharges, accidental spills, 

drilling and installation operations, and seismic surveys. These sensitive areas need to be 

considered when planning offshore activities. 

Bony Fish Populations 

Various fish species in the North Sea are exploited by the offshore UK and other EU country 

fishing fleets. In addition to these species, there are also migratory species for example 

salmon and trout. This section details the important species encountered in the vicinity and 

outlines their life cycles. The impact on the catch sizes is discussed in Section 3.3.2 on 

commercial fisheries and economic impact. 

The most vulnerable phase of the life cycle of demersal, pelagic fish and shellfish from oil 

pollution and general disturbance is during the egg and larval stage. As can be seen from 

Table 3 - 18 both spawning and nursery regions of a variety of fish species occur in the 

proposed development area. These include economically important species such as cod and 

species whose stocks are outside safe biological limits as defined by ICES (International 

council for the Exploration of the Seas). 

Table 3 - 18 Spawning activity and nursery areas in the region of the development (both 

the NUI and the Pipeline Route) (Coull et. al., 1998), (SEA2, 2001) 

Species J F M A M J J A S O N D Nursery 

Cod 

Herring 

Lemon Sole 

Mackerel 

Sprat 

Sandeel 

Plaice 

Haddock 

Nephrops 

Whiting 

Spawning Peak spawning Nursery Grounds 

Spawning and nursery areas cannot be defined with absolute accuracy and shift over time. 

As such, spawning areas in the vicinity of the Breagh development will also be considered. 

Cod, herring, lemon sole, mackerel, sprat, sandeel and plaice all have spawning grounds in 

the vicinity of the development. The peak spawning periods of various species occur 

between January and July. Figures 3 – 10(a-c) shows the distribution of the spawning 

grounds. From this it can be seen that the spawning areas take place over large areas of the 

North Sea. As such they are unlikely to be significantly affected by the proposed 

development. 

Table 3 - 18 also shows that haddock, lemon sole, whiting, sprat, Nephrops and sandeel have 

nursery areas in the vicinity of the Breagh Development (Coull et. al., 1998). Similarly to the 

spawning grounds and as can be seen from Figures 3 -11 (a-c), the nursery grounds are 

spread over a wide area and thus are unlikely to be significantly affected by the proposed 

3-24



development. However, there are currently restrictions on drilling in block 42/13, 41/19 and 

42/15 (CEFAS), (DECC, 2010). 

Figure 3 – 10a Sandeel and Plaice Spawning Grounds 

Figure 3 – 10b Cod, Herring and Lemon Sole Spawning Grounds 

3-25



Figure 3 – 10c Sprat and Mackerel Spawning Grounds 

Figure 3 – 11a Sandeel and Sprat Nursery Grounds 

3-26

Figure 3 – 11b Nephrops and Whiting Nursery Grounds 

Figure 3 – 11c Haddock and Lemon Sole Nursery Grounds 



3-27



Table 3 -19 summarises the ten fish species which are found in the vicinity of the 

development. 

Table 3 - 19 Overview of the Commercially Important Fish Species found in the Vicinity of 

the Breagh Development (Rogers & Stocks, 2001) (Keltz & Bailey, 2008) 

Haddock Haddock eggs and larvae are pelagic and mainly distributed in surface waters to a 

depth of approximately 40m. The young fish leave their pelagic phase when 

approximately 7 months old and approximately 5cm in length, and enter a bottomdwelling 

(demersal) phase. During the later summer, the juveniles are at their highest 

density off the northeast coast of Scotland (Albert, 1994). 

Cod Cod eggs and larvae are pelagic and mainly distributed in the surface 30m of the 

water column with peak concentrations of larvae in the top 10m and 20m (Rogers & 

Stocks, 2001). 

Plaice Plaice is a benthic species, they spawn throughout the shallower parts of the southern 

North Sea and off the eastern coast of Britain, from Flamborough Head to the Moray 

Firth. Spawning begins in the spring at a water temperature of approximately 6 o C. 

Peak spawning occurs in early January in the eastern part of the English Channel, and 

during February in the Southern Bight, German Bight and off Flamborough Head 

(Muus & Dahlstrom, 1974; Fox et al., 2000). The duration of the planktonic 

developmental stages, two to three months, is long compared with that of many fish 

species. 

Mackerel Mackerel is a pelagic species. In spring, they migrate south to spawn in the North Sea 

between May and July, but they may also spawn along the southern coast of Norway 

and in the Skagerrak (Lockwood, 1978; Dawson, 1991) (Figure 3 -10). The pelagic eggs 

can be found in the central North Sea at depths to 60 m below the surface, but the 

majority are found in the upper mixed layer above 26 m (Coombs et al., 1981). 

Whiting Whiting is a demersal species, they are one of the most numerous and widespread 

species found in the North Sea. As with cod and haddock the juvenile fish are found 

within the first few meters of the water column. The majority of spawning takes place 

in April-May. Hatching typically takes 8 to 12 days depending on the water 

temperature. The spawning season for an individual female lasts at least 10 weeks, 

during which time she releases many batches of eggs. At four years old a single female 

of about 30 cm length may produce 400,000 ripe eggs during a spawning season 

(Hislop & Hall, 1974). 

Herring Herring is a pelagic species, however, during the daytime the shoals remain close to 

the seabed and at dusk move towards the surface. Herring Spawning usually takes 

place at depths of between 15-40m, when herring deposit their sticky eggs on very 

3-28 

specific sediment types, usually gravelly material. 

Lemon Little is known about the spawning habits of lemon sole, and it is thought to spawn 

sole everywhere it is found, throughout the entire year. 

Nephrops In all areas, females mature at about 3 years old and, from then on, carry eggs each 

year from September to April or May. There is a tendency for Nephrops located in 

more northerly waters to spawn later in the year (Farmer 1975). After hatching, the 

larval stage lasts 6 to 8 weeks, before settlement to the seabed. While carrying eggs, 

females come out of their burrows very infrequently, and are naturally protected 

from trawlers Nephrops spend most of their time within muddy sediments emerging 

for feeding, but not travelling far from their burrows. 

Sprat Sprat are found mostly along coasts and in shallow waters. They feed in mid-water in 

water depths of between 0-50m. Most sprat spawn for the first time at an age of 

about two years, and important spawning areas in the North Sea are centred on the 

inner German Bight, the area off the north-western coast of Jutland, and the English



East coast Larval sprat feed in mid-water on copepods, bivalve larvae and mysids. 

Sandeel The five species of sandeel found within UK waters form shoals and bury themselves 

in the sand at night. The eggs of the most predominant species (Ammodytes marinus) 

stick in clumps to the sandy bottom. The larvae drift in the currents before becoming 

demersal at around 2-5 months. 

Two Herring spawning ground surveys were undertaken in support of the development, one 

for the drilling site 42/13-A (Gardline Environmental, 2008) and the other along the vicinity 

of the proposed pipeline route (Gradline Environmental, 2010). A summary of the two 

herring spawning surveys is given below with further details given in Appendix E. 

Herring Spawning Ground Survey for 42/13-A, Breagh A 

The depth at the site ranged from 59.0m LAT to 61.8m LAT. The seabed sediments were 

interpreted as silty sand with patches of gravel, cobbles and boulders. The geophysical data 

and seabed sampling indicated that Quaternary sediments were generally thin, consisting of 

a veneer of silty fine sand overlying silty sandy gravel. In some areas it was noted that the 

gravel was intermittently exposed at the seabed. Particle size analysis using the Wentworth 

Classification found sediment to comprise fine sand or sand using the Modified Folk 

Classification. 

On the whole, it is considered that herring favour relatively shallow water (15-40m depth) 

with strong tidal currents (1.5-3.0 knots). They appear to have a preference for raised banks 

with coarse sediment types such as coarse sand, shell fragments, gravel, small stones and 

rocks (Reid et. al., 2003). As a result of the substrate type being fine sand and the depth of 

the water the herring spawning potential in the area was found to be negligible. 

Herring Spawning Ground Survey for Pipeline Route Survey UK Quads 40, 41 and 42 

The depth along the pipeline route ranged from 32m LAT to 81m LAT. The seabed 

sediments predominantly comprised of sand with components of gravel and silt. Boulder 

fields of varying density are also present throughout much of the route. 

The proposed Breagh to Teesside pipeline route passes through UKCS Quads 40, 41 and 42 

where Herring are reported to spawn between August and October (Coull et. al., 1998). The 

tidal currents are reported to be up to 1.4 knots in this area and therefore when the 

strongest tides are just below the necessary for successful Herring spawning. 

In conclusion, the results show that the potential for herring spawning is either low or nonexistent 

within the proposed pipeline route corridor. This is due to the variables within the 

criteria that govern the suitability of a given environment for herring spawning combining to 

make the seabed poorly suited throughout. For example where gravel was found, the 

seabed composition also included components of sand and fine material resulting in the 

sediment being classified as very poorly sorted. Conversely where the sediment was 

moderately or moderately well sorted, no gravel was found. No evidence of well sorted 

gravels, the seabed type widely considered to be the preferred spawning substrate of 

herring (Drapeau, 1973), was found. This conclusion is further supported by the geophysical 

interpretation, which inferred a seabed composed of predominantly sand with gravel and 

silt components (poorly sorted) through the majority of the route (Gardline 2010). 

3-29



Sharks, Rays and Skates (Chondrichthyes - Elasmobranchii and Holocephali) 

The Chondirchthyes include sharks, rays and skates which, on the whole, are slow growing 

and produce only a few young and are therefore vulnerable to overfishing. Historically they 

have been targeted by commercial fisheries (specifically common skate, long-nose skate and 

angle shark) however overfishing has significantly depleted the numbers in the North Sea. 

Although not often specifically targeted by commercial fisheries anymore they are often 

taken as by-catch which continues to deplete stocks in UK waters. Work is underway to 

develop National Plans of Action for the conservation and management of the 

chondrichthyes. The species identified as being in need of immediate protection are the 

angle shark, common skate, long-noses 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 the Chondichthyes in the UKCS is not extensively documented. However 

from available literature (Ellis et. al., 2004), low numbers of chondrichthyan species may 

occur within the development area these include: 

3-30 

• Spiny Dog Fish (Squalus acanthias) 

• Small Spotted Catshark (Scyliorhinus canicula) 

• Tope (Galeorhinus galeus) 

• Thorny Skate (Amblyraja radiate) 

• Cukoo Ray (Leucoraja naevus) 

• Basking Shark (Cetorhinus maximus) 

• European Sturgeon (Acipenser Sturio) 

• Porbeagle (Lamna nasus) 

Generally, these species occur in small numbers throughout the North Sea at times of peak 

zooplankton distribution and abundance (Rogers & Stocks, 2001). Although present within 

the North Sea they are uncommon and widely dispersed and are unlikely to be found in high 

numbers within the development area. 

3.2.4. Sea Birds 

Sea birds are generally not at risk from routine offshore production operations. However, 

they may be vulnerable to pollution from less regular offshore activities such as well testing 

and flaring, when hydrocarbon dropout to the sea surface can occasionally occur, or from 

discharges such as oil spills. 

Birds are vulnerable to oily surface pollution, which could cause direct toxicity through 

ingestion and hypothermia as a result of the birds’ inability to waterproof their feathers. 

Birds are most vulnerable in the moulting season when they become flightless and spend a 

large amount of time on the water surface. This significantly increases their vulnerability to 

oil spills. 

Figure 3- 12 shows the seasonal distribution of seabirds in the vicinity of the Breagh 

Development (DTI, 2003). It shows that Breagh NUI is in an area of medium importance for 

international concentrations of birds 10 – 49% of biogeographic population. It also shows 

that there are seabird colonies and overwintering waterfowl sites where the pipeline comes 

onshore.



Figure 3- 12 Broadscale distribution of important areas for birds in the North Sea (DTI, 

2003) taken from (Skov et. al., 1995) (Stone et. al., 1995) (Heath & Evans, 2000) (Gibbons 

et. al., 1993) 

The Joint Nature Conservation Committee (JNCC) has produced an Oil Vulnerability Index 

(OVI) for seabirds encountered within each offshore licence block within the North Sea and 

the Irish Sea. For each block, an index of vulnerability for all species is given which consists 

of the following four factors: 

• The amount of time spent on the water 

• Total biogeographically population 

• Reliance on the marine environment 

• Potential rate of population recovery 

Each of these factors is weighted according to its biological importance and the OVI is then 

derived (Williams et. al., 1994). The OVI of seabirds within each offshore licence block 

changes throughout the year (Table 3 - 20 and 3 - 21). This is due to seasonal fluctuations in 

the species and number of birds present in an area. 

3-31



The highest seabird vulnerability in block 42/13 is during January and February and 

September to November (very high). This coincides with JNCCs period of concern for drilling 

in blocks which is between January and April, and September and December. The remainder 

of the year has high vulnerability. Generally seabird vulnerability decreases in the offshore 

water following the winter period when large numbers of seabirds leave the offshore waters 

returning to their coastal colonies for the breeding season. During this breeding period, high 

numbers of breeding seabirds are linked to their colonies and adjacent coastal water for 

feeding. 

The seabird vulnerability along the pipeline route is predominantly high to very high, with 

low to moderate vulnerability occurring in May and April. 

After the breeding season ends in June, large numbers of moulting auks (guillemot, razorbill 

and puffin) disperse widely away from their coastal colonies and into offshore waters. At 

this time these high numbers of birds are particularly vulnerable to oil pollution. 

Fulmar, guillemot and puffin are particularly vulnerable to surface pollutants as they spend 

the majority of their time on the surface of the water. Herring gull, kittiwake and great 

black-backed gulls are less vulnerable as they spend a larger proportion of their time aerial 

and therefore less time on the sea surface (Stone et. al., 1995). 

Table 3 - 20 Oil Vulnerability Index for Seabird within the Breagh Development Area 

Block J F M A M J J A S O N D Overall 

42/7 1 1 4 3 2 2 2 2 1 1 1 2 1 

42/8 1 1 4 1 2 2 2 2 1 1 1 2 1 

42/9 1 1 4 1 2 3 2 2 1 1 1 2 1 

42/11 1 1 ND 3 2 2 2 2 1 1 1 2 1 

42/12 1 1 ND 3 2 2 2 2 1 1 1 2 1 

42/13 1 1 ND 1 2 2 2 2 1 1 1 2 1 

42/14 1 1 ND 1 2 3 2 2 1 1 2 2 1 

42/17 1 1 2 3 2 1 1 1 1 1 1 1 1 

42/18 1 1 2 1 1 1 1 1 1 1 1 1 1 

42/19 1 1 2 1 1 3 2 2 1 1 2 2 1 

Table 3- 21 Oil Vulnerability index for Birds along the Pipeline Route 

41/14 3 1 3 4 2 1 1 1 1 1 1 1 1 

41/13 2 1 3 4 2 1 1 1 1 1 1 1 1 

41/12 2 2 4 4 2 2 1 1 1 1 1 1 1 

41/11 2 2 4 4 2 2 1 1 1 1 1 1 1 

40/10 1 1 4 4 2 2 1 1 1 1 1 1 1 

40/11 1 2 4 4 2 2 1 1 1 1 1 1 1 

Very high 1 High 2 Moderate 3 Low 4 ND =No data 

3.2.5. Marine Mammals 

Marine mammals include mustelids (otters), pinnipeds (seals) and cetaceans (whales, 

dolphins and porpoises), all of which are susceptible to chemical and noise pollution, e.g. 

seismic surveys. 

3-32

Otters 



The otter (Lutra lutra) is a semi-aquatic mammal, which occurs in a wide range of ecological 

conditions, including inland freshwater and coastal areas (particularly in Scotland). 

Populations in coastal areas utilise shallow, inshore marine areas for feeding but also require 

fresh water for bathing and terrestrial areas for resting and breeding holts. Coastal otter 

habitat ranges from sheltered wooded inlets to more open, low-lying coasts. Inland 

populations utilise a range of running and standing freshwaters. These must have an 

abundant supply of food (normally associated with high water quality), together with 

suitable habitat, such as vegetated river banks, islands, reedbeds and woodland, which are 

used for foraging, breeding and resting (JNNC , 2010). Figure 3 – 13 shows the Teesside and 

Cleveland coast is not of importance for Otters (JNCC 2010). 

Figure 3- 13 Distribution of SACs/SCIs/cSACs containing species Otters (Lutra lutra) (JNCC, 

2010) 

Teesside 

Explanation of grades 

A Outstanding examples of the feature 

in a European context. 

B Excellent examples of the feature, 

significantly above the threshold for 

SSSI/ASSI notification but of 

somewhat lower value than grade A 

sites. 

C Examples of the feature which are of 

at least national importance (i.e. 

usually above the threshold for 

SSSI/ASSI notification on terrestrial 

sites) but not significantly above this. 

Pinnipeds 

Seals tend to frequent inshore waters but have been seen from a number of platforms in the 

North Sea (Cosgrove P. , 1996). Both grey seals (Halichoerus grypus) and common seals 

(Phoca vituline) 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 (McConnell et. al., 1984) 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. Transmitters such as VHF (Thompson and Miller, 1990; Thompson et, at., 

1989), and especially satellite relay tags, (McConnell et, at., 1992; McConnell et, al., 1999) 

have revealed that seal movements are on two geographical scales. 

3-33



Common seals were shown to predominantly spend their time at or near haul out sites, 

with short trips to localised offshore areas. They were found to occasionally travel up to 

45km on feeding trips of up to 6 days, although the duration of most trips was less than 12 

hours (Thompson & Miller, 1990). Grey seals on average spend the majority of their time 

within a similar range, with trip duration of less than 3 days, although they occasionally 

make long-distance trips of over 100km (McConnell, Fedak, Lovell, & Hammond, 1999). 

Trips by pups have been reported over large areas, for example from the Isle of May up the 

Norwegian coast and down to the Netherlands (JNCC, 2007). However, the general pattern 

of close proximity to haul out sites suggests that these distant trips are uncommon and are 

possibly made by few individuals (Hammond, 2000). 

A small colony of common seals is located on the Teesside coast adjacent to the 

development area. Data from the Sea Mammal Research Unit (Duck et, al., 2007) records a 

small number of seals (35 individuals) as being present at Teesside in 1994. The Industry 

Nature Conservation Association (INCA) has been monitoring the seal population in Teesside 

since 1989 and currently estimates the population to be between 60 and 70 individuals 

(INCA, 2009). 

Figure 3 - 14 shows the distribution of harbour seals in the UK (JNCC 2007), a small number 

forms a colony in the Teesside, however, there is a much larger population south of Teesside 

in the Wash. 

Figure 3-15 shows the grey seal breading colonies in Britain 2000 -2006. A small colony of 

grey seals is located along the coastline adjacent to the Breagh development. INCA’s report 

states that the Harbour seals in Teesside have also produced pups in previous years, pupping 

season is between late June and Early July (INCA, 2007). 

Tracks of harbour seals were recorded between 2001 (Figure 3-16), females are in blue and 

male are in red (JNCC, 2007). From the figure a number of trips were made to the Breagh 

development area from the colonies in The Wash area, however it should be noted that the 

track data relates to 8 locations around the UK which represents a small proportion of the 

population. 

3-34



Figure 3 – 14 August Distribution (10km squares) of Harbour Seals in Great Britain and 

Ireland between 2006 and 2007 (JNCC, 2007) 

3-35



Figure 3 -15 Grey seal breeding colonies in Britain, distribution by 10km squares, (2000- 

2006) (JNCC, 2007) 

3-36



Figure 3-16 Tracks of Harbour Seals tracked between 2001 and 2005 (JNCC, 2007) 

NOTE: Males are in Red and Females and in Blue 

Cetaceans 

Many of the activities associated with the oil and gas offshore industry have the potential to 

impact on cetaceans. The factors which could cause disturbance include noise or 

obstruction, however the impact will depend on the scale and type of activity. The 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 this food source could have a negative impact on cetaceans. However, generally 

cetaceans have large feeding grounds as such localised contamination in the water column 

around an installation is not likely to have a major impact on individuals. 

Information on the number and distribution of cetaceans is often limited and general, due to 

difficulties in observation and species identification, however the JNCC compiled an Atlas of 

Cetacean distribution in north-west European waters which gives an indication of the types 

of cetaceans and times of the year they are likely to frequent areas of the North Sea (Reid, 

3-37



et. al., 2003). The Atlas is based on a variety of sources, one of which is the SCANS I data 

collected by the Sea Mammal Research Unit at St Andrews University. Additional data has 

since been collected, including the SCANS II data (SCANS II, 2008). 

Low densities of cetaceans have been recorded in the Breagh NUI and along the proposed 

pipeline route development area (Reid et, al., 2003, Stone, 19987, 1998 and 2000). Sightings 

suggest (Table 3 - 22) that white-sided dolphin, white-beaked dolphin and minke whale, 

frequent the area, albeit in low numbers (Figure 3 17 - 20). The Harbour porpoise is the only 

cetacean that occurs in relatively high densities in comparison to other areas of the North 

Sea. (SCANS II). 

Table 3 - 22 Cetaceans likely to frequent the area around the Breagh Development and 

pipeline route (Reid, et. al., 2003) (JNCC, 2008) (SCANS II, 2008) 

Species J F M A M J J A S O N D Abundance Density 

White-sided dolphin 403 0.003 

White-beaked dolphin 403 0.003 

Minke whale 3519 0.022 

Harbour porpoise 88143 0.562 

0-0.001 individuals 0.001-0.01 

1-10 individuals per 100-1000 hrs effort Less than 100hrs 

per hour 

individuals per hour hour 

effort 

Note: The data for white-sided dolphin refers to white-beaked dolphin and white sided dolphin combined due to 

difficulty in distinguishing the two species in the field. 

Table 3 - 23 A summary of population sizes (JNCC 2008) 

White-sided dolphin 

Lagenorhynchus 

acutus 

White-beaked dolphin 

Lagenorhynchus 

albirostris 

Minke whale 

Balaenoptera 

acutorostrata 

Harbour porpoise 

Phocoena phocoena 

3-38 

White-sided dolphin show both seasonal and inter-annual 

variability. They have been sighted in large groups of 10 -100 

individuals. They have been sighted in waters ranging from 100m 

to very deep waters, but also enter the continental shelf waters. 

They can be sighted in the deep waters around the north of 

Scotland throughout the year and enter the North Sea in search of 

food (Reid et. al., 2003). 

White-beaked dolphin are usually found in water depths of 

between 50 and 100m in groups of around 10 individuals, although 

large groups of up to 500 animals have been seen. They are 

present in the UK waters throughout the year, however more 

sightings have been made between June and October (Reid et. al., 

2003). 

Minke whale are a member of the rorquals, the balaenopterid 

family of the baleen whales. They are usually observed in water 

depths of 200m or less and occur throughout the Northern and 

Central North Sea. They are usually sighted in pairs or in solitude; 

however groups of up to 15 individuals can be sighted feeding (Reid 

et, al,. 2003). It appears that animals return to the same seasonal 

feeding grounds (Reid et, al,. 2003). 

Harbour porpoise are frequently found throughout the UK waters. 

They usually occur in groups of one to three individuals in shallow 

waters, although they have been sighted in larger groups and in 

deep water. It is not thought that the species migrate (JNCC, 2008).



Figure 3- 17 Distribution of Atlantic White Sided Dolphin (Reid et. al., 2003) 

Figure 3- 18 Distribution White-Beaked Dolphin(Reid et, al., 2003) 

3-39



3-40 

Figure 3- 19 Distribution of Minke Whale(Reid et, al., 2003) 

Figure 3- 20 Distribution of Harbour Porpoise (Reid et, al., 2003)

3.2.6. Ecologically Important Sites 



The Habitats Directive (Council Directive 92/43/EEC) on the Conservation of Natural Habitats 

and of Wild Fauna and Flora, requires all Member States of the European Union to protect 

certain species and specified habitat types. These habitats and species are to be protected 

by the creation of a series of ‘Special Areas of Conservations’ (SACs), and by various other 

safeguard measures for particular species. The Bird Directive (Council Directive 79/409/EEC) 

on the Conservation of Wild Birds requires member states to nominate sites as Special 

Protection Areas (SPAs). Together with adopted SACs, the SPA network will form the 

‘Natura 2000’ network of sites protected by the Habitats Directive (Refer to Appendix A for 

al list of all applicable environmental legislation). 

The Offshore Marine Conservation (Natural Habitats, &c.) (Amendment) Regulations 2010 

implement the provisions of the Habitats Directive and UK Marine Acts. As part of the 

Habitats Directive provisions, all new projects/developments must assess, either alone or in 

combination, with other plans and projects if they will cause an offence to a marine 

European Protected Species (assessed for the Breagh development in Section 5.5.6). In UK 

waters marine European Protected Species includes all cetaceans, marine turtles and the 

Atlantic sturgeon. 

3.2.7. Annex I Habitats 

Offshore 

There are four habitats listed in Annex I to the Habitats Directive that occur or potentially 

occur in the UK offshore area (EC, 1999): 

• Sandbanks which are slightly covered by seawater at all times 

• Reefs 

• Submarine structures made by leaking gases 

• Submerged or partially submerged sea caves 

The JNCC has development boundaries for SAC sites. These are: 

1. Braemar Pockmarks (candidate SAC) 

2. Darwin Mounds (candidate SAC) 

3. Dogger Bank (draft SAC) 

4. Haig Fras (candidate SAC) 

5. North Norfolk Sand Banks and Saturn Reef (possible SAC) 

6. North West Rockall Bank (possible SAC) 

7. Scanner Pockmark (candidate SAC) 

8. Stanton Banks (candidate SAC) 

9. Wyville Thompson Ridge (possible SAC) 

10. Inner Dowsing, Race Bank and North Ridge (possible SAC) 

11. Haisborough, Hammond and Winterton (possible SAC) 

12. Bassurelle Sandbank (possible SAC) 

13. Hatton Bank (draft SAC) 

Of these four habitat types and the thirteen candidate/draft/possible SACs, four are in the 

vicinity of the development; Dogger Bank and North Norfolk Sandbanks Saturn Reef, Inner 

Dowsing and Haisborough, Hammond and Wintering (Figure - 21). 

None of the environmental surveys undertaken have identified any potential Annex I 

Habitats in either the development area or along the pipeline route. 

3-41



Figure 3- 21 Designated Areas in the Vicinity of the Breagh Development 

The North Norfolk Sandbanks and Saturn Reef 

A series of ten sandbanks which support a range of species which are typical of highly mobile 

fine sand sublittoral sediments and cover an area of approximately 544km 2 . The 

communities change in a westward direction as the mobility of the sandbanks decrease. The 

communities are characterised by species such as Pagurus bernhardus, Liocarcinus 

depurator, Carcinus maenas and Asterias rubens. It forms important spawning and nursery 

grounds for sprat, sole, sandeel, plaice, mackerel and Nephrops, whiting and lemon sole 

(Turnbull et. al., 2005). The Saturn reef is a biogenic reef structure. It is formed by the 

polychaete worm Sabellaria spinulosa through consolidating thousands of fragile sand-tubes 

to create a solid structure that rises from the seabed. 

3-42 

119km 

173km

Dogger Bank 



The area covers an area of approximately 13,405km 2 and extends in an east northeast to 

west southwest direction. It is a sandy mound which is moderately mobile clean sand 

habitat. It has areas of gravelly sand and small patches of sandy gravel and gravel. It is 

characterised by species such as Bathyporeia spp, Fabulina fibula and a wide variety of 

polychaete species. As a result of the Atlantic water from the north meeting the residual 

currents form the Straits of Dover to the south therefore the hydrography of the area is 

energetic (DTI, 2006). 

Inner Dowsing, Race bank and North Ridge 

The area covers approximately 906km 2 and is located off the south Lincolnshire coast. It 

consists of a wide range of sandbank types, including: banks bordering channels, relict linear 

banks and sinusoidal banks. The area contains species such as polychaete and nemertean 

worms and and Sabellaria spinulosa reef communities. The main areas of Sabellaria 

spinulosa reef are found in the south-west of the site. These areas support a diverse 

community of bryozoans, hydroids, sponges and tunicates (JNCC, 2009). 

Haisborough, Hammond and Winterton 

The area covers approximately 1848km 2 and made up of a collection of sandbanks off the 

north-east coast of Norfolk. On the tops of the banks small numbers of polychaete worms 

and amphipods are present. In the troughs between the banks where the sediments are 

more stable bryozoans, hydroids and sea anemones have settled. Bivalves and crustaceans 

are found throughout the site. 

Onshore 

The proposed pipeline route will approach the landfill site between the existing CATs 

pipeline and the Redcar at Coatham Sands Windfarm. A number of protected areas are 

situated around the vicinity of the pipeline route (Figure 3-22). The onshore ES has been 

completed separately and contains further details. 

3-43



Figure 3 - 22 Designated areas in the vicinity of the pipeline route 

Flamborough Head 

The area is located approximately 40km south of the pipeline route. It has been designated 

as an SAC and an SPA under the Birds and Habitats Directives, respectively. It has been 

designated as an SAC for the presence of ‘reefs’, ‘vegetated sea cliffs of the Atlantic and 

Baltic coasts’ and ‘submerged or partially submerged sea caves’ and it has been designated 

as an SPA for supporting 2.6% (1987 count) of the breeding population of kittiwakes (Rissa 

tridactyla). 

Teesmouth and Cleveland Coast 

The pipeline route passes in the vicinity of the Teesmouth and Cleveland Coast Ramsar and 

SPA. The area is a designated SPA and RAMSAR site, due to the large concentrations of birds 

(JNCC, 2008). 

Ramsar sites are selected by criteria set out in the Ramsar convention, the specific criteria 

under which Teesmouth and Cleveland Coast have been designated is for watering birds and 

are as follows: 

• A wetland should be considered internationally important if it regularly supports 

20,000 or more waterbirds. 

• A wetland should be considered internationally important if it regularly supports 1% 

of the individuals in a population of one species or subspecies of waterbirds. 

Teesside and Cleveland Coast supports large numbers of waterfowl (peak winter counts 

9528 for a 5 year peak mean 1998/99 – 2002/03). There are also species present which are 

of international importance: 

3-44 

40km 

95km



• Common redshank Tringa tetanus, 883 inderviduals, representing an average of 

0.7% of the GB population (5 year peak mean 1998/9 – 2002/3) 

• Red knot, Calidris canutus islandica, West and Southern Africa (wintering) 2579 

individuals, repress/enting an average of 0.9% of the GB population (5 year peak 

mean 1998/9-2002/3) 

The SPA designation is for supporting populations of birds that are of European importance 

(listed in Article 4.1 and 4.2 of Annex I of the Birds and Habitats Directive; JNCC, 2008), 

including: 

• During the breading season Little Tern, Sterna albifrons 37 pairs representing at least 

1.5% of the breeding populations in Great Britain (4 year mean 1993-1996) 

• On passage Sandwich Turn, Sterna sandvicensis, 2190 individuals representing at 

least 5.2% of the population in Great Britain (5 year mean 1991-1995) 

• Over wintering Redshank Tringa tetanus, 1648 individuals representing at least 1.1% 

of the wintering Eastern Atlantic – wintering population (5 year peak mean 87-91) 

In addition, the area qualifies under Article 4.2 by regularly supporting at least 20,000 

waterfowl. Including Sanderling Calidris alba, Lapwing Vanellus vanellus, Shelduck Tadorna 

tadorna, Cormorant Phalacrocorax carbo, Redshank Tringa tetanus, Knot Calidris canutus. 

A summary of the species descriptions for each of the birds discussed in this section is given 

in Table 3-24 (JNCC, 2008). 

3-45



Table 3 – 24 Species description of birds within the vicinity 

Little Tern It is estimated that there are 37 pairs at the Teesmouth and Cleveland Coast 

which represents 1.5% of the national population. They nest on the coast 

using sand and shingle beaches and pits as well as tiny inlets of sand or rock 

close inshore. Feeding is close to the colony at a maximum distance of 6km on 

shore and 1.5km offshore. They move south for winter returning to breed 

Sandwich 

Tern 

Ringed 

Plover 

3-46 

during the summer. 

There are only three sites designated for the protection of sandwich terns in 

the UK, of which Teesmouth and Cleveland Coast is one. It is reported that 

there are total number of 2,190 individuals at the Teesmouth and Cleveland 

Coast SPA which comprises 0.6% of the biogeographical population and 5.2% 

of the national population. They pass through Great Britian directly after 

breeding in late July and August and again in spring during March and April. 

Ringed plover migrate through the UK in spring and autumn, mainly in March 

to May and August to September. They feed on invertebrates on sand and 

shingle shores, sandbanks, mudflats, saltmarshes, short grassland, flooded 

fields. They form communal roosts along coast lines close to the feeding 

grounds. The Teesmouth and Cleveland Coast SPA is one of 30 sites designated 

for the protection of Ringed Plover. It is estimated that there are 634 

individuals that pass through the Teesmouth and Cleveland Coast SPA which 

constitutes approximately 2.1% of the national population and 1.3% of the 

biogeographical population. 

Knot Knots migrate through coastal areas in spring and autumn, but also overwinter 

in the Teesmouth and Cleveland Coast SPA, one of 18 sites in the UK which are 

known to support more than 1% of the international population. It is 

estimated that there are 4,190 individuals at the SPA which comprises 1.3% of 

the national population. 

Redshank The Teesmouth and Cleveland Coast SPA supports a population of 1,287 

individuals of Redshank on passage to overwintering or breading sites. This 

comprises 1.1% of the national population. 

A year round ornithological study was undertaken from July 2002 to July 2003 in support of 

the Teesside windfarm development (EDF Energy (Northern Offshore Wind) Ltd, 2004). 

Copies of the tables showing the estimate bird numbers in the Teesside offshore boat study 

area and the total bird numbers counted in the Teesside offshore shore-based study area 

are shown in Figures 3 -23 and 3 -24. The graphs indicate the variations in sightings of the 

species observed throughout the year.

Figure 3 -23 Teesside Offshore, Shore Based Bird Count (EDF 2004) 

Number of Birds 

2500 

2000 

1500 

1000 

500 

0 

Ringed plover 

Knot 

Redshank 

Sandwich tern 

Little tern 

Offshore Bird Counts from Shore 

Figure 3 -24 Teesside Offshore, Bird Count from Boats (EDF 2004) 

Number of Birds 

90 

80 

70 

60 

50 

40 

30 

20 

10 

0 

23/07/2002 

06/08/2002 



29/07/2002 

03/08/2002 

07/08/2002 

21/08/2002 

22/08/2002 

31/08/2002 

03/09/2002 

17/09/2002 

28/09/2002 

14/10/2002 

24/10/2002 

29/11/2002 

01/12/2002 

02/12/2002 

18/12/2002 

31/12/2002 

06/01/2003 

19/01/2003 

21/01/2003 

09/02/2003 

02/03/003 

12/03/2003 

31/03/2003 

11/04/2003 

26/04/2003 

20/05/2003 

29/05/2003 

12/06/2003 

30/06/2003 

21/07/2003 

30/07/2003 

20/08/2002 

03/09/2002 

17/09/2002 

01/10/2002 

Offshore Bird Counts from Boats 

15/10/2002 

29/10/2002 

Knot 

Redshank 

Sandwich tern 

Unidentified tern sp 

12/11/2002 

26/11/2002 

10/12/2002 

24/12/2002 

07/01/2003 

21/01/2003 

04/02/2003 

18/02/2003 

04/03/2003 

18/03/2003 

01/04/2003 

15/04/2003 

29/04/2003 

13/05/2003 

27/05/2003 

10/06/2003 

24/06/2003 

08/07/2003 

3-47



3.2.8. Annex II Species 

Eight species listed on Annex II to the Habitats Directive are known to occur in UK 

waters away from the coast: 

• Bottlenose dolphin (Tursiops truncatus) 

• Harbour porpoise (Phocoena phocoena) 

• Grey seal (Halichoerus grypus) 

• Common seal (Phoca vitulina) 

• Sea lamprey (Petromyzon marinus) 

• Allis shad (Alosa alosa) 

• Twaite shad (Alosa fallax) 

• Otter (Lutra lutra) 

Of these eight species three are likely to occur in/around the Breagh A NUI and proposed 

pipeline route (Reid et, al.,2003; INCA, 2009). 

Harbour porpoise Phocoena phocoena) 

Harbour porpoise Phocoena phocoena appears to favour the continental shelf and may 

make seasonal movements to the coast. This inshore movement appears to be connected 

with the feeding of calves in shallow waters. During this time they have a very intense 

‘social’ life. The highest number of births occur during June and July (although there is, as 

yet, limited evidence concerning where calves are actually born). The young to adult ratio is 

at its highest level during this period. As the end of summer approaches, young and adult 

individuals appear to range more widely together. 

Most of the identified areas with most frequent sightings are in coastal waters. These are 

often areas where there is a high degree of water mixing, sometimes associated with strong 

tidal streams. Such areas have high biological productivity, and are often associated with 

important concentrations of small prey fish. There may be offshore areas supporting similar 

concentrations. However, little is known about these, because of the lack of research effort. 

Grey seal (Halichoerus grypus) 

Grey seals Halichoerus grypus spend most of the year at sea, and may range widely in search 

of prey. They come ashore in autumn to form breeding colonies on rocky shores, beaches, in 

caves, occasionally on sandbanks, and on small largely uninhabited islands. In such locations 

they may spread some distance from the shore and ascend to considerable heights 

At the start of the 2000 breeding season, Great Britain held some 124,000 grey seals. A 

further 300-400 in total are found around the Isle of Man and Northern Ireland. There are 

pupping sites on many coasts between the Isles of Scilly in the south-west, clockwise to 

Donna Nook in Lincolnshire. These rookeries vary greatly in size with the largest being in the 

Inner and Outer Hebrides, Orkney, Isle of May, Farne Islands and Donna Nook. Less than 

15% of pups are born away from the above areas (JNCC 2010). 

Grey seals are known to be present at Teesside and The Wash but only in small numbers and 

are not known to have breeding grounds within the vicinity. 

3-48

Common/Harbor Seal (Phoca vitulina) 



Common seals Phoca vitulina are the characteristic seal of sandflats and estuaries, but are 

also found on rocky shores in Scotland. As pups swim almost immediately after birth, seals 

can breed on sheltered tidal areas where banks allow access to deep water. Seals may range 

widely in search of prey, but individuals often return to favoured haul-out sites 

The common seal Phoca vitulina is widespread around the shores of the UK, but population 

density varies greatly from place to place, with low numbers at many sites. Common seals 

are found from Northern Ireland and the southern Firth of Clyde clockwise round the coast 

to the Thames estuary. The vast majority of common seal haul-outs are found on the coasts 

of Scotland, but with an additional important concentration on The Wash, and a smaller 

number in Strangford Lough, Northern Ireland (JNCC 2010). 

3.3. Socio-Economic Environment 

The need for socio-economic assessment comes directly from EIA regulations which require 

all new projects to consider both positive and negative socio-economic impacts in terms of 

benefits to the local communities and the country and potential interface with existing 

industries and communities. 

3.3.1. Impacts 

Social Impact 

The main social benefits will be short term, and relate to the continuation of jobs in 

construction yards and offshore installation vessels. The development will help maintain 

employment in local services and provide valuable money into the economy. 

Economic Impact 

It is anticipated that the field will commence gas production in Q2 2012, and continue until 

2040. During this time approximately 15.4 Bscm of gas will be produced having a positive 

effect on both reducing UK imports of gas and in providing revenue to the Exchequer. 

Possible Adverse Impacts 

The main area of possible adverse impact is in relation to fishing activity. Although the 

fishing industry generally opposes the addition of new oil and gas offshore installations, it is 

unlikely that there will be any decline in the level of fishing activity as a result of the 

proposed development. A 500m exclusion zone will be in force around the NUI. The 20” 

production pipeline will be coated in concrete and laid directly on the seabed. From 12km 

offshore to landfall the 20” production pipeline will be trenched and buried. The 3” MEG 

pipeline and Fibre Optic cable will be trenched and buried for their entire length to eliminate 

interaction with fishing gear. The 500m exclusion zone around the NUI represents a small 

area within the SNS and the pipelines are designed to be fisherman friendly. Therefore, 

overall the development is unlikely to have a significant impact on fishing effort in ICES 

blocks 38F0, 38F9, 38E8 and 38E9. 

3-49



3.3.2. Commercial Fisheries 

Offshore structures have the potential to interfere with fishing activities as their physical 

presences may obstruct access to fishing grounds. Knowledge of fishing activities and the 

location of the major fishing grounds is therefore an important consideration when 

evaluating any potential environmental impacts from offshore developments. 

The main information source for the distribution of stocks comes from commercial catch 

statistics collected by ICES for statistical source units of 30 nautical miles by 30 nautical miles 

sea areas. In addition, RDUK consulted with The National Federation of Fisherman 

Organisation (NFFO). The purpose of the National Federation of Fishermen’s Organisation is 

to ensure that the fishermen of England, Wales and Northern Ireland have a strong and clear 

voice when decisions are taken affecting their livelihoods, whether those decisions are taken 

in Brussels, London, Belfast or Cardiff. The NFFO provided additional information on local 

commercial fishing which is summarised in Table 3- 25. 

Table 3 - 25 Summary of information supplied by NFFO 

Inner 12nm Mainly demersal trawling but an increase in the use of static gear that 

include pots and nets closer to shore where ground becomes hard and to 

difficult to trawl 

Outer 2/3 of Mainly demersal bottom trawling, vessels range from 12m-21m in length 

pipeline route and use mainly bottom and pair trawling gear with rockhoppers 

Outer 1/3 of 

pipeline route 

Other 

activities 

3-50 

Larger vessels (24 -45m), heavy beam trawling. Generally frequent the 

area throughout the year and their level of activity depend on catches 

within the region 

Crab potting approximately 2.5 – 6nm south of Breagh A location 

The main source for the distribution of stocks comes from commercial catch statistics 

collected by The International Council for the Exploration of the Sea (ICES). ICES has divided 

the North Sea into a number of areas, each of which is sub-divided into rectangles. Each 

rectangle covers 15 license blocks, 30 nautical miles by 30 nautical miles. The Breagh NUI 

and the proposed pipeline will are in ICES rectangles 38F0, 38F9, 38E8 and 38E9. 

Fishing Effort 

Fishing effort is an indicator of the importance of a sea area to the fishing industry. Effort 

may vary considerably from year to year. The assessment of commercial fishing in the 

development area has been compiled using ICES statistical data provided by the Sea 

Fisheries Management Division, Marine Directorate (Sea Fisheries Management Division, 

Marine Directorate, 2009). UK fishermen are obliged to report catch information when 

landing their catches. This information includes quantities of species landed, where they 

were caught and by what method (type of gear/duration of fishing). Figure 3 –25 shows the 

ICES blocks in relation to the development and pipeline route.

Figure 3 – 25 Fishing ICES blocks in development area 



The fishing effort for ICES block 37F0 and 38F0 (the development area) and blocks 38E8 and 

38E9 (the pipeline route) are shown in Table 3 - 26. It shows that the fishing effort by UK 

vessels in UK waters has been decreasing over the last five years. Overall the fishing effort 

within the development area is relatively low in comparison to other blocks where the 

fishing effort can be as high as 20,000 hours per year. 

Table 3 - 26 Fishing Effort (days fished) 

Sum of Effort (Days) 

Year 37F0 38E8 38E9 38F0 Grand Total 

2004 1385 2194 1788 516 5714 

2005 1278 2342 1820 274 5790 

2006 1143 2645 1745 257 5152 

2007 1016 2147 1744 245 4639 

2008 742 1779 1572 546 5714 

Grand Total 5564 11107 8669 1838 27178 

The data obtained from the Marine Directorate (Sea Fisheries Management Division, Marine 

Directorate, 2010) shows that the 37F0, 38F0, 38E8 and 38E9 are predominantly targeted for 

demersal species (Figure 3 -26). Shellfish landings are high for all blocks apart from 38F0. 

There is an unusually high value for pelagic species in block 38F0 in 2008, this is broken up 

by three large landings of Herring in October and November by vessels based in Peterhead. 

The live weight total from ICES rectangles 38F0, 38F0, 38E8 and 38E9 represent less than 

0.9% of the total UK catch in 2008 (Table 3 -26). 

3-51



Figure 3- 26 Quantity Live Catches ICES 37F0, 38F0 and 38E9 (tonnes per year) 

4000 

3000 

2000 

1000 

0 

4000 

3000 

2000 

1000 

0 

Live Weight Caught 

37F0 

Live Weight Caught 

38E9 

Table 3 – 27 Relative contribution of landings from ICES block 37F0, 38F0 38E8 and 38E9 to 

total UK catches (tonnes) 

Year UK total 37F0 38E9 38F0 38E8 37F0 as 

38E9 as 38F0 as 38E8 as 

% UK % UK % UK % UK 

2004 653700 1173 1633 627 822 0.18 0.25 0.10 0.13 

2005 707800 1370 1833 347 1302 0.19 0.26 0.05 0.18 

2006 614200 1180 2089 346 2655 0.19 0.34 0.06 0.43 

2007 610400 2105 1945 366 2401 0.34 0.32 0.06 0.39 

2008 711824 2186 1660 1388 1380 0.30 0.23 0.19 0.19 

Grand Total 2586100 5827 7501 1686 8561 0.23 0.29 0.07 0.33 

There are seasonal variations in catches from ICES 37F0, 38F0, 38E8 and 38E9 with the 

highest catches of demersal and pelagic species being reported during the autumn months 

(Figure 3 – 27). The peak periods for static fishing are July through to November, therefore 

the most sensitive time to undertake offshore pipeline construction (NFFO 2010). 

3-52 

2004 

2005 

2006 

2007 

2008 

2004 

2005 

2006 

2007 

2008 

4000 

3000 

2000 

1000 

0 

4000 

3000 

2000 

1000 

Live weight Caught 

38F0 

Live weight Caught 

38E8 

0 

2004 

2005 

2006 

2007 

2008 

2004 

2005 

2006 

2007 

2008

Figure 3- 27 Seasonal variation in catches from ICES 38F0 and 38E9 

800 

600 

400 

200 

0 

1500 

1000 

500 

200 

150 

100 

50 

0 

200 

150 

100 

50 

0 

0 

Shipping 

38F0 Live weight (tonnes) 2008 

37F0 Live Weight (tonnes) 2008 

38E8 Live Weight (tonnes) 2008 

38E9 Live Weight (tonnes) 2008 



Shellfish 

Demersal 

Pelagic 

Shellfish 

Demersal 

Pelagic 

Shellfish 

Demersal 

Pelagic 

Shellfish 

Demersal 

Pelagic 

The Southern North Sea is a busy sea way with ships following reasonably clearly defined 

shipping lanes. Teesside and Humberside serve as local hubs for shipping traffic in the area 

of Block 48/10a. Bulk, cargo and stand-by vessels, oil and chemical tankers and fishing boats 

operate within the area. Shipping density along the pipeline route and in the vicinity of the 

Breagh field is high to very high (DECC, 2008). 

3-53



Shipping routes passing within 10nmiles of the Breagh location were identified using 

Anatec’s ShipRoutes software (Anatec UK Ltd, 2008). This database is continuously updated 

and takes into account changes to shipping routes necessitated by new and existing oil and 

gas installations. It should be noted that the database does not include details of routes that 

are termed as non-routine traffic, e.g. fishing vessels and traffic to mobile drilling units. At 

the time of producing this environmental statement the data from a 2008 Anatec report has 

been used, a new report is currently being produced for shipping routes for the last six 

months and will be included within the consent to locate application. 

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). Twenty four routes pass within 10 nm radius of the Breagh location (Table 3-28), 

trafficked by an estimated 3,267 vessels per year, an average of 9 vessels per day. 

Of the 24 routes that pass within 10nm of Breagh four pass within 2nm (Figure 3 - 28) 

Table 3 - 28 Ship Routes Passing within 10nm of Breagh Development 

Route No. Description CPA (nm) Bearing (°) Ships Per Year % of Total 

1 Forth-Flushing b 0.5 227 113 3% 

2 Hamburg-Seaham b 0.6 14 3 0% 

3 Faroes-Rotterdam 1.3 256 45 1% 

4 Lerwick-Amsterdam 1.5 81 9 0% 

5 Kiel Canal-Tees* 2.1 5 104 3% 

6 Humber-Harding Field 2.1 272 30 1% 

7 Tees-Ems 2.6 190 40 1% 

8 Hamburg-Tees b 2.7 187 179 5% 

9 Forth-Dover Strait b 2.9 228 554 17% 

10 Tees-Hamburg b 3.0 189 268 8% 

11 Amsterdam-Forth a 3.8 46 48 1% 

12 Rosyth-Zeebrugge a 4.1 229 312 10% 

13 Tyne-Hamburg b 4.2 19 30 1% 

14 Hamburg-Tees c 4.4 191 56 2% 

15 Tyne-Ems 5.9 21 75 2% 

16 Iceland-Rotterdam 6.7 250 280 9% 

17 N Norway/Russia-Humber 7.1 103 235 7% 

18 Amsterdam-Berwick-upon-Tweed 7.4 41 15 0% 

19 Forth-Dover Strait a 7.4 42 693 21% 

20 Peterhead-Dover Strait 7.7 248 70 2% 

21 Aberdeen-Amsterdam b 8.5 60 5 0% 

22 Seaham-Kiel Canal 8.7 7 38 1% 

23 Tay-Amsterdam 8.7 43 15 0% 

24 Sognefjorden-Humber 9.8 107 50 2% 

TOTAL 3267 100% 

Note: CPA – Closest possible approach 

3-54



Figure 3- 28 Mean Shipping Route Positions within 10nm of East Breagh 

3.3.3. Submarine Cables and Pipelines 

The pipeline route surveys identified two telecommunication cables within the vicinity of the 

pipeline (UK-Denmark 4 BT, VNSL North Europe and UK-Germany BT lines), the proposed 

pipeline route will cross these cables at KP86.913 and KP90.595 respectively (Gardline 2010). 

Figure 3 – 29 shows the points where the proposed pipeline route will cross the cables, and 

Figure 3 - 30 is an extract from a cable awareness chart (Kingfisher, 2009). 

3-55



Figure 3 – 29 The cable crossings on the proposed pipeline route 

NOTE: Full PDF drawing can be found in Appendix G 

Figure 3- 30 Cables in the vicinity of the Breagh Development (Kingfisher, 2009) 

3-56 

Cantat 3 

Proposed Pipeline Route 

Pangea 

Breagh Location

3.3.4. Offshore Oil and Gas Within the Vicinity of Breagh 



Block 42/13 and the surrounding blocks have been licensed for oil and gas development, 

however to date there has been very little development in the area (Figure 3 – 31). The 

nearest platforms are listed in Table 3 - 29. By reviewing the Field Development 

Programmes, DECC ensures that licensees take into account implications for other offshore 

oil and gas developments in the area, and the interests of other users of the sea. The 

impacts and their significance of the additional infrastructure, activity and discharges 

associated with this development are discussed in Section 5 of this ES. 

Table 3 - 29 Installations in the vicinity of the Breagh Development 

Installation Distance (km) 

Garrow NUI 45 

Kilmar NUI 61 

Ravenspurn South C 57 

Ravenspurn South B 61 

Ravenspurn North CC 71 

Ravenspurn South A 67 

Cleeton Facilities 61 

Neptune 68 

Minerva 68 

Figure 3- 31 Oil and Gas Infrastructure in the Vicinity of the Breagh Development 

Windfarms 

In December 2000 The Crown Estate announced the first round of UK offshore wind farm 

development. Round 1 windfarm sites are in water depths of less than 20m, and no further 

than 12km offshore. A total of seventeen sites were awarded, to date eleven Round 1 sites 

are either complete or undergoing commissioning. In July 2003 Round 2 windfarm was 

announced and fifteen successful projects were awarded. Of the fifteen sites allocated 

under Round 2, at present the first four are now under construction. 

3-57



In 2008, The Crown Estate announced proposals for Round 3 of offshore windfarm leasing, 

releasing 9 further zones for potential windfarm development, these were of a considerable 

greater distance offshore than previous rounds. 

The areas proposed for the development of windfarms are summarised in Table 3 - 30 and 

displayed in Figure 3 – 32. 

To the north of the proposed pipeline route is the Teesside Windfarm development which is 

scheduled for construction in 2010 (Figure 3 -33). The proposed pipeline route will be 270m 

from the Teesside windfarm boundary at its closest approach. 

Table 3 - 30 Windfarms in the vicinity of the Breagh NUI and Pipeline 

Windfarm Round Distance (km) 

Teesside 1 0.27 

Holdness 3 27 

Dogger 3 51 

West Rough 2 67 

Hubway 2 92 

Triton Knoll 2 112 

Firth of Forth 3 158 

Figure 3- 32 Map showing the location of the areas proposed windfarms 

3-58



Figure 3 - 33 Where the pipeline route comes to shore and Teesside Windfarm 

3.3.5. Shipwrecks 

One ship wreck was identified during the offshore pipeline survey, it is present on the 

pipeline route at KP39.050, with dimensions of 25 x 8 x 5.2m. Ship debris approximately 3m 

in height were identified 96m SSW of the pipeline route at KP76.946 (Figures 3 - 34 and 3 – 

35) 

Figure 3 – 34 The location of the ship wreck on the proposed pipeline route 

Shipwreck 

3-59



Figure 3 – 35 The location of the debris from the pipleline route 

3.3.6. Offshore submarine testing area 

There is a submarine exercise area in 42/13 and around the proposed route. As a result the 

MoD must be notified at least 12 months prior to the sitting of any installation within the 

block. The MoD will respond within 30 days to either state that they are content with the 

location of the installation or to inform the operator that they will need to relocate the 

installation. RDUK have notified MOD and are currently awaiting a response. 

3.4. Overview 

The flora and fauna in the area of the proposed development are typical of those found over 

wide areas of the SNS. 

The development area lies 35km west of the Dogger Bank dSAC. The pSAC’s in the vicinity: 

North Norfolk Sandbanks and Saturn Reef; Inner Dowsing, Race Bank and North Ridge 

Haisburgh; Hammond and Winterton are all over 100km form the development area are 

unlikely to be impacted from the proposed activities. 

The proposed pipeline route will approach the landfall in close proximity to Teesmouth and 

Cleveland coast RAMSAR and SPA. Other onshore protected areas within the vicinity of the 

development are Flamborough Head SAC and SPA (40km) and Humber Flats, Marshes and 

Coast (95km). 

Planktonic populations are widely distributed and numerous in the North Sea. Due to the 

widespread distribution and high numbers of planktonic organisms, and the generally rapid 

dilution of offshore effluents, significant effects of offshore developments on plankton 

populations are considered to be unlikely. 

Bottom living marine organisms are particularly vulnerable to natural or man-made activities 

that cause major disturbances of the seabed, such as deposition of sedimentary material. 

3-60 

Possible shipwreck debris



However, because the majority of offshore species are recruited from the plankton, benthic 

populations can usually recover once the disturbance ceases. 

The development area is a spawning ground for cod, herring, lemon sole, mackerel, sprat, 

sandeel, plaice. The area is also nursery grounds for lemon sole, sprat, sandeel, haddock, 

nephrops and whiting. However, no evidence was seen from the surveys of herring spawning 

sites being present. 

Offshore seabird vulnerability is predominantly high to very high throughout the year. Auks 

such as the razorbill, puffin and guillimot are particularly vulnerable to surface pollutants as 

they spend the majority of their time on the surface of the water. Gills such as the herring 

gull and great black-backed gulls are less vulnerable as they spend a larger proportion of 

their time aerial and therefore less time on the sea surface. 

Cetaceans occur at low densities throughout the year. Most sightings in the development 

area are of the White beaked dolphin, which have been recorded in higher numbers in May, 

June and November. 

There is a small breeding population of common seals on the Teesside coast, the pupping 

season in from late June to early July. 

Fishing intensities are moderate in the development area compared to other regions of the 

North Sea and are predominantly focused on demersal and shellfish. The peak season for 

commercial fishing is during the autumn. 

The shipping traffic in block 42/13 is heavy with four routes within 2nm of the proposed 

development. 

During the pipeline route surveys 2 shipwrecks were identified, however these wrecks are 

not of historical relevance. 

The project is within an area of MOD submarine testing. The MOD have been contacted and 

RWE are awaiting their response. 

The pipeline route runs at it’s closest approach runs approximately 0.27km from the 

Teesside Windfarm. The wind farm has not yet under construction and although it has been 

approved it is uncertain as to when construction will commence. The existing CATS pipeline 

will act as physical divide between both activities. 

The development area is considered to be a typical Southern North Sea offshore 

environment and, while recognising that there are vulnerable concentrations of seabirds at 

certain times of the year, there are no biological or other features that are particularly 

sensitive to the type of development proposed. The development may cause only a 

localised minor effect on fisheries by limiting commercial fishing access to the immediate 

area of operations. 

3-61

4. Environmental Assessment Methodology 


Section 4 - Environmental Assessment Methodology 

In order to determine the impact that a proposed project may have on the environment it is 

necessary to conduct an environmental assessment. This should be a structured 

methodology for the identification and quantification, where necessary, of emissions and 

discharges, for determining the significance of the impact on the environment from these 

and, finally, reporting the mitigation measures used to reduce the impacts. 

Implicit in the EA is a clear and well documented assessment of the impacts from each phase 

of the proposed project. The options screening process, and hence the initial stages of the 

EA, is discussed more fully in Section 2. 

Potential effects are assessed both in terms of their likelihood, how often they occur, and 

their potential significance, their magnitude, as described below. 

4.1. Likelihood 

The likelihood of occurrence of each potential effect was given a score between 1 and 5 

Table 4 - 1. A low score means that the likelihood of an aspect leading to an impact is low. 

Table 4 - 1 Likelihood of realization of an impact 

Activity Duration Likelihood of Event Likelihood Category 

One year to many years Likely More than once a year 5 

One month to a year Possible 

Less than once per year and more 

than one every 10 years 

4 

One week to a month Unlikely 

Less than once every 10 years and 

more than once per 100 yeas 

3 

One day to a week Remote 

Less than once every 100 years and 

more than once per 1,000 years 

2 

Less than a day Extremely remote 

Less than once every 1,000 years and 

more than once every 10,000 years 

1 

4.2. Consequence 

The magnitude of each potential environmental effect was also rated on a scale of one to 

five, five being the most severe, as shown in Table 4 - 2. Where magnitude appeared to fall 

within 2 categories, the higher category was selected. 

4-1


Section 4 - Environmental Assessment Methodology 

Table 4 - 2 Definition of magnitude of environmental effects 

Level Definition 

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 

Severe 5 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 

Major 4 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. 

Moderate 3 Possible but unlikely effect on human health. 

May cause nuisance. 

Possible short term minor loss to private users or public finances. 

Minor 2 Change is within scope of existing variability but potentially detectable. 

Negligible 1 Effects are unlikely to be noticed or measured. 

4.3. Combining Likelihood and Consequences to Establish Risk 

The overall environmental hazard of each environmental aspect was assessed using the 

combination of the magnitude and likelihood scores in 

Table 4 - 3 below. 

Table 4 - 3 Environmental risk classification matrix 

Likelihood 

of 

occurrence 

5 4 

Magnitude of Effect 

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 of moderate risk, additional mitigation measures were 

considered to demonstrate that the risk was as low as reasonably practicable (ALARP). 

These residual aspects are discussed in Section 5. 

4-2

5. Assessment of Potential Impacts and Controls 


Section 5 – Assessment of Potential Impacts and Controls 

This Section presents the results from the identification and assessment of environmental 

impacts from the proposed 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, 3 and 4 of the ES was used to 

identify potential environmental hazards. These hazards were assessed and screened 

against the criteria set out in Section 4. Hazards that: 

• were subject to regulatory control; 

• were found to pose a moderate or high risk to the environment; 

• or those that were raised during the consultation phase; 

were assessed further to determine the significance of the impact and/or risk posed to the 

environment. 

Table 5 - 1 summarises the results from the screening process, with the remainder of this 

Section discussing the results from the additional assessment. Appendix B lists all potential 

impacts identified and assessed. 

Table 5 - 1 Issues identified as requiring further assessment 

Phase / Issue Aspect / Source 

Surface Installation Exhaust emissions from NUI installation vessels 

Phase 

Physical presence of HLV anchors 

Noise associated with piling activities 


Drilling Phase Atmospheric emissions from drilling operations 

Discharge of WBM 

Physical presence of the drill rig on seabed 

Noise associated with drilling activities 


Subsea Installation Exhaust emissions from subsea installation and commissioning 

and Commissioning vessels 

Phase 

Discharge of hydrotest fluids 

Physical presence of pipelay vessel anchors 

Physical presence of 20” production pipeline 

Physical presence of trenching and associated deposits 

Physical presence of rockdump and mattresses 

Noise associated with subsea installation and commissioning vessels 


Production Phase Physical presence of the NUI 


Wider Development Noise 

Concerns 


Transboundary impacts 

Cumulative impacts 

5-1



5.1 Surface Installation Phase 

5.1.1. Exhaust emissions from NUI installation vessels 

Fuel combustion emissions contribute to global atmospheric concentrations of greenhouse 

gases, regional acid gas loads and in some circumstances low-level ozone and photochemical 

smog formation. The greenhouse gases contribute to overall global warming and NOX and 

SOX contribute to acidification and eutrophication and to local air pollution. 

Acid gases, including sulphur dioxide (SO2) and oxides of nitrogen (NOX) dissolve in 

atmospheric water, increasing the acidity of precipitation which can result in vegetation 

damage, acidification of surface waters and land, and cause damage to buildings and 

infrastructure. 

Oxides of nitrogen (NOX), volatile organic compounds (VOCs) and particulates, which can 

contribute to the formation of low-level ozone and photochemical smog, have implications 

for human health including lung function and heart disease. 

The predicted emissions that will result from the installation of the NUI and the associated 

vessel requirements described in Table 2-5 are provided below in Table 5-2. 

Table 5-2 NUI installation vessel emissions in tonnes 

Fuel 

Use 

CO2 NOx N2O SO2 CO CH4 VOC 

Tow Tug 792 2,534 47.04 0.17 3.17 12.43 0.14 1.58 

HLV 1,265 4,048 75.14 0.28 5.06 19.86 0.23 2.53 

HLV Tug 414 1,325 24.59 0.09 1.66 6.50 0.07 0.83 

Anchor 

Handling Tug 

(x2) 

5-2 

288 922 17.11 0.06 1.15 4.52 0.05 0.58 

Standby Vessel 46 147 2.73 0.01 0.18 0.72 0.01 0.09 

Guard Vessel 132 422 7.84 0.03 0.53 2.07 0.02 0.26 

Total 2,937 9,398 174.46 0.65 11.75 46.11 0.53 5.87 

Note: Atmospheric emissions have been calculated using emissions factors from the EEMS Atmospheric 

Calculations Guidance Issue 1.5 (DECC, 2004). 

Most air quality targets are set in the form of ambient targets with the aim of safeguarding 

human health, particularly in urban areas. No air quality targets per se have been issued for 

offshore however the onshore targets are used as a guide. The emissions associated with 

NUI installation operations will take place 50 km from shore, and prevailing winds will tend 

to carry the emissions away from the nearest coastlines. Consequently, dilution and 

dispersion will be high lowering the environmental risk. 

During the screening (Appendix B) the exhaust emissions from the NUI installation vessels 

were assessed as being of moderate risk mainly due to the duration of operations (~ 4



months). However when compared to overall emissions from shipping within UK waters the 

emissions are minimal. 

During 2006 UK domestic shipping emitted 5,500,000 tonnes CO2 (Department for 

Transport, 2010). The CO2 produced by the NUI installation vessels amounts to 9,398 tonnes 

of CO2, which constitutes approximately 0.17% of the annual CO2 figure reported for 

domestic shipping in the UK during 2006. 

Additionally, the vessel emissions are a reasonable worst case estimate and are therefore 

likely to be overestimated. 

Local environmental effects of offshore atmospheric emissions are not expected to be 

significant in view of the high atmospheric dispersion associated with offshore locations (SEA 

2, 2001). 

Mitigation Measures 

1 Subsea installation vessel activities will be optimised to reduce the number of 

vessels and duration of use. 

2 Vessel routes will be optimised to minimise travel time. 

3 Low sulphur fuels will be used in accordance with prevailing EU and MARPOL 

requirements. 

As a result of these reasons and enhanced exhaust emissions dispersion due to local 

weather conditions, the impacts from the NUI installation are not considered significant and 

are within levels associated with normal vessel operations. 

5.1.2. Physical presence of HLV anchors 

The HLV will maintain station at the installation site via the use of an anchor mooring spread 

deploying up to 12 anchors. Anchor mounds can be formed by the deployment and 

recovery of anchors in fine sediments, particularly where underlying clay is present near the 

surface. 

The seabed sediments within the vicinity of the NUI location are composed of sands or fine 

sands overlying chalk. A clay veneer was observed overlying the chalk in areas around the 

NUI location. 

The benthic communities can be physically smothered or disturbed by the anchors and 

anchor mounds. Trawling over anchor mounds may result in sediment being retained within 

the trawl net, with subsequent damage to nets, equipment and catch. Therefore during 

screening the potential damage from anchor mounds was assessed as a moderate impact. 

However, the seabed disturbance caused by the use of anchors will be localised, and the 

benthos are subject to regular sediment disturbance and reworking and the impacted areas 

are expected to recover quickly following any disturbance. Once deployed the HLV will 

maintain station and is not expected to require multiple anchor deployments. The area 

impacted by the HLV anchors will be relatively small in comparison the available habitat 

within the development area. 

5-3



5-4 


4 Pre development surveys shall be carried out to aid anchor placement. 

5 Movement of the HLV will be minimised. 

In consideration of the above and the proposed mitigation measures the physical presence 

of the HLV anchors is not expected to represent a significant impact overall. 

5.1.3. Noise Associated with Piling Activities 

See section 5.5 

5.1.4. Accidental events 

Accidental spills during the NUI installation phase were classified as being of moderate risk 

by the environmental screening. This was a result of perceived public concern, not as a 

result of the specific activities involved with the installation. The risk of accidental spills 

without consideration to public concern is low. 

Risks during the surface installation phase of the development will be covered by the 

installation vessels’ approved Ship Oil Pollution Emergency Plan (SOPEP). An interface 

document between RDUK and the installation contractor will highlight reporting 

responsibilities. 

Seabird vulnerability in block 42/13 is Very High or High throughout the year. No data was 

available for March. During the installation period, August to October, seabird vulnerability 

is High (August) and Very High (September to October). 


The surface installation phase will be covered under the installation vessel’s SOPEP. As 

such legislative requirements will be followed. Mitigation measures include: 

6 Minimise bunkering operations. 

7 Visual inspection of hoses and connections prior to use. 

8 Test certification of loading hoses and valves. 

9 Additionally, pre job ‘tool-box’ talks will highlight the vulnerability of seabirds, and 

stress the importance of minimising the likelihood of a spill. 

Implementation of these control measures will reduce the potential for spills to a low level, 

and therefore the overall risk is considered to be low.

5.2 Drilling Phase 

5.2.1. Atmospheric emissions from drilling activities 



The environmental screening identified the following drilling activities that could pose a 

moderate risk to the environment: 

• Exhaust emissions from the drill rig 

• Exhaust emissions from the drilling support vessels 

• Well Testing 

Combustion emissions contribute to global atmospheric concentrations of greenhouse 

gases, regional acid gas loads and in some circumstances low-level ozone and photochemical 

smog formation. The greenhouse gases contribute to overall global warming and NOx and 

SOx contribute to acidification and eutrophication and to local air pollution. 

Acid gases, including sulphur dioxide (SO2) and oxides of nitrogen (NOx) dissolve in 

atmospheric water, increasing the acidity of precipitation which can result in vegetation 

damage, acidification of surface waters and land, and cause damage to buildings and 

infrastructure. 

Oxides of nitrogen (NOx), volatile organic compounds (VOCs) and particulates, which can 

contribute to the formation of low-level ozone and photochemical smog, have implications 

for human health including lung function and heart disease. 

The predicted emissions associated with drilling activities (displayed in Table 5-3) are based 

on the vessel activity described in Table 2-10 and well clean up described in Section 2-7. 

Table 5-3 Summary of the emissions from the drill rig and support vessels 

Activity and 

Fuel Use/Gas flared 

(tonnes) 

Emissions (tonnes) 

CO2 NOX N2O SO2 CO CH4 VOC 

Drill Rig 4,550 14,560 270.27 1.001 18.20 71.44 0.819 9.10 

Standby 

vessel 

1,365 4,368 81.08 0.300 5.46 21.43 0.246 2.73 

Supply 

vessel 

3,030 9,696 179.98 0.667 12.12 47.57 0.545 6.06 

Well 

cleanup 

4,267 11,948 5 0 0 29 192 21 

Total 13,212 40,572 536 2.31 35.83 169.03 193.63 39.23 

2007 UKCS 

Platform Emissions 

16,994,805 50,580 1,013 1,503 25,236 56,074 71,748 

Breagh as % of 2007 0.24% 1.06% 0.23% 2.38% 0.67% 0.35% 0.05% 


Calculations Guidance Issue 1.5 (DECC, 2004). 

As discussed previously in Section 5.1.1, most air quality targets are set in the form of 

ambient targets with the aim of safeguarding human health, particularly in urban areas. No 

air quality targets per se have been issued for offshore however the onshore targets are 

used as a guide. The emissions associated with drilling operations will take place 50 km from 

shore, and prevailing winds will tend to carry the emissions away from the nearest 

coastlines. Consequently, dilution and dispersion will be high lowering the environmental 

risk. 

5-5



It is estimated that the total of amount of CO2 emitted by platforms in the UKCS reported 

during 2007 was 16,994,805 tonnes. The drilling rig and vessel CO2 emissions associated 

with the drilling phase of the Breagh development totals 40,572 tonnes. This would 

therefore constitute approximately 0.24 % of the annual CO2 figure reported for platforms in 

the UKCS. The vessel emissions are a worst case and are likely to be overestimated. 

The existing EU Directive (1999/32/EC) regarding the sulphur content of marine fuels sets 

sulphur limits of 0.1% for certain fuels within Community territory, including marine gas oils 

and diesel oils used by ships in inland waterways and territorial waters. A new amending 

Directive is in preparation which would introduce a 1.5% sulphur limit for marine fuels used 

by all seagoing vessels in the North Sea, English Channel and Baltic Sea in line with Annex VI 

of MARPOL. The sulphur content of the marine fuel (marine gas and diesel) to be used 

during the Breagh development drilling and vessel activities is 0.1%. 

Well clean-up is necessary to ensure the well no longer contains any drilling related debris 

(mud, brine, cuttings) which could potentially damage the topsides when production begins. 

Emissions of CO2, CH4 and VOCs are higher during clean up than similar emissions from rig 

and vessel activities associated with drilling and completions. However, well clean ups are 

generally quicker activities than well testing (which are used to characterise the reservoir 

fluids and flow regime) and will only be carried out until the well is ready to be handed over 

for production. 

Atmospheric emissions from oil and gas flaring and combustion emission from power 

generation offshore are regarded as a making a minor contribution to national totals (DTI, 

2003). 

Local environmental effects of offshore atmospheric emissions are not expected to be 

significant in view of the high atmospheric dispersion associated with offshore locations 

(DTI, 2003). 

5-6 


10 Minimising the use of fuel and optimising fuel consumption. 


requirements. 

12 The number and duration of use of support vessels will be minimised. 

13 The selected drilling rig will be subject to an audit to ensure it complies with UK 

and project standards. 

14 Minimise the duration of well clean-up activities. 

As a result of the above mitigation measures and the natural dispersion of emissions, the 

impact from atmospheric emissions associated with drilling activities are not considered 

significant and are within levels associated with normal operations. 

5.2.2. Discharge of water based mud and cuttings 

Drilling operations on the Breagh wells will include the use of both OBM and WBM. For each 

well, a total of 933 m 3 of WBM and 627 m 3 of WBM contaminated cuttings will be 

discharged. For the 8 1 /2” sections of the wells 242 m 3 of OBM will be used and 102 m 3 of



OBM contaminated mud generated per well. All OBM and cuttings will be contained and 

shipped to shore for processing. 

In total, 6,531 m 3 of WBM and 4,389 m 3 of associated cuttings will be discharged into the 

water column and ultimately onto the seabed throughout the Breagh drilling campaign. 

Discharge of drilling mud and cuttings has been shown to cause two main effects on the 

benthic environment surrounding the discharge site: physical smothering of the benthos 

with associated suffocation in the immediate vicinity of the well and temporary elevations in 

the levels of barium in the sediment. 

WBM discharges will disperse rapidly in the water column causing an upper plume of fine 

particles that will settle over wide areas, and a lower plume containing cuttings and barite. 

The fine particles drift away and disperse where as the particles in the lower plume settle to 

the seafloor much more rapidly and form a much more concentrated pattern near the 

discharge point (Parker, 2003). Soluble components of the WBM will disperse into the water 

column without settling at all. The plumes of dispersed fines may cause a temporary, 

localised increase in turbidity immediately following discharge of a batch of WBM. 

The cuttings discharged to sea during the drilling of the Breagh wells will cause initial 

physical smothering of the benthos within the immediate area of the well location; however 

re colonisation is expected to be relatively rapid since the mud formulations used are of low 

toxicity with low bioaccumulation potential and are not persistent in the environment. 

Furthermore, in those parts of the SNS, such as the Breagh development location, where 

water currents are strong and sediments coarse, biological effects from drilling discharges 

are likely to be short lived. 

(Daan & Mulder, 1993) Investigated the possible environmental effects of discharges of 

WBM cuttings from a single well site. This survey indicated that in the short term no adverse 

effects on the benthic community were observed from the presence of cuttings. A follow up 

study was carried out a year later which also revealed no adverse effects on the benthic 

community, and further indicated that there was no change to the sediment characteristics 

beyond one metre from the discharge point. The lack of significant changes due to 

discharge of drilling cuttings has also been investigated by other studies (Hartley, 1990); 

(ERT, 1999); (ERT, 2002); (Kingston, 2002) which confirm these conclusions. 

The most common chemical effect of WBM discharge is a temporary elevation of barium 

concentrations of the sediment, which may extend up to 1,000 m from the drilling location 

along the predominant tidal axis. Barium is persistent in the sediment as barium sulphate or 

barium carbonate, 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. 

No drill cutting modelling has been carried out for the Breagh development. This is mainly 

due the results of the surveys, no Annex I habitats were identified within the area and the 

field is over 40km from the nearest SAC (Dogger Bank). From previous experience thought 

that drill cuttings tend not to travel further than 1,000 m from the drilling location, 

therefore, the discharges will localised and short-lived therefore will negligible impact on the 

benthic community within the area. 

5-7



5-8 

Mitigation measures 

15 Maximise efficient use and recovery of drilling mud. 

16 No discharge of oil based mud to sea. 

17 Use of Low Toxicity chemicals in the WBM formulation. 

It is reasonable to assume that, following the implementation of the above mitigation 

measures, the impacts from the discharge of WBM and associated cuttings are not 

significant overall. 

5.2.3. Physical presence of the rig (seabed) 

The contract for the drilling of the Breagh wells has not yet been awarded. It is likely that a 

relatively large jack-up drill rig, similar in size to the Ensco 102, will be required, the impacts 

of which are discussed below. 

Prior to drilling, the rig’s legs are jacked down onto the seabed with the hull raised on its legs 

above the water providing a stable platform. Excessive penetration by the legs into soft 

seabed is prevented by large round feet called “spud cans” or “spud tanks” at the bottom of 

the legs. 

As the legs are pulled out they may leave scars and/or sediment mounds. Seabed 

disturbance caused by the penetration of these legs into the seabed will be influenced by: 

• The nature of the seabed sediments; and 

• The prevailing sediment transport system in the vicinity of the well location. 

The depth of penetration of the legs will be dependent on the shear strength and load 

bearing capacity of the seabed soils; a firm seabed will result in less depth of penetration 

than a soft seabed. Post-disturbance recovery of the seabed is dependent both on the 

strength of the seabed soils and the ability of the hydrological regime to rework disrupted 

sediments and return the seabed to its original contours. Physical disturbance as a result of 

leg penetration can cause mortality or displacement of benthic species in the impacted zone, 

direct loss of habitat and direct mortality of sessile seabed organisms that cannot move 

away from the contact area at seabed contact points. Two factors minimise these impacts: 

• Biological communities are in a continual state of flux and are able to either adjust to 

disturbed conditions or rapidly re colonise areas that have been disturbed. 

• The mobile nature of the seabed sediments in the local area will aid the rapid recovery 

of the disturbed areas, although some seabed scars may persist in the medium term. 

Spud cans typically have a diameter of 18 m and hence three spud cans will disturb an area 

of seabed of no more than 775 m 2 to a depth of 0.5 m within an area of seabed directly 

below the rig. Once the rig has moved off station, it is expected that the indentations of the 

spud cans will fill in with mobile sediment and will be re-colonised by recruitment of 

juveniles and by more mobile species moving in from the edges of the area. 

Jack-ups can be further stabilised by rock dumping onto the spud cans. Due to the fine 

sediment, installations in the SNS often require additional rockdumping to secure the 

installations and prevent scouring.



Mitigation measures 

18 Seabed surveys will be used to ensure the rig is sited properly to minimise the risk 

of scouring occurring. 

19 If Rockdumping is required it will be controlled to minimise the volume required 

and the subsequent subsea footprint. 

20 A post drilling survey will be carried out which will assess the impact from the drill 

rig spud cans on the seabed. 

It is reasonable to assume that, following the implementation of the above mitigation 

measures, the impacts from the physical presence of the rig and any associated rock dump is 

not significant overall. 

5.2.4. Noise associated with drilling activities and support vessels 

Addressed in Section 5.5 

5.2.5. Accidental Events 

Accidental spills during drilling 

Accidental spills during the drilling phase were assessed as being of moderate risk during the 

environmental screening (Appendix B). This is due mainly to the duration of activity and 

worst case scenario potential impacts. 

The Breagh field is a gas reservoir therefore even in the event of a blowout (worst case) 

there would not be a significant liquid hydrocarbon (condensate) release. In the event of 

such an event the mitigation measures detailed in the Breagh OPEP (Appendix F) would be 

applied. 

Therefore, the most likely source of any spills during drilling would be from spillages of fuel 

from the rig itself or from the standby and supply vessels. Possible causes include spills 

during bunkering on the rig or vessel, hose rupture/ disconnection, loss of containment in 

storage tanks on the rig or the vessel. Table 5-4 below lists potential spill sources on the drill 

rig, these are all most likely to occur during transferring and bunkering of hydrocarbons and 

chemicals, mitigation methods will be in place to prevent these events happening and will 

be detailed within the OPEP. In addition to this both the supply vessel and the standby 

vessel which will remain in the area while the rig is on station, may have up to 1,000 m 3 

diesel storage capacity each, the vessels will each have their own approved Ship Board 

Marine Pollution Emergency Plan’s (SOSPEP) in place. 

Table 5-4 Likely Sources of spills on the Drill Rig 

Source 

Diesel storage 

Base oil 

Brine 

Liquid mud 

Cement 

Methanol 

5-9



RPS conducted oil spill modelling on behalf of Sterling Resources for the proposed 42/13-d 

and 42/13-2 wells located at 54° 34’ 21.59” N, 00° 28’ 43.334” E and 54° 35’ 44.156” N, 00° 

26’ 0.929” E respectively. Several spill scenarios were modelled using OSIS, the results of 

which are summarised in Table 5-5. The modelling found that all spills would weather 

offshore and that the probability of oil beaching was zero. 

Table 5-5 Oil spill modelling (RBA, 2008) 

Oil Type Spill Size Scenario 

5-10 

Wind 

Conditions 

Fate of Spill 

Diesel 10 tonnes Operation spill 30 knot onshore Disperses within an hour 

Diesel 

Diesel 

300 

tonnes 

300 

tonnes 

Rig loss 30 knot onshore Disperses within 8 hours 

Rig loss 

Typical 

conditions 

Under typical conditions the 

spill would weather offshore 

Risks during the drilling phase of the development will be covered by the installation vessels’ 

approved Ship Oil Pollution Emergency Plan (SOPEP), and development Oil Pollution 

Emergency Plan (OPEP). An interface document between RDUK and the rig contractor will 

highlight reporting responsibilities. 





The drilling phase will be covered under the installation Development’s OPEP. As such 

best practices and legislative requirements will be followed, including: 







and therefore the overall risk is considered to be low. 

5.3 Subsea installation and commissioning phase 

5.3.1. Exhaust emissions from installation and commissioning vessels 

As discussed in Section 5.1.1, exhaust emissions contribute to global atmospheric 

concentrations of greenhouse gases, regional acid gas loads and in some circumstances lowlevel 

ozone and photochemical smog formation. 

The exhaust emissions from the installation and commissioning vessels were assessed as 

being of moderate risk.



Details of the requirement for support vessels are given in Section 2. The total fuel use for 

all installation vessels is estimated to be 16,440 tonnes (See Table 5-6). 

The predicted CO2 emissions associated with the subsea installation vessels is 52,608 tonnes. 

To put these emissions into context, the overall emissions from UK domestic shipping in 

2006 was 5,500,000 tonnes CO2 (Department for Transport, 2010). Assuming worst case CO2 

emissions of 52,608 tonnes CO2 the CO2 emissions from the subsea installation vessels 

amount to 0.96% of those emitted from domestic shipping during 2006. 

Table 5 - 6 Summary of the emissions from the subsea installation vessels (tonnes) 

Fuel 

Use 

CO2 NOx N2O SO2 CO CH4 VOC 

All Installation 

Vessels 

2006 UK Domestic 

16,440 52,608 977 3.617 65.760 258.108 2.959 32.880 

Shipping 

Emissions 

- 5,500,000 - - - - - - 


Calculations Issue 1.7 (DECC, 2004) 






requirements. 

5.3.2. Discharge of pipeline hydrotest fluids 

After pipelaying and prior to bringing the pipelines into use the pipeline system will be 

hydrotested. 

The 20” production pipeline and 3” MEG pripeline will be flooded with 70,000 m 3 and 500 

m 3 of fluids respectively as part of the hydrotest. The fluids have not yet been confirmed 

but are likely to include corrosion inhibitor, oxygen scavenger, biocide and fluoroscene dye. 

Following hydrotesting the pipelines will be blown down to static pressure. During 

blowdown the hydrotest fluids from both the 20” production pipeline and the 3” MEG 

pipeline will be discharged at the Breagh A NUI location. 

Concern over the impact of hydrotest water is due to the potential impact of chemicals on 

the marine environment. As a result, hydrotesting was identified as a moderate risk to the 

environment. 

Chemical permits will be sought prior to any chemical use or discharge using relevant 

PON15c applications. The hydrotest fluids are expected to rapidly dilute in the marine 

environment. 

5-11



5-12 


28 The types and volumes of chemicals used to test and protect the pipeline will be 

chosen following risk assessment to minimise the impact on the environment. 

29 The discharge of fluids will be carried out in a manner that will minimise the 

environmental impact. 

The above mitigation measures, and the rapid dilution and dispersion in close proximity to 

the discharge point are likely to minimise any potentially significant impact on the 

environment. Thus, the impact of hydrotesting is not considered to be significant. 

5.3.3. Physical presence of 20” production pipeline 

The 20” production pipeline will be concrete coated for stability and laid directly onto the 

seabed for 88 km from the Breagh NUI to 12 km offshore from where it will be trenched. 

The presence of the pipeline will impact on the benthic communities and has the potential 

to interact with fishing gear therefore it was assessed as a moderate risk to the 

environment. 

The benthic communities in the area under the pipeline will be impacted. Assuming a 

nominal width of impact of 0.5 m, the total area impacted by the 20” production pipeline 

will be approximately 0.044 km 2 . As the pipeline will remain on the seabed the benthic 

communities will not recover. 

The existing benthic communities along the pipeline route are characteristic of, amongst 

other factors, the sediment type. The pipeline route survey showed the sediment types to 

comprise mostly of sand and patchy sand with patches of gravel, cobbles and boulders. The 

installation of the concreted pipeline, in effect, changes the sediment type to a hard 

substrate which may cause changes to the local communities. 

The presence of the pipeline on the seabed may cause a hazard to other users of the sea, in 

particular fishing vessels. The following control measures are proposed to minimise the 

impact on other users of the sea. 


30 The pipeline route will be optimised to minimise the pipeline length. 

31 Temporary exclusion zone will be applied during the installation. 

32 Guard vessels will be utilised during trenching and pipelay. 

33 The pipeline will be marked as a hazard on the admiralty charts. 

Due to the relatively small area of seabed impacted and the mitigation measures above the 

overall impact is considered to be low. 

5.3.4. Physical presence of the pipelay vessel anchors 

If a pipelay barge is used for the 20” production pipeline installation, it will progress along 

the pipeline route via the use of an anchor and wire mooring spread system deploying up to 

12 anchors at a time. Assuming that the pipelay barge has to re-lay its anchors every 2.5 km



then the anchors will be re-laid 40 times. The wirelay barge will maintain station at the 

coffer dam via the use of an 8 anchor and wire spread mooring system. 

Anchors can impact on the benthic communities which can be physically smothered or have 

their habitats disturbed by the anchors. Trawling over anchor mounds may result in 

sediment being retained in the trawl net with consequent damage to nets, equipment and 

catch. Therefore during screening the damage caused by pipelay anchors was identified as 

posing a moderate impact. 

Seabed disturbance from the pipelay barge and and wirelay barge anchors will be localised. 

The added impact from anchors will not be significant and the benthic communities are 

expected to recover rapidly as the benthos recolonise the impacted areas upon removal of 

the anchors. 

Anchors and anchor spreads can interact with other infrastructure in the marine 

environment for example pipelines and cables. The 20” export pipeline will be laid parallel 

to the CATS pipeline from KP 96 to landfall. The CATS pipeline is buried however several 

exposures were noted during the survey indicating that it lies close to the seabed surface in 

places. The pipeline route crosses the Pangea and CANTAT telephone cables at 

approximately KP 87 and KP 90.5 respectively. The risk of interaction between anchor 

spreads and subsea infrastructure occurring can be minimised by careful laying of the anchor 

spread to avoid existing infrastructure. 


34 Pipeline lay barge activities will be optimised to minimise anchor re-deployments. 

35 Pre-deployment surveys shall be carried out and will be used to identify anchor 

locations. 

36 The anchors will be laid in such a manner as to minimise the risk of interaction 

between the anchor spread and the CATS pipeline in the near shore approach and 

the CANTAT and Pangea telephony cables. 

In consideration of the above and the proposed control measures the impacts from the 

pipelay barge and the wirelay barge anchors is not considered to be significant. 

5.3.5. Physical presence of trenching and associated deposits 

From the Breagh A NUI the 20” production pipeline will be coated with concrete and laid 

directly onto the seabed for 88 km. The final 12 km section of pipeline before landfall will be 

trenched and mechanically backfilled. This section of pipeline will be trenched using a 

backhoe dredger for the section immediately near to shore with the remainder being carried 

out by trailing suction hopper dredger. 

The 3” MEG line, which will be laid separately to the 20” production pipeline, will be 

trenched along its entire route. From landfall to around 12 km offshore the 3” MEG pipeline 

will be trenched and mechanically backfilled using backhoe dredger for the nearshore trench 

and trailing suction hopper dredger for the rest. The offshore sections of the 3” MEG 

pipeline will be trenched using a plough and allowed to naturally backfill. 

The plough creates a V shaped trench in the seabed. Commonly, the large trenching 

systems employ a plough of approximately 150 tonnes dry weight, which sits on skids on the 

5-13



seabed and is towed by a vessel using a bollard pull of up to 350 tonnes. Pipeline burial 

physically disturbs the benthic communities and their habitat within the trenched area, and 

may cause some smothering of the communities in the wider area due to the excavated 

material. It is estimated that sediment would be deposited 10m either side of the trench. 

The method also creates a temporary plume of suspended solids. Assuming that the 

trenching of the 3” MEG pipeline impacts on a 20 m wide strip of seabed the total area 

impacted by the trenching of the 88 km offshore section of 3” MEG pipeline is 1.76 km 2 . 

Data obtained from the aggregates industry in similar depth of water with similar sediment 

indicates that a plume may be 2-4m thick and extend up to 4.5km downstream of the site 

(Hitchcock & Bell, 2004). 

The two 12 km sections of inshore pipeline will be trenched and mechanically backfilled. 

After dredging, sediments will be deposited adjacent to the trench at a maximum distance of 

3 km for storage prior to backfilling. Backfilling the 12 km nearshore section of trench 

involves returning the excavated material into the trench by discharge from the trailing 

suction hopper dredger or from the barge within which the sediments will be deposited 

from the backhoe dredger. Ploughing and backfilling impacts on an area of seabed up to 20 

m in width. Allowing for a 50% contingency for distribution of the sediments following 

release from the dredger or barge it is assumed that the discharge of sediments impacts on 

a 30m wide area of seabed. Therefore the area impacted by the two 12 km nearshore 

sections of trench, including the area impacted by temporary sediment storage, will be 1.44 

km 2 

Therefore the total area impacted by the two 12 km sections of inshore trench and the 88 

km length of offshore trench is 3.2 km 2 (see Table 2.7). 

Following the backfilling of the trench (either naturally or mechanically) the benthic 

communities will return to normal in a relatively short duration as communities in coastal 

waters are subject to constant disturbance as a result of the currents and are therefore 

characterised by opportunistic species. In addition, it is likely that the benthic communities 

will re-colonise the impacted area in a relatively short time as they reproduce in large 

numbers (North Sea Conference, 1995). 

Notwithstanding this, the following control measures are proposed to minimise the impact 

associated with the trenching. 

5-14 


37 The pipeline route will be optimised to minimise the length of the route. 

38 Ensure that the trenching is successful. 

39 Use survey data to avoid environmentally sensitive areas where possible. 

With these control measures in place the impact associated with this activity is not 

considered significant overall. 

5.3.6. Physical presence of rockdump and mattresses 

It is anticipated that approximately 3,800 tonnes of rock will be required for pipeline 

stabilisation to mitigate upheaval buckling along sections of the pipeline and to provide 

support at the two cable crossings. The approximate locations of the mattresses and 

rockdump are shown in Table 5-7 along with the area of seabed impacted by each section.

3” pipeline 

20” pipeline 

Table 5-7 Rockdump and mattress laying 

Purpose Location 



Mass of 

rock (t) 

Subsea 

footprint 

(m 2 ) 

Number of 

mattresses 

Subsea 

footprint 

(m 2 ) 

Total subsea 

footprint 

(m 2 ) 

Stabilise 500m hot 

end of pipeline 

KP 0 – 0.5 1,500 1,500 - - 1,500 

CANTAT Cable 

crossing 

PANGEA 

KP 90.5 200 200 8 160 200 

Cable 

Crossing 

KP 86.9 200 200 8 160 200 

CANTAT Cable 

crossing 

PANGEA 

KP 90.5 200 200 8 160 200 

Cable 

Crossing 

KP 86.9 200 200 8 160 200 

Postlay rock dump 

As 

required 

1,500 1,500 - - 1,500 

TOTAL - 3,800 3,800 - - 3,800 

The rockdump which may be required to stabilise the 500 m hot section of the pipeline by 

the Breagh A NUI will be located within the 500 m exclusion zone around the Breagh A NUI. 

The rockdumping required at the four cable crossings and the contingency of 1,500 tonnes 

for postlay rockdumping will be will take place outside of the 500 m exclusion zone. 

Table 5-7 shows an estimate of the area of the seabed that will be impacted by the rock 

dumping. These have been calculated making the assumption that each tonne of rock 

dumped impacts on 1 m 2 of seabed. At each of the cable crossings mattresses will be laid on 

the seabed to separate the pipeline from the cables and rock dumped over the pipelines to 

stabilise them and provide protection. The mattresses themselves will be covered in 

rockdump therefore for the purposes of assessment the area impacted upon by the 

mattresses is assumed to be addressed in the assessment of the rockdump. 

Rockdumping and mattress laying have a similar impact that is, disturbance or smothering of 

the benthos and local loss of habitat. However, it is not anticipated that there will be a 

significant additional seabed disturbance from the installation of mattresses or rock dump as 

the rock dumping required for the 3” MEG pipeline and the 20” production pipeline CANTAT 

cable crossing will be within the area already disturbed by the trenching. 

In addition to the loss of habitat and the smothering of the benthos, the rock dumped areas 

may also lead to temporary or permanent exclusion from presently used fishing areas or 

general nuisance to fishing operations because of the potential snag risk. 

The control measures listed below will be employed to minimise the impact of the 

mattresses and rock dumping. 

5-15



5-16 


40 Minimise the volume of rock required by undertaking upheaval buckling analysis. 

41 Use best practice for trenching to ensure the required depth is reached. 

42 Mark rockdump locations on admiralty charts. 

In consideration of the above control measures and the limited area potentially affected, the 

impact of the mattress laying and rock dumping on the benthic communities is likely to be 

low overall. 

5.3.7. Noise associated with subsea installation and commissioning vessels 

Assessed in Section 5.5.1 

5.3.8. Accidental event 

Accidental spills during the subsea installation and commissioning phase were classified as 

being of moderate risk during the environmental screening. This was a result of perceived 

public concern, not as a result of the specific activities involved with the installation. The 

risk of accidental spills without consideration to public concern is low. 

Risks during the surface installation phase of the development will be covered by the 

installation and commissioning vessels’ approved Ship Oil Pollution Emergency Plan (SOPEP). 

An interface document between RDUK and the installation contractor will highlight reporting 

responsibilities. 



is High (August) and Very High (September to October) and measures will be undertaken to 

minimise the likelihood of a spill. 


The surface installation phase will be covered under the installation vessel’s SOPEP. As 

such legislative requirements will be followed. These include: 




46 Pipelines constructed to requirements as per Pipeline Safety Regulations 1996. 





5.4 Production 

5.4.1 Physical presence of NUI 

The presence of the Breagh A NUI was identified as posing a moderate risk during the 

environmental screening due to potential impact on other users of the sea including fishing 

vessels, ferries, tankers and cargo vessels.



A 500m exclusion zone will be in force around the NUI excluding other sea users from the 

development area which will result in a loss of fishing in the vicinity of the platform. 

However, this impacts upon only a small proportion of the available fishing grounds in the 

area and the surrounding area has been subject to development with other infrastructure so 

the incremental impact is small. 

Vessels may have to navigate an alternate route around the NUI to maintain a safe distance. 

However, the NUI structure is itself small in comparison to other facilities in the SNS and 

thus the incremental impact is considered to be small. The navigational risk will be 

minimised through the addition of the Breagh A NUI on the Admiralty charts and the fitment 

of navigational aids to the NUI. 

The physical presence of the NUI will disturb the mobile benthic fauna and smother the fixed 

flora and fauna directly beneath the feet. The total footprint of the Breagh A NUI jacket is 

1,600 m 2 . The total area of seabed disturbed by the presence of the 4 NUI legs will be much 

smaller than this and as a worst case assessment it is considered that the NUI feet will 

impact upon 204 m 2 of seabed. 

The area impacted by the NUI feet is very small in comparison to the available habitat in the 

area and as such the physical presence of the NUI feet will not result in a significant 

reduction of habitat. The benthos is subject to regular disturbance and it is anticipated that 

the area around the NUI subject to any disturbance during installation will recover quickly. 

A ship collision risk assessment is currently being undertaken on behalf of RDUK, the findings 

of which will be considered by the appropriate members of the Breagh project team and 

included within the subsequent CPA application. 


48 The NUIs and the exclusion zones will be marked as hazardous on the admiralty 

charts. 

49 A 500m protection zone will be applied around the NUI. 

50 Navigational Aids Fixed to the NUI. 

With the implementation of the control measures the residual impact on the physical 

presence of the NUIs on other users of the sea is considered to be low. 

5.4.2 Accidental Events 

Accidental spills during the Production phase were assessed as being of moderate risk during 

the environmental screening due to the public perception of spill events. 

The Breagh development will produce mainly gas with small quantities of water and 

condensate. There will be no processing on the NUI and hazardous areas will drain to a 

bunded collection tank. The collected inventory will be removed by tote tank and supply 

boat for disposal onshore. The most likely source of a spill is therefore from the occasional 

maintenance vessel visits. 

5-17



Any vessels used by RDUK will require an approved Ship Oil Pollution Emergency Plan 

(SOPEP), which will highlight reporting responsibilities. 




5-18 


Vessel SOPEP legislative requirements will be followed. These include: 






5.5 Wider Development Concerns 

5.5.1 Noise 

Noise has been identified as having a moderate environmental risk during the screening due 

to the duration of key project activities, and the heightened public awareness of the impact 

of noise on marine mammals. Specifically the following project activities were identified 

during the EIA. 

• Installation of the NUI 

• Drilling 

• Subsea Installation and Commissioning 

The noise sources associated with these phases can be split into: 

• Vessel Activity 

• Drilling Activity 

• Piling 

A comparative table of sources of marine noise from offshore operations is shown in Table 

5-8 below. The level of sea state refers to the amount of noise generated from wind and 

waves, in the absence of man-made noises these are the most dominant contributors to 

ambient noise. The noise levels associated with sea state 1 have been reported to be in the 

region of 60dB re 1Pa with sea states 3 and 5 being 97dB re 1Pa and 102dB re 1Pa, 

respectively. Typical vessel noise source levels are in the region of 174 dB re 1Pa 

(Richardson, 1995).



Table 5-8 Typical noise level associated with offshore operations 

Source 

Source level dB re 1μPa at 

1m 

Dominant frequency (Hz) 

Piling 2.4m pile 240 50-200 

5m zodiac w. outboard 

motor 

152 6,300 

Jack-up drilling rig 140-160 100 

Semi submersible drilling rig 150 100 

Typical fishing vessel 150-160 100 

Tug barge travelling at 12 

knots 

162 630 

Large tanker 177 100 

Seismic airgun 

210-259 depending on array 

size 

10-1000 

Source: (Richardson, 1995; Nedwell & Edwards 2004) 

A sound wave propagating underwater consists of alternating compressions and rarefaction 

of the water. These alternating sound waves can be detected by receivers, such as an 

animals’ ear, as a change in pressure. Underwater sound waves can be generated from a 

number of natural sources such as rain, wind and plate tectonics as well as from man-made 

sources such as vessel traffic. 

The noise generated throughout the project is predominantly underwater noise. Other than 

an increase in vessel noise no onshore noise is envisaged. 

Sensitivity of marine animals to noise 

Loud sounds in the marine environment can cause a number of physical effects upon marine 

animals. There are two types of impact: auditory and non-auditory. Non-auditory effects 

can occur due to the impulse (which takes into account the frequency of the wave) and the 

pressure levels. Sound waves are pressure fluctuations therefore the local ambient pressure 

(noise levels) must be considered when assessing the impact of an operation. 

Of the activities associated with the development only pile driving would be capable of 

generating the sound levels at source capable of causing physical injury to animals. The 

range at which physical injury could occur is dependent upon the propagation of sound and 

the transmission loss that will occur as it travels from the source, which are dependent upon 

the frequency spectra of the sound waves. 

The hearing thresholds of organisms can be presented as audiograms. It has been proposed 

that for damage to occur the received level of sound must be within the particular 

bandwidth for the organisms in question. Audiograms have been measured for various 

species or estimated based on the ear anatomy, frequency of their call and known reactions 

to sounds. Collaborative Offshore Wind Research Into The Environment (COWRIE) 

undertook a review of the available audiograms for fish and marine mammals (Nedwell, 

2007). These have been reproduced below in Figure 5 –1 and Figure 5 -2. 

5-19



Figure 5 - 1 Hearing threshold data for fish 

Figure 5 - 2 Hearing threshold data for specie of marine mammal 

For marine mammals, hearing impairment can occur when sound levels are high and, in the 

case of transient noise sources, such as pile driving, when marine mammals are exposed to 

repeated sounds. The hearing loss can occur in two forms: 

5-20



• Temporary Threshold Shift (TTS): On exposure to noise the ear’s sensitivity level will 

decrease as a measure of protecting. This process is referred to as a 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) have proposed precautionary noise exposure 

criteria for injury (PTS) and TTS onset. These criteria are currently considered the best 

available by JNCC and are based on quantitative sound level and exposure thresholds over 

which PTS-onset could occur for different groups of species. 

For all three types of hearing groups of marine mammals (low, medium and high) Southall 

propose that for single pulses and multiple pulsed sound, such as that generated by piling, a 

sound pressure level of 230 dB re: 1 μPa (peak), or above, will be sufficient to cause a 

permanent threshold shift in hearing. 

In a study undertaken to investigate the effects of offshore wind farm noise on marine 

mammals and fish (Thomsen, 2006) it was observed that pressure levels of 90 – 120dB 

above the hearing threshold for short duration signals could induce TTS. 

Using the dBht approach which applies the hearing threshold of marine mammal data 

(reproduced in figure 5-2) Nedwell (2007) estimated the exposure duration that marine 

mammals would be able to tolerate before the onset of an injury. This indicates that 

exposure levels (sound levels) will need to be very high in order to the duration of exposure 

(injury time) to be short. Although, these results may need to be viewed with caution as the 

dBht approach has not been scientifically validated and is based on a limited number of 

marine mammal audiograms, but is one of the options to predict potential impacts from 

exposure. 

Upon exposure to a source if the mammal would travel away from the source it would be 

exposed to progressively lower sound levels. The rate at which a mammal would leave the 

area will vary and be dependent upon swim speeds. (Nedwell, 2007) produced a graph 

showing the noise dose received by animals vacating an area at 1m/s, 1.5m/s and 2m/s 

(Figure 5 -3 ) starting from 100 m from the source with a starting source level of 139dBht. It 

shows that the noise dose does not exceed 10 Pa 2 .s. which is well below the 29 Pa 2 .s. limit 

which is estimated to cause PTS. 

Table 5 - 10 Comparison of noise exposure level dB above hearing threshold and the 

approximate exposure duration animals capable of causing a permanent threshold shift in 

hearing (Table adapted from Nedwell, 2007). 

Exposure Level (dBht) Exposure Duration 

90 8 hours 

92 5 hours 

99 1 hour 

110 Approximately 5 minutes 

120 Approximately 30 seconds 

130 Approximately 3 seconds 

5-21



Figure 5 - 3 Noise dose received by an animal vacating an area at various rates from an 

initial distance of 100m from the noise source 

5.5.2 Vessel Noise 

Shipping is the largest contributor to anthropogenic ocean noise and in deeper water is the 

dominant noise source between 50-300Hz (Ulrick, 1967). The use of vessels, especially 

Dynamically Positioned (DP) vessels which use thrusters to maintain position, will cause 

locally elevated noise levels through the transmission of noise from the engines, thrusters 

and propellers into the water column. The majority of the sound generated by large vessel 

movements will be of low frequency and due to the properties of the waveform can this 

potentially travel large distances, the use of smaller vessels typically generate higher 

frequencies of noise and can be important sources of localised noise (Wyatt, 2008). Noise 

from shipping movements would incrementally increase background noise levels, but it 

would not be possible to identify any of the sources from the received levels of background 

noise. There are a number of existing shipping lanes in the vicinity of the development and 

the increase in traffic associated with the development will not be significant or interfere 

with any other vessel movements. 

Peak vessel activity will occur during subsea and surface installation a number of vessels will 

be present for these operations and may be manoeuvring at relatively high power. It is also 

possible that several of them will be using DP which has a high noise output including anchor 

handling tugs, standby vessels, guard vessels, reel lay vessels, survey vessels, trenching and 

trenching support vessels, supply vessels and DSVs. A DP pipelay vessel may be used instead 

of the anchored pipelay barge which if used may generate higher sound levels. 

The noise from vessels is not expected to be capable of causing any injury to marine 

mammals, however, short term behavioural effects may be observed amongst cetaceans, 

but the overall impact of these is thought to be negligible. 

5-22

Figure 5-4 Recorded vessel trajectories in the Breagh area 



5.5.3 Drilling Noise 

A study by Richardson (1995) found that the noise generated by drilling activities from a 4 th 

generation semi-submersible, indicated levels that do not exceed local ambient levels 

beyond 1 km, although weak tones were detectable up to 18 km away. Nedwell and 

Edwards (2002) upon measuring drilling noise in 100m of water around a platform has been 

in the order of 10-20 dB above ambient noise over the frequency range 20Hz to 100 Hz with 

clear evidence of tones at 130, 200, 350 and 600Hz which probably originated from resonant 

frequencies of the drill shaft. No studies were available that measured the noise generated 

from jack up drilling rig, but the semi-submersible and platform drilling sounds are likely to 

be comparable to the sounds generated from the jack-up drilling rig used for the Breagh 

development. As rigs are a stationary source, the noise produced is unlikely to vary in 

intensity significantly over time (Richardson et. al., 1995) but is likely to be louder during 

periods of drilling as opposed to non-drilling periods. Thus any effects on sensitive 

receptors, such as cetaceans, are likely to be restricted to a relatively small radius around 

the drilling rig. Drilling noise will be continuous for long periods (non-pulse sound) and not 

comparable to sudden, powerful, repetitive sound associated with seismic airguns or 

percussion piling or even compared to sudden use of vessel DP systems. The impacts of 

drilling noise are therefore not expected to be significant. 

5.5.4 Noise from piling 

The potential impact of noise associated with the installation of NUI is primarily associated 

with piling. During environmental screening, the noise was assessed as posing a moderate 

risk to the environment. The installation of the structure is anticipated to take 

approximately 6 months from load up to completion of commissioning. However, each of 

the piles is anticipated to take a maximum of 1 day to complete. 

Pile driving noise is influenced by the choice of installation mechanism, with impact pile 

driving typically producing greater sound levels that vibratory pile driving. Other factors 

5-23



which determine the sound characteristics generated are the seabed sediments, water 

depth and in the case of impact pile driving if the pile is driven in air or underwater and the 

strike rate and power of the hammer. 

The blast waves associated with piling are of a simple exponential wave of short duration 

(Nedwell, 2007), but the impulse from the pile driving is more complex due to the 

resonances in the pile, seabed and associated machinery. From evidence collected by 

monitoring sounds generated through the installation of piles in the windfarm industry the 

larger diameter piles have been shown to generate greater sound pressure levels. The 

differences in noise levels caused by piling measurements being made at a different 

locations (where seabed conditions and water depth may vary) are relatively insignificant 

and are of less significance than the changes caused by piles of a different diameter being 

used (Nedwell, et al 2004). 

There is in general, no reliable way of predicting the noise levels from sources of 

anthropogenic noise, such as piling. However, a simplistic model which aligns a line of best 

fit between calibrated piling measurements was developed that allows for the prediction of 

source levels when the diameter of the pile is known (Formulae 1). An alternative way of 

explaining this formula is the source level increases by about 24 dB for every metre increase 

in pile diameter. This equation is of use for small and medium size piles, but is not 

appropriate to apply to larger diameter piles (~5m) as the source levels would be an 

overestimate of likely levels due to the model not being able to predict a flattening out of 

the sound levels as would be expected. 

Formulae 1. 

RL = 24.3D + 179 dB re.1µPa @ 1 metre 

Where: 

RL = Received Level (Equivalent to a Source Level at 1m) 

D = Diameter of pile 

The 12 piles required to install the NUI will have a maximum diameter of 2.4 m. Using the 

formulae above the predicted maximum source level is 237.32 dB re 1.@ 1 metre (peak) for 

each pile. 

In order to provide an objective and quantitative assessment of the likely degree of any 

environmental effect upon marine receptors it is necessary to estimate the sound level as a 

function of distance. The formulae below takes into account transmission loss, which is a 

measure of the rate at which sound energy is lost respectively to geometric spreading of the 

sound and absorption of the sound. 

Formulae 2. 

RL = SL- NlogR-αR 

Where: 

RL = Received Level 

SL = Source Level 

N = coefficients relating to geometric spreading of sound 

α = coefficient relating to absorption of sound 

R = range 

5-24



As the water depths at the location of the NUI are relatively deep it is appropriate to use a 

deep water acoustic transmission loss model. In the run of this model the parameters such 

used in the modelling of the Greater Gabbard offshore windfarm study were applied 

(Gardline, 2009). The coefficients used for geometric spreading (N) and absorption of sound 

(α) were 18 and 0.0003, respectively. In the first 100 metres the received levels have 

decreased to 201 dB re 1 µPa@1m and they steadily decrease further with distance from the 

source (Figure 5 -5). 

The sound levels generated by pile driving are expected to exceed the background levels 

(typically 130 – 140dB re1µ Pa) to a distance of approximately 20-24 km. The results from 

the modelling of the sounds from the NUI support Nedwell et al (2007) who found that 

source levels generated by piling can remain above the ambient noise level to a range of 25 

km. It is, therefore, expected that there will be some sound induced effects on both the fish 

and marine mammal species in the area out to the distance at which the sound level 

generated by piling will be masked by the ambient sound levels. 

Figure 5 - 5 Acoustic transmission loss of a source level of 237.32 dB re 1 µPa@1m with 

increasing range (metres) from piling location, marked are sound levels that are 

representative of ambient noise levels and injury thresholds (for cetaceans Southall et al, 

2007) 

Recieved levels dB re1microPa@1m 

260 

240 

220 

200 

180 

160 

140 

120 

100 

Range metres 

Recieved Level 

Injury threshold 

Ambient noise 

Generally, piles are between 20 m and 30 m long and take between 1 and 2 hours to install 

depending upon the pile diameter and substrate type. The hammer blows are of a 

frequency of between 30 - 60 beats per minute and last between 50 ms and 100 ms in 

5-25



duration (Thomsen, 2006). The spectra recorded during piling operations undertaken during 

the Burbo Bank wind farm installation are shown in Figure 5-6 below, in this instance the pile 

diameter was considerably greater (4.7 m) and generated a source level of 249 dB re 1µPa @ 

1m. As can be seen from figure 5 -6 the dominant piling frequencies are those less than 200 

Hz, it is expected that piling of the NUI will generate a similar spectra of frequencies. 

Figure 5 - 6 Spectra for piling at the Burbo Bank wind farm (Nedwell, 2007) 

Analysis undertaken in the COWRIE 2007 report (Nedwell, 2007) identified that at a distance 

of 250m a static harbour porpoise could be exposed to noise during one entire pile driving 

event without harm. It is likely that, upon exposure to audible noise, marine mammals will 

move away from the source and there is evidence from the installation of offshore 

windfarms that marine mammals leave the area when piling commences (Tougard, 2007). 

Thus for multiple pile driving operations, it is unlikely that the noise dose limit of 29 Pa 2 .sec 

which Nedwell proposed as a criteria for auditory injury from exposure events is likely will be 

exceeded. 

An alternative injury threshold to the Southall criteria has been put forward by Nedwell 

based on the hearing thresholds of marine mammals. It has been estimated that 130dB 

above their hearing threshold (termed dBht), is a level which is sufficient to cause injury. A 

COWRIE report provides a graph of the perceived sound levels in dBht for the various species 

during installation of a winfarm pile (Nedwell, 2007)(Reproduced in Figure 5-7). Although 

the sound levels generated in this example of a windfarm are in excess of those expected 

from the piling of the NUI, it can be seen that the 130 dBht injury zone is within 

approximately 10 m of the source, thus only organisms within this area are likely to suffer 

injury, although the use of dBht as a valid injury threshold is currently not validated it does 

tend to support the evidence that the possibility of any type of physiological injury to marine 

mammals would be limited to the immediate proximity of the pile. 

5-26



Figure 5 - 7 Best fit curves for the variation with range of the species continuous perceived 

sound level in dBht units during impact pile drive operations during construction of the 

Burbo Bank Offshore Windfarm 

In conclusion, it is likely that all marine mammal and fish species encountered in the 

development area will be subject to some sound induced effects, however it is unlikely that 

this will only cause injury if the organism is within very close proximity to the operation. In 

order to minimise the impact on marine mammals the following control measures are 

proposed. With these measures in place, the overall noise from the installation of the 

structures is not considered to be significant. 


The JNCC piling protocol will be followed including: 

54 Piling will commence using soft start. 

55 A trained marine mammal observer will be present during piling operations. 

56 A 500 m exclusion zone will be adopted. 

5.5.5 Impacts to Seals 

As discussed in Section 3 a breeding colony of seals is resident at Seal Sands. Whilst seals 

are less likely to visit the Breagh A NUI location they may be temporarily disturbed by the 

vessels involved in the near shore pipeline installation. The area around Redcar is heavily 

industrialised and the seals resident at Seal Sands will already be regularly exposed and 

habituated to vessel noise from vessels using the river Tees. 

The mitigation measures proposed for installation of the manifold should be sufficient to 

avoid any impacts upon seals. 

In view of the existing vessel traffic in the area and low observed marine mammal numbers 

noise disturbance from drilling and support vessel is assessed to be of low significance. 

5-27




57 The duration of vessel use will be minimised where possible. 

58 Minimise the number of vessels used. 

59 Minimise the duration of drilling. 

5.5.6 Impacts to cetaceans and European Protected Species 

Marine European Protected Species (EPS) include cetaceans, marine turtles and the Atlantic 

sturgeon. However, it is unlikely that marine turtles or Atlantic sturgeon will be found in the 

development area in any numbers worthy of further consideration. Therefore, the 

assessment has only focussed on the cetaceans likely to be encountered. 

The Offshore Marine Regulations 2007 (as amended) have a revised definition of 

‘disturbance’ to European Protected Species. The Offshore Marine Regulations extended the 

offence to areas of UK jurisdiction beyond 12 nm. It is now an offence under UK Regulations 

to deliberately disturb wild animals of a European Protected Species (EPS) and an offence 

may be caused by anyone who; 

(a) deliberately captures, injures, or kills any wild animal of a European protected 

species; (termed ‘the injury offence’) 

(b) deliberately disturbs wild animals of any such species (termed ‘the disturbance 

offence’) 

New developments must consider if their activity, either alone or in combination with other 

activities, is likely to cause an offence to a European protected species. Figure 5.8 illustrates 

the suggested approach to a risk assessment for the offence of deliberate injury and 

deliberate disturbance. If there is a risk of injury or disturbance of EPS that cannot be 

removed or sufficiently reduced by using alternatives and/or mitigation measures, then the 

activity may still be able to go ahead under licence. The licence assessment will be carried 

out by the appropriate authority, in the case of oil and gas activities this will be DECC. 

Figure 5 – 8 A suggested approach to risk assessment for offences of ‘deliberate injury’ and 

‘deliberate disturbance’ (Adapted from JNCC, 2010). 

Offshore pilling has been recognised as an activity that could, in certain circumstances, cause 

both an injury offence and a disturbance offence (JNCC, 2010). The loudest sounds 

generated from the Breagh development will be during the installation of the 2.4 m 

diameter piles 237 dB re 1 µPa@1m. If the activity was to proceed without any form of 

5-28



mitigation measures in place, there could be a very minor risk of exposing cetaceans in the 

immediate vicinity of piling operations to noise levels that could cause permanent hearing 

damage. Therefore, there is a very minor risk of causing an injury offence to the cetacean 

species likely to be in the vicinity of the operations. As harbour porpoise is the only cetacean 

that occurs in a relatively high density of animals per 0.562 km 2 the risk of an injury offence is 

most prevalent to this species, there is a far lower risk of exposing animals that have low 

densities per km 2 such as the white beaked dolphin, white sided dolphin and Minke whale 

(Figure 5 – 11). 

According to the sound modelling results the sound levels decrease very rapidly with 

distance from the source as the higher frequencies components are attenuated, it is only in 

the immediate piling zone, within the first few meters, that there is any risk of causing 

injury. 

If the mitigation measures are followed, specifically; adherence to the JNCC piling protocol 

and the use of marine mammal observers then this will be sufficient to ensure that no 

marine mammals are within the 500m zone before the commencement of piling activities. 

Therefore, the risk of causing an injury offence to an EPS is negligible. 

From the modelling carried out from the piling activity the noise levels may not return to 

background levels for up to 20 km from the source or an area of 1,256 km 2 around the 

source. Abundance and density estimates were taken for cetacean species for the southern 

North Sea survey area from the SCANS II survey information, which are currently the best 

available abundance and density estimates for the species in question. The data extracted 

for the densities and abundances were taken from the survey area (U) are shown in (Figure 5 

- 9). A conservative estimate of the number of individuals that could be in the area where 

piling noise is above ambient noise levels is shown in Table 5-11. The greatest number of 

individuals potentially exposed (1220.5) corresponds with the most numerous species, the 

harbour porpoise. For assessment purposes the white sided and white beaked dolphin 

abundance and density estimates were grouped, due to the difficulties in distinguishing 

these animals in the field, only 3 individuals of each of these species are thought to be 

exposed, and this corresponds to 0.75% of the abundance of animals within this area of the 

southern North Sea (SCANS II). 

Figure 5 - 9 Survey areas used to calculate the density of individuals and abundance. 

(Reproduced from SCANS II, 2008) 

5-29



Table 5 - 11 Abundance and density of marine mammals in the development area and 

approximate number of individuals potentially exposed to piling sounds above the 

ambient noise level (Table adapted from SCANS II, 2008). 

5-30 

Species Abundance 

Density 

(individuals per 

km) 

Individuals 

effected 

Percentage of 

abundance in 

area ‘U’ 

Minke whale 3,519 0.022 77.48 2.2% 

Harbour porpoise 

White-sided & 

88,143 0.562 1,220.5 1.38% 

White-beaked dolphin 

Lag. sp. 

405 0.003 3 0.7% 

A disturbance offence as described the Habitat Regulations has been interpreted by JNCC as 

a type of reaction that can cause a sustained or chronic disruption of behaviour scoring 5 or 

more in the Southall et al. (2007) behavioural response severity scale. Although it is possible 

that large numbers of animals could potentially be exposed to the sound from piling 

operations, it is thought that this will generally only induce minor or no behavioural 

responses. As the duration of each piling event spans a relatively short time frame




60 Minimise duration and number of vessels used for the installation of the pipeline. 

61 Ensure that potential for accidental spills is minimised through compliance with 

the relevant legislation. 

5.5.8 Cumulative impacts 

The offshore environment in the vicinity of the Breagh development has not been subject to 

extensive oil and gas development, as described in Section 3.4.4. The closest platform 

(Garrow NUI) is approximately 45 km from the Breagh development where only three wells 

have been drilled to date. Similarly, there is little oil and gas development along the pipeline 

route with the exception of the CATs pipeline adjacent to the coastal section. 

The Teesside windfarm is scheduled for installation north of the pipeline route in 2010. Up 

to 30 turbines will be installed. A transmission cable will transfer power generated to shore 

and will landfall north of the 20” Breagh production pipeline. Pipelaying activities for the 

Breagh development will take place to the south of windfarm during Q3 and Q4 2011 and 

will take place in a controlled construction corridor. In consideration of the works 

undertaken as part of the Teesside Offshore Windfarm and the infrastructure present in the 

area, the presence of the 20” production pipeline and 3” MEG pipeline do not represent a 

significant cumulative impact. 

There is an area with a high level of static fishing activity south of the proposed pipeline 

route with other areas being fished to a moderate level. Similarly, the levels of shipping 

traffic in the area are moderate. 

As described earlier in this section, offshore the emissions to air will be relatively low in 

comparison to those emitted by the oil and gas industry in the UKCS due to the fact that 

processing will take place onshore. 

There will be no gas processing on the NUI, as such there will be no produced water 

discharged to sea. Non-hazardous open drains and overflows will discharge to sea along 

with the small volumes of sewage generated during maintenance visits. Hazardous areas 

will drain to a bunded collection tank and the collected inventory removed by tote tank and 

supply boat for disposal onshore. 

With the small discharges to air and to sea from the NUI and the large distances between 

the Breagh development and other oil and gas developments, it is unlikely that there will be 

any cumulative impacts from discharges. 

There will be an increase in vessel movements along the pipeline route and at the 

development site during the installation phase, however these activities are temporary, 

consequently there is not anticipated to be a significant cumulative impact. During the 

production period, the additional traffic required for maintenance visits will be low, 

consequently the cumulative impact associated with the vessel movement is anticipated to 

be low. 

TGPP is an existing plant which processes gas and condensate from a number of fields in the 

North Sea. There will be no new sources of emissions to air associated with the normal 

5-31



operation of the additional plant. There will be no new continuous discharges to water 

associated with the operation of the additional plant. However, a portion of hydrotest 

water will be processed and disposed of at the plant. This is a one off activity during 

commissioning. Wastewater arising from the glycol recovery and regeneration unit will be 

taken off-site via tanker. Any solid waste arising as a result of the operation of the 

additional plant will be managed according to the existing procedures implemented at the 

TGPP to facilitate the appropriate management, storage and disposal of waste. The existing 

TGPP is operated according to the limits and conditions specified in an Environmental Permit 

issued by the Environment Agency under the requirements of the Environmental Permitting 

(England and Wales) Regulations 2007. An application will be made to the Environment 

Agency for a variation to that permit to encompass the operation of the new plant. 

In summary, no significant cumulative impacts are anticipated. 

5.5.9 Transboundary impacts 

The Breagh development is relatively far from the closest transboundary line, approximately 

200 km west of the UK and Dutch median line. 

As discussed above, the emissions to sea and to air from the Breagh development are 

minimal. As a result of the distance from the transboundary line and the small discharges, it 

is considered unlikely that there will be any transboundary impacts. 

5-32

6. Conclusions 


Section 6 - Conclusions 

A detailed EIA of the development has been carried out in order to determine the potential 

impacts on the environment and their significance. The identification of the potential 

impacts was based on the nature of the proposed activities and was undertaken using 

available literature and guidance documents, industry specific experience and discussions 

with relevant authorities including DECC, JNCC, CEFAS, the NFFO, NE and the MMO. The EIA 

process will continue throughout the project with the incorporation of the commitments 

made in this ES into the design process, construction and ultimately affecting the way in 

which the field is produced. 

6.1. Environmental Effects 

The development area is considered to be a typical Southern North Sea offshore 

environment where there are no biological or other features that are particularly sensitive to 

the type of development proposed. 

The potential impacts to the environment from all phases of the project were assessed (e.g. 

installation phase, production phase etc). The environmental aspects of each of the key 

activities for each phase of the development were identified and, where possible, the 

potential effects quantified in terms of their likelihood, potential significance and 

magnitude. The results were assessed on the basis of the risk posed to the environment and 

were summarised as of either low, moderate or high risk. 

The initial screening assessment showed that the majority of the key activities are of low risk 

and that there are no key activities which are of high risk, however there are a number of 

aspects that are of moderate risk. Following the identification of suitable mitigation 

measures, additional assessment was undertaken for the key activities which were initially 

found to be of moderate risk. This found that all residual risks to the environment were low. 

6.2. Minimising Environmental Impact 

Overall, execution of the proposed development following the incorporation of the control 

measures is not expected to have a significant impact on the environment. 

6.2.1. Commitments 

The following commitments made within this ES will be incorporated into the Breagh project 

planning and execution processes. 

6-1



6-2 


SURFACE INSTALLATION: 





requirements. 

4 Pre development surveys shall be carried out to aid anchor placement. 

5 Movement of the HLV will be minimised. 






DRILLING: 

10 Minimising the use of fuel and optimising fuel consumption. 


requirements. 

12 The number and duration of use of support vessels will be minimised. 

13 The selected drilling rig will be subject to an audit to ensure it complies with UK 

and project standards. 

14 Minimise the duration of well clean-up activities. 

15 Maximise efficient use and recovery of drilling mud. 

16 No discharge of oil based mud to sea. 

17 Use of Low Toxicity chemicals in the WBM formulation. 

18 Seabed surveys will be used to ensure the rig is sited properly to minimise the risk 

of scouring occurring. 

19 If Rockdumping is required it will be controlled to minimise the volume required 

and the subsequent subsea footprint. 

20 A post drilling survey will be carried out which will assess the impact from the drill 

rig spud cans on the seabed. 






SUBSEA: 





requirements. 

28 The types and volumes of chemicals used to test and protect the pipeline will be 

chosen following risk assessment to minimise the impact on the environment. 

29 The discharge of fluids will be carried out in a manner that will minimise the 

environmental impact. 

30 The pipeline route will be optimised to minimise the pipeline length. 

31 Temporary exclusion zone will be applied during the installation.



32 Guard vessels will be utilised during trenching and pipelay. 

33 The pipeline will be marked as a hazard on the admiralty charts. 

34 Pipeline lay barge activities will be optimised to minimise anchor re-deployments. 

35 Pre-deployment surveys shall be carried out and will be used to identify anchor 

locations. 

36 The anchors will be laid in such a manner as to minimise the risk of interaction 

between the anchor spread and the CATS pipeline in the near shore approach and 

the CANTAT and Pangea telephony cables. 

37 The pipeline route will be optimised to minimise the length of the route. 

38 Ensure that the trenching is successful. 

39 Use survey data to avoid environmentally sensitive areas were possible. 

40 Minimise the volume of rock required by undertaking upheaval buckling analysis. 

41 Use best practice for trenching to ensure the required depth is reached. 

42 Mark rockdump locations on admiralty charts. 




46 Pipelines constructed to requirements as per Pipeline Safety Regulations 1996. 



PRODUCTION: 

48 The NUIs and the exclusion zones will be marked as hazardous on the admiralty 

charts. 

49 A 500m protection zone will be applied around the NUI. 

50 Navigational Aid Fixed to the NUI. 




WIDER DEVELOPMENT CONCERNS: 

54 Piling will commence using soft start. 

55 A trained marine mammal observer will be present during piling operations. 

56 A 500 m exclusion zone will be adopted. 

57 The duration of vessel use will be minimised where possible. 

58 Minimise the no. of vessels used. 

59 Minimise the duration of drilling. 

60 Minimise duration and number of vessels used for the installation of the pipeline. 

61 Ensure that potential for accidental spills is minimised through compliance with 

the relevant legislation. 

6.3. Overall Conclusion 

Overall it is concluded that the proposed development will not result in any significant longterm 

environmental, cumulative or transboundary impacts. The potential discharges and 

emissions, which will be minimised through design and mitigation measures, are likely to be 

dispersed rapidly in the immediate environment. 

6-3

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7-7

Appendix A – Register of Environmental Legislation 

General 

Issue Legislation Regulator and Requirements 



General MARPOL 73/78 UK Regulations apply to ALL vessels regardless of flag whilst in UK Territorial Waters (12nm from coastline), and implement 

the requirements of MARPOL 73/78. Similarly, MARPOL 73/78 requirements apply to ALL vessels whilst on the High Seas 

(outside territorial waters). 

Annexes I Prevention of pollution by oil, II 

Control of pollution by noxious liquid 

substances and V Prevention of pollution 

by garbage from ships MARPOL 

Territorial Waters Territorial Sea Act 1987 

Territorial Waters Order 

The international Maritime Organisation may designate area 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 area special mandatory methods for the prevention 

of sea pollution is required and these special areas are provided with a higher level of protection than other areas of the sea. 

Defines the territorial waters of the UK. 

Public Participation Public Participation Directive 2003/35/EC 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. 

Environmental 

Liability 

Environmental Damage Regulations 2009 

Environmental Liability (Scotland) 

Regulations 2009 

Brings into force rules to force 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. 

Consenting 


EIA 

The Offshore Petroleum Production and 

Pipe-lines (Assessment of Environmental 

Effects) Regulations 1999 and the 

Offshore Petroleum Production and Pipe- 

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. 

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A-2 

lines (Assessment of Environmental 

Effects) (Amendment) Regulations 2007 

Consenting 

A statutory Environmental Statement (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 or extension to a pipelines of 800mm diameter and 40km or more in length. 

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; 

• 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 Environmental Statement is at the discretion of the Secretary of State for: 

• Smaller development and pipelines; 

• Exploration, appraisal and development wells and any sidetracks; 

• Production consent variations and renewals. 

If a Direction as to the requirement for an Environmental Statement is desired then the Petroleum Operations Notice 15 

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 seeking a chemical permit during decommissioning operations (not on portal – paper version of 

application form can be found at https://www.og.decc.gov.uk/regulation/pons/index.htm and should be emailed to 

the Environmental Management Team at DECC); 

• PON 15f seeking a chemical permit during workover/well intervention operations.

Field 

Development 

Plan 

Pipeline Works 

Authorisation 

Consenting 

Petroleum Act 1998 Regulator: Department of Energy and Climate Change 

Operator is required to submit plans for development of field to DECC for approval. 

Petroleum Act 1998 Regulator: Department of Energy and Climate Change 



Construction of a pipeline is prohibited in, under or over controlled waters, except in accordance with an authorisation 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; 

• 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; 

• Secretary of State considers any representations and issues authorisation. 

The PWA process addresses the requirements for DEPCON (Deposits Consent) required under the Food and Environment 

protection Act 1985 (as amended). 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 Pipe-line 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. 

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); 

• The project shall ensure that there is insurance cover in order to enable liability to third parties caused by the 

A-3



A-4 

Consenting 

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; 

Seabed lease Crown Estate Act 1961 Regulator: Crown Estate Commissioners 

Agreement required for occupation of seabed. 

• Consent shall be obtained from the placement of rock and concrete mattresses for burying, protecting or supporting 

the pipeline and conditions may be attached to that consent; 

• No object, equipment or material of any kind which is not an integral part of the pipeline shall be disposed of at sea 

or abandoned on the seabed during the construction and installation of the pipelines. Where such items are 

accidently dropped or left in the sea, every reasonable effort shall be made to recover them; 

• So far as is reasonably practicable that part of the sea bottom which is disturbed by the laying or trenching 

operations shall be restored to a condition that will not interfere with fishing activities. 

Appropriate fishing organisations shall be informed every 24 hours of the positions at which construction work is being carried 

out during the next 24 hours and on the following 3 days. Radio broadcasts shall be made from the installation vessel twice 

daily. Well use NAVTEX. 

If any defects in the pipelines are disclose 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.

Location of 

structures 

Well consent 

Coast Protection Act 1949 Regulator: DECC 

Petroleum Act 1998 

Petroleum Operations Notice No 4 

Consenting 



The issuing of 'consent to locate' under the Coast Protection Act Regulations 1949 Section 34, Part II by the Secretary of 

State to an individual or organisation provides an indication that impacts have been considered with respect to (i) navigation 

and (ii) the local habitat within the proposed area; that no significant impacts would occur as a consequence of the proposed 

offshore installation. 

The consent issued as part of the PWA for work in support of pipelines or part of the PON 4 for drilling (if it is a separate 

vessel not from a surface installation). 

Regulator: DECC 

Application for consent to drill exploration, appraisal and development wells must be submitted to DECC through the WONS. 

Drilling 


Muds, cuttings 

and chemical use 

and discharge 

Food Environmental Protection Act 1985 

(as amended) (FEPA) and the Deposits in 

the Sea (Exemption) Order 1985 

The Offshore Petroleum Activities (Oil 

Pollution Prevention and Control) 

Regulations 2005 – OPPC (replacing 

Prevention of Oil Pollution Act 1971 (as 

amended)) 

Offshore Chemicals Regulations 2002 

PON 15b 

Implementing the requirements of OSPAR 

Regulators: DECC supported by MARINE SCOTLAND and CEFAS 

Deposits in the sea are regulated through FEPA. Discharge of drill cuttings and muds during drilling are specifically excluded 

from the licensing requirements of this Act 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. 


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, 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 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 

A-5



Rig Stabilisation 

Dangerous 

Goods 

Chemical data 

sheets and 

labelling 

A-6 

Decision 2000/2 on a Harmonised 

Mandatory Control System for the Use and 

Reduction of the Discharge of Offshore 

Chemicals and associated 

Recommendations 

The Offshore Petroleum Production and 

Pipe-lines (Assessment of Environmental 

Effects) Regulations 1999 and the 

Offshore Petroleum Production and Pipelines 

(Assessment of Environmental 

Effects) (Amendment) Regulations 2007 

Offshore Petroleum (Conservation of 

Habitats) Regulations 2001 and 2007 & 

2009 amendments 

The Merchant Shipping (Dangerous 

Goods and Marine Pollutants) Regulations 

1997 and 2000 amended in 2006 

The Chemicals (Hazard Information and 

Packaging for Supply) Regulations 2002 

EC Regulation 1907/2006 (REACH) 

REACH Enforcement Regulations 2008 SI 

2852 

Drilling 

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 when the discharge has a permits 

under the Offshore Chemicals Regulations. 


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. 

Regulator: Maritime and Coastguard 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. 


REACH deals with the registration, evaluation, authorisation and restriction of chemical substances. 

Installation including Pipelay and Support Vessels 


Rock dumping 

and other 


(as amended) (FEPA) and the Petroleum 

Act 1998 

Regulators: DECC supported by MARINE SCOTLAND and CEFAS and within territorial waters Scottish Government 

Marine Directorate 

Deposits in the sea are regulated through FEPA but, as a result of the Petroleum Act 1998 this does not apply to anything

deposits of the 

seabed 

Fisheries liaison 

Machinery space 

drainage from 

shipping 

Waste from 

vessels and 

construction 


Model Clauses of Licence 

HSE Offshore Safety Division Operations 

Notice 3 

The Merchant Shipping (Prevention of Oil 

Pollution) Regulations 1996 and the 2000 

and 2005 amendments 

The Merchant Shipping (Prevention of 

Pollution by Garbage) Regulations 1998 

which has been superseded by The 

Merchant Shipping (Prevention of Pollution 

by Sewage and Garbage) Regulations 

2008 

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. 

Regulator: Maritime and Coastguards Agency 

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 then 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. 


All wastes to be segregated, stored and returned to shore for disposal. 

No garbage to be dumped overboard in a ‘Special Area’ 

Food waste can be discharged only if: 

• Greater than 12 miles from coastline; and 

• Ground to less than 25mm particle size. 

Vessels must have a garbage management plan with suitable labelling and notices displayed. 

A-7



Sewage from 

vessels 

Atmospheric 

emissions form 

vessels 

Antifouling 

coating on 

vessels 

Discharges 

A-8 


MARPOL 73/78 Annex IV Regulations for 

the Prevention of Pollution by Sewage 

from Ships 

MARPOL 73/78 Annex VI Regulations for 

the Prevention of Air Pollution from Ships 

International Convention on the Control of 

Harmful Antifouling Systems on Ships 

Surface Waters (Dangerous Substances) 

(Classification) Regulations, 1998 

Control of Pesticides Regulations (as 

amended) Regulations 1997 

OSPAR and Helsinki Conventions 



Regulations 2005 (replaced the Prevention 

of Oil Pollution Act 1971) 


Requirement for ships to discharge sewage only under certain conditions: The discharge of sewage into the sea is prohibited, 

except when the ship: 

• has in operation an approved sewage treatment plant; 

• or is discharging comminuted and disinfected sewage using an approved system at a distance of more than three 

nautical miles from the nearest land; or 

• is discharging sewage which is not comminuted or disinfected at a distance of more than 12 nautical miles from the 

nearest land. 

This does not apply of offshore installations as defined in the Petroleum Act 1998. 


The Annex sets limits on sulphur oxide and nitrogen oxide emissions from ship exhausts and prohibits deliberate emissions of 

ozone depleting substances. It caps 4.5%m/m on the sulphur content of fuel oil. 

Special SOx emission control areas (SECAS) where sulphur emissions are limited further and sulphur content in fuel oil must 

not exceed 1.5%m/m or have an exhaust gas cleaning system fitted. The North Sea is one such SECAS. 

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. 

It was proposed by the International Convention on the Control of Harmful Antifouling Systems on Ships that the use of 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). 


Offshore Chemicals Regulations 2002 Regulator: DECC 

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. An OPPC permit is not required if the discharge 

originated from a vessel covered by the Merchant Shipping (Prevention of Oil Pollution) Regulations. 

A permit is required for discharge or oil to sea and is obtained from DECC. 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




PON 15c chemicals. 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 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. 

Commissioning and Operations 


Discharges of 

linefill and 

hydrotest fluids 

Displacement 

water 

Chemical use 

and discharge 

Dangerous goods 


(as amended) (FEPA) and the Petroleum 

Act 1998 





PON 15 c, d and f 

The Merchant Shipping (Dangerous 

Goods and Marine Pollutants) Regulations 

1997 

2000 amended in 2004 

Regulator: DECC supported by MARINE SCOTLAND and CEFAS and, within territorial waters, Scottish Government 

Marine Directorate 

Deposits in the sea, including liquid discharges, are regulated through FEPA but as stated in the installation section 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 line-fill and hydrotest fluids are permitted under the Petroleum Act 1998 and this is incorporated and permitted 

within the PON 15c process. 


The discharge of oil requires an OPPC permit which are issued by DECC. 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. 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 and 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. 


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. 

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Chemical data 

sheets and 

labelling 

Machinery space 

drainage from 

shipping 

Radioactive 

sources 

Produced water 

A-10 

The Chemicals (Hazard Information and 

Packaging for Supply) Regulations 2002 

The Merchant Shipping (Prevention of Oil 

Pollution) Regulations 1996 and the 2000 

and 2005 amendments 


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. 

Regulator: Maritime and Coastguards Agency 

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 then 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. 

Radioactive Substances Act 1993 Regulator: SEPA or Environment Agency (EA) 




Convention on the Protection of the Marine 

Environment of the North East Atlantic 

1992 (OSPAR Convention) 

OSPAR Recommendation 2006/4 

amending OSPAR Recommendation 

2001/1 For the Management of Produced 

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. 


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. 

In addition, each installation will have permit for re-injection of produced water. 

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 

The OSPAR Recommendation 2001/1 is implemented under OPPC.

Hazardous and 

non-hazardous 

drainage 

(excluding 

machinery space 

drainage) 

Well workover, 

intervention and 

service fluid 

discharges 

Maintenance 

and cleaning 

discharges 

Other minor oily 

discharges 

Oily sand and 

sludge 

Combustion 

emissions 

Water on Offshore Installations 
















Pollution Prevention and Control Act 1999 

(applies to waters outside the 3nm limit) 

Environmental Permitting (England and 

Wales) Regulations 2007 came into force 





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. 


Requires a permit for well workover, intervention and service fluid discharges. Specific monitoring and reporting 

requirements are included on each schedule permit and reporting is via EEMS. 


Requires a permit for maintenance and cleaning discharges, however it may be possible to include it in an existing permit. 

Specific monitoring and reporting requirements are included on each schedule permit and reporting is via EEMS. 


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. 


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. 


Requires 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. 

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CO2 Combustions 

Sources and 

Emissions 

Ozone Depleting 

Substances 

A-12 

on 6 th April 2008 making existing 

legislation more efficient by combining 

Pollution Prevention and Control and 

Waste Management Licensing regulations. 

Offshore Combustion Installation 

(Prevention and Control of Pollution) 

Regulations 2007 (amendments to the 

2001 regulation) 

Greenhouse Gas Emissions Trading 

Scheme Regulations 2005 as amended 

which has been superseded by 

Greenhouse Gas Emissions Trading 

Scheme (Amendment) Regulations 2007 

The EU F Gases Regulation (EC) 

No. 842/2006 

UK Fluorinated Greenhouse Gases 


The EU Ozone Depleting Substances 

(ODS) Regulation (EC) 

REGULATION (EC) No. 2037/2000 

UK Environmental Protection (Controls on 

ODS) (Amendment) Regulations 2008 


Requirements included: 

The operator to apply for a permit, in writing to Secretary of State with prescribed information detailed in the Regulations. 

• Secretary of State will publish applications in the Gazetters 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. 


A permit is required to emit greenhouse gas from combustion plants which an aggregate thermal rating of >20MW(th) and 

from flaring. The requirement must be registered and an application made from the UK allocation plan. 


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 the Environmental Emissions Monitoring System 

(EEMS) on all emissions of HFCs / PFCs and SF6 from relevant equipment 

Creates offences and penalties for not complying with recovery of f-gases legislation, labelling, qualifications and certificates 

required to work with products or equipment containing them. 


Controls the emissions from refrigeration systems, air-conditioning units, fire-protection systems and heat pumps. Requires 

operators to: 

• Maintain annual records 

• Check relevant equipment annually for leakages of ODS 

• Monitor and annually report (by 31 March each year) data to the Environmental Emissions Monitoring System 

(EEMS) on all emissions of halons, CFCs (if applicable) and HCFCs from relevant equipment

Flaring and 

Venting 

Nearshore 

Discharges 

Sewage from 

installations 

Waste 

Model Clauses of Licences Regulator: DECC 

European Parliament and Council 

Directive 2000/60/EC or The Water 

Framework Directive 

Implemented in England and Wales by: 

The Water Environment (Water 

Framework Directive) (England and 

Wales) Regulations 2003 

The Water Resources Act 1990 which has 

been superseded by the Water Resources 

Act 1991 

Implemented in Scotland by: 

Water Environment and Water Services 

(Scotland) Act 2003 and is regulated 

through the Water Environment 

(Controlled Activities) Regulations 2005 

which has been superseded by the Water 

Environment (Controlled Activities) 

(Scotland) Amendment Regulations 2007 

Food and Environment Protection Act 

1985 (as amended) 

Deposits in the Sea (Exemptions) Order 

1985 


Pollution by Garbage) Regulations 1998 

which has been superseded by The 

Merchant Shipping (Prevention of Pollution 

by Sewage and Garbage) Regulations 

2008 




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 level have stabilised. Flaring requirements must not exceed installations flare consent. 

Regulator: SEPA and EA 

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. 

Regulator: DECC supported by CEFAS and MARINE SCOTLAND 

Discharges of sewage, grey and black water as part of routine operations are permitted discharges under the Deposits in the 

Sea (Exemptions) Order 1985. 


The new Regulations replace the existing legislation and bring it into line with the current version of Annex V. 

Sewage: Implements the revised Annex IV (prevention of pollution by sewage) of MARPOL into UK law. The main addition 

to Annex IV is that ships must have one of three recommended sewage systems. Existing ships must comply five years after 

the regulations come into force. 

Garbage: Will replaces the Merchant Shipping (Prevention of Pollution by Garbage) Regulations 1998 

• All wastes to be segregated and stored and returned to shore for disposal. 

• No garbage to be dumped overboard from an installation. 

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Rock dumping 

etc 

A-14 

Environmental Protection Act 1990 – Duty 

of Care which has been replaced by the 

Environmental Protection (Duty of Care) 


Environmental Protection (Duty of Care) 

(England) (Amendment) Regulations 2003 

Hazard Waste Regulations (England and 

Wales) 2005 and 2009 amendment 

Special Waste (Scotland) Regulations 

1997 (as amended) has been superseded 

by the Special Waste Amendment 

(Scotland) Regulations 2004. 

The Waste Batteries (Scotland) 


Waste Batteries and Accumulators 

Regulations 2009 SI 890 

Food and Environment Protection Act 

1985 (as amended) and Petroleum Act 

1998 


• 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 

Waste transfer notes (for general waste) and Waste Consignment Notes (for waste designated ‘Special’ in Scotland or 

‘Hazardous’ in England and Wales) to be used for hazardous wastes. In addition, the regulatory authorities need to be 

notified regarding the disposal of hazardous or special waste. 

Regulator: SEPA 

The Waste Batteries (Scotland) Regulations amends the Pollution Prevention and Control (Scotland) Regulations 2000/323 to 

ban incinerating waste industrial and automotive batteries and amends the Landfill (Scotland) Regulations 2003/235 to ban 

waste industrial and vehicle batteries from landfills. 

Regulator: SEPA 

Establishes a legal framework and schemes for collecting, treating and recycling portable, industrial and vehicle batteries. 

Applies to all types of batteries except when used for military and space equipment. 

Regulators: DECC supported by MARINE SCOTLAND and CEFAS and within territorial waters Marine Scotland or 

DEFRA 

Deposits in the sea are regulated through FEPA but, as a result of the Petroleum Act 1998 this does not apply to anything 

done for the purpose of constructing a pipeline for the purpose of establishing or maintaining an offshore installation within 

the meaning of Part IV of that Act. 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 This is 

applied for through either the PWA or if no PWA exists through a FEPA application form.

Decommissioning 


Chemical use and 

discharge 

Preliminary 

discussions 

Decommissioning 

proposals 


PON 15e 

Petroleum Act 1998 as amended by the 

Energy Act 2008 and in accordance with 

OSPAR Decision 98/3 

IMO Guidelines and Standards for the 

removal of offshore installations and 

structures on the continental shelf 1989 

DECC Guidance note for Industry 

Decommissioning of Offshore Installations 

and Pipelines 2009 




Under these Regulations, permits to use and discharge chemicals need to be obtained. Types of permit required for the 

operations would be a PON15e for use and discharges of chemicals during decommissioning. The permits are applied for 

using the application form found at https://www.og.decc.gov.uk/regulation/pons/index.htm and emailed to Environmental 

Management Team at DECC. The application requires a description of the work carried out, a site specific environmental 

impact assessment and a list of all the chemicals intended for use and or discharge, along with a risk assessment for the 

environmental effect of the discharge of chemicals into the sea. The permit obtained may include conditions. 


The OSPAR Decision 98/3 concerns the decommissioning of installations but there are no international guidelines for the 

decommissioning of pipelines. 

Under the terms of the Decision 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 completed 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. A review of this decision is planned for 2008. 

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 

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 

A-15



A-16 

Accidental Events 


Oil pollution 

emergency 

planning 

Oil pollution 

emergency 

planning 

Pipeline 

emergency 

prevention 

Spill reporting 

The Merchant Shipping (Oil Pollution 

Preparedness, Response and Cooperation) 

Regulations 1998 which has 

been superseded by The Merchant 

Shipping (Oil Pollution Preparedness, 

Response and Co-operation Convention) 

(Amendment) Regulations 2001 

Offshore Installations (Emergency 

Pollution Control) Regulations 2002 


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. 


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. 

Pipeline Safety Regulations 1996 Regulator: Health and Safety Executive 

Model Clauses of Licence 

PON 1 

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 

Birds 

European Council Directive 79/409/EEC 

(The Birds Directive) 

Wildlife and Countryside Act 1981 (as 

amended) 

Countryside and Rights of Way Act 

(CRoW) Act 2000 

Nature Conservation (Scotland) Act 2004 

European Council Directive 92/43/EEC 

(EC Habitats Directive) 

Conservation (Natural Habitats &c.) 

Regulations 1994 and amendments which 

has been superseded by the Conservation 

(Natural Habitats, c.) (Amendment) 

(England and Wales) Regulations 2009 

Conservation (Natural Habitats, &c) 

Amendment (Scotland) Regulations 2007 

which has been superseded by 

Conservation (Natural Habitats, &c) 

Amendment (Scotland) Regulations 2008 

The Offshore Maine Conservation (Natural 

Habitats, 7c) Regulations 2007 

Offshore Petroleum (Conservation of 

Habitats) Regulations 2001 and 2007 & 

2009 amendments 

The Conservation of Habitats and Species 


Convention on Wetland of International 

Importance Especially as Waterfowl 

Habitats 1971 (The Ramsar Convention) 



Regulator: Competent authorities following advice from UK statutory nature conservation agencies (Natural 

England, Countryside Council for Wales and Scottish Natural Heritage, work is co-ordinated by JNCC 

Anyone who kills, injures, takes from the wild or disturbs certain birds, animals/mammals commits and offence. 

• The Birds Directive aims to protect ranges of species, as well as population and breeding of certain populations of 

birds. 

• Extends out to territorial waters 

• Provides for the establishment of Sites of Special Scientific Interest (SSSIs) 

• Under the Birds Directive, member states to take measures to conserve certain areas, including the establishment 

of Special Protection Areas (SPAs) both on land and within the territorial waters. 

Regulator: Competent authorities, following any advice from UK statutory nature conservation agencies (Natural 

England, Countryside Council for Wales and Scottish Natural Heritage. 

Regulations provide for the designation and protection of ‘European Sites’, the protection of ‘European Protected Species’ 

and the adaption of planning and other controls for the protection of European Sites only as far as the limit of territorial waters 

(12nm from the coastline). 

Regulator: (DECC regulator for oil and gas activities) - Joint Nature Conservation Committee provides advice to 

competent authorities 

These regulations apply the Habitats Directive and the Birds Directive in relation of oil and gas plans or projects wholly or 

partly on the United Kingdom’s Continental Self and superjacent waters outside territorial waters. 

Regulator: Competent Authorities following advice from UK statutory nature conservation agencies 

These regulations implement aspects of the Marine and Coastal Access Act 2009. They also consolidate the Conservation 

(Natural Habitats, &c) Regulations 1994 (as amended) and the Offshore Marine Conservation Regulations 2007 (as 

amended) 

UK work coordinated through Joint Nature Conservation Committee 

Aims to prevent encroachment or loss of wetlands on a worldwide scale. Recognises 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 

A-17



Cetaceans 

A-18 

Agreement on the Conservation of Small 

Cetaceans of the Baltic and North Seas 

1991 (ASCOBANS) 

Wildlife Protection 

that are recognised as important to waterfowl habitat. 

Defra UK coordinating authority, scientific advisory body Joint Nature Conservation Committee 

Requires governments to undertake habitat management, conduct surveys and research and to enforce legislation to protect 

small cetaceans. 

Pending Legislation 


Waste 

Emissions 


Pollution by Sewage and Garbage from 

Ships) (Amendment) Regulations 2009 


The amending regulations have be subject to an 8 week consultation period ending on the 22nd September 2009 to correct 

errors in the 2008 Regulations. 

National Waste Strategy Commits the UK to a target of cutting landfill of biodegradable waste by two thirds by 2020. 

The Climate Change Act which became 

law in the UK on 26 November 2008 

The Climate Change Act is intended to introduce powers to combat climate change by setting sectoral annual reduction 

targets for the reduction of CO2 emissions until 2050 and targets for energy efficiency. Targets to reduce CO2 emissions by at 

least 60% by 2050 and 26-32% by 2020, against a 1990 baseline will be put into law. Consideration will also be given to 

including other greenhouse gases and emissions from shipping. 

Climate Change (Scotland) Bill, 2008 Was published by the Scottish Government on December 5, 2008 

EU ETS Phase III (2013 – 2020) The aim will be to reduce EU emissions by 21% between 2005 and 2020. There will be no National Allocation Plans (NAPs) 

with allocations being managed centrally by the EU. 

Revised EU ETS Directive 

Directive 2009/29/EC Published on 5 th 

June 2009 

The Directive states that member states must transpose by 31 st December 2012 and Articles 9(a)(2) and 11 by 31 st 

December 2009. 

The directives includes: 

• 20 per cent reduction in EU GHG emissions by 2020 from 1990 levels, (increasing to 30 per cent when there is an 

international climate agreement); 

• 20 per cent of total EU energy consumption to come from renewable energy sources by 2020; and 

• measures to support carbon capture and storage. 

Consultation on the first stage transposition of the revised EU ETS Directive closes on 30 th September 2011. 

Draft Regulations were laid before parliament on 2 nd December 2009, called “The Greenhouse Gas Emissions Data and 

National Implementation Measures Regulations 2009”. They are coming into force on the 31 st December.

Chemicals 

Proposed EU instruments on greenhouse 

gas emissions and trading scheme 


Two new proposed EU instruments are out for consultation by the European Commission: 



• Proposal 2008/16/EC for a Directive amending Directive 2003/87/EC so as to improve and extend the greenhouse 

gas emission allowance trading system of the Community 

• Proposal 2008/17/EC for a Decision on the effort of Member States to reduce their greenhouse gas emissions to 

meet the Community's greenhouse gas emission reduction commitments up to 2020 

Annex VI of MARPOL 73/78 The Merchant Shipping (Pollution) Act 2006 enables the UK Government to produce Regulations to implement Annex VI of 

MARPOL 73/78. Draft new Regulations are currently under preparation by the MCA. 

Consultation on Offshore Chemicals 

Regulations 2002 and OPPC Regulations 

2005 

Annex VI of MARPOL 73/78 is concerned with the control of emissions of ozone depleting substances, NOx, SOx and VOCs 

and require an International Air Pollution Prevention Certificate following survey to ensure compliance. UK installations will be 

given the option of obtaining a UK Air Pollution Certificate through independent surveyors or to have the survey carried out 

during routine DECC inspections by DECC inspector. The procedure for this survey will be contained in an Marine Safety 

Notice from the MCA. 

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: 

• 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. 

Consultation documents were issued in July 2009 for responses by October 2009 on the proposed changes to the ORC 

Regulations. The key amendments would entail distinguishing between intentional discharges and other releases; and 

incorporating a new offence in relation to such other releases. 

Following the consultation the draft Amended Regulations are awaiting approval. 

Produced Water OSPAR Recommendation OSPAR is looking into a new Risk Based Approach in relation to the discharge of produced water. It is anticipated that a new 

OSPAR Recommendation will be in place by 2010. 

Wildlife 

The UK Marine and Coastal Access Act 

given Royal Assent on the 12 th November 

2009 

The Marine and Coastal Access Act will put in place a better system for delivering sustainable development of the marine and 

coastal environment. It will address both the use and protection of marine resources. It extends to offshore waters (>12 nm) 

and England and Wales territorial waters. Five key issues are covered: 

• Planning in the marine area; 

A-19



A-20 

Scottish Marine Act Passed on the 10 th 

March 2010. 


• Licensing activities in the marine area; 

• Marine nature conservation; 

• Modernising marine fisheries management; and 

• A new management organization 

Work is currently underway to implement the Act. 

The Scottish Marine Bill was passed by Scottish Parliament on 4 th February 2010. Key proposals within the Bill: 

• Development of a new marine management organisation, Marine Scotland, to oversee the implementation of the 

Bill's objectives and to regulating and permitting certain activities. 

• Introduce local accountability / focus on activities and future development. 

• Introduction of marine protected areas (MPA). 

• Establishment of national marine objectives which are likely to be based on the UK objectives. 

• Development of a marine science strategy.

B. Environmental Assessment 

Potential impacts for each key project phase and associated environmental effect before and after mitigation measures. 

Key - Risk 

High Moderate Low 

Environmental Aspect Source Activity Description 

Greenhouse gases / 

air emissions 

Exhaust emissions 

from installation 

vessels including 

Barge, Tow tugs, HLV, 

Anchor handling 

vessel, Standby vessel, 

Guard vessel. 

Generation of power 

during the installation of 

the structure will result in 

the emission of various 

combustion gasses. 

Surface Installation Phase 

Potential effects and significance of 

potential impacts 

May contribute to global warming (CH4, 

CO2), acid effects (SOx, NOx), potential 

localised smog formation (VOC, NOx) 

The development location is several km 

from existing installations. 

Likelihood Consequence Risk 


Appendix B – Environmental Impact Assessment 

Mitigation of 

impacts and actions 

to address concerns 

Atmospheric 

emissions from 

installation vessels 

during the 

installation of the 

structure will be 

minimised through 

careful planning to 

reduce the number 

of vessels required 

and the amount of 

time required on 

location and in 

transit. 

Vessels will be 

audited prior to use. 

Residual impact and/or 

concern 

Emissions to air due to 

the NUI installation will 

be kept as low as 

reasonably practicable. 

B-1



Discharges to water 

Discharges to land 

Physical presence 

B-2 

Food wastes from 


including barge, tow 

tugs, HLV, Anchor 

handling tug, Standby 

vessel, Guard vessel. 

Sewage from 


including barge, tow 

tugs, Heavy lift vessel, 

Anchor handling tug, 

Standby vessel, Guard 

vessel. 

General wastes from 

all installation vessels 

Physical Presence of 

NUI structure 

Small quantities of food 

waste will be discharged 

overboard in compliance 

with MARPOL. 

The small quantities of 

sewage discharged from 

the vessels will be 

naturally dispersed in the 

water column. 

The general waste from 

the offshore activities will 

be disposed of onshore. 

The types of wastes 

include oil, scrap metal 

and domestic wastes. 


Assessed under “Production” 

4 3 Moderate 

This may cause transient organic 

enrichment of the water column leading 

to minor increase in plankton and fish 

populations. None envisaged None envisaged 


4 1 Low 

There may be organic enrichment in the 

vicinity of the discharge possibly leading 

to a small increase in plankton and fish 



4 1 Low 

The disposal options include re-use, 

recycling, incineration and landfill. 

Incineration has emissions to air 

associated with it and disposal to land 

reduces the space available in landfills and 

may have methane emissions associated 

with decomposition. 


3 2 Low 

All wastes to be 

minimised and 

properly segregated 

for 

recycling/disposal 

onshore. 

Minimal impact

Noise 

Physical presence of 



HLV anchors 

Noise associated with 

piling activities 

The presence of the 

installation vessels and 

associated vessel 

movements has potential 

implications for other 

users of the sea, 

specifically fishing and 

shipping vessels. 

The HLV will use 8 

anchors to maintain 

station at the installation 

site. 

The Breagh A jacket will 

be secured to the seabed 

via the use of up to 12 

piles. Each pile may take 

up to 1 day to install 

therefore piling activities 

are anticipated to last a 


The increased vessel movements during 

the installation period may cause 

disturbance to other users of the sea. The 

area has a relatively moderate frequency 

of use by other users (fishing vessels and 

shipping traffic). 


3 1 Low 

The use of anchors may leave depressions 

in the seabed and cause localised 

disturbance of the benthos. Fishing 

vessels may be excluded from the area 

around the HLV anchor spread during the 

installation period. 


4 2 Moderate 

Noise is a potential source of disturbance 

for the marine environment in particular 

cetaceans which frequent the area. The 

number of cetaceans in the area has been 

shown to be relatively low. 



The installation 

period will be 

minimised and the 

number of vessels 

and their 

movements 

optimised. 

Other users of the 

sea in the area will 

be notified of the 

vessel movements. 

The HLV will be 

present at the 

installation site for 

a relatively short 

period of time. 

The impacted area 

is expected to be 

rapidly recolonised. 

An MMO will be 

present on board 

during piling 

activities. 

Follow guidelines 

for soft start piling. 

Short term, very 

localised impact. 

Short term impact 


B-3



Accidental Event 

B-4 


the vessels required 

for the installation 

activities 

Hydrocarbon spills 

from transfer of oil, 

chemicals and bulk 

solids between 

installation vessel and 

supply vessels 


maximum of 8 days. Likelihood Consequence Risk 

The vessels used for 

installation will generate 

noise in the marine 

environment. Sources 

include rotation of 

propellers, use of 

positioning thrusters and 

vessel engines. 

A rupture of a loading 

hose, overfilling of 

storage vessels or diesel 

spills from vessels could 

lead to a release of 

hydrocarbons into the 

environment. 

2 3 Moderate 

The level of noise associated with these 

activities is relatively low in comparison to 

others, for example piling. The number of 

cetaceans in the area has been shown to 

be relatively low. 


4 1 Low 

Potential detrimental impact on water 

quality and marine flora and fauna. 


3 3 Moderate 

Use of vessels will 

be kept to a 

minimum. 

Installation period 

will be minimised. 

Approved OPEP, 

tool box talks, bulk 

loading procedures, 

general 

environmental 

awareness training. 

RDUK will 

undertake an audit 

of vessels prior to 

commencement of 

activities. 


None envisaged


Greenhouse gases / 

air emissions 


from drilling 

operations including 

drill rig, supply vessels, 

standby vessel and 

well test. 

Generation of power 

during the proposed 

drilling operations will 

result in the emission of 

various gases from drill 

rig. 

Emission of various 

combustion gases will 

result from vessel 

movements and 

operations. 

Flaring from the clean up 

will result in the emission 

of combustion gases. 

Well cleaning activities 

will be restricted to 24 

hours. 

Drilling Phase 




CO2), acid effects (SOx, NOx), potential 



5 2 Moderate 



Mitigation of 

impacts and actions 

to address concerns 

Drilling time and 

vessel movements 


Use of low sulphur 

diesel. 

The drill rig and 

vessels will be 

audited to ensure 

that they comply 

with UK standards 

and are operated 

and maintained 

properly. 

Flaring will be 

undertaken using 

high efficiency 

burners and the 

volume flared will 

be kept to a 

minimum. 

Residual Impact 

and/or concern 

Emissions to air from 

drilling activities will 

be kept as low as 

reasonably practicable 

B-5



Discharges to sea 

B-6 

Drilling operations 

discharge of WBM 

Drilling operations 

discharges of oil 

contaminated water 

from deck and drill pit. 

Water associated with 

well clean up 

Water based mud will be 

used for drilling the top 

sections of the wells 

producing WBM 

contaminated cuttings, 

spent WBM and 

completion brine. A total 

of 627 m 3 of WBM 

contaminated cuttings 

and 933 m 3 of WBM will 

discharged per well. 

Deck and drill pit cleaning 

operations can generate 

oil contaminated water. 

This is treated offshore 

and discharged. 

Recovered oil is back 

loaded and transported 

to shore for treatment 

and disposal. 

During well clean up 

there is likely to be some 

water contaminated with 

reservoir hydrocarbons. 

This will be cleaned and 


Short term impact on water quality and 

localised smothering of seabed and 

associated biota. 


4 3 Moderate 

There may be a short term effect on water 

quality and the flora and fauna 


2 2 Low 

May have a short term localised impact on 

water quality 

Maximise efficient 

use and recovery of 

WBM. 

Use of low toxicity 

chemicals where 

possible. 

Oil content of water 

to be 15ppm or less 

before disposal, in 

accordance with 

MARPOL. 

Rig audit to review 

drainage system 

management. 

Audit of well clean 

up kit. 

Review of personnel 

training. 

Sampling of water 

Minimal discharges of 

WBM to sea with only 

temporary effects on 

water column and 

seabed 

Short term impact

Drain water 

Food wastes from rig 

and support vessels 

Sewage from rig and 

support vessels 




discharged overboard. Likelihood Consequence Risk to ensure oil 

content is




B-8 

General wastes from 

all installation vessels 

OBM and cuttings 

The general waste from 

the offshore activities will 

be disposed of onshore. 

The types of wastes 

include oil, scrap metal 

and domestic wastes. 

The last section will be 

drilled with OBM and the 

cuttings will be skipped 

and shipped for onshore 

disposal. 


4 1 Low 

The disposal options include re-use, 

recycling, incineration and landfill. 

Incineration has emissions to air 

associated with it and disposal to land 

reduces the space available in landfills and 

may have methane emissions associated 

with decomposition. 


2 1 Low 

The oil based mud used will be skipped 

and shipped. Hydrocarbons will be 

recovered and cleaned cuttings will go to 

landfill 


3 1 Low 


minimised and 


for 

recycling/disposal 

onshore. 

Rig audit will review 

waste management 

and handling 

procedures. 

OBM will be 

recovered for reuse. 

Cleaned cuttings 

may be reused as 

aggregate or 

disposed of to 

landfill 

Minimal impact 

Minimal impact


Noise 


the drill rig and 

associated vessels at 

the surface 


drill rig on seabed 


the drilling and with 

the vessels required to 

support drilling 

activities including 

supply vessels and the 

standby vessel. 

Physical presence of the 

drill rig and associated 

vessels at the surface. 


spudcans on the seabed. 

Drilling rig is likely to 

have 3 jack up legs. 

A jack up drill rig will be 

on location for the 

duration of 455 days. A 

standby vessel will be on 

location at the drill site 

throughout the entire 

drill location for 455 days. 

Supply vessels will visit 

the drill rig periodically 

utilising 303 vessel days 

throughout the drilling 

period. 


It is anticipated that the rig will be on 

location for a maximum of 455 days. 

There are two shipping routes within 1 km 

of the well locations which may be 

impacted by the development. Fishing 

vessels will be excluded from the 500 m 

exclusion zone around the rig. 


5 1 Low 

Spudcans may displace or smother the 

benthos and leave indentations in the 

seabed surface 


5 3 Moderate 

Potential source of disturbance in the local 

marine environment from a number of 

sources including drilling activities, rig 

engines, vessel thrusters, propellers and 

engines. 

Risk Consequence Risk 

5 2 Moderate 



Fishermen will be 

alerted to presence 

of drill rig and 

location of wells. 

Drill rig will be 

located within 

existing 500 m 

exclusion zone 

The impacted area 

is expected to 

rapidly re-colonise 

upon 

demobilisation of 

the drill rig 

Drilling time will be 

minimised. 

Low numbers of 

marine mammals 

have been observed 

in the area. 

Development is 

within an area of 

existing oil and gas 

production. 




B-9




B-10 

Bunkering spills of 

chemicals and 

hydrocarbons from 

the rig and supply 

vessels. 

Various chemicals are 

stored during the 

drilling process with 

an associated risk of 

loss of containment. 




spills could lead to a 

release of hydrocarbons 

or chemicals. 

Loss of containment of 

chemicals stored or 

accidental spillage. 


A spill of hydrocarbons or chemicals could 

impact on the flora and fauna of the water 

and seabirds in the area. 


3 3 Moderate 

Approved SOPEP 

and OPEP 

Review of 

bunkering 

operations and 

hose management 

during rig audit. 

Wherever possible, 

chemicals will be 

chosen which are 

either PLONOR 

(Poses Little or No 

Risk to the 

environment) or of 

a Low Hazard 

Quotient, HQ


Greenhouse gases and 

air emissions 

Discharges to water 


from subsea 


including personnel 

supply vessel, 

pipesupply vessel, 

anchor handling tugs, 

DSV, pipelay barge, 

shallow water lay 

barge, pipelay vessel, 

survey vessels, 

backhoe dredger, 

trailing suction hopper 

dredger and trenching 

support vessels. 

Food wastes from all 

subsea installation and 

commissioning 


Subsea Installation & Commissioning Phase 

Vessel movement from 

port to the site and time 

spent on location 

requires the use of fuel 

and subsequent 

emissions of various 

combustion gases. 

The duration of the 

pipeline installation and 

commissioning phase will 

be approximately 90 

days. The survey vessel 

will be on location for 

180 days to conduct pre 

and post lay surveys. 


waste will be discharged 

overboard in compliance 

with MARPOL. 



The gases emitted may contribute to 

global warming (CH4 and CO2), acid 

effects (SOx and NOx) and the potential 

for localised smog formation (VOC, NOx 

and particulates). 


4 2 Moderate 

May cause transient organic enrichment 

of the water column leading to a minor 

increase in plankton and fish populations. 




Mitigation of impacts 

and actions to 

address concerns 

Low sulphur fuel will 

be used, in 

compliance with 

legislation. 

Duration of 

installation period will 

be optimised to 

minimise the number 

of vessel days 

required. 

Similarly, the routes 

taken between 

destinations will be 

optimised. 

Pipelay vessels will be 

audited prior to work 

commencing to 

ensure that they are 

maintained and 

operated properly. 

All foods will be 

macerated to less 

than 25 mm to 

increase biological 



Emissions to air 

through support 

vessel use will be as 

low as possible, 

however these cannot 

be eliminated entirely. 


B-11



B-12 

Sewage from all 

installation and 



Drainage water from 

pipelay vessels 


Small quantities of 

sewage will be discharged 

from vessels and will be 

naturally dispersed in the 

water column. 

Pipelay vessels may 

discharge rainfall 

contaminated following 

incidental spillage of 

lubricating fluids or 

detergents used to clean 

the area. 

4 1 Low breakdown 

A minor increase in plankton and fish 

populations may occur as a result of 

transient organic enrichment in the 

vicinity of the discharge. None envisaged None envisaged 


4 1 Low 

Possible degradgation of marine water 

quality and toxic bioaccumulation effects 

on aquatic organisms 


4 1 Low 

MARPOL compliant 

filtration and 

monitoring 

equipment with 

discharges of oil in 

water at less than 15 

ppm. Tanks and 

machinery spaces are 

fitted with bunding to 

collect spillages and 

waste. 

Audit of chemical 

handling and 

management 

procedures as part of 

rig audit. 

Good working practice 

will minimise 

potential spillage.

Disposal to Land 

Discharge of hydrotest 

fluids from 3” MEG 

pipeline and 20” 

production pipeline. 

General waste from all 

subsea installation and 

support vessels. 


The 3” MEG pipeline will 

be flooded with 500 m 3 of 

inhibited water and 

containing corrosion 

inhibitor, biocide and 

fluoroscene dye. The 20” 

production pipeline will 

be flooded with 70,000m 3 

of inhibited water of a 

similar composition. 

After testing the 

blowdown of the 

pipelines to static 

pressure will take place 

offshore. The remaining 

fluids will be pumped 

onshore for treatment 

and disposal following 

commencement of 

production. 

Pipelay vessel and 


commissioning vessels 

will generate a number of 

wastes during the 

installation, including 

waste oil, scrap metal 

and domestic waste. 

Discharge of hydrotest fluids may have a 

short term, localised effect on water 

quality, and potential toxic effects to 

aquatic flora and fauna. 


2 3 Moderate 

The waste will be disposed of on shore 

either through re-use, recycling, 

incineration or landfill. Incineration will 

have associated discharges to air. 

Disposal to landfill will reduce the space 

available and has methane emissions 

associated with decomposition. 



Use of chemicals will 

be kept to a minimum 

and will be of as low a 

hazard quotient as 

possible. 

Discharge of fluids 

will be carried out in 

a manner which will 

minimise 

environmental 

impact. 

All chemicals will be 

risk assessed as part 

of the OCR and 

detailed in the 

subsequent PON 15C. 

Onshore treatment 

and disposal within 

levels permitted at 

TGPP. 


minimised and 


for recycling/disposal 

onshore. 

Rapid dispersion and 

dilution of residual 

components will occur 

in close proximity to 

the discharge point. 


B-13




B-14 





The presence of the 



and associated vessel 

movements has potential 

implications for other 

users of the sea, 

specifically fishing and 

shipping vessels. 

The 3” pipelay vessel will 

be dynamically 

positioned, consequently 

it is not anticipated that 

there will be any impact 

on the seabed. If a ship 

shaped pipelay vessel is 

used to lay the 20” 

pipeline it will be DP and 

will not impact on the 

seabed. 


4 1 Low 

The increased vessel movements during 

the installation period may cause 

disturbance to other users of the sea. 

The area has a relatively low frequency of 

use by other users (fishing vessels and 

shipping traffic). Shipping and 

commercial fishing vessel are prohibited 

from entering the safety zone around the 

pipelay. 


3 1 Low 

Minimise installation 

period. 

Minimise number 

vessels used and 

optimise and 

minimise movements. 

Inform other users of 

the sea of vessel 

movements. 

Short term and 

localised impact


pipelay vessel anchors 

including wire lay 

barge and pipelay 

barge 


20” production 

pipeline 


Wire lay barge will be 

anchored close to the 

coffer dam. 8 anchors 

will be used to maintain 

station. If a pipelay barge 

is used to lay the 20” 

production pipeline it will 

use up to 12 anchors to 

maintain station and 

progress along the route. 

It is assumed that the 

pipelay barge anchors 

have to be re-laid every 

2.5 km 

Of the 100 km 20” 

production pipeline 88 

km will be laid on the 

seabed and will remain 

untrenched. The final 12 

km approach to shore will 

be trenched. Assuming a 

nominal width of impact 

of 0.5 m for the 88 km of 

pipeline which will be laid 

directly onto the seabed, 

the area of impact will be 

in the region of 0.044 

km 2 . 

Anchoring the pipelay vessels may leave 

depressions in the seabed along the 

pipelay route. 


4 2 Moderate 

The pipeline will smother the benthos 

immediately beneath it. The presence of 

the pipeline will introduce a new habitat 

to the area. 


5 2 Moderate 



The pipelay barge will 

be present at each 

location for a short 

period of time. 

Benthic communities 

are expected to 

rapidly recolonise the 

effected area. 

The benthic 

communities within 

the area are subject 

to regular 

disturbance, e.g. from 

trawling, and are 

expected to recover 

quickly from this 

short term 

disturbance. 

The total area 

impacted is relatively 

small in comparison 

to the available 

habitat within the 

development area. 

Short term, very 

localised, impact 


B-15



B-16 


the trenching and 

associated sediment 

deposits 


The trenching will have 

an impact on the seabed 

along the length of the 

trench itself, either side 

of the trench where the 

displaced sediment 

settles and in the area 

effected by active 

backfilling. Sediment will 

also be stored adjacent to 

the trench (up to 3km) 

along the 12km 

nearshore sections prior 

to backfilling. The 3” 

MEG pipeline will be 

trenched along its entire 

length for 100 km. The 

20” production pipeline 

will be trenched along 

the nearshore pipeline 

from 12 km offshore to 

landfall. The area 

impacted by the 

combined length of 

pipeline which will be 

trenched is 1.34 km 2 . 

The benthic communities living in the 

trenched area may be disturbed and/or 

smothered by the deposition of sediment 

and the disturbance to the seabed. 


3 3 Moderate 

The area impacted 

will be minimised by 

optimising the 

pipeline route. The 

benthos are 

anticipated to recover 

from the short term 

disturbance. 

The pipeline route 

will be optimised to 

minimise its length. 

Short term impact.


rockdump and 

mattresses 


200 tonnes of rockdump 

is required at each cable 

crossing impacting on 800 

m 2 of seabed. Mattresses 

will also be used at cable 

crossings but will be 

covered by the rockdump 

so are not relevant to the 

assessment. Spot 

rockdumping is not 

expected to be required 

however a contingency of 

1,500 tonnes of spot rock 

dumping is provided for 

impacting on 1,500 m 2 of 

seabed along the pipeline 

route. The hot end of 

the pipeline at the Breagh 

A NUI may require 

rockdump for 

stabilisation and a worst 

case of 1,500 tonnes is 

assumed impacting on 

1,500 m 2 of seabed. Total 

impacted area from 

rockdump is 3,800 m 2 . 

Rockdumping may smother the benthos 

and alter the habitat type thus effecting 

the communities present in the area. 


5 3 Moderate 



Minimise the 

volume/mass of rock 

and mattresses 

required by 

optimising the 

pipeline route with 

respect to soil types 

(ease of trenching) 

and length. 

Undertake studies to 

investigate the 

potential for 

upheaval buckling, 

thus optimising the 

volume of rock 

required to mitigate 

against its effects. 


B-17



Noise 

Protected Species 

B-18 


the vessels required 

for the installation and 


activities. 


interaction with 

vessels during the 

installation of the 

pipeline. 


The vessels associated 

with the installation and 

commissioning activities 

will generate noise. 

Sources include rotation 

of propellers, use of 

positioning thrusters and 

vessel engines. 

Movement of vessels 

with associated increase 

in noise, chance of spill 

and physical presence 

during the installation 

and commissioning of the 

pipeline. 

The level of noise associated with these 

activities is relatively low in comparison 

to others, for example piling. The 

number of cetaceans in the area has 

been shown to be relatively low. 


4 2 Moderate 

The increased movement of vessels may 

have an impact on the protected bird 

populations and cetaceans in the vicinity 

of the coastal section of the pipeline. 


3 2 Low 

Use of vessels will be 

kept to a minimum. 

Installation period 


Minimise duration 

and use of vessels for 

the installation 

period. 

All vessels will have 

approved OPEPs. 

Vessels will be 

audited prior to use 

to ensure that they 

are maintained and 

operated properly. 


Negligible

Visual Impacts 


Pipelay vessels 

including back hoe 

dredger and barge, 

trailing suction hopper 

dredger, shallow 

water lay barge, 

pipelay barge, reel lay 

vessel and support 

vessels. 

Hydrocarbon spills 

during installation and 

commissioning phase 

from transfer of oil, 

chemicals and bulk 

solids between 


and supply vessels 


Pipelay vessels will 

operate within sight of 

the shore throughout the 

pipelay installation and 

commissioning period 

which will last 104 days. 




spills from vessels could 

lead to a release of 

hydrocarbons into the 

environment. 

The presence of installation vessels 

within site of shore may temporarily 

reduce the amenity value of the shore 

area. 


3 2 Low 

Potential detrimental impact on water 

quality and marine flora and fauna. 


3 3 Moderate 



Minimise duration 

and use of vessels for 

the installation 

period. 

Approved OPEP, tool 

box talks, bulk loading 

procedures, general 

environmental 

awareness training. 

Audit of vessels prior 

to commencement of 

activities. 


None envisaged 

B-19




Greenhouse gases/air 

emissions 

B-20 

Flaring/Venting 

Power requirement 

Vessel movements 

No flaring will occur. 

A maintenance vent will 

be installed on the NUI. 

6,883 sm 3 of natural gas 

will be vented during 

blowdown of the Breagh 

NUI A topsides. 

Power requirements will 

be provided by 3 diesel 

generators on the NUI. 

Fuel consumption is 

conservatively estimated 

at 50 tonnes per year. 

Periodic maintenance 

and inspection of both 

the surface and 

subsurface installations 

will require vessels and 

the associated emissions 

of combustion gases. 

Production Phase 



Mitigation of impacts 

and actions to 

address concerns 

Venting may contribute to global 

warming (CH4, CO2) and acid effects (SOx, 

NOx) Maintenance and 

Likelihood Consequence Risk emergency use only 

5 1 Low 


CO2), acid effects (SOx, NOx) and potential 



5 1 Low 


CO2), acid effects (SOx, NOx) and potential 



3 2 Low 

Minimise the use of 

the diesel generator. 

Low Sulphur fuel will 

be utilised. 

The generators will 

be properly 

maintained to ensure 

that they operate 

efficiently. 

Minimise the number 

of vessels used for 

inspection and 

maintenance and the 

duration of 

operations. 




Small impact 

None envisaged

Discharges to sea 

Sewage from NUI 

during maintenance 

visits. 

Overflows from 

hazardous open drains 

tank will be routed 

overboard. 

Food wastes from all 

maintenance vessels 

Sewage from all 




the NUI will be naturally 

dispersed in the water 

column. 

Volumes of nonhazardous 

water (mostly 

rainwater) will be 

discharged to sea. 


waste discharged over 

board in compliance 

with MARPOL will be 

naturally dispersed in 

the water column. 



the vessels will be 

naturally dispersed in 

the water column. 





of the water column possibly leading to a 

small increase in plankton and fish 



3 1 Low 

No impact envisaged as the discharges 

are not anticipated to be contaminated. 


5 1 Low 

Organic enrichment in the vicinity of the 

discharge possibly leading to a small 

increase in plankton population. 


3 1 Low 

None envisaged None envisaged 

None envisaged None envisaged 


of the water column possibly leading to a 

small increase in plankton and fish 



3 1 Low 

B-21




B-22 

Hazardous drains will 

be drained to a 

Hazardous Open Drains 

Tank which will be 

removed and disposed 

of onshore. 

General waste from 


Small quantities of water 

contaminated with 

chemicals. 

Vessels generate wastes 

such as scrap metal, 

waste oil and domestic 

waste which need to be 

disposed of on shore. 


The disposal options include treatment or 

incineration. There are emissions to air 

associated with incineration. 


3 2 Low 

The disposal options include reuse, 

recycling, incineration and landfill. There 

are emissions to air associated with 

incineration and landfill. Landfilling 

waste reduces the space available in the 

landfill. 


3 1 Low 

All waste to be 

disposed on 

incompliance with 

the waste 

Regulations. 

All waste to be 

disposed on 

incompliance with 

the waste 

Regulations. 

Dispose of waste 

following the 

disposal route 

hierarchy (reduce, reuse…) 

Minimal Impact 

Minimal impact

Physical Presence 


the NUI 



The Breagh A NUI will be 

an obstacle for other 

users of the sea. 

The NUI jacket will be 

held in position with up 

to 8 piles which will be 

driven through the 

subsea feet. The total 

subsea footprint of the 

jacket is 1,600 m 2 . 

The presence of 


may have an impact on 

the other users of the 

sea. 


The present of the NUI may cause 

disruption to other users of the sea. The 

area has a relatively moderate frequency 

of use by other users (fishing vessels and 

shipping traffic). 

The presence of the jacket will cause 

disturbance and displacement of the 

seabed and benthic communities. It is 

anticipated that the surrounding area will 

recover relatively quickly following the 

installation. 


5 2 Moderate 

The area has a relatively moderate 

frequency of use by other users (fishing 

vessels and shipping traffic). 


3 2 Low 



The positions of the 

NUI will be marked 

on admiralty charts 

with a 500m 

exclusion zone 

around them. 

The area impacted by 

the subsea feet will 

be relatively smaller 

than the total 

footprint of the 

jacket. 

The area impacted is 


to the total available 

habitat in the area. 

Other users of the 

sea will be notified of 

vessel movements. 

Vessel movements 




B-23




B-24 

Hydrocarbon spill / 

chemical spill 

Visual Impacts NUI 

Hydrocarbon and 

chemical spills may 

result from damage to 

the pipelines, (injection 

chemicals will be 

supplied from shore 

through a 3” pipeline), 

spills from vessels and 

spills from the diesel and 

aviation fuel storage. 

Loss of containment may 

occur during bunkering 

of diesel, aviation fuel or 

the hazardous drainage 

tank. It is not anticipated 

that there will be any 

routine discharges to 

sea. 

Presence of NUI 

throughout the life of 

field 


Accidental spills may have a detrimental 

impact on the water quality and marine 

fauna and flora. 


3 3 Moderate 

Presence of NUI throughout the life of 

field may cause a small reduction in the 

amenity of the development area. 


All vessels will be 

covered by approved 

Shipboard Oil 

Pollution Emergency 

Plans (SOPEPs). 

All pipelines will be 

designed and 

constructed to 

comply with the HSE 

requirements as per 

the Pipeline Safety 


The development will 

take place in an area 

containing existing oil 

and gas 

developments. 

The NUI design is 


to other platforms in 

the area and as such 

does not represent a 

significant addition of 

infrastructure to the 


None envisaged


5 1 Low area. 

Decommissioning Phase 



The OSPAR Decision 98/3 concerns the decommissioning of installations but there are no international guidelines for the decommissioning of pipelines. Under the terms of 

the Decision there is a prohibition on dumping and leaving wholly or partly in place of offshore installations as such all installations installed post 1999 should be removed 

entirely. Currently there are options for the decommissioning of the pipelines, either the reuse of the main pipeline, abandonment or complete removal. 

There are a variety of environmental effects relating the decommissioning of the development including emissions to air and water, waste disposal, energy use, onshore 

disposal and recycling. The overriding decommissioning philosophy is to minimise the environmental impact on the area. A detailed decommissioning philosophy 

document will be prepared and submitted to DECC in accordance with the Act. It will provide details and an environmental assessment of the end of field like options. 

B-25

C. Proposed Drilling Chemical Use 


Appendix C – Proposed Drilling Chemical List 

This section details the chemicals which it is anticipated will be required for the drilling of the Breagh wells. This list is provisional and will be clarified in the 

subsequent PON 15B. 

36" SECTION 

Chemicals Chemical Function Group Chemical Label Code Estimated 

Use (tonnes) 

Estimated 

Discharge 

(tonnes) 

Caustic Soda Water based Drilling Fluid Additive - 0.50 0.50 E 

M-I BAR Weighting Chemical PLO 70.00 70.00 E 

M-I GEL Viscosifier PLO 30.00 30.00 E 

POLYPAC - All Grades Viscosifier PLO 2.00 2.00 E 

Soda Ash Other PLO 0.50 0.50 E 


Citric Acid Water based Drilling Fluid Additive PLO 4.00 4.00 E 

DUO-TEC Viscosifier - 2.00 2.00 GOLD 

DUO-VIS Viscosifier - 2.00 2.00 GOLD 

Guar Gum Viscosifier PLO 10.00 10.00 E 

Lime Water based Drilling Fluid Additive PLO 1.00 1.00 E 



Mica Lost Circulation Material PLO 2.00 2.00 E 

Nutplug (Fine, Medium, Coarse) Lost Circulation Material PLO 2.00 2.00 E 

Nutshells - All Grades Lost Circulation Material PLO 2.00 2.00 E 


SAFE-SURF E Defoamer (Drilling) - 2.00 2.00 GOLD 

SAPP Water based Drilling Fluid Additive PLO 2.00 2.00 E 

HQ* 

C-1




Sodium Bicarbonate Cement or Cement Additive PLO 2.00 2.00 E 

26" SECTION 


Use (tonnes) 

C-2 

Estimated 

Discharge 

(tonnes) 


Drilling Starch Fluid Loss Control Chemical PLO 15.00 15.00 E 







Potassium Chloride Brine Water based Drilling Fluid Additive PLO 400.00 400.00 E 

Potassium Chloride Powder Brine (Completion) PLO 15.00 15.00 E 

GLYDRIL HC Water based Drilling Fluid Additive PLO 60.00 60.00 E 

GLYDRIL MC Water based Drilling Fluid Additive PLO 60.00 60.00 E 

SAFE-CIDE Biocide - 0.50 0.50 GOLD 




CONQOR 404 NS Corrosion Inhibitor - 4.00 4.00 GOLD 

DEFOAM NS Defoamer - 1.00 1.00 GOLD 




Dyna Red Seepage Control Fiber (all grades) Lost Circulation Material PLO 6.00 6.00 E 


HQ*



G-SEAL Lost Circulation Material PLO 5.00 5.00 E 



IDCAP D Shale Inhibitor / Encapsulator SUB 4.00 4.00 GOLD 

KWIK-SEAL - All Grades Lost Circulation Material PLO 6.00 6.00 E 




Mica - All Grades Lost Circulation Material PLO 2.00 2.00 E 




POLY-PLUS RD Water based Drilling Fluid Additive - 4.00 4.00 GOLD 



SAFECARB - All Grades Weighting Control PLO 10.00 10.00 E 





Sodium Chloride Brine Brine (Completion) PLO 190.48 190.48 E 

Sodium Chloride Powder (Salt PVD or Granular Salt) Water based Drilling Fluid Additive PLO 15.00 15.00 E 


17.5" SECTION 


Use (tonnes) 

Estimated 

Discharge 

(tonnes) 

Caustic Soda Water based Drilling Fluid Additive INORGANIC 1.20 1.20 E 


HQ* 

C-3


































C-4


















12.25" SECTION 


Use (tonnes) 

Estimated 

Discharge 

(tonnes) 











HQ* 

C-5













FORM-A-SQUEEZE Fluid Loss Control Chemical PLO 4.00 4.00 E 





















C-6





Soltex® Additive Shale Inhibitor / Encapsulator SUB 6.00 6.00 GOLD 

Sugar Thinner PLO 1.00 1.00 E 

8.5" SECTION 


Use (tonnes) 

Estimated 

Discharge 

(tonnes) 

BENTONE 920 Viscosifier - 7.00 0.00 E 

Calcium Chloride (all grades) Brine (Completion) PLO 40.00 0.00 E 

Calcium Chloride brine Water based Drilling Fluid Additive PLO 100.00 0.00 E 

DF1 OPF Base Oil - 240.00 0.00 E 

ECOTROL RD Fluid Loss Control Chemical - 2.00 0.00 E 

Lime OPF Additive - 10.00 0.00 E 

MI-BAR Weighting Chemical PLO 250.00 0.00 E 

SAFE-CARB (all grades) Weighting Chemical PLO 30.00 0.00 E 

TRUVIS Viscosifier - 7.00 0.00 D 

VERSACLEAN FL Emulsifier - 10.00 0.00 B 

VERSACLEAN VB Emulsifier - 10.00 0.00 B 

VERSATROL M Fluid Loss Control Chemical PLO 2.00 0.00 E 

BENTONE 920 Viscosifier - 14.00 0.00 E 

Calcium Chloride (all grades) Brine (Completion) PLO 80.00 0.00 E 

Calcium Chloride brine Water based Drilling Fluid Additive PLO 240.00 0.00 E 



DF1 OPF Base Oil - 480.00 0.00 E 


DUOVIS Viscosifier - 5.00 0.00 GOLD 

Dyna Red Seepage Control Fiber (all grades) Fluid Loss Control Chemical PLO 5.00 0.00 E 

HQ* 

C-7



ECOTROL RD Fluid Loss Control Chemical - 4.43 0.00 E 


Ironite Sponge Water based Drilling Fluid Additive PLO 4.00 0.00 E 

KWIKSEAL (all grades) Lost Circulation Material PLO 5.00 0.00 E 

Lime OPF Additive - 11.82 0.00 E 

MI-BAR Weighting Chemical PLO 442.18 0.00 E 

Mica Lost Circulation Material PLO 10.00 0.00 E 



Potassium Chloride Powder Water based Drilling Fluid Additive PLO 20.00 0.00 E 



SAFE-SCAV HSB Hydrogen Sulphide Scavenger - 2.00 0.00 GOLD 

SAFE-SURF E Surfactant - 6.00 0.00 GOLD 

SAFE-SURF NS Detergent / Cleaning Fluid - 8.00 0.00 GOLD 



Soltex® Additive Shale Inhibitor / Encapsulator SUB 8.00 0.00 GOLD 

SWA-EH OPF Additive - 2.00 0.00 D 

TRUVIS Viscosifier - 10.00 0.00 D 

VEN-CHEM 222 OPF Additive - 6.00 0.00 E 

VERSACLEAN FL Emulsifier - 10.00 0.00 B 

VERSACLEAN VB Emulsifier - 10.00 0.00 B 

VERSAGEL HT Viscosifer - 10.00 0.00 E 

VERSAPAC Fluid Loss Control Chemical SUB 6.00 0.00 B 

VERSATROL M Fluid Loss Control Chemical - 10.00 0.00 E 

WT-1040 Pipe Release Chemical - 6.00 0.00 GOLD 

C-8

COMPLETION/ABANDONMENT SECTION 


Use (tonnes) 



Estimated 

Discharge 

(tonnes) 

Sodium Chloride Brine Water based Drilling Fluid Additive PLO 500.00 500.00 E 

DEFOAM NS Defoamer (Drilling) - 0.50 0.50 GOLD 



HEC Viscosifier PLO 1.00 1.00 E 


SAFE-COR 220X Corrosion Inhibitor - 8.00 8.00 GOLD 

SAFE-SCAV NA Oxygen Scavenger PLO 4.00 4.00 E 


Sodium Chloride Powder (Salt PVD or Granular Salt) Water based Drilling Fluid Additive PLO 10 10 E 

Sodium Chloride Brine Water based Drilling Fluid Additive PLO 1000 1000 E 


Calcium Chloride Brine Water based Drilling Fluid Additive PLO 1129.46 1129.46 E 

Calcium Chloride Brine (Completion) PLO 10.00 10.00 E 

DEFOAM NS Defoamer (Drilling) - 1.00 1.00 GOLD 



Potassium Chloride Brine (Completion) PLO 20.00 20.00 E 

HEC Viscosifier PLO 2.00 2.00 E 



SAFE-COR 220X Corrosion Inhibitor - 10.00 8.00 GOLD 

SAFE-SCAV CA Oxygen Scavenger - 5.00 4.00 GOLD 

SAFE-SCAV NA Oxygen Scavenger PLO 5.00 4.00 E 

SAFE-SCAV HSB Hydrogen Sulphide Scavenger - 2.00 2.00 GOLD 

HQ* 

C-9






CEMENTING CHEMICALS 


Use (tonnes) 

C-10 

Estimated 

Discharge 

(tonnes) 

GASSTOP LIQUID Cement or Cement Additive SUB 8.684 0.868 GOLD 

SEM 8 Cement or Cement Additive - 0.718 0.359 GOLD 

MUSOL SOLVENT Cement or Cement Additive - 0.625 0.313 GOLD 

CFR 8L Dispersant - 3.934 1.311 GOLD 

HR 4L Cement or Cement Additive PLO 12.098 2.688 E 

HALAD 300L NS Cement or Cement Additive - 14.626 1.170 GOLD 

SILICALITE LIQUID Cement or Cement Additive PLO 55.619 2.781 E 

ECONOLITE LIQUID Cement or Cement Additive PLO 13.800 1.533 E 

TUNED SPACER E+ Cement or Cement Additive PLO 7.959 2.313 E 

Fluorodye UC Fluorodye UC Dye - 0.121 0.121 GOLD 

NF-6 Defoamer (Drilling) - 0.578 0.263 GOLD 

CALCIUM CHLORIDE Cement or Cement Additive PLO 11.561 1.541 E 

CEMENT - CLASS G Cement or Cement Additive PLO 735.000 75.000 E 

Contingency Chemicals 

SEM 8 Cement or Cement Additive - 1.197 0.599 GOLD 

MUSOL SOLVENT Cement or Cement Additive - 1.042 0.521 GOLD 

MICROMAX Cement or Cement Additive - 68.027 17.007 E 

MICROMAX FF Cement or Cement Additive - 68.027 17.007 E 

HR 4L Cement or Cement Additive PLO 3.361 0.672 E 

CFR Dispersant - 3.278 0.656 GOLD 

HALAD 300L NS Cement or Cement Additive - 11.701 0.585 GOLD 

HQ*



GASSTOP LIQUID Cement or Cement Additive SUB 5.789 0.579 GOLD 

SILICALITE LIQUID Cement or Cement Additive PLO 15.891 1.589 E 

TUNED SPACER E+ Cement or Cement Additive PLO 0.680 3.401 E 

CALCIUM CHLORIDE Cement or Cement Additive PLO 7.707 0.771 E 

ECONOLITE LIQUID Cement or Cement Additive PLO 15.333 0.767 E 

Fluorodye UC Dye - 0.121 0.121 GOLD 

NF6 Defoamer (Drilling) - 0.263 0.105 GOLD 

CEMENT CLASS G Cement or Cement Additive PLO 150.000 30.000 E 

K35 Cement or Cement Additive PLO 0.998 9.98E-01 E 

S TEK Other SUB 0.244 2.44E-01 GOLD 

NF6 Defoamer (Drilling) - 0.035 3.51E-02 GOLD 

Greenbase Flowzan Biopolymer Viscosifier - 0.042 4.15E-02 GOLD 

R TEK TLost Circulation Material PLO 0.590 5.90E-01 E 

C TEK Lost Circulation Material PLO 11.791 1.18E+01 E 

T TEK (All Grades) Lost Circulation Material PLO 20.862 2.09E+01 E 

HCl Well Stimulation Chemical - 0.175 1.75E-01 E 

CL 30 Crosslinking Chemical PLO 0.054 5.44E-02 E 

WG 33 Gelling Chemical SUB 0.458 4.58E-01 GOLD 

C-11

D. Environmental Management 

D.1. Management System 

D.1.1. HS&E Management System Structure 


Appendix D – Environmental Management 

The HS&EMS governs how RDUK’s staff and directly employed consultants/contracted 

personnel, working within the RDUK corporate organisation or in RDUK project teams, will 

conduct their activities. 

The HS&EMS is not certified for compliance with ISO14001 or OHSAS18001 standards. The 

HS&EMS was, however, assessed in 2008 by an accredited third party certification body 

(LRQA) and verified as meeting EMS requirements set out in the OSPAR Recommendation 

and DECC Guidance. The EMS is scheduled to be re-assessed in August 2010 as part of the 

two year cycle. 

The HS&EMS is based on the requirements of the Company HS&E Policy Statement (Figure 

D2). It has been developed in accordance with current UK environmental legislation and 

health & safety legislation, including The Health & Safety at Work etc. Act (HSWA) and 

various Regulations made under HSWA. 

The content and structure of the HS&EMS have also been based on: 

• Principles in the Health and Safety Executive publication HS(G)65 ‘Successful Health and 

Safety Management’; 

• OHSAS 18001 ‘Occupational Health & Safety Management Systems – Specification’; 

• BS EN ISO 14001 standard for Environmental Management Systems. 

RDUK’s Environmental Health and Safety Management System comprises five key elements 

which together provide the framework of a “Plan – Do – Check – Act” approach to EHS 

management. These five key principles underlying the system are shown in Figure D.1 

below. 

Figure D -1 Principle HS&EMS for RDUK 

D-1



The RDUK HS&EMS applies at all levels within the RWE Dea UK organisation, including all 

subsidiary companies. 

It applies to all RDUK business activities which include: 

• offshore exploration for oil and gas 

o evaluation of geotechnical data 

o seismic survey 

o exploration and appraisal drilling 

o well testing 

• offshore oil and gas field development 

o project management 

o survey 

o development drilling 

o platform and subsea infrastructure construction 

o pipeline and cable installation 

o commissioning 

• offshore oil and gas production 

o operations management 

o maintenance 

o support logistics 

o modifications to facilities 

o abandonment 

Contractors employed by RDUK and suppliers of major equipment and services are selected 

following evaluation of their competence and capability to manage HS&E in their scope of 

supply to a level that is acceptable to RDUK. Potential contractors or suppliers are required 

to submit information about their HS&EMS and HS&E performance for review. Specific 

HS&E requirements are included in contracts and orders. 

D.2. Environmental Policy 

The EHS management system requires that all environmental aspects are identified and their 

impacts assessed for all production installations, development projects and exploration 

activities. This includes all aspects which relate to discharges to sea, atmospheric emissions 

and waste management. 

Significant environmental aspects are described in Aspect Data Sheets and compiled into an 

Aspects Register. Aspect Data Sheets also indicate controls including monitoring to mitigate 

adverse impacts, compliance requirements and records to be compiled. This ensures that all 

legal licensing / reporting requirements are identified and that the necessary procedures 

and processes are in place to manage and control all activities. 

D-2

Figure D – 2 RWE HS&E Policy Statement 



D-3

E. Survey Data 


Appendix E – Survey Data 

A total of seven surveys have been undertaken to support the Breagh Development (Figure E 

-1) consisting of pipeline route surveys and well site/rig site surveys: 


• ‘Phase I’ Inshore Pipeline Route Survey (ORISIS), completed Sep/Oct 2009, (Ref C9031)* 

• ‘Phase II’ Inshore Survey (OSIRIS), completed April 2010, (Ref C10003)* 

• ‘Phase I’ Offshore Pipeline Route Survey (Breagh East to Teesside Pipeline Route Survey 

UKCS Blocks 40, 41 and 42) (Gardline), completed Jul/Aug 2009, (Ref 8120) 

• ‘Phase II’ Offshore Pipeline Route Survey (Gardline), completed Feb 2010, (Ref 8272) 

* Note ‘Phase I’ and ‘Phase II’ of the inshore OSIRIS survey have been incorporated within this section 

Well Site/ Rig Site Surveys 

• Debris Clearance Survey UKCS Block 42/13 Proposed Location 42/13-3 Breagh West 

(Fugro Survey Ltd, 2008),completed June 2008, (Ref 9664.2) 

• UKCS 42/13 –D, Breagh East Rig Site and Environmental Baseline Survey including a 

herring spawning ground survey (Gardline Environmental, 2008), completed May/June 

2008, (Ref 7629) 

• UKCS 42/13 – A, Site Survey and Environmental Baseline Survey including a herring 

spawning ground survey (Gardline Environmental, 2006), completed March/April 2006, 

(Ref 6723) 

Figure E1 Surveyed Areas 


Rig Site Surveys 

E-1



The following section provides a summary of each of the surveys in more detail than given 

within Section 3. This organised as follows: 

• E – 1 Inshore Pipeline Route Survey that incorporates ‘Phase I’ and ‘Phase II’ of the 

OSIRIS Pipeline Route Survey and an Environmental Baseline Report undertaken by 

CMACS on behalf of OSIRIS. 

• E – 2 ‘Phase I’ Offshore Pipeline Route Survey undertaken by Gardline that includes 

the Pipeline Route Survey and Environmental Baseline Report (the Herring Spawning 

Report from this survey is incorporated into ‘Phase II’ report) 

• E – 3 ‘Phase II’ Offshore Pipeline Route undertaken by Gardline and includes details 

on the Pipeline Route Survey and Herring Spawning Report for ‘Phase I’ and ‘Phase 

II’ Offshore Pipeline Route Surveys. 

• E – 4 Debris Clearing Survey undertaken by Fugro 

• E- 5 UKCS 42/13D Breagh East Rig Site Survey undertaken by Gardline and includes 

an Environmental Baseline Report and Herring Spawning Report. 

• E – 6 UKCS 42/13 A Site Survey, undertaken by Gardline and includes Environmental 

Baseline Report and Herring Spawning Report 

E-2

E1 Inshore Pipeline Route Survey 



• Pipeline Route Survey Phase ‘Phase I and Phase II’ (OSIRIS) 

• Environmental Baseline Report , undertaken by CMACS on behalf of OSIRIS. 

Survey Breagh East Teesside Route Survey Inshore Survey 

‘Phase I and Phase II’ 

Date September - October 2009 ‘Phase I’ 

February 2010 ‘Phase II’ 

Surveyor OSIRIS 

Survey Coordinates Route E Eastings (m) Northings (m) 

East Breagh Pipeline 

End (KP0) 

336926.32 6050236.03 

TP1 333410.23 6053578.60 

CP1 (r = 3000) 331354.32 6051393.82 

TP2 331667.17 6054377.46 

TP3 262735.65 6061605.30 

CP2 (r = 3000) 263048.51 6064588.95 

TP4 262464.91 6061646.26 

TP5 247263.94 6064659.74 

CP3 (r = 3000) 246686.34 6061717.06 

TP6 24684.85 6064544.96 

Landfall (KP104.719) 235120.20 6060803.54 

Objective To undertake surveys for the inner part of the pipeline 

route from approximately KP84.058 to nominal 

landfall at 104.720 and assess inshore pipeline route 

options in order to determine optimal route. ‘Phase II’ 

was undertaken to complete sub-bottom profile data 

(Figure E-2). 

Equipment • APPLANIX POS MV Inertial Navigation System 

(INS) 

• C-NAV 2050M dGPS 

• HEMISPHERE Crescent VS100 dGPS SYSTEM 

• RESON ‘SEABAT’ 7125 Single Head Multi-Beam 

Echo Sounder 

• SIMRAD EA400 Dual Frequency Hydrographic 

Echo Sounder 

• APPLIED ACOUSTICS AA200 ‘Boomer’ Sub-Bottom 

Profiling system 

• APPLIED ACOUSTICS CSP 1000 Seismic Power 

Source 

• CODA TECHNOLOGIES DA2000 Digital Data 

Acquisition System 

• KLEIN 3000 Dual Frequency Side Scan Sonar 

system c/w ‘SonarPro’ software 

• GEOMETRICS G882 Caesium Vapour Marine 

Magnetometer 

• RESON SVP15 Sound Velocity Probe 

• RESON SVP71 Sound Velocity Probe 

E-3



• VALEPORT ‘Midas’ Tide Gauge 

• QPS QINSy Navigation and Processing Software 

System, version 8.0 

Sampling Strategy The initial project scope of work was designed so that 

3 survey lines, comprising a centre line and two wing 

lines at 50m offset, were to be surveyed on Route A 

from the landfall to KP 91.5, providing 6.6km of 

overlap with the offshore route surveyed by Gardline 

Geosurveys. 

Results 

Water Depths Depths along the proposed route range from a 

minimum of 0.1m above LAT (3.1m below MSL) at KP 

103.958 to 46.4m LAT (49.6m below MSL) at KP 

86.783. A maximum seabed gradient of 18.4° was 

recorded between KP93.038 and KP93.049. 

Seabed Features A number of seabed features were identified during 

the survey, including: 

• Silty fine sands 

• Megaripples 

• Bedrock outcrops 

• Boulder of varies sizes 

• Possible anchor scars 

Shallow soils Generally 1.0 – 5.0m of sandy or silty sand with 

overlaying bedrock. Occasional boulders were 

identified at some stations. 

Magnetometer 39 magnetic anomalies were noted, most of which 

related to the buried CATS pipeline 

Pipeline/Umbilical/Cable Crossing The following cables cross the proposed route 

E-4 

• CANTAT 3 in-service cable at KP90.595 

• Pangea in-service cable at KP86.919 

CATS pipeline runs parallel to and approximately 95m 

– 110m NNW of the pipeline route. The ‘CATS’ pipeline 

is exposed at two locations, some 95m to 99m to the 

NNW of the proposed route between KP 99.976 and 

KP100.417

Figure E – 2 Proposed Pipeline Routes, ‘Phase I’ Inshore Survey (OSIRIS 2009) 

Pipeline Route C 

Pipeline Route B 

Pipeline Route D 

E-5 

Pipeline Route A 

Pipeline Route E 


Appendix E – Survey Data



Survey Inshore Environmental Baseline Report (CMACS) 

Prepared for OSIRIS 

Date March 2010 

Surveyor CMACS 

Objective To investigate the proposed pipeline route between 

KP99.5 and KP104.5 (Landfall). The survey 

established baseline figures for the current benthic 

faunal communities and sediment chemistry, it also 

investigated the area for the potential Annex I 

Habitats. 

Equipment The survey was carried out using underwater camera 

and grab sample equipment 

Sampling Strategy Four grab sampling sites and eleven camera sites 

(Figure E - 3). 

Results 

Seabed Features Predominantly sand with a small portion of silt and 

gravel at certain locations (Figure E-4). 

Particle Size Analysis The sediment samples from all four stations were 

dominated by fine and very fine sand, typically 

contributing over 75% of the weight of the sample. 

There was a small proportion of fine gravel at 

stations 2 and 4 and a proportion of silt at station 3. 

Hydrocarbon Concentrations Hydrocarbon concentrations were low at all four 

sample stations but increased with distance from the 

shore. This is sometimes due to a higher proportion 

of fine sediment with increasing distance from the 

coast but such a relationship was not found in the 

particle size analysis. 

Metal Concentrations There is a positive relationship between metal levels 

and proportion of silt; relatively high concentrations 

of each metal were found at station three where 

there was 11% silt in the sediment. However, metal 

content of the sediment overall was low with none 

of the determinants found at a level that exceeded 

the probable effect level. 

Macrofauna The ten most common species found were: 

• Chaetozone christei 

• Bathyporeia elegans 

• Magelona filiformis 

• Tanaissus lilljeborgi 

• Bathuporeia guillamsoniana 

• Magelona johnstoni 

• Chrysallida sarsi 

• Nucula sp. Juv. 

• Pontocrates arenarius 

Annex I Habitats None Identified 

E-6



Figure E – 3 Environmental Survey Locations, inshore Environmental Baseline (CMACS 

2010) 

Figure E – 4 Camera Imagery at the points of interest Environmental Baseline (CMACS 

2010) 

Site: Point of interest 1 

Position: 241028 

6062865 

Substratum: Sand 

Depth:31m 

Megarippled sand 

waves 

E-7



E-8 


Position 240286 

6062591 


Depth:29.2m 

Mega rippled 

sandwaves 

Starfish Asterias rubens 


Position: 237149 

6061365 


Depth:8.9m 

Dense hornwrack 

Flustra foliacea 

Dead mans fingers 

Alcyonum digitatum 

Dahlia anemone



E.2 ‘Phase I Offshore Pipeline Route Survey (Breagh East to Teesside Pipeline Route 

Survey UKCS Block 40, 41 and 42) 

• Pipeline Route Survey Report 

• Baseline Environment Report 

• Herring Spawning Report (incorporated in ‘Phase II’) 

Survey Breagh East to Teesside Offshore Pipeline Route Survey 


Date July – August 2009 

Surveyor Gardline Environmental Limited 

Survey Coordinates Proposed Pipeline Route 


End 

Easting Northing 

336 962.3 6 050 236.0 

TP1 333 410.2 6 053 578.6 

CP1 331 354.3 6 051 393.8 

TP2 331 667.2 6 054 377.5 

Cats Pipeline Crossing 242 753.8 6 063 700.5 

TP3 242 256.5 6 063 752.6 

TP4 240 321.4 6 063 292.6 

TP5 239 827.8 6062 975.2 

CP3 238 205.5 6 065 498.7 

TP6 (20m LAT) 239 352.5 6 061 196.6 

Objective The purpose of the survey was to determine the 

suitability of the proposed route and identify any 

shallow geological or topographical conditions that 

could impair pipe laying or trenching operations. In 

addition, it also investigated the area for the presence 

of habitats protected under the EU Habitats Directive 

92/42/EEC 

Equipment Single and multi-beam echo sounder, sidescan sonar, 

magnetometer, hull mounted pinger, sparker, 

environmental camera, environmental grab, vibrocore 

and CPT equipment was used during this survey. 

Positioning control for the survey was the Subsea7 

Veripos DGPS service. 

Sampling Strategy During the survey, only KP0.00 to approximately KP96 

was surveyed. The inshore section of the survey, 

beyond approximately KP 96 was being acquired 

separately. The survey corridor was approximately 

360m wide, comprising a centreline with additional lines 

either side offset at 60m, 120m and 180m. The route 

corridor was widened in two areas where possible 

E-9



E-10 

wrecks were found. Cross lines 1000m in length were 

spaced at 1000m intervals to coincide with geotechnical 

sampling locations. 

Results 

Water Depths Along the pipeline route centreline, water depth ranges 

from a minimum of 32.0m LAT at KP96.52 to a 

maximum of 81.5m LAT at KP20.50. The seabed is often 

irregular due to the close approach/outcrop of bedrock. 

A maximum gradient of 9.5° is present at KP89.75. 

Seabed Material Seabed sediments predominantly comprise sand with 

components of gravel and silt. 

Boulder fields of varying density are present through 

much of the route, although they are absent at some 

sampling sites. 

Rock outcrops at seabed were common throughout the 

route (Figure E-5). 

Seabed Obstructions Seabed sediments predominantly comprise sand with 

components of gravel and silt. Boulder fields of varying 

density are present through much of the route. 

Extensive boulder fields are present along the majority 

of the proposed route. 

Pipeline/Umbilical/Cable 

Crossings 

In addition: 

• Bedrock often outcrops at seabed. 

• The 42/13-4 well lies 78m northeast of KP0.000. 



• A wreck lies at KP39.050 with dimensions of 25 x 8 x 

5.2m. 

• The PANGEA North and CANTAT 3 in-service cables 

cross the proposed route at KP85.557 and KP92.262 

respectively. 

The following cables cross the proposed route (as-found 

and Kingfisher positions): 

• PANGEA North in-service cable at KP85.557 


Shallow Soils A layer of predominantly sand with gravel and silt 

components (Holocene)



Holocene and Quaternary sediments are >5m thick 

along some of the route. Chalk becoming claystone (at 

approximately KP20) underlies these sediments where 

present, and often outcrops. 

Habitat Assessment Twenty-five stations were investigated using a digital 

stills camera and video system, followed by sampling 

with a Day grab. No environmentally sensitive habitats, 

protected under Annex 1 of the EU Habitats Directive, 

were observed within the survey corridor (see 

Environmental Baseline report and Figure E-13). 

Pipeline Constraints/Hazards • The presence of extensive boulder fields and rock 

outcrop at seabed, and the above obstructions, 

particularly the wreck at KP39.050, should be taken 

into consideration for pipelay purposes. 

• In-service cable crossings are present at KP85.557 and 

KP92.262. 

• No environmentally sensitive habitats, protected 

under Annex 1 of the EU Habitats Directive, were 

observed within the survey corridor. 

Herring Spawning Potential (Results are incorporated into ‘Phase II’ survey report) 

E-11



Figure E – 5 Camera imagery along selected stations in the Offshore Pipeline 

Environmental Baseline Report ‘Phase I’ (Gardline 2010) 

Station ENV2 

Fix No: 18 

Location: 328400 E 

6054781 N 

Depth: 62m 

E-12 

Sediment 

Description 

Mix of slightly 

rippled fine and 

medium brown sand 

with scattered 

cobbles and shell 

debris 

Flora and Fauna 

Annelida (unident. 

tube worm species), 

Zoantharia (unident. 

colonial anemone 

species), 

euphausiids (krill) 

Station ENV4 

Fix No: 37 


6055550 N 

Depth: 64m 

Sediment 

Description 

Mix of fine brown 

sand and gravel. 

Scattered cobbles 

and shell debris. 


Dead men’s fingers 

Alcyonium 

digitatum), 

anemone hermit 

crab (Pagurus 

prideaux), cloak 

anemone (Adamsia 

carciniopados)



Station ENV7 

Fix No: 63 


6057879 N 

Depth: 67m 

Sediment 

Description 

Mix of slightly 

rippled fine, medium 

and 

coarse brown sand 

with occasional 

scattered shell 

debris 


Nothing visible 

Station ENV9 

Fix No: 86 


6059895 N 

Depth: 59m 

Sediment 

Description 

Mix of rippled 

medium and coarse 

brown 

sand with high 

density of shell 

debris 



(Alcyonium 

digitatum 

E-13



E-14 

Station ENV11 

Fix No: 111 


6060542 N 

Depth: 58m 

Sediment 

Description 

Mix of gravel and 

fine/medium sand 

with scattered shell 

debris 



(Alcyonium 

digitatum), 

polychaete (possibly 

Pomatoceros 

species) 

Station ENV13 

Fix No: 133 


6061050 N 

Depth: 59m 

Sediment 

Description 


medium/fine sand 

with scattered shell 

debris 


Nothing visible



Station ENV16 

Fix No: 169 


6062363 N 

Depth: 51m 

Sediment 

Description 


very coarse sand 

with shell debris 


Nothing visible 

Station ENV18 

Fix No: 191 


6062866 N 

Depth: 43m 

Sediment 

Description 

Mix of rock, 

boulders, silt and 

gravel 


Long clawed squat 

lobster (Munida 

rugosa), common 

sea urchin (Echinus 

esculentus), dead 

men’s fingers 

(Alcyonium 

digitatum), 

echinoderm 

E-15



E-16 

Station ENV21 

Fix No: 216 


6062869 N 

Depth: 43m 

Sediment 

Description 

Mix of gravel, very 

coarse sand and 

rock with scattered 

shell debris 


Antenna hydroid 

(Nemertesia 

antennina), 

branched antenna 

hydroid (Nemertesia 

ramosa), 

echinoderm 

(unident. brittle star 

species) 

Station ENV23 

Fix No: 235 


6063655 N 

Depth: 34m 

Sediment 

Description 

Mix of cobbles, 

gravel and silt with 


debris 



(Alcyonium 

digitatum), 

small brittle star 

(Ophiura albida)



Station ENV25 

Fix No: 261 


6063699 N 

Depth: 36m 

Sediment 

Description 

Mix of cobbles, 

gravel and silt with 


debris 


Echinoderm 

(unident. brittle star 

species), common 

prawn (Palaemon 

serratus), small 

brittle star (Ophiura 

albida) 

E-17



Survey Offshore ‘Phase I’ Environmental Baseline Report 

Date July and August 2009 


Objective To investigate the proposed pipeline route and 

establish baseline figures for the current benthic 

faunal communities, sediment chemistry and to 

investigate the area for the presence of habitats 

protected under the EU Habitats Directive 

92/42/EEC. 

Equipment The survey was carried out by the survey vessel M/V 

Sea Profiler using single and multi-beam echo 

sounders, pinger, boomer, sidescan sonar, 

vibrocorer, high resolution digitial seismic 

equipment, underwater camera and grab sample 

equipment 

Sampling Strategy Samples were taken at twenty-five sampling stations 

within the survey area (Figure E - 13). 

Results 

Water Depths Along the pipeline route centreline, water depth 

ranges from a minimum of 32.0m LAT at KP96.52 to 

a maximum of 81.5m LAT at KP20.50. The seabed is 

often irregular due to the close approach/outcrop of 

bedrock. A maximum gradient of 9.5° is present at 

KP89.75 (Figure E – 14). 

Seabed Features The seabed sediments comprised predominantly 

sand with gravel and silt components through the 

majority of the route, with areas of megaripples 

common. Extensive boulder fields of varying density 

were present along much of the route. Rock often 

outcropped at the seabed, particularly beyond KP60. 

A relatively uniform flow pattern for the KP10.5 to 

KP62.0 section of the route was evidenced by the 

similar orientation (NE-SW/ENE-WSW) of megaripple 

crests throughout. For the KP68.5 to KP95.0 section, 

a uniform flow pattern with direction perpendicular 

to that of the KP10.5 to KP62.0 section was 

evidenced by the consistent NW-SE/WNW-ESE 

orientation of megaripple crests. The parts of the 

route not covered by the aforementioned ranges did 

not display megaripples so no inference of the 

inherent flow pattern could be made. 

E-18 

The PANGEA North and CANTAT 3 in-service cables 

crossed the route at KP86.913 and KP90.595 

respectively, while possible wreck debris, with 

dimensions 25 x 8 x 5.2m, lay at KP39.050.

Sediment characteristics 

Particle Size Analysis 



The sediment characteristics at the sampled stations 

fell into four distinct groups. The sediment 

characteristics were similar within each group of 

stations: 

• At Stations ENV1 to ENV8(KP0 to KP51.6), 

with the exception of ENV4, mean particle 

diameter along with sand, gravel and fines 

contents of the sediment were in the ranges 

190 to 236μm, 92.9 to 95.2%, 0 to 2.3% and 

4.5 to 6.6% respectively. At Station ENV4 the 

sediment comprised mainly gravel (63.8%). 

• At Stations ENV9 to ENV15, mean particle 


contents of the sediment were in the ranges 

402 to 468μm, 74.7 to 99.9%, 0.1 to 18.8% 

and 0 to 6.6% respectively. The sediment at 

Stations ENV11 and ENV13 comprised 16.0 

to 18.8% gravel compared with 0.1 to 5.1% 

at ENV9, ENV14 and ENV15. Whilst at 

Stations ENV9 and ENV14 the sediment 

contained 0% fines compared to 5.2 to 6.6% 

at the others. 

• At Stations ENV16 to ENV21, mean particle 


contents were in the ranges 1716 to 

1972μm, 35.5 to 42.1%, 51.5 to 59.8% and 

4.6 to 8.3% respectively. Under the 

Wentworth system, due to the similar mean 

particle sizes, the sediment was classified as 

very coarse sand at all stations. 

At Stations ENV22 and ENV24, mean particle 

diameter along with sand, gravel and fines contents 

of the sediment were in the ranges 45 to 50μm, 55.7 

to 60.1%, 0.1 to 0.4% and 39.8 to 43.8% respectively 

(Table E -1). 

E-19



TOM and TOC concentrations at Stations: 

• ENV1 to ENV8 were ≤0.7% and ≤0.5% 

respectively. These values were very similar 

to those of the comparison surveys, as 

expected given the similar physical sediment 

characteristics. 

• ENV9 to ENV15 (KP51.6 to KP75.8) TOM and 

TOC were in the ranges 1.1 to 1.6% and 0.3 

to 0.8% respectively. 

• ENV16 to ENV21 (KP75.8 to KP92.1), TOM 

and TOC were in the ranges 2.9 to 4.1% and 

0.7 to 0.9% respectively 

• ENV22 and ENV24 (KP92.1 to KP101), TOM 

and TOC were in the ranges 5.6 to 8.3% and 

2.0 to 2.5% respectively. 

Hydrocarbon Analysis 

TOM and TOC generally increased moving westwards 

across the proposed route and appeared to be 

inversely related to distance to land (Figure E – 6). 

THCs ranged from 2.78μg g- 1 (Station ENV9) to 356μg 

g -1 (ENV24). 

THC generally increased moving westwards across 

the proposed route. THC variability in relation to 

distance from land is presented in Figure 3.5. With 

the exception of Stations ENV11 and ENV13, THC 

was uniform across the KP0 to KP75.8 section, with a 

mean of 5.9μg g -1 . THC increased across the stations 

within both the KP75.8 to KP92.1 and KP92.1 to 

KP101 sections despite the similar sediment 

Metal Concentrations 

characteristics within each. 

The results therefore indicated that THC was 

terrestrially influenced within 27km (KP75.8) from 

land and the strength of this influence increased as 

distance to land decreased (Table E2 and Figure E -7). 

Analysis indicates that concentrations of As, Ba, Cd, 

Cr, Cu, Hg, Ni, Pb, Sn, V and Zn all increased with 

decreased distance from shore (Table E -3). 

Macrofauna Of the seventeen stations where macrofauna was 

collected, fourteen were included in the report 

ENVStations ENV14, ENV16 and ENV17 were 

excluded because the identification stage of the 

analysis was not complete in time for the report. 

E-20 

TOM and TOC Concentrations 

A total of 5963 individuals representing 308 taxa 

were present in the 28 samples of the fourteen 

stations. Of the taxa present, 49 were juvenile and 

one was represented by both adults and juveniles. 

Juveniles comprised 13% of the total number of 

individuals and 16% of the taxa. 

The benthic community generally appeared diverse



and generally free from pollution impact across the 

proposed route. Species present were characteristic 

of the associated sediment types and spread evenly 

across the various taxa. There was generally no clear 

dominance of any one particular species at any 

station. 

Annex I Habitats None identified 

E-21



Figure E 7 Bathymetry along the proposed pipeline route, ‘Phase I’ environmental 

baseline report, (Gardline 2010) Table E – 1 Particle size analysis along pipeline route, 

‘Phase I’ environmental baseline report, (Gardline 2010) 

Figure E – 6 Percentage of total organic matter (TOM) along pipeline route, ‘Phase I’ 

environmental baseline report, (Gardline 2010) 

E-22



Table E – 2 Concentrations of hydrocarbons along proposed pipeline route, ‘Phase I’ 


Figure E – 9 THC, Total PAH and NPD variability along the pipeline route, ‘Phase I’ 


E-23



Table E – 3 Concentrations of metals along the pipeline route, ‘Phase I’ environmental 

baseline report, (Gardline 2010) 

E-24



E. 3. Offshore Pipeline Route Survey (Breagh East to Teesside Pipeline Route survey 

UKCS 40, 41 and 42 ‘Phase II’) 

• Pipeline Route Survey Report 

• Baseline Environmental report (will be included within subsequent PON15C 

application) 

• Herring Spawning Report (Incorporated from both ‘Phase I’ and ‘Phase II’ Surveys) 

Survey Offshore Pipeline Survey ‘Phase II’ 

Date January and February 2010 


Survey Coordinates Pipeline Route 

Easting Northing 


End 

336 962.3 6 050 236.0 

TP1 333 410.2 6 053 578.6 

CP1 331 354.3 6 051 393.8 

TP2 331 667.2 6 054 377.5 

TP3 262 735.65 6 061 605.30 

CP2 263 048.51 6 064 588.95 

TP4 262 464.91 6 061 646.24 

TP5 247 171.53 6 064 679.26 

CP3 246 587.94 6 061 736.57 

TP6 245 573.42 6 064 559.83 

Landfall 235 120.20 6 060 803.54 

Objective The original route survey (Phase 1) was acquired in 2009 

(Gardline Project No. 8120). However, the proposed 

route was revised between TP3 and landfall. Data were 

acquired along this revised section of the proposed 

route during Phase 2, in addition to the acquisition of 

outstanding vibrocores along the existing route. 

Equipment Single and multi-beam echo sounder, sidescan sonar, 

magnetometer, hull mounted pinger, sparker, 

environmental camera, environmental grab, vibrocore 

and CPT equipment was used during this survey. 

Positioning control for the survey was the Subsea7 

Veripos DGPS service. 

Sampling Strategy During the survey, only KP0.00 to approximately 

KP104.0 has been surveyed. The survey corridor is 

approximately 360m wide, comprising a centreline with 

additional lines either side offset at 60m, 120m and 

180m. The route corridor was widened in two areas 

where possible wrecks were found. Cross lines 1000m in 

length were spaced at 1000m intervals to coincide with 

geotechnical sampling locations 

Results 

Water Depths Along the pipeline route centreline, water depth ranges 

E-25



from a minimum of 11.8m LAT at KP104.73 to a 

maximum of 81.5m LAT at KP20.50. The seabed is often 

irregular due to the close approach/outcrop of bedrock, 

particularly towards the inshore end. A maximum 

gradient of 5.7° is present at KP93.14. 

Seabed Material • Seabed sediments predominantly comprise sand 

with components of gravel and silt. 

• Boulder fields of varying density are present along 

much of the proposed route, and this should be 

taken into consideration for pipeline installation. 

Rock often outcrops along the proposed route, 

particularly beyond KP60. 

Seabed Obstructions • Extensive boulder fields are present along the 

majority of the proposed route. 

• Bedrock often outcrops at seabed. 




• A wreck lies at KP39.050 with dimensions of 25 x 8 

x 5.2m. 

• Possible wreck debris 3m high lies 96m SSW of 

KP76.946. 

• The PANGEA North and CANTAT 3 in-service cables 

cross the proposed route at KP86.913 and KP90.595 

respectively. 

• PL774: Everest to Teesside (CATS Trunkline) 36” Gas 

Line lies 55m NNW of KP97.83 at its closest 

approach. 

Pipeline/Umbilical/Cable 

Crossings 

E-26 

The following cables cross the proposed route (as-found 

and Kingfisher positions): 

• PANGEA North in-service cable at KP86.913 


Shallow Soils A layer of predominantly sand with gravel and silt 

components (Holocene)



Pipeline Constants/Hazards The presence of extensive boulder fields and rock 

outcrop at seabed, and the above obstructions, 

particularly the wreck at KP39.050, should be taken into 

consideration for pipelay purposes. 

In-service cable crossings are present at KP86.913 and 

KP90.595. 

Survey East Breagh to Teesside Pipeline Route Survey Herring 

Spawning Report 

Date July and August 2009 and 

January – February 2010 


Objective To describe the superficial sediment structure around 

the proposed Breagh NUI location to approximately 5km 

from the landfall at Teesside and identify substrates 

suitable for herring spawning such as raised gravel 

banks. 

Equipment The survey was carried out by survey vessel MVSea 

Profiler. A Day grab was used to obtain sediment 

samples and an underwater camera to take digital stills 

of the seabed. Geophysical data from the pipeline 

Environmental baseline survey above was also used as 

appropriate. 

Sampling strategy In accordance with CEFAS guidelines (2001), a review of 

geophysical data was conducted to investigate the 

presence of gravels, which could indicate potential 

spawning grounds for herring. 35 sample stations were 

chosen around the proposed Breagh NUI and along the 

proposed pipeline route. Day grabs collected from 

each station to provide samples for analysis. Sample 

stations were also investigated with video and stills 

digital imaging equipment. 

Results 

Seabed The seabed generally shoaled westwards along the 

proposed route. Along the route centreline, depth 

ranged from a minimum of 11.8m LAT at KP101.52 to a 

maximum of 81.5m at KP20.50. The seabed was often 

irregular due to the close approach/outcrop of bedrock, 

particularly towards the inshore end. A maximum 

gradient of 5.7° was present at KP93.14. 

Seabed Imagery Stills and video footage generally supported the 

geophysical interpretation. There was no evidence of 

Sabellaria spinulosa reefs or other Annex 1 habitats 

within the surveyed area. 

Seabed Sampling Grab sampling observations were mostly consistent 

with the geophysical interpretation and evidence from 

the seabed imagery. 

Spawning Potential The results show that the potential for herring spawning 

E-27



E-28 

is either low or non-existent within the proposed 

pipeline route corridor. This is due to the variables 

within the criteria that govern the suitability of a given 

environment for herring spawning combining to make 

the seabed poorly suited throughout. For example 

where gravel was found, the seabed composition also 

included components of sand and fine material resulting 

in the sediment being classified as very poorly sorted. 

Conversely where the sediment was moderately or 

moderately well sorted, no gravel was found. No 

evidence of well sorted gravels, the seabed type widely 

considered to be the preferred spawning substrate of 

herring (Drapeau, 1973), was found. This conclusion is 

further supported by the geophysical interpretation, 

which inferred a seabed composed of predominantly 

sand with gravel and silt components (poorly sorted) 

through the majority of the route (Table E-4 and E – 5).



Table 3 – 4 Summary of herring spawning potential for pipeline route survey ‘Phase I’ 

Herring Spawning Ground Potential 

High Meets all of the criteria. Significant herring spawning potential. 

Moderate Meets most of the criteria. Some herring spawning potential. 

Low Meets few of the criteria. Insignificant herring spawning potential. 

None Meets none of the criteria. No herring spawning potential. 

E-29



Table 3 – 5 Summary of Herring Spawning Potential for Pipeline route Survey ‘Phase II’ 

E-30 

Herring Spawning Ground Potential 

High Meets all of the criteria. Significant herring spawning potential. 

Moderate Meets most of the criteria. Some herring spawning potential. 

Low Meets few of the criteria. Insignificant herring spawning potential. 

None Meets none of the criteria. No herring spawning potential.

E. 4. Debris Clearing Survey 

Survey Debris Clearing Survey 



Date June 2008 

Surveyor Fugro Survey Ltd. 

To provide bathymetric, seabed, sub-seabed and 

foundation conditions information of the West 

Objective 

Breagh Well location for the emplacement and 

operation of a jack-up drilling rig. 

The survey was carried out by the survey vessel M/V 

Geo Prospector. Data were acquired using single and 

Equipment 

multibeam echo sounders, side scan sonar, hull 

mounted pinger and chirp. 

The survey was carried out within an analogue 

survey grid centered on the proposed Breagh West 

Sampling Strategy 

well location. The grid comprised 13 main lines 

orientated 345°/165° and 9 cross lines orientated 

075°/255°. 

Results 

Bathymetry 

Seabed features 

The water depth around the proposed location is 

59.7m LAT. The seabed deepens across the survey 

area in a north-easterly direction from a minimum 

water depth of 58.7m LAT in the south-west corner 

of the survey area to a maximum depth of 60.8m LAT 

in the north-northeast corner of the survey area. 

The seabed gradient at the proposed location is 



E. 5 UKCS 42/13D Breagh East Rig Site Survey 

• Environment Baseline Report 

• Herring Spawning Report 

Survey East Breagh Environmental Baseline Report 

Date June 2008 


To investigate the proposed East Breagh location and 

establish baseline figures for the current benthic 

faunal communities, sediment chemistry and 

Objective 

granulometry around the proposed well location and 

to investigate the area for the presence of habitats 

protected 

92/42/EEC. 

under the EU Habitats Directive 

Equipment 

The survey was carried out by the survey vessel M/V 

L’Espoir using single and multi-beam echo sounders, 

pinger, boomer, sidescan sonar, vibrocorer, high 

resolution digitial seismic equipment, underwater 

camera and grab sample equipment 

Samples were taken at ten sampling stations within 

the survey area. One was located at the original East 

Breagh well location, three were arranged in line 


Results 

with the main current flow, three were located in 

areas of high reflectivity and three were sited at 

random points within 1km of the proposed well 

location. 

Seabed 

Relatively flat, deepening from the S.W. of the survey 

site to the N.E. with an average gradient of

Macrofauna 



Cr, Cu, Hg, Ni, Pb, Sn, V and Zn were all less than 

suggested background concentrations for North East 

Atlantic region sediments given by OSPAR (2005). 

The 10 most common species found in the survey 

area are as follows: 

1. Bathyporeia elegans 

2. Echinocyamus pusillus 

3. Corymorpha nutans 

4. Nuculoma tenuis 

5. Owenia fusiformis 

6. Scoloplos armiger 

7. Sthenelais limicola 

8. Goniada maculata 

9. Urothoe elegans 

10. Abra prismatica 

Fidelity scores for the 7 most abundant species were 

between 0.7 and 1 indicating that their abundances 

were similar at the majority of sample stations. 

Multivariate analysis revealed the presence of a 

uniform community indicative of a relatively stable 

environment that has not been subject to significant 

anthropogenic contamination or disturbance. 

E-33



Figure E – 11 Bathymetry in the area East Breagh Rig Site Survey (Gardline 2008), 

E-34



Survey East Breagh Herring Spawning Report 

Date May – June 2008 


To describe the superficial sediment structure 

around the proposed Breagh East location and 

Objective 

identify substrates suitable for herring spawning 

such as rasied gravel banks. 

The survey was carried out by survey vessel MV 

L’Espoir. A Day grab was used to obtain sediment 

samples and an underwater camera to take digital 

Equipment 

stills of the seabed. Geophysical data from the East 

Breagh Environmental baseline survey above was 

also used as appropriate. 

In accordance with CEFAS guidelines (2001), a 

review of geophysical data was conducted to 

investigate the presence of gravels, which could 

indicate potential spawning grounds for herring. Ten 


sample stations were chosen around the proposed 

Breagh East well location and a Day grab collected 

from each station to provide samples for analysis. 

Sample stations were also investigated with video 

and stills digital imaging equipment (Figure E – 9). 

Results 

Seabed 

Seabed imagery 

Seabed sampling 

Bathymetric data revealed a relatively flat seabed, 

deepening from the S.W. of the survey site to the 

N.E. with an average gradient of



Spawning Potential 

E-36 

Herring spawning potential was calculated according 

to guidelines provided by CEFAS (2001). For an area 

to be considered suitable for herring spawning, the 

sediment should meet the following criteria: 

• Consist mainly of fractions >2mm in 

diameter or contain a mixture of sand and 

exposed gravel with a low silt fraction; 

• Be well sorted; 

• Have little, or no fine



Figure E – 9 Target and sampling locations, Breagh East Herring spawning report (Garline 

2008) 

E-37



Table E – 6 Summary of herring spawning potential Breagh East Herring spawning report 

(Garline 2008) 

Key 

Station 

E-38 

Station Designation 1 

Percentage coarse 

sand to granule (0.5 

to 4mm)/ Sorting 

coefficient 

Sediment 

Description 

Percentage fine 

material (%

E 6 UKCS 42/13 – A, Site Survey 

• Environmental Baseline Report 

• Herring Spawning Report 



Survey UKCS 42/13–A, Environmental Baseline Report 

Date Gardline Environmental Limited 

Objective To investigate the proposed West Breagh location 

and establish baseline figures for the current benthic 

faunal communities, sediment chemistry and 

granulometry around the proposed well location and 

to investigate the area for the presence of habitats 

protected under the EU Habitats Directive 

92/42/EEC. 

Equipment The survey was carried out by the survey vessel M/V 

Tridens 1 using single and multi-beam echo 

sounders, hull mounted pinger, surface tow boomer, 

mini air gun, sidescan sonar, gradiometer, CPT, 

cibrocorer, underwater camera and grab sample 

equipment 

Sampling Strategy Acoustic data did not identify the presence of 

biogenic reefs or other potentially sensitive habitats. 

As such, ten sampling stations were arranged in a 

standard cruciform pattern according to the main 

NNW-SSE current direction. 

Results 

Seabed Relatively flat, deepening from the centre of the 

survey site to the N.E. No indication of presence of 

biogenic reefs or other sensitive habitats (Figure E – 

10). 

Sediment Sediment comprised of silty sand with numerous 

patches of gravel, cobbles and boulders ranging 

between 0.2 and 1.3m (Figure E – 11). Towards the 

north and north east of the survey area, seabed 

sediments consisted of silty sand with occasional 

cobbles and boulders. All but one sediment sample 

contained small quantities of fines. TOM ranged 

between 0.5% and 0.9% and as such sediments 

sampled are classified as nutrient poor 

Hydrocarbon Analysis THC concentrations in all samples were less than or 

equal to 1.6µg g -1 . Analysis of chromatographs 

suggests that sediments in the immediate vicinity of 

the survey area are unlikely to have been exposed to 

significant hydrocarbon contamination as a result of 

either anthropogenic activity or natural seepage in 

the recent past. Concentrations of individual PAHs 

were mostly similar to or lower than values proposed 

by OSPAR (2005) as being representative of 

background concentration in sediments from the 

North East Atlantic region. 

E-39



Metal Concentrations HF extraction showed that concentrations of As, Cd, 

Cr, Cu, Hg, Ni, Pb, V and Zn were all normal for 

muddy sand sediments and were comparable to or 

less than suggested background concentrations for 

North East Atlantic region sediments given by OSPAR 

(2005). 

Macrofauna The 10 most common species found in the survey 

area are as follows: 

E-40 

1. Paramphinome jeffreysii 

2. OPHIURODIEA spp. (Juv) 

3. Chaetozone christiei 

4. NEMERTEA spp. 

5. Owenia fusiformis 

6. Scholoplos armiger 

7. Spiophanes bombyx 

8. Eudorellopsis deformis 

9. Mysella bydentat 

10. Goniada maculate 

Fidelity scores for the 8 most abundant species were 

between 0.7 and 1 indicating that their abundances 

were similar at the majority of sample stations. 

Multivariate analysis revealed the presence of a 

uniform community indicative of a relatively stable 

environment that has not been subject to significant 

point source anthropogenic contamination. 

Uninhabited sabellaria spinulosa tubes were found 

at nine sample locations, 

Annex I Habitats No Annex I Habitats were observed in the surveyed 

area.



Figure E – 10 Bathymetry in the surveyed area UKCS 42/13-A site Survey (Gardline 2006) 

E-41



Figure E – 11 Seabed features UKCS 42/13-A site Survey (Gardline 2006) 

E-42



Survey Breagh West Herring Spawning Report 

Date March – April 2006 


To describe the superficial sediment structure 

Objective 

around the proposed Breagh West location and 

identify substrates suitable for herring spawning 

such as raised gravel banks. 

The survey was carried out by survey vessel MV 

Tridens 1. A Day grab was used to obtain sediment 

Equipment 

samples and an underwater camera to take digital 

stills of the seabed. Geophysical data from the West 

Breagh Environmental baseline survey above was 

also used as appropriate. 

In accordance with CEFAS guidelines (2001), a 

review of geophysical data was conducted to 

investigate the presence of gravels, which could 

indicate potential spawning grounds for herring. Ten 


sample stations were chosen around the proposed 

Breagh West well location and a Day grab collected 

from each station to provide Samples for analysis. 

Sample stations were also investigated with video 

and stills digital imaging equipment (Figure E – 12). 

Results 

Bathymetric data revealed a relatively flat seabed, 

Seabed 

deepening from the centre of the survey site to the 

N.E. There was no indication of the presence of 

biogenic reefs or other sensitive habitats. 

A minimum of 5 seabed photographs, separated by 

an interval of at least 10 seconds, were taken at each 

location. The seabed imagery supported the 

interpretation of fine silty sands across all sampling 

stations. Fauna were in abundance at rocky stations 

(5,6 & 7). Rocks were commonly encrusted by soft 

Seabed imagery 

coral known as dead man’s fingers (Alcyonium 

digitatum). Other fauna identified included starfish, 

brittlestars, hermit crabs (Pagarus bernhardus), 

several flatfish including plaice (Platessa 

pleuronectes) a sea urchin and some small 

Seabed sampling 

unidentified fish. No Sabellaria spinulosa were 

apparent in the video footage or camera stills. 

Grab sampling observations were consistent with the 

geophysical interpretation and evidence from the 

seabed imagery. The sediments from all stations 

were described as fine to coarse silty sand with some 

shell fragments. Particle sizes ranged between 

189µm and 215µm with a mean of 201µm (± 9SD). 

This equates to a range of 2.22 to 2.40 in phi and a 

mean of 2.32 (± 0.06 SD) which is indicative of a 

E-43



Spawning Potential 

E-44 

uniform sandy environment. Analysis of sediment 

samples indicated the presence of sea urchins, 

ragworms, starfish, pipefish and crabs. There was no 

evidence in the seabed imagery of S. Spinulosa reefs. 

However, subsequent analysis of the sediment 

samples confirmed the presence unihabitated 

Sabellaria tubes at Stations 4,5,6,7 and 8. 

Herring spawning potential was calculated according 

to guidelines provided by CEFAS (2001). For an area 

to be considered suitable for herring spawning, the 

sediment should meet the following criteria: 

• Consist mainly of fractions >2mm in 

• 

diameter or contain a mixture of sand and 

exposed gravel with a low silt fraction; 

Be well sorted; 

• Have little, or no fine



Figure E – 15 Target and sampling areas, Breagh West Herring Spawning report (Gardline 

2006) 

E-45



Table E – 7 Summary of herring spawning potential Breagh West Herring Spawning report 

(Gardline 2006) 

Station 

E-46 

Station Designation 1 

Percentage coarse 

sand to granule (0.5 

to 4mm)/ Sorting 

coefficient 

Sediment 

Description 

Percentage fine 

material (%

F. Oil Spill Modelling 


Appendix F – Oil Spill Modelling 

The Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) 

Regulations 1998 implements the International Convention on Oil Pollution Preparedness, 

Response and Co-operation, 1990 (OPRC, 1990) and makes clear the requirement to have an 

Oil Pollution Emergency Plan for offshore installations located in UK waters. 

RDUK intend to prepare an OPEP to cover all aspects of the proposed development for 

submission to DECC that will meet the above requirements and meet the conditions of the 

Offshore Installation (Emergency Pollution Control) Regulations 2002. 

This Appendix summarises the oil spill risks and the oil spill modelling carried out by Sterling 

Resources during the preparation of an OPEP to drill the 42/13-d and 42/13-e Exploration 

Wells in the Breagh field. This modelling remains valid for the new proposed development 

as the worst case scenario will remain the same. 

F.1. Spill Risk 

The potential hydrocarbon risks are detailed in Table F-1 below: 

Table F-1: Main Potential hydrocarbon Spillage Sources 

Type of Oil Potential Spill Sources 

Diesel Diesel storage tanks on NUI. 

Bunkering operations at NUI 

Drilling Rig Storage tanks 

Bunkering operations at Drilling Rig 

Oil Based Mud Liquid mud storage facilities on the drilling rig 

Condensate Condensate levels are expected to be very low. 

Will pose a safety problem if spilt due to gas cloud 

and possibility of fire or explosion. 

Aviation Fuel Storage tanks on NUI 

Lube and Hydraulic Oil Lube and Hydraulic oil drums stored on deck of 

the drilling rig. 

The proposed wells will target a gas reservoir with a small proportion of condensate to gas. 

Thus the main spill risk associated with the development will be from diesel storage facilities 

on both the drilling rig and the NUI. The most frequently expected type of spill would be a 

small (< 1 tonne) spill of oil or chemical from the rig inventory during bulk transfer to/from 

the NUI and drilling rig, or leakage during use or storage. 

The diesel volume required on the NUI per year is anticipated to be 50 tonnes. The storage 

capacity will be designed for 6 months supply, approximately 25 tonnes of diesel. The total 

maximum drilling rig storage capacity for diesel is 300 tonnes. 

F-1



F.2. Modelling Results and Conclusions 

Stochastic modelling was undertaken by Sterling Resources for the two existing wells in the 

Breagh field using worst case spill scenarios. Figure F-2 and Figure F-3 below show the 

results from this stochastic modelling. A small spill of 10 tonnes, under 30 knot wind will 

disperse after 8 hours and will not reach the shore. A spill of the full drilling rig fuel 

inventory of 300 tonnes, under 30 knot wind will disperse after 8 hours and will not reach 

the shore. 

Stochastic modelling, using typical wind conditions during the proposed drilling period also 

indicates that the worst case spill scenarios, i.e. the full rig inventory of fuel oil, would 

weather offshore with a zero probability of oil beaching. 

Figure F-2 Modelled spill trajectory for 10 tonne instantaneous diesel spill at the proposed 

development location with a 30 knot onshore wind. 

F-2



Figure F-3. Modelled spill trajectory for a 300 tonne instantaneous diesel spill at the 

proposed development location with a 30 knot onshore wind. 

Figure F-4. Stochastic Model 300 tonnes of diesel representing rig loss. 

F-3

G. Drawings 


Appendix G – Drawings 

Within this Appendix is a full A3 drawing of the two cable crossings, PANGEA and CANTAT 3 on the 

proposed pipeline route. More details of these crossings can be found in Sections 2, 3 and Appendix 

E within the ES.

Figure E – 13 Locations of environmental survey stations, Offshore Pipeline Route Survey Environmental Baseline Report ‘Phase I’ (Gardline 2010) 



E-46

Figure E 14 Bathymetry along the proposed pipeline route, ‘Phase I’ Environmental Baseline Report, (Gardline 2010) 



E-47

Figure E – 15 Seabed Features, Debris Clearance Survey (Fugro 2008) 



E-48

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