Alma Field Development Environmental Statement

EnQuest Heather Limited  Alma Field Development Environmental Statement DECC Document Ref: D/4110/2011 Intertek METOC Document Ref: P1459BA_RN2525_Rev0 EnQuest Heather Limited Document Ref: ENQ-KN501-HS-001-ENS-0001 ISSUED: 21 JULY 2011

WHERE ENGINEERING MEETS THE ENVIRONMENT

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

STANDARD INFORMATION SHEET Project Name

 Alma  Alma Field eld Develo Developme pment nt

DECC Reference Number

D/4110/2011

Type of Project

Small oil field development

Undertaker Name

EnQuest Heather Limited

Undertaker Address

5 Floor Consort House, Stell Road, Aberdeen, AB11 5QF, United Kingdom

Licencees / Owners

EnQuest Heather Limited (100%) EnQuest Heather Limited wishes to redevelop the Ardmore field in the UK Central North Sea (CNS). The field, to be renamed Alma, will be developed through two drill centres tied-back via new oil production and water injection flowlines to the Uisge Gorm floating production, offloading and storage facility (FPSO). The development will consist of six production wells and two water injection wells (which will be used to drive production due to low reservoir pressures). Wells will be drilled using a combination of water and oil based muds. Cuttings and water based muds will be discharged to sea both at the seabed and from the drilling rig approximately 10m below the sea surface. Oil based mud and cuttings will not be discharged and will be skipped and shipped back to shore for disposal.

Short Description

Due to the relatively short expected field life of the Alma development (ten years), the Uisge Gorm FPSO will be used instead of installing a platform. Produced crude will be collect by shuttle tanker once every two weeks. The majority of the produced gas will be used for power generation, however there may be a short period early part of field life where excess gas is produced that cannot be burned, this will be flared.  All produc produced ed water water will will be be re-i re-injecte njected. d. Production flowlines will be surface laid and protected. The water injection flowline will be trenched and buried, but where trenching is not possible it will be surface laid and protected. Concrete mattresses and rock material will be used for protection. Current estimates are that based on a 10 year field life the base case recovery from the Alma field will be 20.7 million barrels (2.8 million tonnes) and a high recovery case of 32.5 million barrels (4.4 million tonnes). Peak production in the first year will be in the region of 4.5 million barrels (0.61 million tonnes) for the base case and 7.8 million barrels (1.06 million tonnes) for the high recovery case. Construction is scheduled to start in January 2012 with the drilling of the first producer wells. First oil is anticipated in August 2013.

 Antic ipated Start of  Anticipated Works

January 2012

Previous / Other Statements Related to this Project

N/A

Significant Environmental Impacts Identified

EnQuest is aiming to limit environmental effects to low impact through project design, mitigation measures and operational controls. No impacts associated with the development have been categorised as Major or Critical, meaning that the majority of the impacts were assessed as having no or minor residual impact (i.e., impacts can be managed through effective standard operating operating procedures). A few impacts were assessed as Moderate (i.e., the residual impact has been subject to feasible and cost effective mitigation and no further measures are practicable). During construction and production it is considered that the following activities may have an impact: on the environment; atmospheric emissions from power generation; generation; anchoring ; discharge of chemicals and drill cuttings; positioning of structures, rock material and concrete mattressing on the seabed; and the accidental spill of hydrocarbons and/or chemicals. However in all instances the severity of the impact is limited by the nature and composition of the environment and by the fact that these activities are shortterm and affect a localised area. With mitigation measures in place, the Alma field development development wil l have a minor i mpact on t he environment.

Statement Prepared By

Intertek METOC and EnQuest Heather Limited

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NON-TECHNICAL SUMMARY INTRODUCTION EnQuest Heather Limited wishes to redevelop the Ardmore field in the UK Central North Sea (CNS). The field, to be renamed Alma, will be developed through two drill centres tied-back via new oil production and water injection flowlines to a floating production, offloading and storage facility (FPSO). Export will be through the use of a shuttle tanker from the FPSO. The proposed Alma development will be located in United Kingdom continental shelf (UKCS) Blocks 30/24 and 30/25, approximately 274km east of the nearest landfall on the Northumberland coastline and approximately 18.5km from the Norway/UK international boundary (median line). In compliance with regulatory requirements, and to responsibly manage any impacts from the development, EnQuest has carried out an Environmental Impact Assessment (EIA) of the proposed development. The EIA process establishes the environmental baseline in the area of the proposed development and identifies environmental sensitivities, particularly with relevance to the concerns of stakeholders and regulatory bodies. It also evaluates relevant environmental impacts and their significance, and finally proposes mitigation measures which the operator will implement to minimise these t hese impacts. This document reports on the EIA process, its findings and conclusions.

GOVERNING GOVER NING LEGISLA LEGISLATION TION Offshore oil and gas developments are governed by a collection of international, European Community (EU) and UK laws, policies and guidelines. These dictate the management goals and objectives which an environmental assessment may aim to achieve. The main UK regulations that apply to the project are: Petroleum Act 1998 – Requires all offshore oil and gas development to apply for consent to undertake the project. Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) (Amendment) Regulations Regulations 2007 – These regulations implement implement the EC EIA and Public Participation Directive, and require an ES to be submitted for offshore oil and gas projects and public participation in the consent process.

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Offshore Marine Conservation (Natural Habitats, &c.) Regulations 2007 (as amended in 2009 and 2010) – These regulations implement in the UK the EC Habitats Directive (92/43/EC) and the EC Birds Directive (79/409/EC) and aim to protect marine species and wild birds from environmentally damaging activities. It is now an offence under the Regulations Regulations to deliberately disturb wild animals of a European Protected Species. Offshore Petroleum Activities (Conservation of Habitats) Regulations 2001 (amended in 2007) – The regulations apply the EC Habitats and EC Birds Directives in relation to oil and gas projects on the UKCS.

PROJECT JUSTIFICATION Oil is the UK’s second largest source of primary energy, supplying over 30% of the country’s total energy needs needs (OGUK 2009). In 2008, the UKCS oil production production was enough enough to satisfy 97% of domestic consumption, produced mainly from fields in the Central North Sea (CNS) basin, with some production production in the NNS and Southern Southern North Sea (SNS). In 2000, the UK Government identified the need to stimulate oil and gas investment and activity to ensure that indigenous indigenous production of oil and and gas remained at significant significant levels into the future. future. The Promote UK campaign is designed to attract new entrants onto the UKCS, and focused on: Independent oil companies with the resources to drill wildcat exploration wells and exploit the full value chain from exploration to development; and Niche ‘developers’, particularly those with the skills to develop previously undeveloped discoveries by using technically innovative and best cost solutions (DECC 2011a).  As a result of these initiatives, EnQuest has been active on the UKCS since 2010.

It

specialises in predominantly mature areas of the NNS and CNS, aiming to maximise the potential from existing fields fields and future developments developments in the UKCS. The longer term strategy is to become a prominent exploration and development operator. The Alma Field development is part of this strategy and fits many of the UK energy policy objectives: It would bring on-stream a marginal field that it is now feasible to develop with the prevailing oil price and the small field allowance applicable to this size of field It is a national resource that will help contribute towards energy security

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Current estimates predict that P50 1 recovery over field life will be 20.7 million barrels of oil (2.8 million tonnes). P10 2  recovery is estimated to be 32.5 million barrels (4.4 million tonnes).

PROJECT AL TERN TERNATIVES ATIVES EnQuest have considered considered a number number of development development options for the Alma Alma field. Given the compact nature of the field and relatively short field life, the decommissioning strategy has played an important important role in option selection.

Options considered considered included included the choice of

surface facilities (FPSO, floating production facility (FPF), platform or subsea tie-back), the choice of drilling rig (semi submersible or heavy duty jack-up) and the installation philosophy of the flowlines (trenched and buried or surface laid and protected).  After considerable deliberation, deliberation, the FPSO, semi submersible and a combination of trenching and surface lay options were selected, based on combination of technical, environmental economic considerations. considerations. Table 3-3 details all the pros pros and cons of each option. FPSO  A number of FPSOs are are available for for deployment Provides an integrated storage and offloading system Modifications required are more economic that other available options e.g. new platform FPSOs fit for expected field life Using an existing FPSO is cheaper than a new build FPSOs considered have proven track record in the UKCS Minimal seabed disturbance from installation Can be easily redeployed at end of field life Semi Se mi Submersible Less weather dependant during positioning on site More scope for moving rig but maintaining same anchor pattern – less seabed disturbance. disturbance.

For example, moving to allow allow subsea infrastructure infrastructure to be installed, installed,

moving rig if subsurface philosophy changes

1

 50% confidence level of this volume of oil being produced  10% confidence level of this volume of oil being produced

2

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 Ability to drill six wells on same anchor pattern – less seabed disturbance Easier to run horizontal xmas trees Better selection options- at least two rigs are known to be available Current drilling team has extensive knowledge of semi submersible drilling operations Flowlines Buried Greater protection for flowlines – no additional protection such as rock would be required except for mattressing and grouting at trench transition areas Conventional / proven solution Option to surface protect spans which cannot be buried due to existing subsurface obstructions Surface Laid Ease of installation - range of installation vessels available Benefit as compact field layout with possible drilling rig on site during installation Lower mobilisation costs for installation Potential of re-use / decommissioning easier Conventional / proven solution Minimal seabed disturbance Lower risk of subsurface obstructions because no trenching  Additional protection such as rock material will be required for certain spans Technically preferred option for production flowlines due to temperature issues

PROJECT DESCRIPTION

SCHEDULE Construction is scheduled to start in January 2012 with the drilling of the first production well. Construction activities will continue through to May 2013 with first oil expected in third quarter 2013. A total of six production wells and two water injector wells will be batch drilled and are

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expected to take approximately three months each to drill and complete. Field life is anticipated to be ten years.

CONSTRUCTION The development will consist of: The drilling of six producers and two water injectors The Uisge Gorm FPSO Two 10-inch production flowlines, one 10-inch water-injection flowline, two control umbilicals and one power cable Production wells will target a total of three reservoirs within the Alma Development area: Devonian, Zechstein and Rotliegend. Three production wells will be drilled in five sections using a combination of water based mud (WBM) and oil based mud (OBM), with each section cement cased. The remaining three production wells and the two water injection wells will be drilled in four sections also using a combination of WBM and OBM, with each section cement cased. Cuttings and WBM will either be discharged at the seabed or to sea approximately 10m below sea surface from the drilling rig. All OBM and cuttings will be skipped and shipped to shore for disposal. The water injection flowline will be trenched and backfilled. In the event of any undulations in the trench (and subsequently the flowline) a contingency will be in place for the provision of approximately 5,000 tonnes of rock for deposition for protection. The rock will be deployed to mitigate any upheaval buckling (less of a problem with flexible flowlines) or pipeline out of straightness events experienced during the trenching and pipe-lay activities. This may be required for pipeline protection, depth of cover anomalies or dropped object protection. The requirement for rock deposition will be identified during post lay survey and if required the rock will be placed accurately utilising a dynamically positioned fall pipe rock installation vessel. The vessel will be equipped with a fall pipe to deploy rock accurately in the spot location. Where trenching is not possible the water injection flowline will be surface laid and protected where required with concrete mattress to eliminate any pipe-spans or seabed obstructions. The production flowlines will be surface laid and protected. They cannot be trenched as the arrival temperature of the production fluids at the FPSO would be too high.  After tie-in, the flowlines will be hydrotested and leak tested before being dewatered and then commissioned.

Concrete mattresses and rock material will be used for dropped object

protection and stability. The water-injection flowlines will terminate directly in the FPSO. The production flowlines will terminate at a bolted straight “T” piece from which flexible risers will

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take produced fluids to the FPSO. All flexible risers will be secured by either vertical piled or gravity base anchors and horizontal clump weight anchors. The Uisge Gorm FPSO will be held permanently on station without any aid from thrusters or other external sources by nine anchors. Modifications and upgrades will be carried out on the FPSO turret to accommodate the new flowline/umbilical riser systems required to receive and process the Alma hydrocarbons and to export injected water. The upgrades will be finished before the FPSO is mobilised to the field.

Note: Image is for illustrative purposes only and does not necessarily reflect exact layout of flowlines and associated infrastructure

PRODUCTION Produced crude oil and associated gas will be produced back to the FPSO and oil then offloaded onto shuttle tankers for export. First oil is currently expected in third quarter 2013. Current estimates are that based on a 10 year field life the base case recovery from the Alma field will be 20.7 million barrels (2.8 million tonnes) of crude oil and a high recovery case of 32.5 million barrels (4.4 million tonnes). Peak production in the first year will be in the region of 4.5 million barrels (0.61

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million tonnes) for the base case and 7.8 million barrels (1.06 million tonnes) for the high recovery case. The reservoir pressure at Alma is such that produced water re-injection is required to ensure that satisfactory quantities of crude oil are produced. Sufficient quantities of gas are expected to be produced with the crude to be used for power generation onboard the FPSO. Produced water will be passed through a bank of hydrocyclones which will take oil in water (OIW) concentrations from approximately 1000mgl -1  to below 30mgl-1. It will then be routed through a degasser and settling vessel. The produced water then passes through the pumps past an overboard discharge point and into four injection pumps that push the produced water down the water injection flowline to be re-injected. Should any produced water be discharged (due to temporary failure, or routine maintenance of the produced water reinjection system) then OIW concentrations will be below 30mgl -1. Early in the field life there will be the need to flare gas.

This would be due to either

insufficient gas production to power the generators on the FPSO or because of an excess of gas produced, over that demanded for fuel.

DECOMMISSIONING Field life is expected to be ten years.

Before the end of field life, arrangements for

decommissioning will be developed in accordance with the prevailing UK government and international legislation.

The development plan is based on the assumption that similar

requirements to current legislation will be applicable.

These requirements have been

considered in the design of the facilities and during project planning.

The impacts of

decommissioning activities on the environment have not been assessed under the scope of this document as they will be the subject of a separate EIA.

ENVIRONMENTAL IMPACT AND MITIGATION Mitigation is an integral part of the Alma development.

All of the potential interactions

between project activities and environmental receptors are subject to either standard recognised best practice mitigation measures or to impact specific, feasible and cost effective mitigation. In general, the mitigation proposed will be sufficient to reduce the effects of activities to below levels which will cause a significant residual impact. For those where mitigation isn’t enough, the residual impacts are detailed below with a discussion of the mitigation that will help to reduce the impact to the acceptable levels identified.

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The following table summarises the findings of the detailed EIA process undertaken in relation to the Alma development and outlines details of the impacts that were considered to have a residual impact on the environment. Receptor & Type of Impact

Baseline & Impact Assessment

Significance of Residual Impact

Mitigation

The Alma development area comprises a

More than

 ACOPS

 Advisory Committee on Protection of the Sea

 ALSF

 Aggregates Levy Sustainability Fund

 API

 American Petroleum Institute

B.P

Before Present

BAT

Best Available Technique

bbls

Barrels

BGS

British Geological Society

BOP

Blow-Out Preventer

bopd

Barrels of Oil Per Day

BS&W

Bottom Sediment and Water

BSI

British Standards Institute

bwpd

Barrels of Water Per Day

CBD

Convention on Biological Diversity

CEFAS

Centre for Environment, Fisheries and Aquaculture Science

CH4

Methane

CMT

EnQuest Crisis Management Team

CNS

Central North Sea

CO

Carbon Monoxide

CO2

Carbon Dioxide

CPR

Continuous Plankton Recorder

dB

Decibel

DECC

Department of Energy and Climate Change

Defra

Department for Environment, Food and Rural Affairs

DMRB

Design Manual for Roads and Bridges

DP

Dynamic Positioning

DSV

Diving Support Vessel

DTI

Department of Trade and Industry

EC

European Commission

EEMS

Environmental Emissions Monitoring Scheme

EIA

Environmental Impact Assessment

EMS

Environmental Management System

EPS

European Protected Species

ERC

Emergency Response Centre

ES

Environmental Statement

ESP

Electrical Submersible Pump

EU ETS

European Union Emissions Trading Scheme

FAO

Food and Agriculture Organisation

FDP

Field Development Plan

FPSO

Floating, Production, Storage and Offloading

FRS

Fisheries Research Service

GESAMP

The Joint Group of Experts on the Scientific Aspects of Marine Environmental Protection

GGL

Gardline Geosurvey Limited

GIS

Geographical Information Service

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H

HQ

Hazard Quotient

HR

Conservation (Natural Habitats &c.) Regulations 1994 (as amended)

HSE

Health and Safety Executive

HSEQ

Health, Safety, Environmental and Quality

Hz

Hertz

IBA

Important Bird Areas

ICES

International Council for the Exploration of the Seas

IMT

Incident Management Team

IPPC

Integrated Pollution Prevention and Control Directive

ISO

International Organization of Standardization

J

JNCC

Joint Nature Conservation Committee

K

KISCA

Kingfisher Cables

km

Kilometre

km2

Kilometres squared

kPa

Kilo Pascal

kw

Kilo Watt

LAQM

Local Air Quality Management (LAQM) Support. Defra, UK Local Air Quality Management

LAT

Lowest Astronomical Tide

µgl-1

Microgram per Litre

µgm-3

Microgram per Cubic Metre

µPa

Micro Pascal

m

Metre

m2

Metre Squared

m3

Cubic Metre

MBES

Multi-Beam Echo Sounder

MCA

Maritime and Coastguard Agency

MCAA

Marine and Coastal Access Act

MCZ

Marine Conservation Zone

MEG

Monoethylene Glycol

mgl-1

Milligram per Litre

mmbbls

Million Barrels

MMO

Marine Mammal Observer

MMO

Marine Management Organisation

MMscf/d

Million Standard Cubic Feet per Day

MODU

Mobile Offshore Drilling Unit

ms-1

Metres per Second

MW

Mega Watt

MW(th)

Mega Watt (Thermal)

MWh

Mega Watt Hour

N2O

Nitrous Oxide

nm

Nautical Miles

NNE

North-North East

NNS

Northern North Sea

NO2

Nitrogen Dioxide

NOEC

No Observed Effect Concentration

NOx

Nitric Oxides

OBM

Oil Based Mud

I

L M

N

O

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OCNS

Offshore Chemical Notification Scheme

OCR

Offshore Chemical Regulators

OESEA

Offshore Energy Strategic Environmental Assessment

OGED

Oil and Gas Exploration and Development

OGUK

Oil and Gas UK

OIW

Oil in Water

OMR

Offshore Marine Conservation (Natural Habitats &c) Regulations 2007 (as amended in 2010)

OPEP

Oil Pollution Emergency Plan

OPPC

Oil Pollution Prevention and Control

OSPAR

Convention for the Protection of the Marine Environment of the North East Atlantic (Oslo Paris Convention)

OSRL

Oil Spill Response Limited

PAH

Polycyclic Aromatic Hydrocarbons

PAIH

Potential Annex I Habitat

PEXA

Practice and Exercise Areas

PIG

Pipeline Inspection Gauge

PLANC

Permits Licenses Approvals Notifications and Consents

PLONOR

Posing Little or No Risk

PLV

Pipeline Laying Vessels

PM 10

Particles Measuring 10µm or less

PM 2.5

Particles Measuring 2.5µm or less

PON

Petroleum Operations Notice

ppb

Parts per billion

ppm

Parts per million

PSA

Particle size analysis

psia

Pounds per Square Inch Atmospheric

PW

Produced Water

PWA

Pipelines Works Authorisation

PWRI

Produced Water Reinjection

Q

QMS

Quality Management System

R

REACH

Registration, Evaluation, Authorisation and restriction of Chemicals

ROV

Remotely Operated Vehicle

RYA

Royal Yachting Association

SAC

Special Area of Conservation

SCANS

Small Cetaceans in the European Atlantic and North Sea

scfd-1

Standard Cubic Foot per Day

SCI

Sites of Community Importance

SEA

Strategic Environmental Assessment

SFF

Scottish Fishermen's Federation

SMRU

Sea Mammal Research Unit

SNS

Southern North Sea

SO2

Sulphur Dioxide

SoS

Secretary of State

SOx

Oxides of Sulphur

SPA

Special Protection Area

SPL

Sound Pressure Levels

SSE

Scottish and Southern Energy

SSS

Sidescan Sonar

P

S

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SSW

South-South West

SUB

Substitution

T

THC

Total Hydrocarbons

U

UK

United Kingdom

UK BAP

UK Biodiversity Action Plan

UKCIP

UK Climate Impact Programme

UKCP

United Kingdom Climate Predictions

UKCS

United Kingdom Continental Shelf

UKMMAS

UK Marine Monitoring and Assessment Strategy

UKOOA

United Kingdom Offshore Operators Association (now Oil and Gas UK)

UNFCCC

United Nations Framework Convention on Climate Change

VHF

Very High Frequency

VOC

Volatile Organic Compounds

WBM

Water Based Mud

WLCDF

Well Life-Cycle Decision Framework

V W

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GLOSSARY  A

B

C

D

E

 Air Gun

Source of seismic energy used in acquisition of marine seismic data. This gun releases highly compressed air into water.

 Analogue Survey

e.g., bathymetry, sonar imagery and shallow profiling. Technique of representing a sensor's input as amplitude modulated electrical signal (e.g., analogue profiles are output on sweep recorders as opposed to digital).

 Anode

Positive electrode.

 Appraisal Well

Phase of petroleum operations that immediately follows successful exploratory drilling. Appraisal wells might be drilled to determine the size of the oil or gas field and how to develop it most efficiently.

 Aspect (environmental)

Element of an organisations activities, products or services that can interact with the environment.

Backfill

The replacement of excavated sediment into a trench.

Bathymetry

The measurement of the depth of the ocean floor from the water surface; the oceanic equivalent of topography.

Beaufort Force

Empirical measure (scale of 0 to 12) for describing wind velocity based mainly on observed sea conditions established by Admiral Francis Beaufort (1774 to 1857).

Benthic

Pertaining to the environment and conditions of organisms living at the bottom of the sea.

Biogenic

Chemicals or material produced by living organisms or biological processes.

Blow-out

Uncontrolled flow of reservoir fluids into the wellbore, and sometimes catastrophically to the surface. A blow-out may consist of salt water, oil, gas or a mixture of these.

Blow-out Preventer (BOP)

 A large valve at the top of a well that may be closed if the drilling crew loses control of the pressure within the well.

Catch Per Unit Effort (CPUE)

Measurement of the mass of fish caught for a given amount of energy and resources expended by a fishing fleet.

Conductor

Casing string that is usually put in to the wellbore at the surface to stop the sides of the well falling in.

Cone Penetrometer Test (CPT)

Method of providing data for use in characterising subsurface marine sediments consisting of a steel cone that is hydraulically pushed into the ground. Sensors on the tip of the cone collect data to classify sediment type by measuring cone-tip pressure and friction.

Cuttings

Small pieces of rock that break away due to the action of the bit teeth. Cuttings are screened out of the liquid mud system at the shale shakers and are monitored for composition, size, shape, colour, texture, hydrocarbon content and other properties.

Demersal

Organisms dwelling at or near the bottom of the sea.

Development

The phase of petroleum operations that occurs after exploration has proven successful, and before full-scale production. The newly discovered oil or gas field is assessed during an appraisal phase, a plan to fully and efficiently exploit it is created, and additional wells are usually drilled.

Downhole

In a well bore.

Echolocation

Used by animals to orientate, navigate, and find food it is the detection of the position, distance and size of an object by means of reflected sound.

Echosounding

The action or process of sounding or ascertaining the depth of water or of an object below a ship by measuring the time taken for a transmitted sound-signal to return as an echo.

Effort

Measure of input extended by people to catch fish (expressed in days fished).

Environmental Impact  Assessment (EIA)

The critical appraisal of the likely effects of a proposed project, activity, or policy on the environment, both positive and negative.

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Environmental Statement (ES)

 A means of submitting to the regulatory authority, statutory consultees, non-government organisations and the wider public, the findings of an EIA.

Epifauna

Organisms living on the seabed surface.

Epilithic

Organisms growing attached to an inorganic substratum, such as rocks, stones, etc.

F

Flaring

The burning of unwanted gas through a pipe. Flaring is a means of disposal used when there is no way to transport the gas to market and the operator cannot use the gas for another purpose.

G

Geohazard

 Any geological or hydrological process that poses a threat to people and/or their property.

Geophysical

The study of the earth by quantitative physical methods, especially by seismic reflection and refraction, gravity, magnetic, electrical, electromagnetic, and radioactivity methods.

Geotechnical

The study of soil and rock below the ground to determine its properties.

Grey Water

Non-industrial wastewater generated from domestic processes such as washing dishes, laundry and bathing.

H

Hydrotest

The process of pumping water through a pipeline at a higher pressure level than is normally used when transporting petroleum to confirm the continued safe operation of the pipeline, ensuring that it's free of any defects.

I

ICES rectangles

Statistical divisions of the sea.

Impact (environmental)

 Any change to the environment, whether adverse or beneficial, wholly or partially resulting from an organisation's activities, products or services.

Infauna

Organisms that live within the sediment.

Kingfisher Bulletins

Fortnightly bulletin providing free safety information to all sea users.

Kilometre Point (KP)

 A general term for the distance along a route from a fixed reference point.

L

Lowest Astronomical Tide (LAT)

The lowest level that can be expected to occur under average meteorological conditions and under any combination of astronomical conditions.

M

Macrofauna

Benthic animals larger than 1 mm in size and include the large polychaete worms, corals, shellfish, and starfish.

Magnetometer

 An instrument for measuring the strength of a magnetic field.

MARPOL Convention

International Convention for the Prevention of Pollution from Ships (1973/1978).

Median Line

Offshore international boundary.

Mobile Offshore Drilling Unit (MoDU)

 A generic term for several classes of self-contained floatable or floating drilling machines such as  jack-ups, and semi-submersibles.

Multivariate

Describes a collection of procedures which involve observation and analysis of two or more statistical variables at a time.

North Atlantic Oscillation

 A climatic phenomenon in the North Atlantic Ocean of fluctuations in the difference of sea-level pressure between the Icelandic Low and the Azores high.

Notices to Mariners

Information issued from a number of different sources, such as the UK Hydrographic Office, Trinity House or Local Harbour Authorities and may contain a variety of information such as chart updates, changes in buoyage, prior warning of activities such as dredging, exclusion zones, etc.

Oil Producer

 A well producing oil.

OSPAR

Instrument guiding international cooperation on the protection of the marine environment of the North-East Atlantic.

Pelagic

Relating to or occurring or living in or frequenting the open ocean.

Petrogenic

 A contaminant produced from unburned petroleum products.

Phytoplankton

Microscopic floating plants that exist within the water column.

K

N

O

P

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R

S

Phytoplankton Bloom

High concentration of phytoplankton in an area, caused by increased reproduction.

Pinger

Seismic source.

Platform

 An offshore structure that is permanently fixed to the seabed used to house workers and machinery needed to drill and then produce oil and natural gas in the ocean.

Plugged and  Abandoned

To prepare a well to be closed permanently with cement plugs and salvage all recoverable equipment, usually after either logs determine there is insufficient hydrocarbon potential to complete the well, or after production operations have drained the reservoir.

Potential Annex I Habitat (PAIH)

Habitat (as defined in Annex I of the EC Habitats Directive) identified in offshore areas to be put forward to the government for protection as part of the Natura 2000 in UK offshore waters programme.

Produced Water (PW)

Formation water (naturally occurring layer of water in oil and gas reservoirs) and injected water that is produced along with hydrocarbons. At the surface, the water is separated from the hydrocarbons, treated to remove as much of the hydrocarbons as possible and discharged into the sea or injected back into wells.

Ramsar Site

Wetland of international importance designated under the Ramsar Convention (1971).

Receptor (environmental)

Element of the environment that an environmental aspect can interact with or impact.

Re-injection (produced water)

Method of enhanced oil recovery to compensate for the natural decline of an oil field production by increasing the pressure in the reservoir. Produced water is injected to maintain reservoir pressure and hydraulically drive oil toward a producing well.

Reservoir

Subsurface body of rock having sufficient porosity and permeability to store and transmit fluids

Rig

 A drilling unit that is not permanently fixed to the seabed, e.g., a drillship, a semi-submersible or a  jack-up unit. Also means the derrick and its associated machinery.

Riser

The pipe which connects a rig or platform to a subsea wellhead or subsea pipeline during drilling or production operations to take mud returns to the surface; or the pipe which connects a pipeline to a platform.

Seismic

Pertaining to waves of elastic energy, such as that transmitted by P-waves and S-waves, in the frequency range of approximately 1 to 100 Hz, used to interpret the composition, fluid content, extent and geometry of rocks in the subsurface.

Semi-Diurnal

Occurring once every 12 hours.

Semi-Submersible Rig

Floating vessel that can be used for drilling supported primarily on large pontoon-like structures submerged below the sea surface usually anchored with six to twelve anchors.

Shellfish

 An aquatic animal, such as a mollusc or crustacean, which has a shell or shell-like exoskeleton.

Side-Scan Sonar (SSS)

Sonar device used for mapping the seabed.

Spawning

Reproductive activity of fish; the act of releasing eggs into the water by female fish for fertilisation by male fish.

Species

 A group of related organisms having common characteristics and capable of interbreeding.

Stochastic Model

 A model involving or containing a random variable or variables; involving chance or probability.

Subsea

Situated or occurring underwater.

Subsea Control System

Subsea system that provides electro/hydraulic control of subsea and downhole hydraulically operated valves. It also provides a data link to the platform control system conveying subsea/downhole operating parameters and performance.

Subsea Control Umbilical

Connects remotely positioned subsea satellite production and/or injection trees to subsea template controls or to surface controls on a platform. An umbilical can include up to eighteen separate control hoses within a casing e.g., hydraulic hoses, chemical injection hoses and electrical cables.

Suspended (well)

 A well that has been capped-off temporarily.

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T

Taxa

Categories in the biological classification system for all living organisms (i.e., kingdom, phylum, class, order, family, genus, species).

Thermocline

The vertical zone in the water column where temperature changes rapidly with depth.

Tie-in

 An operation in pipeline construction in which two sections of line are connected; a loop tied into the main line.

Topside

The superstructure of a platform.

Umbilical

 A conduit through which hydraulic fluids, chemicals, power and data are supplied (see subsea control umbilical).

Univariate

Describes a collection of procedures which involve observation and analysis of one statistical variable.

V

Vibrocore

 Acquisition of seabed sediment cores using a vibrating steel tube which penetrates the seabed to a particular depth.

W

Water Injector

 A well in which filtered and treated seawater is injected into a lower water-bearing section of the reservoir, the primary objective typically being to maintain reservoir pressure.

Well Head

The surface termination of a wellbore that incorporates facilities for installing casing hangers during the well construction phase. The wellhead also incorporates a means of hanging the production tubing and installing the Christmas tree and surface flow-control facilities in preparation for the production phase of the well.

Well-Test

 A test whereby the nature and quantity of the formation fluids in a possible oil- or gas-bearing stratum are determined by allowing them to flow to the surface through the drill string under carefully controlled conditions.

X

Xmas Tree

 An array of pipes and valves fitted to a production wellhead to control the flow of oil or gas and prevent a possible blow-out.

Z

Zooplankton

Small aquatic animals that float or weakly swim within the water column. Generally longer than 153 µm, up to about 5,000 µm (5 mm).

U

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1

INTRODUCTION EnQuest Heather Limited wishes to redevelop the Ardmore field in the UK Central North Sea (CNS). The field, to be renamed Alma, will be developed through two drill centres tied-back via new oil production and water injection flowlines to a floating production, offloading and storage facility (FPSO). This Environmental Statement (ES) has been prepared on behalf of EnQuest to meet the requirements of United Kingdom (UK) legislation and in support of their field development plan. It covers: Drilling of six production wells and two water-injection wells Installation of two 10-inch production flowlines, one 10-inch waterinjection flowline, two control umbilicals and one power cable Installation of the Uisge Gorm Floating, Production, Storage and Offloading (FPSO) facility Export of crude oil via shuttle tanker Operation and production of the field for an expected 10 years

1.1

THE DEVELOPER EnQuest Heather Limited is an independent oil and gas production and development company with a geographic focus on the UK continental shelf (UKCS). The Groups’ asset portfolio comprises primarily producing assets and development opportunities, together with exploration and appraisal opportunities, all of which are located in the UKCS. It has working interests in the Don, Thistle, Deveron, Heather, Ivy and Broom oil fields. EnQuest believes that the UKCS represents a significant hydrocarbon basin in a low-risk region. The UKCS continues to benefit from an extensive installed infrastructure base and skilled labour to develop, operate and manage assets. EnQuest’s management has considerable experience of working in the UKCS region and is familiar with the regulatory authorities and competitive landscape. EnQuest Heather Limited owns a 100% stake of the equity of the Alma Field.

1.2

PROJECT OVERVIEW  As a redevelopment of the Ardmore field, the Alma field will be a small oil development with a field life of ten years. The field is located in UKCS Blocks 30/24 and 30/25, 274km east of the nearest landfall on the Northumberland coastline in the CNS. It is approximately 18.5km from the Norway/UK international boundary (median line). The project location is shown in Figure 11 and the co-ordinates are given in Table 1-1.

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2°0'E

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Alma Field Development Environmental Statement

Legend

Figure 1-1: Project Location

Median line Land UKCS Block

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3°20'E

Uisge Gorm FPSO Northern Drill Centre Southern Drill Centre Production Flowline

Date

Wednesday, July 6, 2011 15:10:52

Projection

ED 1950 UTM Zone 31N

Spheroid

International 1924

Datum

D European 1950

Data Source

EnQuest, UKDeal, KISCA

File Reference

J:\P1459\Mxd\Environmental Statement\.mxd Figure 1-1 Project Location

WI Flowline

W X " )  A 

Produced By

Louise Mann

Reviewed By

 Anna Farley

Checked FPSO Platform Well Pipeline Cable Hydrocarbon Field

km

NOTE: Not to be used for navigation

0

4

8

16

24

32

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 © Metoc Ltd, 2011. All rights reserved.

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Table 1-1: Project co-ordinates Structure

Easting (E)

Northing (N)

Latitude (N)

Longitude (E)

Uisge Gorm FPSO

488 250

6 227 000

56° 11' 16.16"

02° 48' 38.45"

Northern drill centre (production wells)

485 469

6 228 541

56° 12' 05.72"

02° 45' 56.84"

Southern drill centre (water-injection wells) Datum: WGS84

485 858

6 224 891

56° 10' 07.71"

02° 46' 20.12"

1.2.1

Field History The Argyll field was discovered in 1971 and brought on stream as the UK’s first oilfield by the Hamilton Brothers. The Field was decommissioned in 1992 due to the low oil price prevalent at the time. Between 1975 and 1992 Argyll produced 74.8 mmbbl (million barrels) oil. The final field rate was 5,000 bopd (barrels oil per day) with a 70% water cut. The Argyll Field was renamed Ardmore and redeveloped by Tuscan and Acorn, with second phase first oil in 2003. Between 2003 and 2005 Ardmore produced a further 5.2 mmbbl oil. The field was the decommissioned again in 2008 because of low profitability. EnQuest now plan to rename and redevelop the Ardmore field as Alma as it is now commercially viable to develop from a small marginal field due to the prevailing oil price. As the entire previous field infrastructure was removed during the Ardmore decommissioning, and as Alma is a marginal field and production will likely be short-term, EnQuest are proposing to use an FPSO rather than install a platform. The Field consists of three main productive intervals, namely Zechstein carbonates and evaporates, Rotliegend Aeolian sandstone and Devonian sandstone/siltstone. It is located on a large Palaeozoic, southwest to northeast trending tilted fault block on the south-western flank of the Central Graben. The Field structure measures approximately 2.5km wide and 6km long.

1.2.2

Schedule Construction is scheduled to start in January 2012 with the drilling of the first production well. Construction activities will continue through to May 2013 with first oil expected in third quarter 2013. A total of six production wells and two water injector wells will be batch drilled and are expected to take approximately three months each to drill and complete. Field life is anticipated to be ten years.

1.2.3

Construction The Alma field development will consist of eight wells; six oil producers and two water-injectors. The water injectors will be drilled from a southern drill centre and the production wells from a northern drill centre. All wells will be tied-back via new flexible flowlines to the Uisge Gorm FPSO. Flowlines will consist of one 10-inch water-injection flowline to the southern drill centre and two 10-inch production flowlines to the northern drill centre. As a general rule the water injection flowline will be trenched and backfilled where possible. In the event of any undulations in the trench (and subsequently the flowline) a contingency will be in place for the provision of approximately 5,000

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tonnes of rock for deposition for protection. The rock will be deployed to mitigate any upheaval buckling (low risk for flexible flowlines) or pipeline out of straightness events experienced during the trenching and pipe-lay activities. This may be required for pipeline protection, depth of cover anomalies or dropped object protection. The requirement for rock deposition will be identified during post lay survey and if required the rock will be placed accurately using a dynamically positioned installation vessel. The vessel will be equipped with a fall pipe to deploy rock accurately in the spot location. Due to the infield debris (both buried and on the seabed), wellheads and the associated infrastructure in place from previous field operations, it is difficult to establish a clear route and therefore it will not always be possible to trench and backfill the flowline. Where it is not possible to trench, the line will be surface-laid and protected by concrete mattresses and grout bags. The use of trenching and backfilling will be optimised and surface laid pipe minimised. The production flowlines cannot be trenched and backfilled as this would result in high arrival temperatures of the production fluids at the FPSO. The flowlines will instead be surface laid and protected by concrete mattresses and rock material where required. Production wells will be fitted with electrical submersible pumps (ESPs) to assist flow rates. The wells will be drilled from a semi-submersible drilling rig. Drilling is expected to commence in January 2012, with the rig remaining on site until April 2013. The production flowlines will terminate in a manifold at the northern drill centre and in a bolted straight “T” piece to the flexible risers beneath the FPSO. This “T” piece will allow for future tie-ins. The risers will then connect to the FPSO in a lazy S configuration. In addition a control umbilical will be surface laid out to each drill centre and a power cable will also be laid out to the production wells. The flowline corridor will be approximately 30m wide to the southern drill centre and 50m wide to the northern drill centre. Each riser will be held in place with a vertical and horizontal hold-back tether. Each hold-back tether will consist of one upper piled or gravity riser base (vertical) and one lower clump weight holdback anchor (horizontal) (Figure 1-2). Figure 1-2: FPSO ris er hold -back tether exampl e

Note: Image is for illustrative purposes only and does not necessarily reflect exact layout of flowlines and associated infrastructure.

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It is possible that the flowlines will require dropped object protection around the well head areas. This will take the form of concrete mattresses. It is also likely that the first 50m of the flowlines, control umbilical and power cable will be mattressed. Installation and tie-in of the flowlines is expected to occur between January and April 2013. The Uisge Gorm will be held on station by nine mooring lines, configured in three clusters. The FSPO is secured to the seabed with anchors. The anchors will be within a radius of 1,592m of the FPSO. Mooring installation is expected to commence in September 2012.

1.2.4

Production First oil from the field is currently expected in third quarter 2013. Production forecasts suggest the field will produce approximately 120,000 barrels of fluids per day (19,080m 3). The four production wells are expected to have a high water cut and will be produced with the aid of electric submersible pumps (ESPs). At the start of field life the water / oil ratio will be approximately 70% basic sediment and water (BS&W). As the reservoir declines the water / oil ratio will increase and by the end approximately 90 barrels (14.31m 3) of water will be produced for every 10 barrels (1.59m 3) of oil. Reservoir pressure will be maintained by produced water reinjection supplemented with treated seawater introduced through the two new water-injection wells. It is expected that a shuttle tanker will visit the FPSO once every two weeks to offload stored crude oil via a loading hose and tanker mooring system. Under normal operations all produced water (PW) will be re-injected with treated seawater into the water-injection wells. There is the possibility that PW may be discharged if one of the water-injection pumps fails. Therefore, a new PW handling process will be installed to ensure oil in water concentrations are below 30mgl-1. The FPSO will be powered by two 14MW steam turbines which can be fuelled by diesel, fuel gas or crude oil. Under normal operations gas produced from the reservoir will be used to power the steam boilers. When gas production proves insufficient to power a boiler it will switch to duel fuel e.g., fuel gas and crude oil. As the boilers will run on gas augmented by crude, no gas will be flared, however there may be a short period during the early part of field life where excess gas is produced that cannot be burned, this will be flared.

1.2.5

Decommissioning Field life is expected to be ten years and therefore decommissioning and abandonment will occur around 2023. The arrangements for decommissioning the field will be developed in accordance with UK government legislation and international agreements in force at the end of field life. However, the development plan is based on the following assumptions (see Section 5-4): Plug and abandon all wells Removal of the conductors to below the mud line  All subsea infrastructure e.g. flowlines, flexible risers, well heads and manifolds will be removed FPSO will be removed and relocated

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ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Third party confirmation of seabed clearance These requirements were considered in the design of facilities and during project planning.

1.3

FORMAT OF THE ENVIRONMENTAL STATEMENT This ES is divided into the principal sections outlined in Table 1-2. Table 1-2: Struct ure of thi s ES

Section

Title

Content

-

Non-Technical Summary

The aim of the non-technical summary is to enable communication with those unfamiliar with the environmental impact assessment (EIA) process and terminology by summarising the key findings of the ES document in simple terms.

1

Introduction

An introduction describing the developer and summarising the project.

2

Institutional, Policy and Regulatory Frameworks

 A description of the legislative frameworks which govern the project and the EIA.

3

Project Justification

This section justifies why the project is preferable to alternative options elsewhere.

4

EIA Methodology

A description of the process followed when conducting the EIA.

5

Project Description

A description of the project in terms of the activities that will be undertaken during the construction, operation and decommissioning stages of the project.

6

Project Footprint

A quantitative description of the emissions to air, sea and ground from the construction, operation and decommissioning stages of the project.

7

Accidental Events

This section describes the types of accidental event that could occur during the construction and production phases of the project and presents a summary of the oil spill modelling undertaken to inform the EIA.

8

Impacts on Physical Environment

9

Impacts on Biological Environment

10

Impacts on Human Environment

These sections describe the physical, biological and human baseline environment in the project area and identify those activities of the project that may interact with environmental receptors. They evaluate and specify project impacts upon the individual receptors, describing them quantitatively wherever possible (in some cases only a qualitative assessment is possible) and in each case the level of significance has been determined. Mitigation measures to avoid, reduce or remedy the effects identified in the impact assessment are outlined.

11

Cumulative and Incombination Impacts

This section considers cumulative impacts where the project contributes to impacts occurring from other activities or processes.

12

Environmental Management

This section describes the EnQuest corporate and project specific management system outlining how EnQuest will manage health, safety and environment activities arising from the project.

13

Conclusions

14

References

 A

Appendix A

This section contains the environmental impact assessment tables.

B

Appendix B

This section contains the description of the oil spill modelling carried out for the Alma development and its associated impacts.

C

Appendix C

This section contains a summary of chemicals that could be used for the drilling of the wells.

D

Appendix D

This section contains the JNCC noise assessment flowcharts and graphs used to carry out the noise assessment in Section 8.

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1.4

ES AVAILABILITY  A digital or hard copy of the ES is available on request from: Burton Millar EnQuest Senior HSE Advisor, Projects Level 5, Consort House Stell Road  Aberdeen  AB11 5QR Email: [email protected] The ES can also be downloaded from the Press Releases area at www.metoc.co.uk.

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ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

2

INSTITUTIONAL, POLICY AND REGULATORY FRAMEWORKS Offshore oil and gas developments are governed by a collection of international, European Commission (EC) and UK laws, policies and guidelines. These laws, policies and guidelines are implemented through various institutional frameworks. The management goals and objectives that an environmental assessment may aim to achieve are governed by these laws/policies and institutional frameworks. Although not an exhaustive list, the following section outlines the main policies, laws and guidelines relevant to this project and considered in this ES.

2.1

RELEVANT POLICY GUIDELINES Energy White Paper 2007 and the UK Low Carbon Transition Plan 2009  – Sets out the UK Governments international and domestic energy strategy to respond to the changing circumstances in global energy markets and to address the long term energy challenges the country faces (DTI 2007, HM Government 2009). Marine Policy Statement – UK Government and devolved administrations have worked together to set out a number of high level marine objectives which articulate the outcomes they are seeking for the UK marine area as a whole. Their vision is to achieve clean, healthy, safe, productive and biologically diverse oceans and seas. The Department for Environment, Food and Rural Affairs (Defra) are responsible for developing this strategy. It sets out the general environmental, social and economic considerations that need to be taken into account in marine planning. Consultation on the Statement and supporting documents has been ongoing since 2008 and the Marine Policy Statement was adopted in March 2011 (Defra 2011). UK Biodiversity Action Plan (UK BAP) – The UK BAP is the UK Government’s response to the Convention on Biological Diversity (CBD) (1992). It describes the UK’s biological resources and provides detailed plans for the protection of these resources. In 2007 the UK BAP list was reviewed and now includes 1,150 species and 65 habitats. Action plans, which set out priorities, actions, targets and reporting targets, have been created for 382 species and 45 habitats.

2.2

INTERNATIONAL CONVENTIONS , EC AND UK LAWS AND REGULATIONS

2.2.1

International Conventions Convention for the Protection of the Marine Environment of the North East Atlantic (Oslo Paris Convention (OSPAR) Convention) 1992 – main legislative instrument regulating international cooperation. It concentrates on provisions to protect the marine environment through the use of best available techniques, best environmental practice and where appropriate clean technologies (OGUK 2008). The precautionary principle concept also features prominently. The convention regulates European standards

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ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

on the offshore oil and gas industry, marine biodiversity and baseline monitoring of environmental conditions (OGUK 2008). As a signatory to the Convention, the UK, and therefore the UK oil and gas industry and this project, are governed by the legislative framework the Convention enforces. For example, the OSPAR convention prohibits the discharge of oil based mud (OBM), which determines how drill cuttings are managed during a drilling operation. Convention on Biological Diversity (CBD) 1992 – this international treaty sets out commitments for maintaining the world's ecological biodiversity as the world develops. The Convention establishes three main goals: the conservation of biological diversity, the sustainable use of its components, and the fair and equitable sharing of the benefits from the use of genetic resources. UK Government has reacted to the commitments of the Convention by establishing the UK BAP discussed in Section 2.1. United Nations Framework Convention on Climate Change (1994) The Convention sets an overall framework for intergovernmental efforts to tackle the challenge posed by climate change. It recognises that the climate system is a shared resource whose stability can be affected by industrial and other emissions of carbon dioxide and other greenhouse gases. Under the Convention the Government is committed to gather and share information on greenhouse gas emissions and launch national strategies for addressing greenhouse gas emissions (UNFCCC 2008). The convention has also influenced EC and UK legislation, being pivotal in the establishment of the EC Council Directive 2003/87/EC and the UK Greenhouse Gas Emissions Trading Scheme Regulations, discussed in Sections 2.2.2 and 2.2.3. Convention on Environmental Impact Assessment in a Transboundary Context (Espoo) 1991 – The Espoo Convention sets out the obligations of Parties to assess the environmental impact of certain activities at an early stage of planning. It also lays down a general obligation to States to notify and consult each other on all major projects under consideration that are likely to have a significant adverse environmental impact across boundaries. The Convention was adopted in 1991 and entered into force in 1997.

2.2.2

EC Law The European Commission issues directives, regulations, decisions, opinions and recommendations (see glossary for definitions) to member states. The above cover all aspects of society from culture, technology and human rights to the environment, wildlife and nature conservation. The development will be subject to a wide range of Directives and Regulations as they are implemented in UK law. A number of the key Directives are listed below: Council Directive 97/11/EC (EIA Directive) – Amended Directive 85/337/EC on the assessment of the effects of certain public and private projects on the environment. Requires environmental assessments to be carried out for certain types of offshore oil and gas activities. Council Directive 2003/35/EC (Public Participation Directive) – provides for public participation in respect of the drawing up of certain plans and programmes relating to the environment and amending with regard to public participation and access to justice Council Directive 85/337/EC.

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Council Directive 2001/42/EC (SEA Directive) – The purpose of the Strategic Environmental Assessment (SEA) Directive is to ensure that environmental consequences of certain plans and programmes are identified and assessed during their preparation and before their adoption. This will mean that environmental assessments carried out for individual projects will be able to take advantage of additional data and information on the regional impacts of the oil and gas industry. Council Directive 92/43/EC (Habitats Directive) – Directive on the conservation of natural habitats and wild fauna and flora. The Directive introduces a range of measures to protect 189 habitats and 788 species listed in the Annexes. Each member state is also required to prepare and propose a national list of sites to be adopted as Special Areas of Conservation (SACs). Council Directive 79/409/EC (Birds Directive) – The Directive provides a framework for the conservation and management of, and human interactions with, wild birds in Europe. Like the Habitats Directive it introduces a range of measures to maintain the favourable conservation status of all wild bird species across their distributional range and allows for the establishment of Special Protection Areas (SPAs) for rare or vulnerable species. Council Directive 2008/1/EC (Integrated Pollution Prevention and Control (IPPC) Directive) – replaces Directive 96/61/EC and aims to prevent and control emissions to air, water and soil from industrial installations. The directive aims to increase the use of best available techniques (BATs), to ensure a higher level of environmental protection. Council Directive 2003/87/EC (EU Emissions Trading Scheme (EU ETS) Directive) – The Directive establishes a scheme for greenhouse gas emissions allowance trading within the European Community. The Directive requires that member states establish national allocation plans for emissions. Registration, Evaluation, Authorisation and restriction of Chemicals (REACH) - Applies to substances manufactured or imported into the EU in quantities of 1 tonne or more per year. Aims to protect human health and the environment from chemical use. OSPAR Recommendation 2010/5 on the assessment of environmental impacts on threatened and/or declining species – Requires that Contracting Parties to OSPAR take into consideration the relevant species and habitats on the OSPAR List of threatened and/or declining species and habitats when assessments of environmental impacts of human activities that may affect the marine environment of the OSPAR maritime area are prepared.

2.2.3

UK Law  Although not an exhaustive list, the main UK regulations applying to the project are listed below: Petroleum Act 1998 – Requires all offshore oil and gas development to apply for consent to undertake the project. Consent is issued by the Secretary of State (SoS) and in addition to giving consent to construct the development authorises the owners to operate the development.

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Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) (Amendment) Regulations 2007 – amend the 1999 regulations of the same name. The regulations implement the EC EIA Directive and Public Participation Directive; requiring an ES to be submitted for offshore oil and gas projects and public participation in the consent process. Offshore Petroleum Activities (Conservation of Habitats) Regulations 2001 (amended in 2007) – The regulations apply the Habitats Directive and Birds Directive in relation to oil and gas projects on the UKCS. Offshore Marine Conservation (Natural Habitats, &c.) Regulations 2007 (as amended in 2009 and 2010) – These regulations apply in the offshore area of the UK and protect marine species and wild birds through a number of offences that aim to prevent environmentally damaging activities. It is now an offence under the Regulations to deliberately disturb wild animals of a European Protected Species. The regulations also implement in the UK the EC Directives 92/43/EC (Habitats Directive) and 79/409/EC (Birds Directive). Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2011 – The regulations are designed to encourage operators to reduce the quantities of hydrocarbons discharged during the course of offshore operations. Offshore Chemical (Amendment) Regulations 2011 – Requires all offshore operators using and/or discharging chemicals to apply for a chemical permit. With respect to the project this will take the form of Petroleum Operators Notices (PONs) for the drilling (PON15B) and pipeline (PON15C) which will be submitted to the Department of Energy and Climate Change (DECC) in advance of operations. Merchant Shipping (Oil Pollution Preparedness, Response Co-operation Convention) Regulations 1998 – Under these regulations operators of offshore oil and gas installations and pipelines must have an approved oil pollution emergency plan (OPEP) setting out arrangements for responding to incidents which cause or may cause marine pollution by oil, with a view to preventing such pollution or reducing or minimising its effect. The Offshore Installations (Emergency Pollution Control) Regulations 2002 – The Regulations give the UK Government powers to intervene in the event of an incident or accident involving an offshore installation where there is, or may be risk of, significant pollution, or where the operator is failing or has failed to implement effective control and preventative operations. The Greenhouse Gas Emissions Trading Scheme Regulation 2005 – provide a framework for a greenhouse gas emissions trading scheme and implement EC Directive 2003/87/EC. Any installation with combustion plant that on its own or in aggregate with any other combustion plant has a rated thermal input exceeding 20MW(th) is required to be registered under the EU ETS. The Offshore Combustion Installations (Prevention and Control of Pollution) (Amendment) Regulations 2007 – The regulations implement EC Directive 96/61/EC and apply to combustion installations located on offshore oil and gas platforms where an item of combustion plant on its

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own, or together with any other combustion plant installed on a platform, has a rated thermal input exceeding 50MW(th). Marine and Coastal Access Act (MCAA) 2009 – The Act seeks to improve management and increase protection of the marine environment. It is a large Act that covers a multitude of provisions. Amongst other things it establishes a new Marine Management Organisation, to produce marine plans, administer marine environmental licensing, enforce environmental protection law and manage marine fisheries, and introduces new mechanisms for the designation of marine conservation zones. Energy Act 2008 – The provisions of the Coast Protection Act relating to navigation considerations regarding the oil and gas industry were transferred to the Energy Act in April 2011 by the MCAA. The change introduces a formal application process linked the environmental regime for consent to locate fixed infrastructure e.g., pipelines, platforms, wellheads, drilling rigs etc. It will also apply to some vessel activities if the vessel is physically connected to the seabed that could constrain their ability to navigate e.g., drill ships and intervention vessels. The Merchant Shipping (Prevention of Pollution by Sewage and Garbage from Ships) Regulations 2008 – The regulations implement in the UK the requirements of MARPOL 73/78 Annex IV. It should be noted that MARPOL also defines a ship to include fixed and or floating platforms and these are required where appropriate to comply with the requirements similar to those set out of vessels.

2.3

SEA AND EIA GUIDELINES The DECC have issued guidance notes regarding the Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) (Amendment) Regulations 2007, providing details of the required contents of an ES. This ES takes into account this latest guidance (DECC 2009a). In addition, the DECC has recently released a statement in a letter to industry (23 December 2010) stating that the ES assessment of potential impacts from hydrocarbon releases must be extended to match the scope of the recently amended OPEP guidelines. The EIA process is designed to consider the potential impacts from an individual project, ignoring those from other activities in the area. Although consideration is now being given to cumulative impacts in EIA this is still project specific. As a result of the limitations of the EIA process there is now a push towards using EIA at a more strategic stage of the industry development phase. SEAs consider environmental objectives at policy and planning stages, provide a common basis for EIA preparation and ensures that total activity level in one region does not impose unacceptable regional environmental impacts. In 2001 the EC adopted a Directive on the assessment of the effects of certain plans and programmes on the environment 2001/42/EC (SEA Directive).  Although the UK have yet to formally implement this Directive, the DECC has produced a series of SEAs for regions of the UKCS. This project lies within SEA region 2. Once SEAs were completed for all regions of the UKCS an Offshore Energy SEA was undertaken in 2008/2009 to inform further seaward rounds of oil and gas licensing, future licensing for the underground storage of combustible gas in depleted and other offshore oil and/or gas fields and further rounds of offshore wind farm leasing. This OESEA was updated with

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amendments issued in 2011. The technical reports and recommendations made in all of these SEAs were used to inform this EIA.

2.4

UK INSTITUTIONAL FRAMEWORK Secretary of State (SoS) – The ES review and approval process culminates in an approval from the SoS under the Petroleum Act 1998. The SoS is also the focal point for appeals to decisions. The SoS leads the DECC. Department for Energy and Climate Change (DECC) – Administers the Petroleum Act 1998 under which project consents are given. They are the principal environmental regulator for the offshore oil and gas industry and are responsible for implementation of the EIA Regulations. They also have representatives at OSPAR as a Regulatory Authority. Department for Environment Food and Rural Affairs (Defra) – Responsible for implementation of Government programmes for the protection of the environment, food (including fisheries) and rural affairs.  At the European and international level Defra represent the UKs interests at OSPAR. The department provides advice to the DECC on a range of subjects including: environmental statements, the interactions between fisheries and offshore operations, offshore construction and drilling activities, marine pollution and chemical use and discharge. In Scotland many of the advisory responsibilities for the offshore oil and gas industry are delegated to Marine Scotland. Joint Nature Conservation Committee (JNCC) – Responsible for promoting nature conservation at UK and international levels. They are the main government and industry advisor on offshore sensitivities with respect to seabirds and cetaceans. Amongst other roles they advise the DECC on environmental statements and are the body responsible for identification and recommendation on offshore conservation areas under the EC Habitat Directive. Marine Scotland – Is the directorate of Scottish Government responsible for the integrated management of Scotland’s sea. Amongst other roles they advise the DECC on the Offshore Chemical Regulations and impacts on fish and fisheries.

2.5

ENQUEST CORPORATE POLICY EnQuest will conduct its operations in a responsible manner that protects the health and safety of people and minimises the impact on the environment. The commitment of EnQuest with respect to environmental issues is laid down in the Environmental policy, presented as Figure 2-1. The Environmental Policy along with the Health & Safety (H&S), Social Responsibility, and Quality Policies are reviewed annually by the H&SEQ management team and communicated to all persons working on behalf of the organisation. EnQuest maintains a comprehensive HSE management system, details of which are provided in Section 11.

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Figure 2-1: EnQuest Environmental Policy

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3

PROJECT JUSTIFICATION AND ALTERNATIVES

3.1

PROJECT JUSTIFICATION Internationally and nationally, energy demand is growing. Given the current uncertainties in the western economies, the visibility of this demand may not be as good over the next few years as it was at the start of the century. However, irrespective of growth, it is likely that for some time to come the energy demand will be met largely by fossil fuels such as oil, gas and coal (DTI 2007). Currently, oil and gas provide 75% of the UK’s total primary energy demand (OGUK 2010). In 2009, the UKCS oil production was enough to satisfy 94% of domestic consumption, produced mainly from fields in the Central North Sea (CNS) basin, with some production in the NNS and Southern North Sea (SNS). Having access to its own reserves has contributed greatly to the UK’s wealth (OGUK 2010). This security of supply has also enhanced the UK’s selfsufficiency in the international arena, particularly at a time when increased competition for resources and global economic uncertainty is leading to high fluctuations in energy markets and fuel costs. UK oil production peaked in 1999 and is currently declining. Production averaged 0.9 billion barrels of oil equivalent in 2009, a decline of nearly 10% in 2008 production figures (OGUK 2009). In 2020, 70% of the UK’s primary energy will still come from oil an d gas, even if the UK’s target to achieve 20% energy from renewable sources 3  is achieved. If investment is sustained, the UKCS has the potential to satisfy 50% of the UK oil and gas demand in 2020 (OGUK 2010). However, as consumer demand increases and production continues to decline, at some stage in the future the UK will switch to being a net importer. In 2000, the UK Government identified the need to stimulate oil and gas investment and activity to ensure that indigenous production of oil and gas remained at significant levels into the future. The Promote UK  campaign is designed to attract new entrants onto the UKCS, and focused on: Independent oil companies with the resources to drill wildcat exploration wells and exploit the full value chain from exploration to development; and Niche ‘developers’, particularly those with the skills to develop previously undeveloped discoveries by using technically innovative and best cost solutions (DECC 2011a).  As a result of these initiatives, EnQuest has been active on the UKCS since 2010. It specialises in predominantly mature areas of the NNS and CNS, aiming to maximise the potential from existing fields and future developments in the UKCS. The longer term strategy is to become a prominent exploration and development operator. The development of the Alma Field is part of this strategy and would bring on-stream a marginal field that it is now feasible to develop with the prevailing oil price.

3

 The European Council agreed in 2007 to a binding agreement that sets a target for 20% of the EU’s energy to be from renewables by 2020. The UK Energy White Paper commits the UK to see renewables grow as a proportion of the UK electricity supply to 10% by 2010, with an aspirational level of 20% by 2020 (DTI 2007)

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The Alma development fits many of the UK energy policy objectives: It is an economically viable development that has been designed to maximise reserve recovery within an existing mature province using best cost solutions It is a national resource that will help to contribute towards energy security  As stated above, UK oil production for 2009 was 900 million barrels of oil equivalent (123 million tonnes) (OGUK 2010). Assuming the 10% decline in production noted earlier continues, current annual decline in production will be approximately 90 million barrels (12.3 million tonnes) per year. Current estimates are that, based on an 11 year field life, the base case recovery (P50 4) from the Alma field will be 19.97 million barrels (2.7 million tonnes) with a high recovery case (P10 5) of 32.57 million barrels (4.4 million tonnes). The cumulative production profiles for both cases are shown in Tables 3-1 and Figure 3-1: Table 3-1: Cumulative (by y ear) producti on profiles Year

Base Case (P50)

High Recovery (P10)

MMbbls

Tonnes

MMbbls

Tonnes

2013

2.16

0.30

2.66

0.36

2014

6.09

0.83

9.32

1.26

2015

8.84

1.21

14.02

1.90

2016

11.02

1.51

17.71

2.40

2017

12.86

1.76

20.75

2.81

2018

14.46

1.98

23.34

3.16

2019

15.91

2.18

25.60

3.46

2020

17.24

2.36

27.62

3.73

2021

18.48

2.53

29.42

3.98

2022

19.62

2.68

31.07

4.20

2023

20.7

2.83

32.57

4.40

Source: EnQuest

The Alma field therefore aligns with UK Energy Policy objectives by providing a cost effective solution for a small scale hydrocarbon resource, in a manner that minimises risk to people and the environment. EnQuest’s participation in North Sea oil and gas exploration and production thus contributes towards achieving the national objectives to prolong indigenous production, and to attract new independent companies into the North Sea.

4

 50% confidence level of this volume of oil being produced  10% confidence level of this volume of oil being produced

5

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Figure 3-1: Cumulative (by year) production profiles

3.2

ALTERNATIVES

The consideration of alternatives to a proposed project is a requirement of many EIA processes and a standard requirement of the Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) (Amendment) Regulations 2007. A comparison of alternatives helps to determine the best method of achieving the project by indicating the best available technology (BAT) or the best environmental practice (BEP) or at the very least the option which minimises environmental impacts. The type and range of alternatives considered might include: Supply or activity alternatives e.g., using the location to develop oil reserves or for alternative offshore technologies Location alternatives, either for the entire project or for individual components e.g., the siting of a platform or the routing of a pipeline Process or infrastructure alternatives e.g., use of waste-minimising or energy-efficient technology, establishing new infrastructure or using existing facilities Scheduling alternatives e.g., to avoid sensitive periods of the year for particular environmental receptors The World Bank recommends a tiered approach to the analysis of alternatives. It is designed to bring environmental considerations into all stages of development planning and ideally begins with strategic environmental assessment (SEA) to analyse broad alternatives within a region (Sadler and McCabe 2002). In the UK, a set of SEAs are in place which fulfils this purpose.

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This section discusses: The alternatives to the proposed project (Section 3.2.1) i.e., why the development of an oil project is considered the best alternative for the area in relation to the UK energy strategy The alternatives that were considered within the project (Section 3.2.2) e.g., location, process, infrastructure and scheduling alternatives.

3.2.1

Alternatives to the proposed project In light of declining fossil fuel reserves, part of the UK energy strategy is to encourage the development of alternative energy sources to ensure security of supply (DTI 2007). Offshore technologies being considered include wind farms and wave and tidal devices. Some of the technologies considered are not proven and currently it is only wind farms that are being actively developed on a commercial scale. The UK Government has set a target that 20% of the electricity supply by 2020 will be supplied from renewable energy sources (DTI 2007). The need to reduce carbon emissions whilst ensuring secure energy supplies means that the UK cannot rely on renewable energy alone. The UK will continue to need fossils fuels as part of a diverse energy mix for some time to come (DTI 2007) and as such the development of the Alma reserves is very much in line with the current UK energy policies. The Alma field is a re-development of an existing oil field and is not within a zone designated as a currently feasible site for an alternative offshore technology such as wind. As such, the development of the field is considered to be the best option for providing a new energy source. In terms of alternative oil reserves, EnQuest is always looking for potential new sources of oil, but for commercial reasons they have to target proven reserves first.

3.2.2

Alternatives within the proposed project EnQuest has investigated a range of development options for the following project elements:

1)

Production System

2)

Drilling rig

3)

Production flowlines

These are tabulated below, (Table 3-2) highlighting advantages and disadvantages with respect to technical, economic and environmental considerations. The FPSO was selected as the best production option. For a small development with a relatively short field life such as Alma, the ability to re-use an existing production facility is a key factor - on both economic and environmental grounds. Having selected the FPSO option, the Uisge Gorm was selected as the most suitable for the following reasons:  Alma requires a similar mooring configuration and the vessel has previously worked within 15km from the proposed Alma location  An UKCS North Sea safety case already exists

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Recent North Sea service and maintenance records are up to date for recent production operations Large range of capacity handling Can install produced water reinjection (PWRI) with minimal oil in water (OIW) discharge, benefiting environment Potential for a change from diesel power generation, providing environmental improvement

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Table 3-2: Pros and cons or dif ferent development scenarios Option

Pro

Con

Decision

1A: FPSO

 A limited number of FPSOs are available for deployment

 Age of available FPSOs / fatigue life

Selected

Provides an integrated storage and offloading system

Substantial modifications required

Modification required are more economic that other available options e.g. new platform

Tanker offloading system potentially higher risk of oil spills than export pipelines

FPSOs fit for expected field life Using an existing FPSO is cheaper than a new build FPSOs considered have proven track record in the UKCS Minimal seabed disturbance from installation Can be easily redeployed at end of field life 1B; Petrofac OE&O FPF-1

Readily available Would provide consistent Duty Holder across all EnQuest Assets Would be suitable for deployment to NNS at end of field life Established contracting strategy with Petrofac Offshore Engineering and Operations (OE&O)

Would require substantial replacement of a number of systems e.g. process system, accommodation and utilities, riser connection system, helideck, primary and secondary steelwork, mooring system

Rejected

Fatigue and integrity issues No crude storage / offloading capabilities so would require export routes Limited pipeline export routes

1C: New platform

Systems designed specifically for Field

Limited pipeline export routes

New facility and equipment designed for field life Latest technology designed into build

Utilisation of existing facility and avoidance of new build environmental impacts

Definitive build cost

Larger seabed footprint than FPSO

Lower OPEX costs

Jacket structure would require substantial piling operations

Rejected

Substantial costs incurred with build and installation Would require decommissioning at end of field life Higher CAPEX

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Option

Pro

Con

Decision

1D: Subsea tie-back

No requirement for oil storage

Limited opportunities to tie into pipeline export routes. Closest facility is 19km

Rejected

No requirement for tanker mooring and offloading facility Lower OPEX costs associated with tanker

Would require decommissioning at end of field life

 Avoidance of potential environmental impacts of crude transfer and tanker fuel oil

Potentially larger seabed disturbance with longer export route  Additional costs associated with pipeline crossings

 Avoidance of known seabed hazards from previous operations in field

Identification of clear pipeline routes difficult due to large amount of seabed hazards from previous production operations Would incur environmental impacts from pipelay trenching and installation vessel activity.

2A: SemiSubmersible Drilling Rig

Less weather dependant during positioning on site

More waiting on weather during operations

More scope for moving rig but maintaining same anchor pattern – less seabed disturbance. For example, moving to allow subsea infrastructure to be installed, moving rig if subsurface philosophy changes, ability to drill six wells on same anchor pattern

Moving to new wellhead location (skidding rig) on same anchor pattern dependent on weather

Easier to run horizontal xmas trees

Selected

More expensive day rates Potentially larger seabed footprint if consider scour marks from anchor catenary as well as anchor mounds

Better selection options- at least two rigs are known to be available Current drilling team has extensive knowledge of semi submersible drilling operations 2B: Heavy Duty Jack-up Drilling Rig

Lower operation day rates

Lower lifting and storage capacity

Potentially lower waiting on weather once located on individual well

Movement between individual wellheads is limited and may require full rig move outside of footprint – could lead to greater seabed disturbance that a semi-submersible

Potentially smaller seabed footprint (only area of spud cans)

Rejected

Rig availability tighter than for semi-submersibles Spud can disturbance could affect future rig locations Would require additional geotechnical site investigations for spud can placement which could not be covered under Alma surveys in 2010 Riser tensioning capacity is greater in deeper water Jack-up may experience problems with horizontal xmas trees

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Option

Pro

Con

Decision

3B: Buried flowlines (water injection)

Greater protection for flowlines – no additional protection such as rock would be required except for mattressing and grouting at trench transition areas

Larger seabed footprint

Selected

Conventional / proven solution

 As the flowlines would run quite hot, there would be the requirement for large cooling spools if trenched

Option to surface protect spans which cannot be buried due to existing subsurface obstructions

If select low temperature option for flowlines then flowlines could not be protected or buried

Harder to decommission would likely leave in-situ at end of field life Higher mobilisation costs for installation as would need more vessels and equipment Higher risk of subsurface obstructions during trenching which would need to be micro-routed

3A: Surface laid flowlines (production)

Ease of installation – range of installation vessels available. Benefit as compact field layout with possible drilling rig on site during installation

Greater risk of damage

Selected

Procurement costs

Lower mobilisation costs for installation

May require dropped object protection e.g. rock material, concrete mattresses which will increase seabed footprint

Potential of re-use / decommissioning easier

Less than 1m of silty sand as surface layer. May sink into sand.

Conventional / proven solution Risers only solution available with FPSO Minimal seabed disturbance Lower risk of subsurface obstructions because no trenching

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4

IMPACT ASSESSMENT METHODOLOGY

4.1

ENVIRONMENTAL AND HUMAN IMPACT ASSESSMENT PROCESS The EIA process comprises a number of different phases as follows: Project definition and understanding how environmental considerations have formed an essential part in the development concept, definition and selection of activities (Sections 3, 5, 6 and 7) Scoping of potential impacts and information collection on environmental conditions (Sections 4.1.4.1, 8, 9, and 10) Prediction and assessment of potential impacts (Sections 8, 9 and 10) Development of management and mitigation measures (Sections 8, 9 and 10) Residual impact significance assessment (Sections 8, 9 and 10) Communication and reporting of results These steps are informed by the assessment team, the project engineering and management team and by stakeholder consultation throughout the EIA process as shown in Figure 4-1. Further details of the stakeholder engagement process undertaken for the Alma field and its contribution to the project are provided in Section 4.3. Figure 4-1: Overview of EIA methodology

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4.1.1

Project Definition The first stage of the EIA process is to establish a detailed understanding and description of the project and its associated emissions, effluents and physical footprint. EnQuest’s project engineers and contractors have defined project activities relating to construction, commissioning, operations and decommissioning of the Alma field, which are presented as the Project Description (Section 5). Working with the project engineers, the assessment team has calculated the footprint of the project on the environment (Section 6), by quantitatively establishing emissions to air, water and the seabed. Where it has not been possible to establish a quantitative footprint, qualitative methods have been used.

4.1.2

Establish Baseline Environment In order to assess the potential impacts resulting from the project it is necessary to identify the environmental and human conditions that currently exist at the site. The environmental and human attributes which are considered have been divided into the three categories below: The physical environment: air, climate change, water and seabed conditions (Section 8) The biological environment: plankton, benthic ecology, fish, shellfish and elasmobranchs, seabirds, marine mammals, protected sites and species (Section 9) The human environment: archaeology, commercial fishing, shipping and navigation, recreational sea users, other seabed users such as other oil and gas developments, wind farms, marine aggregate extraction and military practice and exercise areas (Section 10)  A good understanding of the baseline for these attributes has been achieved through two activities: Undertaking and review of primary (baseline) field studies Detailed review of all secondary resources (i.e., existing documentation and literature) The data sources used to describe each environmental or human receptor are listed at the beginning of each baseline sub-category in Sections 7, 8 and 9. A summary of the primary and secondary information sources used for the project are as follows: Primary Data  A site survey of the Alma field development was carried out between December 2010 and January 2011 by Gardline Geosurvey (GGL 2011). Geophysical (high resolution seismic, single beam and multi-beam echo sounding, sidescan sonar, magnetometer, chirp and mini airgun), geotechnical (vibrocore and CPT) and environmental (grab sampling and still photography) data were collected over the following areas (Figure 4-2): 8km x 7.1km anchoring conditions survey 3.179km pipeline survey (Northern drill centre to FPSO) 3.329km pipeline survey (Southern drill centre to FPSO)

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1km x 1km well site survey at Northern drill centre 1km x 1km well site survey at Southern drill centre The aim of the survey campaign was to: Characterise the seabed and shallow geology in terms of topographical conditions, shallow geological and seabed features, sediment type and sediment particle size distribution Identify obstructions and debris on the seabed Characterise the anchoring conditions To provide a top hole prognosis for the two surveyed proposed well locations Characterise the benthic community Determine whether any features of conservation importance are present  All data acquired were of good quality and sufficient resolution to identify physical and biological features of importance, if present. The project area is in a well characterised region of the CNS and available survey data show that the benthic community over the Alma field is typical of the surrounding area.

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Figure 4-2: Alma development sur vey extents

Source: GGL (2011)

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Secondary data Other data on particular elements of the physical, biological and human environment were obtained from appropriate agencies where required. In addition, existing documentation and literature was used to compile the existing baseline. Specific details for the information resources relating to each aspect assessed are detailed in Sections 8 to 10. Examples of some of the key secondary data sources used are given below. Strategic environmental assessment (SEA) undertaken by the DECC to inform licensing in the CNS (DTI 2001a) Offshore Energy SEA – undertaken by the DECC to inform licensing of all energy developments in the UK (DECC 2009b) Fisheries sensitivity maps for British waters (Coull et al. 1998) Block specific seabird vulnerability tables for the UK (JNCC 1999) Cetacean population estimates and distribution obtained from the Sea Mammal Research Unit (SMRU) in the form of the Small Cetaceans in the European Atlantic and North Sea (SCANS-II) final report (SCANS-II 2008) and from the Joint Nature Conservation Committee in the form of the Atlas of cetacean distribution on the north-west European Continental Shelf (Reid et al. 2003) UK coastal atlas of recreational boating (RYA 2008) Marine Management Organisation (MMO) commercial fishery catch, landing and effort statistics for the period 2003 to 2009 (MMO 2010) Information on UK existing oil and gas developments (UK Deal 2010) License boundary information from the Crown Estate on wind farms and marine aggregate extraction areas (The Crown Estate 2011). The following limitations or assumptions were made when establishing the project environmental baseline: Third party and publicly available information is correct at the time of publication Baseline conditions are accurate at the time of physical surveys but due to the dynamic nature of the environment, conditions may change during the construction, operation and decommissioning phases of the development The development, including surrounding area, will not be subject to unforeseen events of a severe nature

4.1.3

Identification of Project Aspects Once baseline information had been collated, the assessment of potential changes to the baseline resulting from the Alma development required the identification of project aspects.  A project aspect is defined as “an element of an organisations activities, products or services that can interact with the environment” (BSI 2001). To identify the project aspects, proposed activities as described in Section 5, are considered for the construction, operational and decommissioning phases, in terms of their direct or indirect potential to:

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Breach relevant legal standards, corporate environmental policy and management systems Interact with the existing natural environment including its physical and biological elements Interact with the existing human environment Cause significant stakeholder concerns.  A summary of the project activity components are listed in Table 4-1. Table 4-1: Project activities  Activities

Activity Components

Construction

Presence of vessels (including drilling rig and support vessels) Drilling of wells Installation of FPSO Installation of subsea infrastructure e.g., flowlines, umbilicals, power cables, wellheads, manifolds

Production

Presence of FPSO Presence and movements of vessels (export tanker and supply vessels) Power generation Start-up gas flaring (if necessary) Discharge of produced water FPSO maintenance

 Accidental Events

Chemical and hydrocarbon release (< 1 tonne) Chemical and hydrocarbon release (< 10 tonnes) Chemical and hydrocarbon release (> 10 tonnes) Overboard loss of equipment or waste

4.1.4

Determination of Potential Impacts

4.1.4.1

Scoping  An Interaction Matrix was developed to illustrate the identified interactions of project aspects and environmental and human resources in a consistent and robust manner. An example of the matrix is included in Table 4-2. Potential impacts were identified through a systematic process whereby each individual project activity was considered with respect to its potential to interact with a physical, biological or human receptor. The project aspects were identified as outlined above and were listed down the vertical column (or ‘y’ axis) of the scoping matrix. The horizontal (or ‘x’) axis was comprised of environmental and human resources and receptors that are susceptible to impacts, grouped into physical, biological and human components. Based on their experience, an understanding of the project description, and the nature and extent of project aspects, the assessment team identified whether a project aspect had the potential to interact (positively or negatively) with the environmental receptors. If it was deemed possible that an interaction may occur this was recorded as a tick ( ) in the matrix cell at the intersection between the aspect and the receptor. The completed Matrix is provided as  Appendix A for reference.

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Table 4-2: Extract from the Alma issues sc oping matrix Environmental Receptor

Physical

Biological

Project Aspect

   s    n    o     i     t    n     i     d    e    n    r    m    u    o    e     l     h    o    c    p    c     d    s    r    e    o     t    e     b    m    a    a     t    e     A     W     S

    h    s     i     f     l     l    s    e    e     h     i     t    s     i    n    n     d    c    o     i    u    n     t     k     h    m    a     t    n    n    m     h    a    e    o     i    s     l     P     B   c     F

Human

   s     d    r     i     b    a    e     S

   s     l    a    m    m    a    m    e    n     i    r    a     M





    d    s    e    e    i     t    c    c    e    e    p     t    s    o    r    d    p    n    e    a    n    s     i    r    e    a    t     i     M   s

   y    g    o     l    o    e    a     h    c    r     A

   g    n     i     h    s     i     f    e    r     l    a    s    t    u     i    a    c    r     G   c    g    u    e     d    t    n    r     i    m    n    s    p    a    a    p    m    l     f     i    o     i    r     h    n     C    O    i     S

   e    n     i    r    a    m    r    *    e    s    r     h     t    e    s     O   u

General Construction Physical presence and movement of drilling rig and support vessels







Exhaust gas emissions

4.1.4.2



Prediction and Assessment of Potential Impacts The prediction of impacts (risk assessment) was undertaken to determine what changes may occur (negative or positive) to the receptor (i.e., environment and human) as a consequence of the project and its associated activities. The diverse range of potential impacts considered in the EIA process resulted in a range of prediction methods being used including quantitative, semi-quantitative and qualitative methods. The impact prediction and assessment process took into account any mitigation or control measures that are part of the project design/project plan. Additional mitigation measures aimed at further reducing identified impacts are then proposed where necessary or as appropriate. Table 4-3 provides an example of an activity associated with the project, its aspects and potential impacts. Table 4-3: Example development activity, aspect and impact i dentification Project Activit y

Vessel movements

 Aspect

Exhaust gas emissions

Impact

Localised deterioration in air quality

Once the impact has been identified, its significance is assessed using the following criteria: Likelihood – How likely is an impact to occur as a result of an activity (see Section 4.1.4.4 and Table 4-4). Severity – The severity or consequence of an impact is a function of a range of considerations (see Section 4.1.4.5 and Table 4-5). 4.1.4.3

Nature of Impacts In considering impacts related to this project, both negative and positive impacts have been identified. Furthermore, direct, secondary, indirect and cumulative impacts are also considered. These are further described below: Negative Impact - an impact that is considered to represent an adverse change from the baseline condition or introduces a new undesirable factor

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ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Positive Impact - an impact that is considered to represent an improvement on the baseline condition or introduces a new desirable factor Direct Impact - impacts that result from a direct interaction between a project activity and the receiving environment (e.g., between occupation of an area of seabed and the habitats which are lost) Secondary Impact - Impacts that follow on from the primary interactions between the project and its environment as a result of subsequent interactions within the environment (e.g., loss of part of a habitat affects the viability of a species population over a wider area) Indirect Impact - Impacts that result from other activities that are encouraged to happen as a consequence of the project (e.g., project implementation promotes service industries in the region) Cumulative Impact - Impacts that act together with other impacts to affect the same environmental resource or receptor 4.1.4.4

Likelihood of Impact Occurrence The likelihood (probability) of an impact occurring has been defined using the qualitative scale of probability categories in Table 4-5. Likelihood is estimated on the basis of experience and/or evidence that such an outcome has previously occurred. Table 4-4: Assessment process for identification of potential impacts

4.1.4.5

Likelihood

Definition

Very Unlikely

Freak combination of factors required for event to occur.

Unlikely

Rare combination of factors required for event to occur.

Possible

Could happen with additional factors present.

Likely

Not certain. Additional factors may result in event.

Very Likely

 Almost inevitable an event would result.

Impact Severity In evaluating the severity (positive or negative) of environmental or human impacts, the following factors have been taken into consideration: Duration of the Impact: how often the impact will occur and for how long will it interact with the receiving environment Spatial Extent of Impacts: whether the impact effects the local, regional or wider environment Sensitivity of Receiving Environment: the nature, importance (i.e., whether of local, national, regional or international importance) and the sensitivity or adaptability to change of the receptors or resources that could be affected. This also takes account of any laws, regulations or standards aimed at protecting the receiving environment Recoverability of Receptor: how long until the receptor will return to preimpact condition.

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These are further defined in Table 4-5. Table 4-5: Severity definitions Term

Value

Definition

Impact Duration Short

1

Moderate

2

Long

3

Permanent

4

•

The interpretation of these descriptors varies according to the impact topic. For example, a short term impact to the seabed, such as the effects of levelling works, may last for a year, whereas a short term impact to water quality, such as effects from the discharge of water based mud, could involve a period of 12 to 24 hours.

•

The primary zone of influence of the project. In this instance the local region encompasses the area within a radius of 1 km around the project footprint.

Spatial Extent Local

1

Widespread

2

•

Impacts extend beyond project locality to impact on the region. The region in this instance would encompass the CNS.

Extensive

3

•

Impacts on a national scale (effects well beyond the CNS).

Global

4

•

Impacts on a global scale (e.g., global warming).

Sensitivity of Receiving Environment •

Low

Medium

High

Very High

1

2

3

4

 Abundant/ common species/ environment and broadly distributed

•

Robust in nature and proven to be adaptable to changing environments

•

Valued but not unique

•

Range/ abundance covers numerous regions

•

Under pressure but has some ability to adapt to changing environment

•

Valued locally as an important species or environment

•

Range/ abundance restricted to a limited number of areas

•

Under pressure and showing some, but slow, adaptability to changing environment

•

Valued regionally as an important species or environment

•

Rare/ unique species/ environment

•

Under significant pressure and likely to fail or be irreversibly damaged

•

Valued globally as an important species or environment

•

The interpretation of these descriptors varies according to the impact topic. For example, a long recoverability to plankton species, such as the toxic effects of a chemical discharge may last a few months. Whereas a long recoverability to some fish species, such as removal of benthic breeding habitat, could involve a period of 10 to 20 years.

Recoverability of Receptors Short

1

Moderate

2

Long

3

Irreversible

4

The outcomes from each of the above factors were then tallied to decide an overall grading value of the severity of a particular impact. Where quantification of potential impacts is possible, the decision has been based on numerical values, representing regulatory limits, project standards or guidelines (e.g., noise and air quality impacts).

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 A number of environmental aspects such as ecology, landscape, visual and generally all human impacts require a more qualitative approach for determining severity. Semi-quantitative and/or qualitative methods have therefore been used whereby the criteria have been set according to severity factors as defined in Table 4-6 above. The severity factors have been scored with a numeric value from 1 to 4. The sum of values for each of the factors was used to determine the overall severity as summarised in the scale outlined below: Negligible (sum of values 4 - 6) Low (sum of values 7 - 9) Medium (sum of values 10 – 12) High (sum of values 13 – 16) 4.1.4.6

Assessing Impact Significance For the potential impacts associated with the Alma field development, the significance of each impact is determined by assessing the impact severity against the likelihood of the impact occurring as summarised in the impact significance assessment matrix provided in Table 4-6. It is important to emphasise that the resulting significance from these two elements is not the likelihood of the activity occurring, but rather it is the likelihood of that activity causing the impact described. Table 4-6: Environmental and h uman impact si gnificance assessment matrix Likelihood Severity

Very Unlikely

Unlikely

Possible

Likely

Very Likely

Negligible (4 -6)

Insignificant

Minor

Minor

Minor

Minor

Low (7 - 9)

Minor

Minor

Minor

Moderate

Moderate

Medium (10 – 12)

Minor

Minor

Moderate

Moderate

Major

High (13 – 16)

Moderate

Moderate

Moderate

Major

Critical

Based on the outcome of the significance assessment the following points need to be considered: Critical Significance It is not possible to manage or mitigate critical impacts. These require the identification of alternatives (elimination of source of potential impact). Such impacts are intolerable and could potentially result in abandonment of a project. Major Signific ance Check that the residual impact has been subject to feasible and cost effective mitigation where possible Where no further reduction in impact levels can be made, it remains a high-level impact and which may therefore be subject to offsets

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Moderate Significance Check that the residual impact has been subject to feasible and cost effective mitigation and that no further measures are practicable Minor Significance Not mitigated further  An assessment of the significance of the impacts from the project was undertaken and the results are presented in the technical assessment sections (Section 8 to 10) to follow and Appendix A.

4.1.5

Mitigation of Potential Impacts Mitigation measures are the actions or systems that are used, or have been proposed, to manage or reduce the potential negative impacts identified. They may also be used to enhance the positive benefits, especially in relation to human issues. Application of mitigation measures to reduce potential negative impacts and enhance the benefits of a proposed activity is achieved by the application of the following mitigation hierarchy:  Avoid at Source/Reduce at Source: Avoiding or reducing at source is essentially designing the project so that a feature causing a potential impact is designed out or altered.  Abate on Site: This involves adding something to the basic design to abate the potential impact – pollution controls fall within this category.  Abate at Receptor: If a potential impact cannot be abated on-site then measures can be implemented off-site. Repair or Remedy: Some potential impacts involve unavoidable damage to a resource. Repair involves restoration and reinstatement measures. Compensate/ offset: replace in kind or with a different resource of equal value Mitigation is an integral part of the Alma development. All of the potential impacts identified from this project are subjected to either standard recognised best practice mitigation measures or to impact specific, feasible and cost effective mitigation. The mitigations measures considered pertinent for each environmental and human issue considered are outlined in the individual technical sections to follow, are summarised in Section 12 and detailed in  Appendix A.

4.1.6

Residual Impact Assessment Residual impact is the remaining or mitigated impact level after all avoidance, design and management measures have been taken into account. If the risk assessment determined that after mitigation measures were applied there would be no residual impact no further assessment was undertaken on the impact. If, however, it was concluded that a residual impact may still be expected the impact assessment was re-conducted starting with an assessment of the likelihood and severity, to determine the significance of the residual impact The results of the residual impact assessment are presented in the technical assessment sections (Section 8 to 10) to follow and Appendix A.

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4.2

CUMULATIVE AND INDIRECT IMPACTS In accordance with the EIA regulations, the EIA has given consideration to cumulative and indirect impacts and interactions. The definitions of these three types of impact overlap, generally without any agreed and accepted definitions. For the purposes of this assessment, the definitions proposed by the European Commission (1999) have been used. The definitions are as follows: Indirect Impacts – Impacts on the environment, which are not a direct result of the project, often produced away from or as a result of a complex pathway. These are sometimes referred to as secondary impacts. An example of an indirect impact is the impact on commercial fish landings as a consequence of the poor stock recruitment because seabed disturbance has caused the loss of spawning grounds. Cumulative Impacts – Impacts that result from incremental changes caused by other past, present or reasonably foreseeable actions together with the project. Cumulative impacts can either be the interactions of the same type of activity within:  A single current project e.g., habitat loss caused by pipeline trenching added to the habitat loss cause by the installation of subsea structures leading to an overall larger area of habitat loss than one activity on its own. Two projects in the same area whether this be historic, future, or a different industry e.g., habitat loss caused by the Alma field development combined with the habitat loss caused by the decommissioning of the previous fields combined with the habitat loss of trawling leading to an overall larger area of habitat loss Impact Interactions – The reactions between impacts whether between the impacts of just one project or between the impacts of other projects in the area. For example, the discharge of oil in produced water and the discharge of chemicals could individually not have an impact on water quality but combined could mean quality deteriorates past threshold levels. Impacts considered in this ES relate to impacts due to the project and: Other activities within the project Other oil and gas projects (past, present and future) Other seabed users e.g., commercial fishing, wind farms, marine aggregate extraction Climate change e.g., changes in sea level The assessment of cumulative impacts has been dependant on the public availability of consented developments. It is generally acknowledged that there are difficulties in assessing cumulative impacts via a single-project EIA. One of the objectives of the SEA process was to strategically address cumulative impacts from oil and gas projects on a regional scale. In accordance with the EIA regulations it evaluates "any direct or indirect effects (including secondary, short, medium and long-term, permanent and temporary, positive and negative effects) resulting from the existence of the activity, the use of natural resources and the emission of pollutants, the creation of nuisances and the elimination of waste".

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Section 11 presents, quantitative assessments of the cumulative and indirect impacts and interactions (where possible), qualitative descriptions of impacts including the spatial and temporal scope of the assessments and a discussion of which impacts have not been addressed and why.

4.3

EIA STAKEHOLDER CONSULTATION  Although not a statutory requirement, it is recognised best practice that EIA methodology should also include stakeholder consultation. Early consultation can often be a critical first step to the development of a comprehensive and balanced EIA, especially in areas of heightened sensitivity both environmentally and from a human perspective. Views of the interested parties serve to focus the environmental studies and identify specific issues which require further consideration. Figure 4-1 presents a graphical depiction of the process followed and identifies that stakeholder consultation is a key component to the whole process. Through previous project experience and consultation with the authorities, the key stakeholders identified for the Alma field development are the DECC, the JNCC, Marine Scotland and the Scottish Fishermen’s Federation (SFF). Consultation has been undertaken by EnQuest with the aforementioned stakeholders on the proposed scope of the EIA. High level discussions have been held with Michael Sutherland at SFF. EnQuest presented overview of development and subsea infrastructure. SFF had no upfront objections. The HSE and the DECC were consulted on suitability of using the FPSO in terms of environmental performance. Consultation between the DECC and EnQuest regarding the proposal to lay all flowlines on surface unprotected. Responses and advice from all consultees have been incorporated into project planning.

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5

PROJECT DESCRIPTION The project description covers activities to be undertaken during construction, commissioning, production and the decommissioning of the development after the end of production life. Also provided in this section is an outline schedule, setting out the likely timetable over which these activities will be performed. The section provides the basis upon which the prediction and evaluation of the environmental and human impacts has been conducted. The key elements of the Alma Field development included in the study are: Drilling of six production wells and two water injection wells Installation of two 10-inch production flowlines, one 10-inch water injection flowline, two control umbilicals and one power cable Installation of the Deepwater Uisge Gorm Floating, Production, Storage and Offloading (FPSO) facility Export of crude oil via shuttle tanker Operation and production of the field for an expected 10 years  An overview of the field development is shown in Figure 5-1 below. Figure 5-1: Alma field development

Note:  Diagram for illustrative purposes only and does not necessarily reflect exact layout of flowlines and associated infrastructure.

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5.1

SCHEDULE Construction is scheduled to start in January 2012 with the drilling of the first production well. The FPSO will be installed in January 2013 and flowlines will be installed and commissioned between January and May 2013. First oil is expected in August 2013 (Table 5-1). Table 5-1: Project schedule  Activity

2012 Q1

Q2

2013 Q3

Q4

Q1

Q2

Q3

Drilling Flowline installation FPSO installation Field commissioning First oil

5.2

CONSTRUCTION ACTIVITIES The activities involved during the construction phase include the installation of the FPSO, drilling of wells and installation and commissioning of new flowlines and risers. Information on the activities is generally well defined however, minor changes, if any, will be captured by the PON15 process.

5.2.1

FPSO EnQuest will use the Uisge Gorm floating production, offloading and storage (FPSO) facility for the field development (Figure 5-2). The vessel entered operation in 1995 at the Flora and Fife field (including Angus and Fergus fields) for Amerada Hess. Current vessel and performance data is provided in Table 5-2. The main functions of the FPSO are: Control of and receipt of fluids from the subsea wells Processing of the incoming fluids for separation into stabilised crude, water and gas Storage of the stabilised crude and offloading into tandem moored shuttle tankers (expected frequency of one tanker per fortnight) Chemical injection and treatment and re-injection of produced water with an oil content of below 30 mgl -1 Power generation for process, offloading, utilities and ship systems Utilisation of produced gas for fuel gas Provide accommodation and helideck for operating and maintenance personnel

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Figure 5-2: Uisg e Gorm FPSO

Source: www.bluewater-offshore.com

Table 5-2: Current unmodified Uisge Gorm vessel and performance data Vessel data Length

248.3m

Breadth

39.9m

Depth

20.5m

Dead weight tonnage

92,000

 Accommodation

65 persons

Performance data Storage capacities

Exportable crude

94,500 m3 (594,340 bbls)

Slop tanks

4,450 m3 (28,000 bbls)

Fuel oil

2,400 m3 (15,100 bbls)

Fluid capacity

121,000 bpd

Crude

57,000 bopd

Produced water (max)

100,000 bwpd

Oil in water content

< 30 ppm

Gas (max)

20 MMscfd at 2,500 psia

Water injection

Capacity (max)

70,000 bwpd

Power

Main generators

1 x steam turbine, 3 x diesel

Capacity

1 x 1,500 kW + 3 x 900 kW

Emergency generator

1 x 550 kW diesel

Processing capacities

The FPSO is held permanently on station without any aid from thrusters or other external sources. This is achieved by using a passive turret mooring system. Nine mooring lines, configured into three clusters, are used, as illustrated in Figure 5-3. The mooring lines come together at the turntable built into the FPSO. The FPSO is able to rotate around the turret to obtain optimal orientation relative to the prevailing weather conditions. The anchor chains are

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secured to the seabed with anchors. At Alma the anchors will be within a radius of 1,592m of the FPSO (Figure 5-4).  A 500m safety exclusion zone will be established around the structure enforced by a standby vessel on a 24 hour basis. Figure 5-3: Turret mooring system

Source: www.vryhof.com

Modifications and upgrades will be carried out on the FPSO turret to accommodate the new flowline/umbilical riser systems required to receive and process the Alma hydrocarbons and to pump injection water. The upgrades will be finished before the FPSO is mobilised to the field. The upgrades will include: New chemical injection skid and produced water re-injection pumps Turret modifications Upgrades to control system and new subsea control system equipment installed on the subsea trees and on the Uisge Gorm to facilitate full control of the field. New first stage separator New and additional power generation (including steam and inert gas) Well control hydraulics  Accommodation upgrades, fabric maintenance, structure and hull steelwork remedial works, painting Hydrocyclones for water clean-up

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Figure 5-4: Field layout show ing FPSO and drilling rig anchor patterns

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5.2.2

Wells EnQuest plans to drill eight wells: Six production wells (P1 - P6) Two water injection wells (W1 and W2) The water injection wells will be drilled from the southern drill centre and the production wells from the northern drill centre (See Figure 5-4). Wells will be drilled from a semi-submersible (semi-sub) mobile drilling unit (MoDU) and will be suspended pending tie-in to the flowlines and FPSO. The production wells will target a total of three reservoirs within the Alma Development area: Devonian, Zechstein and Rotliegend. The wells are expected to have a high water cut (initial 70% basic sediments and water) and will be produced with the aid of ESPs. The wells will be approximately 30m apart (in their respective drill centres) and will be batch drilled from the drilling rig. Drilling on the first production well will start in January 2012, with all production wells due to be completed by October 2012. The drilling rig will then move to the southern drill centre to start on the water injection wells. It is expected that all drilling will finish by April 2013.

5.2.2.1

Drilling rig EnQuest have a number of rig options that they are considering. They currently have the Transocean John Shaw semi-sub MODU on contract and it is possible that this rig could be used at Alma. If it is not available, due to EnQuest’s other drilling commitments, a semi-sub with a similar specification could be used. The John Shaw (Figure 5-5) is approximately 86m x 65m x 35m (topside) with an operating draft of 21m. It is capable of operating in depths up to 549m, drilling to depths of 7620m and has the berth capacity for 99 personnel.  A 500m safety exclusion zone will be established around the rig enforced by a guard vessel on a 24 hour basis. Figure 5-5: Typical semi-submersible drilling rig

Source: www.deepwater.com

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To support the drilling operation, the following systems and services are located on the rig: Bulk storage – is provided for fuel oil, bulk drilling mud and cement, liquid drilling fluids, drill water and potable water Pipe and materials storage – covered storage is provided for sacked material, drilling equipment, spares etc, and deck storage for drill pipe casing Helideck and craneage - for loading/off loading personnel, equipment and supplies Environmental protection – sewage treatment unit and hazardous and non-hazardous drainage systems, which collect rainwater and/or any minor spills to a drains tank prior to discharge to sea, or allow transfer to tote tanks for shipment to shore and disposal by licensed waste disposal contractors The rig is self-propelled but maintains station by using eight anchors. Anchors will be limited to an established anchor pattern within 1,500m radius of each drill centre (Figure 5-4). The rig is expected to use four 15 tonne and four 12 tonne Vryhof Strevpris anchors in a catenary system. In this anchor system, the anchor chains rest on the seabed and can scour when made to move due to weather conditions. When anchors are lifted clear at the end of the operation, the anchors can cause sediment deposition onto the seabed, creating a mound. Anchor mounds are common where seabed sediments or shallow sub-surface sediments are composed of fine sands or clay. It is possible that up to eight anchor mounds will be created at each drill centre. 5.2.2.2

Well design and drilling The two main types of drilling fluids (muds) typically used in offshore drilling; water based mud (WBM) and low toxicity oil based mud (OBM), will be used during the wells. Drilling muds have five primary purposes: To remove the cuttings (produced by the drill bit) from the formation and carry them to surface Lubricate and cool the drill bit during operation. Maintain hydrostatic pressure so that gas and fluids from the formation do not enter the well bore causing a kick or blow-out. Build a filter cake on the hole wall to prevent fluid loss to the formation. Support and prevent caving of the wall of the hole. The drilling rig circulates the mud by pumping it through the drill string to the drill bit. From here it travels back up the annular space between the drill string and the sides of the hole being drilled. The circulating system is essentially a closed system with the mud recycled throughout the drilling of the well. Various products may be added to make up for losses (to formation), to adjust the mud’s properties, or to overcome difficult conditions (e.g., stuck drill pipe or loss of well pressure of fluid). Three of the six producer wells will be drilled in five sections (36", 26", 17½", 12¼" and 8½" sections). The top two sections will be drilled with water based

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mud (WBM), the middle section will either be drilled with WBM or oil based mud (OBM) and the bottom two sections will be drilled with OBM. The 36" section will be drilled as an open hole using WBM with all cuttings being discharged directly to the seabed. A 30" conductor will be run and cemented into place to support the hole walls. The 26" section will then be drilled with WBM with cuttings also being discharged directly to the seabed. Once complete a 20" casing will be cemented in to the hole and a marine riser installed to allow all further cuttings and drilling fluids to be returned to the rig. The 17½" section will either be drilled with WBM or OBM. If WBM is used then cuttings will be discharged to sea from the rig after passing over the shale shakers. Shale shakers are a vibrating sieve that drilling fluid and cuttings pass over. The liquid phase of the mud passes through the screen wire mess whilst the larger solids including the drill cuttings are retained on the screen and eventually fall off the back of the shaker. The fluids are recycled back into the drilling system whilst the retained solids and drill cuttings are discharged from the rig via a cuttings chute that is typically positioned 10m below the water line. Once the 17 ½" hole section is complete the 13 ⅜" casing will be run and cemented into the wellbore. The 12¼" and 8½" sections will both be drilled using OBM with no discharge of cuttings. The 12 ¼" section will be lined by a 9 ⅝" casing and the 8 ½" hole section will be lined with a 7" liner. The other three producer wells and the two water injection wells will be drilled in four sections (36", 26", 12¼" and 8½" sections). The top two sections will be drilled with WBM and the bottom two sections will be drilled with OBM. The 36" and 26” sections will be drilled as before, however no 17½" section will be drilled for these wells. The 12¼" and 8½" sections will both be drilled using OBM with no discharge of cuttings. The 12 ¼" section will be lined by a 9 ⅝" casing and the 8 ½" hole section will be lined with a 7" liner. OSPAR Decision 2000/3 prevents the discharge of OBM to the marine environment. Therefore, all returned OBM fluids and associated drill cuttings will be collected and skipped and shipped for thermal treatment onshore.  A preliminary list of chemicals to be used during drilling is supplied for reference in Appendix B. Chemical and drill cuttings discharges are quantified in Section 6.1.2.1 and 6.1.3.3. The exact formulation to be used for each well will be finalised in a PON15B application submitted to the DECC at least 28 days prior to drilling each well. 5.2.2.3

Cementing Casing is cemented into place in all the sections of the well bore down to the interface with the reservoir. As each diameter section of the well bore, is finished, sections of metal casing, slightly smaller than the well bore diameter are placed in the hole to provide structural integrity. These are cemented in to place by pushing cement in the space (annulus) between the casing and the borehole. The cement fluids are pre-mixed in pits on the drilling rig before being pumped downhole. To minimise the quantities of chemicals pumped down hole, a cement liquid additive system will be used to calculate the volumes of premixed fluid required for the job. It is possible that dead volumes (approximately 10%

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of the total mixed) may remain in the pit after the operation, which will be discharged to sea.  A preliminary list of chemicals to be used during cementing is supplied for reference in Appendix B and summarised in Section 6.1.2.1. The exact chemicals to be used for each well will be finalised in a PON15B application submitted to the DECC at least 28 days prior to drilling each well. 5.2.2.4

Completion The wells will be completed with completion components and tubing which ar e designed to last the life of the wells within acceptable corrosion limits. The completions will include the necessary hardware for the location, operation and power supply for the downhole electric submersible pumps.

5.2.2.5

Well bore clean-up There will be no flaring associated with the clean-up of the wells. On completion of the 8½" section, the wellbore will be cleaned-up to remove residual quantities of OBM from the casing before the wellbore is suspended by displacing it to inhibited seawater. The clean-up will involve a 60bbls (9.5m 3) spacer / detergent mix being circulated in front of the inhibited seawater. The interface between the spacer/detergent mix and the OBM will be contained and back loaded for thermal processing onshore. It is possible that a large cleanup pill of fluid (CLEANPERF) will be run and if used this would be flowed back to the FPSO on well start-up. During the course of operations, EnQuest will follow a hierarchy of choices when dealing with contaminated fluid in order to minimise the volume discharged to sea, in line with Oil and Gas UK "Good Practice for Clean-Up Operations" document (OGUK 2006). The well bore clean-up pill, plus any interface containing visible OBM generated during the clean-up will be shipped to shore for disposal. However, any wastewater containing no visible OBM generated during clean-up will be discharged into the marine environment. This discharge will be permitted under Condition 5 of the relevant PON15B approval.  All discharges will be sampled, analysed and reported at the end of the drilling operation. Any residual oils in discharged water are likely to be rapidly dispersed in the water column and broken down through bio-physical weathering processes. If any sheen is observed on the sea surface during wellbore clean-up, this will be reported using a PON 1.

5.2.3

Flowlines and Subsea Infrastructure Two 10-inch production flowlines and one 10-inch water injection flowline will be installed in the field. A chemical umbilical will be installed out to both drill centres and an additional power cable will be laid to the production drill centre. The umbilicals to the drill centres and the power cables will be surface laid and due to the suitable nature of the seabed will self bury.  At the interface between the production and water injection flowlines and the risers up to the FPSO, the flowlines will be connected to the risers with a bolted straight “T” piece with the “T” piece blanked off for potential future tie-ins. The flexible risers will be stabilised using two holdback tethers connected to either two piles for each riser or a gravity base structure (clump weights).

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The risers and umbilicals will be routed up in to the FPSO turret, though guide “I” tubes, to the riser deck where they are hung-off and connected to the turntable system. The riser deck is located above the water level to ease hookup, inspection and maintenance. All risers are continuous, non-bonded flexible risers running from the riser base structure to the turret in a lazy-S configuration. The water injection flowline will go straight from the riser base structure to the water injection wellheads whilst the production flowlines, umbilical and power cable will terminate at a simple manifold at the northern drill centre. Engineering is currently being carried out to establish the requirement for piles. The preference environmentally is to retain the risers with gravity base structures or clump weights. Should it be established that piles are necessary, then six piles will be required for the holdback tethers on the risers (similar to the one shown in Figure 5-6), two for each riser and will be approximately 24 inches in diameter. It is anticipated each pile will take 2 hours to install. Figure 5-6: Typical top hat riser tether utilis ing pil es

Source: EnQuest

The flowlines are flexible and the base case is for the water injection flowline to be trenched and backfilled and the production flowlines to be surface laid and protected.  A large number of seabed obstructions and hazards were identified during the site survey from previous oil exploration and production activities. These included abandoned wellheads, lengths of pipe, wire and a number of spud-can depressions. Due to this and the physical dimensions of the development area it is proving difficult to identify a corridor for the water injection flowline where trenching of the whole route would be possible. Where trenching is not possible the flowline will be surface laid and protected with concrete mattress to eliminate any spans or seabed obstructions.  A standby vessel will be on-site during the installation of the flowlines and during production acting as guard vessel, so additional protection has not been

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considered necessary. Dropped object protection (concrete mattresses) will be placed around the wellhead areas. 5.2.3.1

Installation and commissioning of flowlines Installation of flowlines typically follows the below process: Trenched and backfilled Flooded with chemically inhibited seawater Tied-in at both ends Hydrotested Leak-tested Dewatered and commissioned Prior to the flowlines being laid, an intrusive flowline route obstruction survey will be conducted. The survey vessel will remain on-site for the duration of the installation to provide support to the other construction vessels. It is expected that the flowlines will be laid using a dynamically positioned (DP) pipelay vessel, followed by a vessel with a trenching spread that will jet cut the trenches. The flowline will then be guided into the trench and the dispersed spoil will cover the flowline afterwards. DP vessel  A DP vessel will use thrusters to position itself over the pipeline route. A typical vessel used for this type of operation has a draft of 6.5m. The housing for the thruster propellers may extend to a maximum of 2m below this depth. The propellers create disturbance in the water column typically to 5m, below which the effects are not discernible from natural currents and wave orbital movements. Therefore, the deepest effects from a DP vessel are anticipated to reach down to approximately 14m from the sea surface.  At the start of the installation process an initiation anchor (typically a conventional 13½ tonne anchor or similar) will be used to help position the vessel and flowline in the target box. However, during the installation process the vessel will not use anchors for positioning. Installation Touch-down of the flowlines will be monitored by a ROV. Installation is expected to take place between January and August 2013. The production flowlines will be laid on the seabed and then protected with concrete mattresses as required. Trenching The water injection flowline will be trenched by a vessel equipped with a jet trenching ROV, similar to the one pictured in Figure 5-7. Jet trenching machines use high pressure water jets to fluidise the seabed beneath the pipeline. The water jets are mounted on swords which are lowered up to 2m in to the seabed on either side of the pipeline. The high pressured water disrupts the sediments, forming a trench full of fluidised material, into which the pipeline sinks under its

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own weight. Any trench created backfills naturally. A trench will be cut for the water injection flowline and is likely to be 2m wide depending on the ROV used and the configuration of the jets. Installation proceeds, on average, at a rate of 1.6km/day (Cranswick 2001). Figure 5-7: Typical jet trenching ROV

Source: www.ctcmarine.com

Trenching is expected to take up to 2 days to complete, allowing for any delays. The trench will be initiated and terminated 50m from the FPSO and drill centres. The target depth for the trench will be 1m allowing for 0.6m cover from top of flowline to mean seabed level. The trench depth has been selected based on a consideration of the geotechnical characteristics of the area, the geotechnical site survey (GGL 2011) and from estimated upheaval buckling criteria. The trench depth selected has been designed to eliminate the need for rock dumping.  After trenching and backfill the final seabed profile will be a shallow depression over the flowlines due to the loss of finer sediments from displaced material through winnowing. In the event of any undulations in the trench (and subsequently the flowline) a contingency will be in place for the provision of approximately 5,000 tonnes of rock for deposition for protection. The rock will be deployed to mitigate any upheaval buckling or pipeline out of straightness events experienced during the trenching and pipe-lay activities. This may be required for pipeline protection, depth of cover anomalies or dropped object protection. The requirement for rock deposition will be identified during post lay survey and if required the rock will be placed accurately utilising a dynamically positioned fall pipe rock installation vessel. The vessel will be equipped with a fall pipe to deploy rock accurately in the spot location. Commissioning Once installed, the flowlines will be leak tested using inhibited seawater. A dive support vessel (DSV) will be used to pump inhibited seawater into the flowlines. Typically 20% line volume is used to build up the pressure in the line until test pressure has been established and stabilised. Test pressure will be held for 24 hours before the flowlines are depressurised. The inhibited seawater is typically discharged from the DSV at the sea surface.  After leak testing, the flowlines will be tied-in at both ends and leak-tested. Leak testing follows a similar procedure to hydrotesting, using inhibited

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seawater. Additional quantities of inhibited seawater pumped into the flowlines to establish leak test pressures will be discharged as above. Once fully installed and tested, the volumes of inhibited seawater remaining in the production flowlines will be flowed ahead of produced fluids to the FPSO where they will pass through the process system. Volumes in the water injection flowline will be pushed into the water injection wells. Exact details of the chemicals to be used during flooding, hydrotesting and leak-test were not available at the time of the ES submission, but will be provided in the PON15C for each flowline as required under the Offshore Chemical (Amendment) Regulations 2011. In total, four vessels will be used for flowline installation and commissioning: Survey vessel Pipeline installation vessel Dive support vessel Guard vessel In is anticipated that installation of the flowlines will commence in January 2013 and will be undertaken within a five month window. Tie-in of the wells will be conducted from a DSV which will use dynamic positioning (DP) to keep station. 5.2.3.2

Subsea tie-in Production wells Wells will be tied back to the manifold and into the main export flowlines through flexible jumpers and drop down spools. The jumpers and spool pieces will be pre-filled with monoethylene glycol (MEG), surface laid and connected at each end. The MEG is typically dyed with RX-9022 at a concentration of 100mgl -1. Typically five dye sticks, such as Dyestick RX-9034A (which weigh 50g), will be placed in the spool pieces to assist with leak detection. The chemicals introduced into the spool pieces will remain in the flowline until the well comes on to production. They will then be exported to the FPSO with produced oil where they will enter the production train and eventually be re-injected with produced water. The chemical cores in the new sections of control umbilical will be pre-filled onshore with the fields control fluid; Castrol Transaqua HT2 or an equivalent control fluid. On start-up of the production wells it will be pushed out of the chemical cores and into the production flowline, from where it will be produced back to the FPSO with first oil. As Castrol Transaqua HT2 is a water based control fluid, it is expected to partition into the water phase and will be reinjected with produced water. Once the spool pieces are connected, they will be leak tested. MEG dyed with RX-9022, at a concentration of 100mgl -1 will be pumped into the spool pieces to increase the pressure in the line. Once test pressure is established the pressure will be released by discharging the fluids. The chemicals used during leak testing will be introduced and discharged from the DSV.

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Water injection wells The water injection flexible jumpers and drop down spools will be pre-filled onshore with potable water inhibited with RX-9022 at a concentration of 100mgl -1 and RX-5227 at a concentration of 500mgl -1. They will then be surface laid and connected at each end. The RX-9022, RX-5227 and potable water will remain in the flowline until the well comes into use. They will then be injected into the well ahead of the injection water. Typically three dye sticks, such as Dyestick RX-9034A dye sticks, will be placed in the spool pieces to assist with leak detection. Typically, half a dye stick per flange will be used. These dye sticks will also be injected into the well will the fluids in the flowlines at well start-up and will not be discharged to sea. The chemical cores in the new sections of control umbilical will be pre-filled onshore with the fields control fluid; Castrol Transaqua HT2. On start-up of the well it will be used to function test the xmas tree valves. The Castrol Transaqua HT2 (or equivalent control fluid) will eventually be discharged to sea during normal tree valve operations. Once the jumpers and spool pieces are connected, they will be leak tested. Leak testing will involve pumping seawater dyed with RX-9022 (at a concentration of 100mgl -1) and RX-5227 (at a concentration of 500mgl -1) into the spool pieces to increase the pressure. Once test pressure is established the pressure will be released by discharging the fluids. The chemicals used during leak testing will be introduced and discharged from the DSV. Chemicals typically used during installation and leak testing are provided in  Appendix B. These may change in future, but all proposed chemical use and discharge will be finalised in the PON15C chemical permit for each flowline as required under the Offshore Chemical (Amendment) Regulations 2011. 5.2.3.3

Manifold Two tie-in spools will be required, one for each flowline, at the FPSO where the flowline connects to the risers. A 6 slot manifold will be required for the production well centre to the south and will be approximately 6m x 5m x 3m (tall) and weigh 100 tonnes. The manifold will be a gravity based structure, held in place with additional ballast units.

5.2.3.4

Protection Subsea struc tures  All subsea structures will be of a fishing friendly design, of the type approved by the Scottish Fishermen’s Federation (SFF). Such structures typically feature raked sides that are designed to lift trawl wires and gear up and over, significantly reducing the risk of snagging. Horizontal xmas trees will be used for the well heads. They have a relatively low profile and allow the manufacturer to offer a protection structure integral with the tree frame and including deflection members. It is assumed that the trees will be provided with an integrated protection frame and that the conductor has been cemented such that it provides adequate resistance to fishing interaction loads. A conductor/riser analysis will be performed to confirm the

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wellhead is able to withstand the predicted snag loading from fishing activity in the area. To provide cathodic corrosion protection, sacrificial anodes will be attached to the structures. The volume, composition and location of the anodes will be determined during detailed design.  Anodes are an aluminium zinc indium alloy, typical specifications for which are given in Table 5-3. Anodes vary in weight and are designed to provide protection to the flowline for 10 years. Table 5-3: Sacrificial anode c ompositi on Chemical Cadmium Copper Indium Iron Silicon Zinc Others (each)  Aluminium

Composition (% by weight) 0.002 (maximum) 0.005 (maximum) 0.016 - 0.030 0.09 (maximum) 0.10 (maximum) 4-6 0.02 (maximum) Remainder

Flowline physical protection The production flowlines may be protected along their length as well as between the wellheads and the manifold by concrete mattresses. Concrete mattresses consist of hexagonal concrete elements linked together with high strength non-degradable polypropylene rope, approximately 6m by 3m in dimension and 300mm thick. Divers will position these over exposed  jumper lines, spools and flowlines. Grout bags may be used at smaller exposed areas, typically at joins between mattresses and close by to any subsea installations. The manifold will be within 100m of the wellheads and all jumpers/spool pieces will be within a 10m corridor from the wellheads to the manifold. It is also likely that the first 50m of the flowlines, control umbilical and power cable will be mattressed. At the production centre the flowline corridor will be 50m. At the water-injector centre the flowline corridor will be 30m. In the event of any undulations in the trench (and subsequently the flowline) a contingency will be in place for the provision of approximately 5,000 tonnes of rock for deposition for protection. The rock will be deployed to mitigate any upheaval buckling or pipeline out of straightness events experienced during the trenching and pipe-lay activities. This may be required for pipeline protection, depth of cover anomalies or dropped object protection. The requirement for rock deposition will be identified during post lay survey and if required the rock will be placed accurately utilising a dynamically positioned fall pipe rock installation vessel. The vessel will be equipped with a fall pipe to deploy rock accurately in the spot location.

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5.3

PRODUCTION OPERATIONS  As discussed in Section 3-1, current estimates are that the Alma field will produce a maximum of 32.5 MMbbls of crude oil and 8.1 Bscf of gas. The gas to oil ratio is assumed to be 250 scf per barrel. Wells are expected to have a high water cut and will be produced with the aid of ESP’s. Reservoir pressures will be maintained by produced water reinjection supplemented with treated seawater. The FPSO will support all production activities with crude oil offloading every two weeks. Field life is anticipated to be approximately ten years.

5.3.1

Produced Fluids Offloading It is anticipated that a shuttle tanker will visit the FPSO initially once every two weeks to offload stored crude oil. During offloading operations the offloading hose is suspended in a free-hanging catenary configuration between the FPSO stern and the bow of the shuttle tanker. Between offloading operations, the free end of the offloading hose is hung-off from a support platform at the FPSO stern (Figure 5-8). The shuttle tanker has a maximum offloading capacity of 100,000m 3 (87,000 tonnes). Figure 5-8: Offlo ading f rom Uis ge Gorm FPSO

Source: www.oilrig-photos.com/picture/number115.asp

5.3.2

Power Generation The FPSO will have its original three 0.9MW rated diesel engines and two new 14MW steam boilers. The steam boilers can be fuelled by diesel (fuel oil), fuel gas or crude oil. Under normal operations gas produced from the reservoir will be used to power the steam boilers. However, as gas production declines over field life there will be insufficient gas produced to power both and eventually even one of the steam boilers. When gas production proves insufficient to power a boiler it will switch to duel fuel e.g., fuel gas and crude oil will be burnt at the same time. As the boilers will run on gas augmented by crude, only excess gas will be flared, however there may be a short period during the early

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part of field life where excess gas is produced that cannot be burned, this will be flared. At the peak of production it is anticipated that gas production will be in the order of 7 mmscf/d (198,200m3/d). For the steam boilers there will be a waste heat recovery scheme in place. Waste heat will be recycled back into the boilers and turned into steam. This means less waste heat is vented to the atmosphere. The diesel engines will be used primarily during start-up when the flow of produced gas is insufficient to run the steam boilers. Once the steam boilers are operational the diesel engines will be switched off and only used during maintenance. The steam boilers are typically 86% thermal efficient and operate at low pressures. This means that emissions of NOx are typically low. Reservoir hydrocarbons at Alma have low sulphur content and therefore SOx emissions will also be low. Figure 5-9 shows the monthly cumulative CO 2  emissions from the installed capacity of the three 0.9MW diesel generators and one 1.5MW steam driven turbo generator on the Uisge Gorm from January 2008 to August 2008 (only data available at time of EIA preparation). The monthly CO 2 emissions are well below permitted levels, with a total of 28,018 tonnes of CO 2  having been generated by the end of August 2008. Figure 5-9: Cumulative total CO2 (tonnes) f rom Uisge Gorm FPSO (Jan-Aug 2008)

Source: Bluewater 

5.3.3

Gas Flaring The flare system provides the facilities to safely collect and dispose of normal and/or emergency hydrocarbon liquid and gas releases from all areas of the process plant. The system is designed to handle all flaring situations that could occur and to meet all the relevant environmental and safety criteria.  As discussed in Section 5.3.2 above, the vast majority of produced gas will be used for power generation. It is expected that gas will only be flared in an emergency situation. There will be no flaring as a part of well clean-up.

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Over 8.138 Bscf (230.4 million m 3) will be produced from the Alma Development. Of this, 7.88 Bscf (223 million m3) will be used as fuel gas for power generation on the FPSO and it is anticipated that no more than 258,500 scf (7,320m3) will be flared. Consent to flare under the Petroleum Act 1998 will be applied for approximately three to four months before start-up. This will cover any flaring during commissioning, start-up and production. Additionally, flaring activity will be considered in applying for an allowance under the EU Emissions Trading Scheme (EU ETS).

5.3.4

Chemical Use  A number of chemicals will be required during production operations. Initial chemical injection facilities are expected to be: Topsides corrosion inhibitor Topsides scale inhibitor Seawater biocide Oxygen scavenger Demulsifier  Antifoam De-oiler Subsea scale inhibitor Subsea hydraulic control fluid Chemicals will either be dosed into injection water or supplied to the wells through the chemical umbilical. The quantities required will be calculated based upon production flows, temperatures and pressures.  All chemical use will be permitted under an Offshore Chemical (Amendment) Regulations 2011 chemical permit i.e., PON15D. The majority of chemicals will be within a closed system with no discharge to sea; however some chemicals such as control fluids may be discharged at the wellheads. These permitted discharges will be risk assessed.

5.3.5

Produced Water (PW) Under normal operations all PW will be re-injected with treated seawater into the water injection wells. The PW system has been designed to handle up to 140,000bwpd (22,260m 3/d). Production forecasts suggest that the field will produce approximately 120,000bbls (19,000m 3) of fluids per day. At the start of field life the water / oil ratio will be approximately 70% e.g., 30bbls of oil and 70bbls of water for every 100bbls of total produced fluids. As the reservoir declines the water / oil ratio will increase and by the end the oil water ratio will be 95% water and 5% oil (5bbls of oil for every 95bbls of water). However, throughout field life 120,000bwpd will need to be injected to maintain the reservoir pressure and balance. Any shortfall between the volume of PW extracted and the volume to be injected will be made up with treated seawater. The PW system has been designed to achieve, as a minimum, oil in water (OIW) concentrations of 30mgl-1. Historically, the Uisge Gorm was regularly

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achieving OIW concentrations of 10 tonnes) Spill modelling (Section 7 and Appendix B) shows that in the loss of containment from the FPSO and/or export tanker (due each other); depending on the prevailing wind conditions at areas of the North Sea area could potentially be affected if measures are taken.

event of a total to collision with the time, large no intervention

Oil spill modelling indicates that oil has the potential to beach along the coast. In this situation there is the potential that near shore recreation could be affected if restrictions are imposed to assist with response operations. There may also be knock-on effects on the tourist industry if the spill beaches in substantial quantities. As the likelihood of such an event occurring is highly unlikely, the EIA concluded that the residual impact is of minor significance.

10.4

ARCHAEOLOGY

10.4.1

Baseline Data Sources Prehistoric Archaeology Data concerning the general submarine archaeology of the North Sea was compiled as part of the Strategic Environmental Assessment for areas SEA2 and SEA3 (Flemming 2002). In addition, some information is available under the aegis of the Aggregates Levy Sustainability Fund (ALSF). This represents a pilot study and is currently restricted to near coastal areas (Wessex  Archaeology 2008). Historic Remains Information on the status of wrecks is available through the Maritime and Coastguard Agency (MCA 2011).

10.4.2

Existing Baseline

10.4.2.1

Prehistoric Archaeology  As a result of glaciation episodes peaking at about 280,000 yrs before present (B.P.), 150,000 yrs B.P. and 20,000 yrs B.P., the sea bed of what is now the North Sea has been repeatedly exposed and there is significant evidence that areas of the North Sea not covered by ice were habitable. While older remains (>100,000 yrs) are unlikely to have been preserved as far north as Alma, as the area was glaciated prior to this, more recent artefacts may be present. At its greatest extent, some 15,000yrs B.P. the so-called Doggerland may have extended as far north as 61°N, with the Alma area remaining as dry land for about 5000 years. It is possible, therefore, that individual artefacts, such as stone tools, or remains of settlement sites could be encountered during

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operations at Alma. If properly reported and conserved such remains could provide significant information concerning early human development in the Doggerland region. It is likely that any sites discovered will be within the jurisdiction of the Ancient Monuments and Archaeological Areas Act 1979. While this act is primarily land based, it has also been applied to provide some protection for underwater sites. The Act provides for the scheduling of ‘monuments’, which encompasses buildings, structures or work, cave or excavation, vehicle, vessel, aircraft or other movable structure. In order to be eligible for scheduling, a ‘monument’ must be of national importance. Geophysical and geotechnical survey results (Gardline 2011) do not show any anomalies typically associated with archaeological sites. 10.4.2.2

Historic Remains Throughout the historical period there have been important trade and other routes across the North Sea. While the majority of wrecks resulting from natural events (storms etc) are likely to be coastal in nature some may have occurred in deeper water. The more likely cause of deep water wrecks (including aircraft remains) is wartime activity. Wreck material (broadly any artefact on the seabed as a result of once being on board of or part of a vessel) is presumed to have an owner irrespective of date of loss. It is a legal requirement (under section 236 of the Merchant Shipping  Act 1995) that recovered wreck material should be reported to the Receiver of Wrecks. Three key pieces of legislation (MCA 2011) applicable to the protection of wrecks in UK waters are: Protection o f Wrecks A ct 1973 This act provides for Protection for designated wrecks which are deemed to be important by virtue of their historical, archaeological or artistic value. Protection for wrecks that are designated as dangerous by virtue of their contents (e.g. ammunition transporters). The Protection of Military Remains Act 1986 This Act makes it an offence to interfere with the wreckage of any crashed, sunken or stranded military aircraft or designated vessel without a licence. This is irrespective of loss of life or whether the loss occurred during peacetime or wartime. All aircraft which have crashed while on military service (including non-UK) receive automatic protection, but vessels must be individually designated. Sites may be designated as Protected Places (automatic for military aircraft, but for vessels requires designation by name, although the location may not be known) or as Controlled Sites.

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 An ci ent Monum ent s an d A rc haeolo gi cal Ar eas Act 1979  As per Section 9.4.2.1 above, is possible that any wrecks discovered will be within the jurisdiction of the Ancient Monuments and Archaeological Areas  Act 1979. In conclusion, there are no known wreck sites (or any other historical remains) within the Alma area and no indication from the survey data (GEL 2011) that any such sites are likely to be present. If present remains may be fragmentary, particularly where these are a result of wartime activity. Part of the reason for protection of such sites is the risk of munitions being present in the vicinity of the wreckage. Unexploded munitions are not rendered safe on immersion in water, and may become dangerously unstable.

10.4.3

Potential Impact Identification The EIA has identified that during the project life cycle, the activities listed below have the potential to interact with archaeology (Table 10-8). Table 10-8: Archaeology p otential impact identification Project Activity Construction Physical presence and movement of vessels Installation of flowlines

Aspect

Potential Impact

 Anchoring Physical presence of subsea infrastructure and flowlines

Physical damage to existing and undiscovered archaeology

Trenching and backfill Production Physical presence, operation and maintenance of FPSO  Accidental Events

Presence of FPSO and anchors

Physical damage to existing and undiscovered archaeology

Overboard loss of equipment or waste

Dropped objects

Physical damage to existing and undiscovered archaeology

The impact of disturbance of an archaeological site is related to the cultural value of a site. This is likely to be increased if a site: Establishes evidence of human occupation in areas where there was no previous evidence Contains examples of previously unknown or poorly preserved artefacts Is of historical significance Uniquely among environmental impacts the discovery of archaeological remains provides an opportunity for positive (i.e., beneficial) impact if such remains are promptly reported and made available for preservation. It is not possible to predict the finding of submerged pre-historic sites. However, if found such discoveries will be of inestimable importance to our understanding of the early settlement of North West Europe. Correct recording and preservation of any artefacts or remains found is both a legal obligation and would be likely to have a high positive publicity value.

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10.4.4

Mitigation Measures The British Marine Aggregate Producers Association (BMAPA) has produced a protocol for reporting finds of archaeological interest (Wessex Archaeology 2005). This has the specific aim of reducing adverse effects of marine aggregate dredging on the historic environment. However, it is equally applicable to other industries working in the North Sea. These protocols will be followed in the event of discovery of artefacts on the seabed, which could potentially be of archaeological significance.

10.4.5

Residual Impact Significance Assessment It is unlikely that any remains of archaeological significance exist within the  Alma area. However, in the unlikely event of an unforeseen site discovery, the proposed mitigation measures would ensure damage to the site would be minimised and the nature of the discovery properly reported. It is therefore likely that any damage would be of minor significance, while the value of the discovery may be of moderate/major (positive) significance.

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11

CUMULATIVE AND INDIRECT IMPACTS  As discussed in Section 4.2, the EIA has given consideration to cumulative and indirect impacts and interactions. The definitions of these three types of impact overlap, generally without any agreed and accepted definitions. For the purposes of this assessment, the definitions proposed by the European Commission (1999) have been used. The definitions are as follows: Indirect Impacts (secondary impacts) – Impacts on the environment, which are not a direct result of the project, often produced away from or as a result of a complex pathway. Cumulative Impacts – Impacts that result from incremental changes caused by other past, present or reasonably foreseeable actions together with the project. Impact Interactions – The reactions between impacts whether between the impacts of just one project or between the impacts of other projects in the area. It is difficult to quantify indirect impacts due to the project but where possible this was undertaken as part of the main EIA. For example, the potential for chemicals to bioaccumulate up the food chain and affect the top predators such as seabirds and marine mammals. In addition, the EIA also considered cumulative impacts from similar activities within the project e.g., the combined effects on habitat loss from numerous types of seabed disturbance. The results of this assessment are therefore discussed in Sections 8, 9 and 10 and in  Appendix A. This Section focuses on the potential for cumulative and indirect impacts and interactions relative to Alma and: Past and future oil and gas developments (Section 11.1) Other seabed/marine users e.g., commercial fishing, wind farms, marine aggregate extraction (Section 11.2) Climate change (Section 11.3)

11.1

OTHER OIL AND GAS DEVELOPMENTS The Alma development field lies in a mature oil and gas producing area within the CNS. Formerly called the Argyll field, it was discovered in 1971 and brought on stream as the UK’s first offshore oilfield in 1975 before being decommissioned in 1992 (DTI 2001c). The Argyll field was renamed Ardmore and redeveloped in 2003 before again being decommissioned in 2008. There is little current existing infrastructure in the immediate area of the development with the nearest oil and gas activity at the Clyde platform 40.5km to the northwest. However, the long-established, and on-going, oil and gas exploration and production activities of the wider region, gives rise to the potential for cumulative environmental impacts.

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It is possible that, in future, EnQuest may drill an additional production well in the Galia field, situated within Block 30/24 (Figure 11-1). If the well goes ahead it would be tied-back to the northern drill centre via a new flexible production flowline and control umbilical. Construction of the well and flowline will probably be along the same lines as the wells and flowlines in the Alma development, with the exception that the production flowline from Galia to the northern drill centre will be trenched. The project will require a full EIA, whether as an  Addendum to the Alma Field ES or as a separate field ES in its own right. However, it can be assumed that the tie-back would have the following seabed footprint:  Anchor mounds and scars from a new drilling rig location affecting 2,600m2 of seabed Trenching and backfill of the new 6km flowline would affect approximately 12,000m2 of seabed 500m radius safety exclusion zone established around the wellhead EnQuest are not aware of any other new developments in a 40km radius of the  Alma development. Figure 11-1: Galia production well in r elation to the wid er Alma development

Note: Image is for illustrative purposes only and does not necessarily reflect exact layout of flowlines and associated infrastructure

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11.1.1

Deterioration in local air quality The EIA concluded that the meteorological conditions in the CNS were of sufficient strength to enable rapid dispersion and dilution of SO x  and NO x emissions from construction and production activities. Air dispersion modelling indicated that gas concentrations would be significantly below guideline levels for human health and environmental protection within 500m of the discharge point i.e., from either a vessel, rig or FPSO (see Section 8.1.5.1). The majority of the Alma construction and production emissions will occur in the vicinity of the proposed FPSO, 40.5km from the nearest existing installation and 273km from the nearest coastline. In conclusion, Alma is considered to be sufficiently distant from any planned or existing developments such that a cumulative impact of emissions on air quality is unlikely to occur. The effects of the gases on the Alma workforce are dealt with under occupational health regulations and again are out of scope of this assessment. In addition, the generally windy offshore conditions will aid in the dispersion of gases and as such cumulative impacts of atmospheric emissions from the development on regional background levels are considered insignificant.

11.1.2

Deterioration in water quality During construction and production, there is likely to be chemical discharges including discharges of WBM. The chemicals discharged are relatively benign, the majority being risk assessed by the CEFAS as HQ colour band Gold or OCNS category E. These are categories for products that present the lowest hazard to the environment. Residual currents are such that chemical discharges are likely to be rapidly diluted and dispersed (see Section 8.2.5). The discharge of these chemicals will be short lived and wells will be drilled sequentially reducing any combined toxic impacts. Therefore, no cumulative impacts on water quality are expected during the construction and production phases of the Alma development with the other installations in the vicinity of the development.  All of the five installations within 50km of the Alma project area (Clyde, Auk A, Fulmar AD, Ekofisk and Judy) discharge produced water to the marine environment (DECC 2011). At Ekofisk, which is in the Norwegian sector of the North Sea, a purification process is used onboard the platform which reduces hydrocarbon content from 30mgl -1 to only 2 to 4mgl -1 (ConocoPhillips 2011). All UK discharging facilities comply with the 30mgl -1  regulatory standard for produced water. Under normal operating conditions, all produced water from the Alma development will be re-injected into the water injection wells. It is only if the system trips, that there is a possibility that produced water will be discharged overboard from the FPSO. Historic research has shown that, due to the rapid dilution, low concentrations and low toxicities of contaminants in produced water, discharges in the North Sea have low potential for biological impact (Wills 2000). Dilutions required for no observed effect concentration (NOEC) are achieved within five minutes, within 10m to 100m from the discharge point.  As the nearest of the five platforms to Alma is 40.5km (i.e., Clyde), it is likely that there will be little or no residual hydrocarbon contamination, during normal operational activities, from other developments around the project area,

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therefore cumulative impacts are not expected. In addition, although the FPSO will be present on site for the field life (10 years), during this time all sewage and food waste is macerated before being discharged overboard. Discharges from visiting vessels will undergo the level of treatment required by shipping regulations. Given the mitigation measures in place and the distance to the nearest discharging facility (Clyde), cumulative effects on water quality are unlikely.

11.1.3

Disturbance of seabed sediments  As discussed in this document, the Alma field development will disturb 0.04km 2 of seabed (see Section 6.1.3.4). The EIA has concluded that the development will have a minor impact on seabed sediments. Disturbance may be visible for up to 5-10 years after construction in the form of anchor/chain footprints, or the presence of cuttings piles. However, in general, although disturbed, the composition of surface sediments in the development area will remain unchanged. In addition, given background levels of contamination associated with the previous use of the area for oil and gas development, levels of hydrocarbon contamination are not expected to increase above existing historical levels. No lasting effect on seabed conditions is expected. It can be assumed that a similar level of disturbance will be observed at the other field developments planned for the CNS. Generally, the development projects are widely spread and footprints will not overlap. It is possible cumulative impacts relative to discharges from neighbouring oil and gas facilities operating contemporaneously may arise. However, the closest discharging facility (Clyde) is over 40km from Alma, suggesting a low potential for cumulative impacts.

11.1.4

Disturbance of habitats or species Drill cuttings There are no other oil and gas developments within 40km of Alma which will be under construction at the same time as the Alma development. Although the drill cuttings piles for the Alma wells (at their respective drill centres) have the potential to overlap, there is not considered to be any potential for cumulative impacts on habitats or benthic species as a result of this aspect of the development in combination with any other development. Pipeline burial The seabed in immediate vicinity of the Alma development is likely to be visibly disturbed on completion of trenching, backfilling and deployment of anchors from the pipeline installation vessel. On retrieval, the anchors are expected to leave a small area of disturbance, much of it which will comprise mobile/loose sediments rather than clay. As there are no other oil and gas developments within 40km, it is unlikely that there will be any cumulative impacts from this aspect of the development.

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Subsea noise Piling noise from Alma is addressed in Section 9.5. As there are no other oil and gas developments within 40km, it is unlikely that there will be any cumulative impacts from this aspect of t he development.

11.1.5

Transboundary impacts The proximity of the development to the UK-Norway median line (closest point 18.5km) also means that transboundary effects must be considered. This will include interaction between the human environments either side of the boundary and the potential for impacts to protected sites or species within UK waters to transfer into protected sites in Norwegian waters. The scale and consequence of any trans-boundary effects will be comparable, or less, than those in UK waters. In the event of an oil spill entering Norwegian waters it may be necessary to implement the NORBRIT Agreement (the Norway-UK Joint Contingency Plan), which sets out command and control procedures for pollution incidents likely to affect both parties.

11.2

OTHER SEABED USERS In general, there are two main cumulative impacts to be considered when assessing the effects of a project on the surrounding region. These are: Whether the combined footprints of overlapping projects have the potential to exacerbate the environmental impacts from the respective projects. Whether projects that do not overlap, when considered in combination, will result in the loss or disturbance of substantial areas of a particular regional habitat.

11.2.1

Commercial fishing The Alma region is of moderate importance for demersal fisheries and low importance for pelagic or shellfish species (Coull et al., 1998). As discussed in Section 10.1, the development is within an area which contributes 48% to the average annual values for herring caught in the region. There are potentially two types of cumulative impacts associated with fisheries: physical disturbance of the seabed and effects on marine ecology. The ES has demonstrated that, given the highly dynamic environment within the project area, physical disturbance, as a result of construction activities, is unlikely to be noticeable above background levels within a minimum of 5 years of the these activities ceasing (Sections 8.4, 9.3 and 10.1). In addition, the community type in the project area is typical for the region and it is considered that the combination of disturbance from trawling and construction will not cause an overall significant loss of habitat type or change in community structure.

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11.2.2

Offshore wind farms Offshore wind farms are becoming more prevalent in UK waters, of which the “Zone 3 - Dogger Bank” (Round 3) is the closest, located 53km to the south of the proposed Alma field development. The zone has been awarded to the developer Forewind 7  (Crown Estate 2011). The first phase is expected to be ready for construction in late 2014. The site is anticipated to have an overall production capacity of 13GW of energy. Due to the distance of the wind farm from the Alma development, it is unlikely that there will be any in combination effects from habitat removal, sediment disturbance and noise generation from piling during construction, especially as the wind farm will not start construction until after completion of construction at the Alma development.

11.2.3

Marine aggregate extraction areas The closest marine aggregate dredging site is the Area 466/1 application area, licensed to Cemex UK Marine Ltd, situated 139km south west of the southern drill centre. Impacts on the marine environment from aggregate extraction primarily relate to the direct disturbance of the seabed and the corresponding effects on marine ecology. Impacts are generally restricted to the area of seabed licensed; although, depending on the dredging activity and prevalent hydrodynamic conditions, sediment plumes from aggregate screening may impact benthic communities within a radius of a few kilometres from the license zone. Due to the distance from aggregate extraction sites, in-combination effects with the Alma development are unlikely. In addition, marine aggregate extraction generally targets sublittoral sands and gravels which support a reasonably diverse biological community, in contrast to the essentially sparse biodiversity of the community found on the fine sands in the Alma project area (see Section 9.2). Therefore, regional impacts from the combined disturbance/loss of habitat types are not anticipated.

11.3

CLIMATE CHANGE  As discussed in Section 8.2, CO2  emissions from the Alma development will contribute, albeit negligibly, to climate change. However, it is also possible that impacts from the development may act in combination with impacts related to climate change to exacerbate physical and biological changes in the environment. Alma has an expected production life of 10 years. Climate change is likely to change the physical and biological baseline environment in the project area over the next 10-25 years. The following impacts on the project area are expected as a consequence of climate change: Sea level rise  – This is expected to slightly affect tidal currents, wave propagation and mobility of seabed sediments (HR Wallingford 2007). However, any changes are likely to be incremental within the project area and within the ranges of survey error. The predicted sea level rise will not affect tidal current direction of strength (HR Wallingford 2007). Ocean acidity and temperature – Minor changes are expected to occur over the next 10-25 years, with major biological shifts potentially occurring 7

 Forewind Consortium – comprising four partners ; SSE (Scottish and Southern Energy plc); RWE npower renewables, the UK subsidiary of RWE Innogy, and two of Norway’s largest companies, Statkraft and Statoil (Crown Estate 2011)

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in the longer term i.e., 100 years. Although, it is unknown how the region’s biological communities will be affected, there is the potential that there will be rapid alterations in the nature and structure of benthic and water column communities. There may also be a northward migration of species as temperature increases. Increased levels of CO 2  in the sea lead to more acidic waters which are likely to reduce the resilience of marine ecosystems, particularly affecting species composed of calcium carbonate. The EIA identified the Alma development will not have any residual impacts on water depth, wind speed or wave conditions. Residual impacts on the environment will be short-term, predominantly affecting marine ecology. As climate change has the potential to affect the biological baseline it is possible that the project can act in combination with climate change to exacerbate this impact. However, the EIA concludes that, following construction, biological communities are anticipated to recover to pre-impact levels/structures or similar within five years (see Section 9.2.4.1). Given the relatively short timescale of the construction impacts, it is considered unlikely that any cumulative impacts from the project and climate change will have significant impacts on marine ecology.

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12

ENVIRONMENTAL MANAGEMENT This section provides an overview of the management systems in place at EnQuest. Whilst the emphasis of an Environmental Statement (ES) is on environmental management, it overlaps with aspects of health and safety and quality management. The following sections therefore describe the management tools EnQuest have in place which cover health, safety, environment and quality (HSEQ). The section also describes how the mitigation measures proposed in this ES will be adopted and bridged into the wider context of the EnQuest Health, Safety and Environmental Management and Quality systems.

12.1

MANAGEMENT SYSTEM EnQuest is a socially responsible employer, committed to maintaining high standards in health, safety and environmental performance. EnQuest implements and operates an integrated Health, Safety and Environmental Management System (HS&EMS) and a Quality Management System (QMS) which has been accepted and endorsed by the Board, and embedded in the overall business culture. The HS&EMS is an integral part of the overall management system. It is laid down in policies, procedures, standards and work instructions. Its general purpose is to prevent EnQuest’s activities from putting people, the environment, property or the reputation of the company at risk. The HS&EMS is designed to match the requirements of ISO-14001:2004 and is based on the requirements of the Health and Safety OHSAS 18001 standard. The QMS is certified to BS EN ISO 9001. The purpose of the HS&EMS and QMS is to enhance health, safety, environmental and quality (HSEQ) performance and provide a framework for HSEQ management for all of the activities carried out throughout the company. The management systems are designed to cover HSEQ aspects which EnQuest can control and directly manage and those it does not control or directly manage, but can be expected to influence. EnQuest requires all contractors, their subcontractors and suppliers to have their own HS&EMS and QMS. Each contractor will be responsible for the HS&E management of their scope of work and will operate according to their own HS&E Management System. However, contractors HS&EMS must be compatible with EnQuest’s HS&EMS and they are required to align their HS&E management with EnQuest’s goals and objectives. Their QMS must meet the applicable requirements of the BS EN ISO 9000 series of standards or an agreed equivalent.

12.2

PROJECT SPECIFIC ENVIRONMENTAL MANAGEMENT  A project specific HS&E plan will be developed for the Alma development which will define how EnQuest will manage HS&E risks and activities. The Project HSEQ Engineer is responsible for maintaining and implementing the plan, and for providing HSEQ controls within the project to ensure that the requirements of the EnQuest HSEQ management systems are met. The Project HSEQ Engineer reports directly to the Development Manager, who is accountable for

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the project as a whole and will implement and maintain a number of documents and processes which include: Project HSE and Quality Plans Regulatory Compliance Procedure Risk management system Document management control However, everyone working on the project either directly or indirectly has a responsibility for ensuring that they meet defined HS&E requirements for their own particular activities. The Alma development HS&E plan (EnQuest 2011) describes how EnQuest will manage HS&E activities arising from the Alma Field Development. This Plan applies from the concept selection stage through to the project execution phases of the project and: Describes how EnQuest will manage the HS&E aspects arising from the project Presents the key HS&E requirements of the project Clearly defines HS&E roles and responsibilities Provides a vehicle for tracking and monitoring Provides an auditable trail for Project HS&E management Sets out EnQuest’s environmental targets as shown in Table 12-1 Table 12-1: EnQuest environmental targets Objective Compliance with consent requirements

Target

Comment

 All permits in place and permit conditions identified to contractors.

Exception Reporting

No deviations from permit requirements No breaches of waste regulations

Compliant management of waste

Waste categorisation and monitoring sufficient for EEMS reporting

 Assurance that the Rig and Installation Vessels are fit for purpose

Confirmation of appropriate and effective rig/vessel audit regime.

Well testing is efficient with respect to atmospheric emissions

No incidents or spills  Assurance that UKOOA Guidelines followed

Improvement opportunit ies for Specific improvement opportunities identified future project activiti es identified and recorded at close out. Source: Extracted from EnQuest HSEQ policy 2011

Exception Reporting

Verify through Audit Report

Exception reporting Lessons learned Register

 All contractors will be requested to develop their own HS&E Plans, which are aligned to the EnQuest Project HSE Plan and are in line with EnQuest project goals and objectives. Compliance with relevant HS&E regulations, codes and standards also needs to be common across all of the companies that will participate in the development.

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Competency of contractor personnel and contractor’s means of achieving a competent workforce for EnQuest projects will be identified in the HSE Plan, assessed in contractor selection and monitored during contractor duration. During construction bridging documents will be in place between the contractors and EnQuest. These will describe the management structure and division of responsibilities, the methodology of execution of the work programme and any emergency response procedures. EnQuest actively monitor and audit contractor’s operational control procedures and their implementation. For example, contractor’s proposed method statements, programmes and resources are reviewed during contractor selection (procurement) and all plans, procedures and standards for operational control are reviewed and approved by EnQuest. The project will be subject to statutory regulatory control which requires various applications and notifications to be made to nominated governmental bodies for approval of the relevant activities. Effective management of these activities is critical for the success of the project and to enable this EnQuest will establish a Permits Licenses Approvals Notifications and Consents (PLANC) register. The register will be regularly monitored to ensure that the necessary consents or notifications are in place when required during the development. The HSEQ Engineer will develop and manage the PLANC register. following are the key permits and consents requirements:

The

Environmental Statement (ES) approval Field Development Plan (FDP) approval Pipelines Works Authorisation (PWA) Petroleum Operations Notices (PON) approval e.g., PON15C (pipelines), PON15B (drilling), PON15D (FPSO) Oil Pollution Emergency Plan (OPEP) It is expected that the mitigation measures identified in the EIA process and reported in this ES will be adopted and bridged into EnQuest’s HSEQ Management System through the PLANC register.

12.3

MANAGEMENT OF MITIGATION MEASURES It is anticipated that the mitigation measures identified in the EIA process and reported in this ES will be adopted and bridged by EnQuest’s HSEQ Management System through the PLANC register. In addition to the standard best practice mitigation measures, including those that are regulatory requirements, which will be enforced during construction and production (see summary in Table 12-2 and Appendix A) EnQuest are committed to the following:

1)

Production flaring will be kept to a minimum

2)

JNCC guidelines on disturbance will be followed to prevent committing an offence under the Conservation (Natural Habitats &c) Regulations 1994 (as amended in 2010) (HR) and the Offshore Marine Conservation (Natural Habitats &c) Regulations 2007 (as amended in 2010) (OMR).

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Table 12-2: Summary of mitigation measures Mitigation measures Ensure all machinery is maintained and serviced Use of cleaner low emission fuels. Stack heights in accordance with the relevant regulations. Ensure all machinery used for transfers is regularly cleaned and maintained. Every vessel will have and implement a written waste management plan, compliant with MARPOL 73/78.  Annex V (Garbage) is particularly relevant. No plastics/plastic containing material will be disposed of at sea, regardless of location. Paper & food wastes will only be discharged outside the 12nm limit. General household products will be selected that are environmentally benign. Daily recording of chemical use to allow more refined and efficient use. Where possible chemicals will be recycled, skipped and shipped or re-injected and not discharged. Selections of chemicals will be made in accordance with the CEFAS ranked list, where chemicals ranked as lower potential hazards are preferentially chosen. Only chemicals permitted through the relevant Offshore Chemicals Regulations chemical permit (i.e. PON15B, C or D) and that have been subject to a risk assessment will be discharged.  All oil discharges will be covered by an approved OPPC permit. The footprint of any anchors, infrastructure and protective structures will be minimised  A 500m safety exclusion zone will be in place around the FPSO and drilling rig at all times, enforced by designated guard vessel The FPSO, drilling rig and support vessels will be appropriately lit. The tanker and supply vessels will follow defined routes.  All relevant notices will be placed in the Kingfisher Bulletin and “Notice to Mariners”  All subsea structures have been designed to be fishing friendly Produced water discharge will be closely monitored to ensure that all contaminants are at an acceptable level. Oil in water, chemical, aromatic and radionuclide concentrations will all be reported via the appropriate OCR permit i.e., PON15D.  Any produced water potentially contaminated with reservoir hydrocarbons will be recycled or re-injected and not discharged unless below permitted levels for discharge via an Oil Pollution, Prevention and Control (OPPC) permit.  A location specific approved OPEP will be in place for the development that covers drilling and production The OPEPs will detail all emergency procedures that will be in place to minimise any spill. Control measures will be in place to ensure rapid response to loss of pipeline containment. These will be outlined in the Alma OPEP.  Accidental spills will be kept to a minimum through training, good housekeeping and through storage/handling procedures e.g., sumps, drains and bundling should catch accidental spills. Management controls will be in place to eliminate bunkering spills e.g. only bunkering during day light and in good weather. EnQuest has access to Tier 1, 2 and 3 oil spill response capabilities through Oil Spill Response Limited (OSRL). EnQuest is a member of OSPRAG which will provide support in a well blow out event. Every reasonable measure will be taken to retrieve dropped objects. If the object cannot be retrieved a PON2 will be submitted to the DECC.  A dropped objects plan will be developed to address risk of dropping objects during construction and operations.

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12.4

OIL SPILL RESPONSE The Alma field will have a site specific oil pollution emergency plan (OPEP) that meets the requirements of The Merchant Shipping (Oil Pollution Preparedness, Response Co-operation Convention) Regulations, The Offshore Installations (Emergency Pollution Control) Regulations and the latest guidance issued by the DECC. The OPEP will cover onshore and offshore responses for an incident in the  Alma field. It will take into consideration drilling activities at the drill centres’, production activities on the FPSO, the production of crude oil and chemicals in the flowlines and the export of crude oil in the offloading tankers. EnQuest has subscribed to Oil Spill Response (OSR) to provide clean-up expertise and equipment in the event of oil spills. In addition, EnQuest has a contract with Petrofac to provide 24 hour emergency support, including the use of the Petrofac Emergency Response Centre (ERC). Equipped with a competent team of professionals, the ERC will be used to coordinate onshore response if required. EnQuest operates a three-tier response system. Tier Three  consists of the Incident Management Team (IMT), with at least one member on call 24 hours a day, seven days a week. The IMT Duty Manager is the first responder to the ERC. Tier Two  is the first level of the EnQuest Crisis Management Team (CMT). Mobilised by the IMT Duty Manager, the CMT sits at EnQuest’s  Aberdeen office. Should an incident escalate, requiring more corporate support, Tier One  is activated, which consists of EnQuest’s senior leadership team, based EnQuest’s company headquarters in London. The installed wellheads will have H4 connectors that will be compatible with the capping device being built under the Well Life-Cycle Decision Framework (WLCDF) Oil and Gas UK (OGUK) initiative.

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13

CONCLUSIONS

13.1

THE PROJECT The field, to be renamed Alma, will be a re-development of the existing  Ardmore field, located within the CNS. Alma will be developed through two drill centres tied-back via new oil production and water injection flowlines to the Uisge Gorm FPSO. The development will consist of six production wells and two water injection wells (which will be used to drive production due to low reservoir pressures). The field is located in UKCS Blocks 30/24 and 30/25, which is 274km east of the nearest landfall on the Northumberland coastline and 18.5km from the UK/Norway median line. Construction is expected to commence in January 2012, with the rig remaining on site until April 2013. Field life is anticipated to be ten years. Overall, the proposed development is regarded as being a small scale oil development, in the context of other oil and gas developments in the wider CNS. Construction activities will generate a range of routine emissions/discharges to air and sea respectively, e.g.;  Atmospheric emissions Drill cuttings and water based mud discharges Chemical discharges Waste water and sewage discharges Subsea noise Once producing, the development will emit produced water containing small quantities of oil and atmospheric emissions.

13.2

EXISTING ENVIRONMENT Existing conditions at the Alma development were established through an environmental baseline and habitat assessment survey, which revealed that: The benthic habitat typically comprised of sparse sandy sediments with low benthic diversity. The majority of benthic taxa were polychaete worms. Stations sampled where historical drilling activity was prevalent were characterised by more disturbance and hydrocarbon contamination tolerant species and lower numbers of sensitive species. No habitats or species of conservation significance under the UK’s Offshore Marine Conservation (Natural Habitats, &c.) (Amendment) Regulations 2010 were observed during seabed surveys. The environmental baseline is similar to other regions of the CNS where oil and gas activity is prevalent. Meteorological conditions around the project support a dilution and dispersion regime which will rapidly reduce the impact significance of emissions to air, water and seabed (i.e., winds are sufficient to disperse atmospheric emissions, tidal currents refresh the water column within an estimated 1.5 hours, currents are generally sufficient to disperse drill cuttings or sediment piles on the seabed within a minimum of 5 years).

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13.3

POTENTIAL IMPACTS The potential effects of the project on the environment were identified and quantified by reviewing the existing baseline environmental conditions with the potential to be affected by the project and identifying and evaluating the effect of any activities associated with the project on these conditions. It should be noted that the majority of activities were assessed as having negligible or minor residual impact on the receiving environment, with a few identified as having a residual impact of moderate significance. This ES reached the following conclusions with regards to the project’s impacts on the environment: Benthic Environment: The total seabed footprint of the development is 0.04km2. Due to fishing activities and previous oil and gas industry activities, the benthos in the project area is typical of a moderately disturbed habitat and consequently species that inhabit the area tend to recover quickly after disturbance. The development area is sufficiently homogenous that any localised losses are unlikely to affect the integrity of the community as a whole. The placement of protective structures such as concrete mattresses will create new habitat for those species that require hard substrate for anchoring. This could lead to settlement of new species and the potential for a localised change in marine ecology. Current speeds are sufficient to erode cuttings piles and these are unlikely to persist for a long period of time. Seabed activities that cause physical disturbance have been classed as having a moderate to minor residual impact. Protected Species: No protected species were identified in the marine benthic surveys. Marine mammals are likely to be the only protected species of relevance in the Alma development. A small amount of piling will be necessary during construction activities which will create subsea noise.  A noise assessment was carried out, following the current JNCC guidelines which identified that, provided mitigation measures are followed, the sound experienced will not exceed the injury or non-trivial disturbance thresholds for marine mammals. There is therefore a negligible risk of an offence under the Conservation (Natural Habitats &c) Regulations 1994 (as amended) and the Offshore Marine Conservation (Natural Habitats &c) Regulation 2007 (as amended in 2010). Protected Are as: There are no protected sites within 40km of the Alma development. The nearest protected site is the Dogger Bank potential Special Area of Conservation (pSAC) which is approximately 78km southeast from the Alma southern drill centre. Due to the distance of the protected site from the development area, it is unlikely that there will be any impacts during normal activities. Water/Sediment Quality: No activities were identified during construction or production that would have the potential to have a significant residual impact on water or sediment quality.  Ai r Qualit y: Given the generally dynamic offshore, concentrations of NO x and SOx  from construction and production activities are not expected to reach European Commission alert thresholds and there is expected to be a minor residual impact on regional air quality.

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Commercial Fishing and Other Marine Users:   With consideration of other development activities in the CNS, safety exclusion zones are likely to have a minor impact on commercial fishing in the area as this will result in vessels being displaced from their fishing grounds. Snagging hazards will be mitigated for by using standard best practice and industry measures (i.e. use of fishing friendly structures).  Ac ci den tal Events : Spi ll of hydr oc arb ons: In the unlikely event of a major oil spill, a worst case scenario loss of containment of 100,000m 3 (87,000 tonnes) of crude oil from the export tanker has been modelled. This indicates that depending on the prevailing wind conditions there is a 1% chance of beaching occurring on a coastline of a North Sea bordering country. Modelling also indicates that, without an intervention response, depending on the prevailing wind conditions, the spill could reach the UK coastline within 8 days and 10 hours and the Danish coastline within 5 days and 12 hours. The spill is likely to have completed dispersed within 417 days. There are numerous protected areas along the coastlines of North Sea bordering countries that could be affected by a spill (Figure 8-3). EnQuest will have an OPEP in place to manage spill response. Cumulative and transboundary impacts:   The potential for cumulative impacts stems from both current on-going production operations and new developments. The Alma Field is in an area of extensive oil development where activities have left their mark on the seabed. Alma is a relatively small development and it is unlikely that the incremental change to seabed disturbance, produced water and atmospheric emissions is likely to substantially change the physical and biological characteristics of the region.

13.4

DECOMMISSIONING Field life is estimated to be approximately ten years and therefore decommissioning and abandonment will occur around 2023. The arrangements for decommissioning the wells and pipelines will be developed in accordance with UK government legislation and international agreements in force at the end of field life. The potential impacts from decommissioning have not been considered in this EIA. They will be the subject of a separate EIA submitted prior to decommissioning.

13.5

ENVIRONMENTAL MANAGEMENT The EnQuest corporate policies and environmental management system provide a fit for purpose framework to implement the mitigation measures proposed in this ES. The EMS also provides adequate control and bridging arrangements for EnQuest to ensure that the contractors implement these mitigation measures. During the construction and production operations, a set of permits and consents will be obtained from the regulatory bodies. Permit conditions under these will also be fed into the EMS to ensure compliance. EMS performance will be regularly benchmarked against recommendations from independent verifications, through internal and independent audits and reviews. With mitigation measures in place, the Alma development will h ave a minor impact on the environment.

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14

REFERENCES  Anatec (2011). Consent to Locate - Alma (Technical Note). Prepared by Anatec on behalf of EnQuest 2nd June 2011. Reference: A2668-ENQ-CR-1 BGS (2004). Technical Report produced for  Assessment – SEA2: North Sea Geology. TR_008

Strategic

Environmental

BSI (2001). Environmental Management - Environmental assessment of sites and organisations (EASO), Reference Number: ISO 14015: 2001 (E). Communities and Local Government (2010). Planning Policy Statement 25: Development and Flood Risk. HMSO, London. Compass Hydrographic Surveys Ltd (2004). Marine Aggregate Licence Area 430: East of Southwold Conoco Phillips (2011). http://w3.conocophillips.com/gcommon/internet/html/reports/sdreport/minimize3  _water.html Coull, K.A., Johnstone, R., and Rogers, S.I. (1998). Fisheries Sensitivity Maps for British Waters. Published and distributed by UKOOA DECC (2009a). Guidance notes for Industry. Guidance notes on the Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999 (as amended). Version No:-46. Issued 10/08/2009. DECC (2009b). UK Offshore Energy Strategic Environmental Assessment. Environmental Report, January 2009. DECC (2011a). Promote UK 2011. Prospectivity of the United Kingdom (UK) Continental Shelf: North Sea Opportunities. https://www.og.decc.gov.uk/UKpromote/summary_information/North_Sea_intro  _2011.pdf  [Accessed February 2011]" DECC (2011b). Water Production sorted by [Accessed March 2011]

field.

DECC Online Maritime Data GIS system. http://www.maritimedata.co.uk/. [accessed June 2011]

from

Defra (2011). statement/

Available

http://www.defra.gov.uk/news/2011/03/18/marine-policy-

Dore, C.J., Murrells, T.P., Passant, N.R., Hobson, M.M., Thistlethwaite, G., Wagner, A., Li, Y., Bush, T., King, K.R., Norris, J., Coleman, P.J., Walker, C., Stewart, R.A., Tsagatakis, I., Conolly, C., Brophy, N.C.J. and Hann, M.R. (2008). UK Emissions of Air Pollutants 1970 to 2006. Issue 1. AEA Technology plc prepared for Defra. DTI (2001a). Strategic Environmental Assessment of the Mature Areas of the North Sea (SEA2). Consultation Document, H.M.S.O, London. DTI (2001b). Contaminant Status of the North Sea. Strategic Environmental  Assessment - SEA2 Technical Report 004

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DTI (2001c). North Sea Fish and Fisheries: Technical report produced for Strategic Environmental Assessment – SEA2. Produced by Cefas & FRS DTI (2001d). Background Information on Marine Mammals Relevant to SEA2. Technical Report 006 produced for Strategic Environmental Assessment – SEA2. Produced by Sea Mammal Research Unit (SMRU), August 2001. DTI (2001e). Human Activities in the North Sea Relevant to SEA2: Technical Report 007 - Existing activities. Produced by BMT Cordah DTI (2002). Background information on marine mammals relevant to SEA 2 and 3. Technical Report 006 to inform SEA 2 and 3. Prepared by Hammond, P.S., Gordon, J.C.D., Grellier, K., Hall, A.J., Northridge, S.P., Thompson, D., and Harwood, J. Available online http://www.offshoresea.org.uk/consultations/SEA_3/TR_SEA3_Mammals.pdf   [Accessed December 2008] DTI (2007). 2007

Meeting the Energy Challenge - A White Paper on Energy. May

EnQuest (2010). Ardmore Redevelopment Basis of Design. Document No. KNIPM-000-BOD-0002 Revision A1 EnQuest (2011). Ardmore Redevelopment Project HSE Plan. Document No. ENQ-KNI-HS-000-PLA-0001 European Commission (1999). Guidelines for the Assessment of Indirect and Cumulative Impacts as well as Impact Interactions. EC DG XI Environment, Nuclear Safety & Civil Protection. May 1999. Produced by Hyder. Flemming, N.C. (2002). The scope of Strategic Environmental Assessment of North Sea areas SEA3 and SEA2 in regard to prehistoric archaeological remains. August 202 Report prepared for the DTI SEA3_TR014 Gaz de France Britain (2005). Cygnus Exploration Well Environmental Statement. DECC Project Reference No.: W/2880/2005. GEL (2011). Alma Field Development Site Survey: Environmental Baseline & Habitat Assessment Survey. Ref 8602 GGL (2011). UKCS Blocks 30/24, 30/25, 30/29 and 30/30 Alma Field Development December 2010 to January 2011 Survey report HM Government (2009). The UK Low Carbon Transition Policy. National strategy for climate and energy. 15th July 2009. JNCC (2010). The protection of marine European Protected Species from injury and disturbance. Guidance for the marine area in England and Wales and the UK offshore marine area. Prepared by JNCC (June 2010). JNCC (2011). 08/02/2011

http://www.jncc.gov.uk/page-4535#DoggerBank

accessed

Johnston, C.M., Turnbull, C.G. and Tasker, M.L. (2004). Natura in UK Offshore waters: Advice to support the implementation of the EC Habitats and Birds Directive in UK Offshore waters. JNCC 04 P23. KISCA (2010). GIS data, last downloaded February 2010

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Law, R.J., Waldock, M.J., Allchin, C.R., Laslett, R.E. and Bailey, K.J. (1994). Contaminants in seawater around England and Wales: Results f rom monitoring surveys, 1990-1992. Mar. Pollut. Bull., 28: 668-675 MMO (2010). 2004 – 2009 landings data for ICES rectangles 41F2 MCA (2011). http://www.dft.gov.uk/mca/ Met Office (2011). Met Office European model (56.0°N 3.14°E Jan 1998 - Nov 2008) OGUK (2006). Good practice for cleanup in well operations. Revision 1. Oil and Gas UK Environmental Legislation website: Well Clean-up. OGUK (2008). Environmental Legislation Website. The Statutory Regime. Web page updated 29 October 2008. [Accessed November 2008] OGUK (2009). EEMS Atmospheric Reporting Data 1.0 - Facility Emissions (Reporting Year 2008) OGUK (2010). EEMS Atmospheric Reporting Data 1.0 - Facility Emissions (Reporting Year 2009) Olsgard, F. and Gray, J.S., (1995). A comprehensive analysis of the effects of offshore oil and gas exploration and production on the benthic communities of the Norwegian continental shelf. Marine Ecology Progress Series, 122: 277306. OSPAR Commission (2000). Quality Status Report 2000, Region II – Greater North Sea. OSPAR Commission, London. 136 + xiii pp Available online http://www.ospar.org/content/content.asp?menu=00790830300000_000000_00 0000 [Accessed January 2009] OSPAR Commission (2010). Quality Status Report 2010 for the North-East OSR (2011). Oil Spill Modelling for Alma Field Development. Prepared for Metoc Ltd. Project Number 4558. Reid, J.B., Evans, P.G.H. and Northridge, S.P. (2003). Atlas of Cetacean distribution in northwest European waters. Joint Nature Conservation Committee, Peterborough, UK. Richardson, W.J., Thomson, D.H., Green Jr, C.R. and Malme, C.I. (1995). Marine mammals and noise. Academic Press, New York. RYA (2008). UK Coastal Atlas of Recreational Boating. Recreational Cruising Routes, Sailing and Racing Areas around the UK Coast. Second Edition Sadler, B. and McCabe, M (Eds) (2002). United Nations Environmental Programme (UNEP) EIA Training Resources Manual, Second Edition. http://eia.unu.edu SCANS-II (2008). Small Cetaceans in the European Atlantic and North Sea. Final Report submitted to the European Commission under project LIFE04NAT/GB/000245. Available from SMRU, Gatty Marine Laboratory, University of St Andrews, St Andrews, Fife, KY16 8LB, UK.

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Skov, H., Durinck, J., Leopold, M.F., and Tasker, M.L. (1995). Important Bird  Areas for seabirds in the North Sea. BirdLife International, Cambridge Stone, C.J., Webb, A., Barton, C., Ratcliff, N., Reed, T.C., Tasker, M., Camphuysen, C. J. and Pienkowski, M.W. (1995). An atlas of seabird distribution in the north-west European waters. Joint Nature Conservation Committee, Peterborough. Stone, C.J. (2003). The effects of seismic activity on marine mammals in UK waters, 1998-2000. JNCC Report No. 323. Joint Nature Conservation Committee, Peterborough, UK. The Crown Estate (2011). The Crown Estate UK Climate Impact Programme (2002). UKCIP02 Climate Change scenarios gateway. UK Deal (2010). GIS data, last downloaded November 2010 UK National Air Quality http://laqm.defra.gov.uk/maps/maps2008.html

Archive

(2009).

UK National Air Quality Archive (2011). http://uk-air.defra.gov.uk/ UKCP (2009). UK climate change http://ukclimateprojections.defra.gov.uk/content/view/2013/500/ UKMMAS (2010). Charting Progress http://chartingprogress.defra.gov.uk/

2

-

The

State

predictions of

UK

Seas.

UKOOA (1999). Drill Cuttings Initiative, Research and Development Programme. Activity 2.1. Faunal Colonisation of Drill Cuttings Pile Based on Literature Review. United Kingdom Offshore Operators Association, Aberdeen, UK. UNFCCC (2008). United Nations Framework Convention on Climate Change (1994). http://unfccc.int/essential_background/convention/items/2627.php Wills, J. (2000). A Survey of Offshore Oilfield Drilling Wastes and Disposal Techniques to Reduce the Ecological Impact of Sea Dumping. Prepared for Ekologicheskaya Vahkta Sakhalina (Sakhalin Environment Watch). http://www.offshore-environment.com/drillingwastecontents.html [accessed October 2008]

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Appendix A Environmental Impact Assessment

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A-1

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A.1

Interaction Matrix Environmental Receptor

Physical

   y     t     i     l    a    u    q    r     i     A

Human

Biological    e    g    n    a     h    c    e     t    a    m     i     l     C

   n    o     t     k    n    a     l     P

   s    e     i     t     i    n    u    m    m    o    c    c     i     h     t    n    e     B

    h    s     i     f     l     l    e     h    s     d    n    a     h    s     i     F

   s     d    r     i     b    a    e     S

   s     l    a    m    m    a    m    e    n     i    r    a     M







































 

   s    e    c    r    u    o    s    e    r    r    e     t    a     W

   s    n    o     i     t     i     d    n    o    c     d    e     b    a    e     S



Project Activity

   s    e     t     i    s     d    s    e    e     i     t    c    c    e    e     t    p    o    s    r     d    p    e    n    n    a     i    r    a     M

   s    e     i    r    e     h    s     i     f     l    a     i    c    r    e    m    m    o     C



















































   g    n     i    p    p     i     h     S

   s    r    e    s    u    e    n     i    r    a    m    r    e     h     t     O

   y    g    o     l    o    e    a     h    c    r     A







General Construction Physical presence and movement of vessels



Bulk storage and transfer







Drilling of wells



Installation of flowlines





Installation of FPSO Production Physical presence, operation and maintenance of FPSO





Physical presence and movement of export tanker and supply vessels





Flaring during initial stages of production











Presence of subsea infrastructure  Accidental Events 













Chemical / hydrocarbon release (< 1 tonne)



 

















Chemical / hydrocarbon release (1-10 tonnes)



















Chemical / hydrocarbon release (> 10 tonnes)



















Overboard loss of equipment or waste

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

A-2



 



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ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Determination of Potential Impact Project  Activity

 Aspect

EIA

Drilling of wells Installation of flowlines

E-3

Mitigation Measures

Residual Impact Assessment Identification of Residual Impact Considering Mitigation Measures

   e    c     d    n    o    y    a    o     i    c     t     i     h    r     i     f     i     l    e    n    e    v    g     k    e     i     i     L     S    S

   n    o     i     t    c    e     S

E-2

Consideration of Mitigation Measures

Potential Impact

Drilling of wells

Discharge of chemicals (including WBM)

Potential toxic effects

    )     N     /     Y     (     ?     A     I     R

 As per Section C3

Potential toxic effects

 Anchoring

Physical damage to individuals

    t    n    e     t    y     d    x     i     t    o    n     E    v    o    o     l     i     t     h     i    a     i     t     i     i     l    s    e    a     t    a     k    r    u    p    n    e     i     L     D     S     S

   y     t     i     l     i     b    a    r    e    v    o    c    e     R

   n    o     i    e     t    c    c    n    e    a    s    c    r     i     f     t     i    o    n    p    g    e     i     S     R

All discharges will be risk assessed and be within permitted levels.  Although sensitive to changes in water quality, the plankton community undergoes a continual change in individuals with those from the surrounding waters and therefore has extremely rapid recovery rates.

   y     l    e    e     l     k     b     i     i     L     i    g    r    o    y     l    g    n    r    e    e     i     V     N    M

Discharge of reservoir hydrocarbons

Severity Factors

 As per section C-3, discharged chemicals will not be present within the water column for long enough or at high enough concentrations to pose a significant threat to plankton.

   e  As per Section     l    e     b     l     b     i    g    r     i     i    o    s     l    s    g    n    o    e     i

C-4

    N

-

-

-

-

-

  -

    1  .     9

    N

-

-

-

-

-

  -

    1  .     9

As per Section C-4. No lasting effect on plankton is expected.

    P     N    M

F - Benthic communities F-1

Physical presence and movement of vessels

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Smothering

   y     l    e    e     l     k     i     b     i     L     i    g    r     l    o    y    r    g    n    e    e     i     V     N    M

The footprint of the anchors will be minimised

 As per Section D-1. Within the impact area sessile species will be killed. The benthic community within the project area is typical for the CNS with no rare or protected species identified in the site surveys. Following removal of the anchors, recolonisation and recovery to pre—impact levels is likely to take place through immigration into the disturbed area over a period of one to five years.

A-8

   e     t    a    r    y    e     l     l    a     d    e    w     k    o    c     i    o    o     Y L     M     L     L

    t    r    o     h     S

   r    o    n     2     i  .     M     9

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Determination of Potential Impact Project  Activity

 Aspect

EIA

G-3

Physical presence and movement of vessels

Physical presence and movement of vessels

Discharge of sewage, grey water, food waste and drainage water

Subsea noise

Organic enrichment leading to raised biological oxygen demand. May increase plankton & fish populations changing balance of food chain Disturbance causing avoidance of spawning & nursery grounds Physical damage to individuals

G-4

Mitigation Measures

Residual Impact Assessment Identification of Residual Impact Considering Mitigation Measures

   e    c     d    n    o    y    a    o     i    c     t     i     h    r     i     f     i     l    e    n    e    v    g     k    e     i     i     L     S    S

   n    o     i     t    c    e     S

G-2

Consideration of Mitigation Measures

Potential Impact

Drilling of wells

Discharge of cuttings

Loss of spawning & nursery ground effecting stock viability Physical damage to individuals

REPORT REF: P1459BA_RN2525_REV0

Severity Factors     )     N     /     Y     (     ?     A     I     R

 As per Section C-1

    t    n    e     t    y     d    x     i     t    o    n     E    v    o    o     l     i     t     h     i    a     i     t     i     i     l    s    e    a     t    a     k    r    u    p    n    e     i     L     D     S     S

   y     t     i     l     i     b    a    r    e    v    o    c    e     R

   n    o     i    e     t    c    c    n    e    a    s    c    r     i     f     t     i    o    n    p    g    e     i     S     R

Considering the active mitigation in place it is likely that any deterioration in fish or shellfish will be transient. It is very unlikely that there will be any residual impacts.

   e     l    e     b     l     b     i    g    r     i     i    o    s     l    s    g     i    n    o    e     P     N    M

    N

No mitigation envisaged

-

-

-

-

-

  -

    3  .     9

As the majority of the noise generated by offshore oil installations is low frequency (10 tonnes: loss of containment from the drilling rig, total loss of inventory from the FPSO and total loss of inventory from the export tanker. A well blow out is highly unlikely given the low reservoir pressures present at Alma (see Section 7.1.1).  A diesel spill will very quickly evaporate and disperse in the marine environment. Oil spill modelling indicates the diesel inventory from the drilling rig would naturally disperse or evaporate within 10 hours (see Section 7.3). Crude oil takes longer to disperse and an intervention response may be necessary to help break it up before it beaches on the shoreline. Water quality is likely to deteriorate in the immediate vicinity of the spill as hydrocarbons are dispersed through the water column. However, it will be naturally biodegraded by microbes within one to two months (NOAA 2006). The concentration and likelihood of natural biodegradation will obviously be dependent on the scale of the incident. However, generally the deterioration in water quality will be short –term.

   y     l    e     k     i     l    n    r     U    o    y    r    w    i    n    e    o     V    L

    M

    Y

   y     l    e     k     i     l    n     U    y    r    e V

    t    r    o     h     S

   e    v     i    s    n    e     t    x     E

   w    o     L

   e     t    a    r    e     d    o     M

   r    o    n     3     i  .     M     8

B -Seabed conditions B-1

Overboard loss of equipment or waste

Dropped objects

Scour around objects

Every reasonable measure will be taken to retrieve dropped objects. If the object cannot be retrieved a PON2 will be submitted to the DECC.  A dropped objects plan will be    e    e     l     b     l     b     i    g    r developed to address risk of     i     l    o    s     i    g    s    n    o    e     i dropping objects during construction     P    N    M and operations.

REPORT REF: P1459BA_RN2525_REV0

A-33

Scour is likely around any object remaining on the seabed. However, given the mitigation measures in place any residual impacts are likely to be negligible.

    N

-

-

-

-

-

  -

    4  .     8

21/07/2011

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Determination of Potential Impact Project  Activity

 Aspect

EIA Potential Impact

   n    o     i     t    c    e     S B-2

B-3

Chemical / hydrocarbon release (< 1 tonne)

Chemical / hydrocarbon release (1-10 tonnes)

Diesel, crude or chemical spill (including OBMs)

Diesel, crude or chemical spill (including OBMs)

REPORT REF: P1459BA_RN2525_REV0

Sediment contamination

Consideration of Mitigation Measures Mitigation Measures

Identification of Residual Impact Considering Mitigation Measures

   e    c     d    n    o    a    o    i    c     t     i     h     f     i    r     i     l    e    e    v    n     k     i    e    i     L    S    S  As per Section A-1

Severity Factors     )     N     /     Y     (     ?     A     I     R

    d    o    o     h     i     l    e     k     i     L

    N

-

   n    o     i     t    a    r    u     D

    t    n    e     t    x     E     l    a     i     t    a    p     S

-

-

   y     t     i    v     i     t     i    s    n    e     S

   y     t     i     l     i     b    a    r    e    v    o    c    e     R

   e    c    n    a    c     i     f     i    n    g     i     S

   n    o     i     t    c    e    s     t    r    o    p    e     R

-

-

  -

    4  .     8

A large number of chemicals will be used during construction activities, particularly associated with drilling the wells. All chemicals will be risk assessed and permitted in the appropriate manner.  A spill 0.1 tonnes occurring during construction is 24% for the Alma development. The majority of spills are likely to be at the sea surface or in the water column. The frequency of the flowline failing is 0.00125 times per year. A spill of crude oil from the production flowline could contaminate sediments and persist for some time however the extent will be localised.

   y     l    r    e    o     k     i     l    w    i    n    o    n     U    L     M

A-34

   y     l    e     k     i     l    n     U

    t    r    o     h     S

    l    a    c    o     L

    h    g     i     H

   e     t    a    r    e     d    o     M

   r    o    n     4     i  .     M     8

21/07/2011

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Determination of Potential Impact Project  Activity

 Aspect

EIA Potential Impact

   n    o     i     t    c    e     S B-4

Chemical / hydrocarbon release (>10 tonnes)

Diesel, crude or chemical spill (including OBMs)

Sediment contamination

Consideration of Mitigation Measures Mitigation Measures

Identification of Residual Impact Considering Mitigation Measures

   e    c     d    n    o    a    o    i    c     t     i     h     f     i    r     i     l    e    e    v    n     k     i    e    i     L    S    S  As per Section A-3

Residual Impact Assessment Severity Factors     )     N     /     Y     (     ?     A     I     R

    d    o    o     h     i     l    e     k     i     L

    Y

   y     l    e     k     i     l    n     U    y    r    e V

   n    o     i     t    a    r    u     D

    t    n    e     t    x     E     l    a     i     t    a    p     S

   y     t     i    v     i     t     i    s    n    e     S

   y     t     i     l     i     b    a    r    e    v    o    c    e     R

    t    r    o     h     S

   e    v     i    s    n    e     t    x     E

    h    g     i     H

   e     t    a    r    e     d    o     M

   e    c    n    a    c     i     f     i    n    g     i     S

   n    o     i     t    c    e    s     t    r    o    p    e     R

Three scenarios have been identified which could result in a spill of crude oil or diesel >10 tonnes: loss of containment from the drilling rig, total loss of inventory from the FPSO and total loss of inventory from the export tanker. A well blow out is highly unlikely given the low reservoir pressures present at Alma (see Section 7.1). Modelling shows that in the event of a worst case crude oil loss of 100,000m3 (87,000 tonnes) then there is a 1% chance of oil beaching along coastline of one of the countries bordering the North Sea. Trajectory modelling, presented in Section 7.3 and Appendix B, indicates that with a prevailing wind towards the UK coastline it will take approximately 200 hours for the spill to beach on the North Yorkshire coastline. Taking into consideration evaporation and dispersion approximately 86,393m 3 of crude oil could beach along the coast. With a prevailing wind towards the nearest international boundary a crude oil spill would first cross the cross the UK / Norway median line (within 5 hours) and then the Norway/Denmark median line after 31 hours. Taking into consideration evaporation and dispersion approximately 161,742m 3 of crude oil could beach along the Danish coast within 130 hours of the spill occurring.  Any components that settle to the seabed will be naturally biodegraded by microbes within one to two months. Elevated concentrations of hydrocarbons may be noticeable in sediments close to the discharge point after a large spill. Given the previous use of the area for oil and gas development, levels of hydrocarbon contamination are not expected to rise over existing historical levels. Crude oil that beaches has the potential to contaminate beach sediments. However, as a spill of this magnitude is extremely rare it is highly unlikely that there will be a residual impact during this development.

   y     l    e     k     i     l    n    r     U    o    y    r    w    i    n    e    o     V    L     M

REPORT REF: P1459BA_RN2525_REV0

A-35

   r    o    n     4     i  .     M     8

21/07/2011

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Determination of Potential Impact Project  Activity

 Aspect

EIA Potential Impact

   n    o     i     t    c    e     S D-2

Chemical / hydrocarbon release (< 1 tonne)

Diesel, crude or chemical spill (including OBMs)

Smothering

Consideration of Mitigation Measures Mitigation Measures

Identification of Residual Impact Considering Mitigation Measures

   e    c     d    n    o    a    o    i    c     t     i     h     f     i    r     i     l    e    e    v    n     k     i    e    i     L    S    S  As per Section A-1

Accidental spills of chemicals will be rapidly diluted and dispersed in the marine environment. The majority of spills are likely to be at the sea surface in water depths of approximately 80m (LAT). It is expected that spilt materials will not be in the water column for long enough or at concentrations that are likely to pose a significant toxic effect to the benthic community. Any spill at the seabed would come from a rupture in the 10" production pipeline or from the wellheads.  A spill of 0.1 tonnes occurring during construction is 24% for the Alma development. These spills are likely to be at the sea surface and would disperse within a couple of hours to a few days depending on the type of hydrocarbon spilt. Discharged materials will not be present within the water column for long enough or at concentrations that are likely to pose a significant toxic threat to marine ecology as a whole.

   y     l    r    e    o     k     i     l    w    i    n    o    n     U    L

In addition, a spill of this size could be easily avoided by these mobile animals.

    M

REPORT REF: P1459BA_RN2525_REV0

Residual Impact Assessment

A-42

    N

-

-

-

-

-

  -

    5  .     9

21/07/2011

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Determination of Potential Impact Project  Activity

 Aspect

EIA Potential Impact

   n    o     i     t    c    e     S G-4

Chemical / hydrocarbon release (>10 tonnes)

Diesel, crude or chemical spill (including OBMs)

Potential toxic effect

Consideration of Mitigation Measures Mitigation Measures

Identification of Residual Impact Considering Mitigation Measures

   e    c     d    n    o    a    o    i    c     t     i     h     f     i    r     i     l    e    e    v    n     k     i    e    i     L    S    S  As per Section A-3

Residual Impact Assessment Severity Factors     )     N     /     Y     (     ?     A     I     R

    d    o    o     h     i     l    e     k     i     L

   n    o     i     t    a    r    u     D

    t    n    e     t    x     E     l    a     i     t    a    p     S

   y     t     i    v     i     t     i    s    n    e     S

   y     t     i     l     i     b    a    r    e    v    o    c    e     R

   e    c    n    a    c     i     f     i    n    g     i     S

   n    o     i     t    c    e    s     t    r    o    p    e     R

There is the potential that marine mammals could be significantly affected if a large crude oil spill was to occur. Although the region surrounding the Alma development is not considered to be particularly important for marine mammals, pods and individuals have been observed throughout the year. Should a major release of crude oil occur, there is the potential that individuals could be affected. In addition should any oil reach the shoreline, haul out sites for pinnipeds may be impacted. Pinnipeds are particularly sensitive between October and January when they are on land pupping and again between February and March during their annual moult. Neonatal pups are particularly at risk from oil coming ashore. Cetaceans have smooth hairless skins over a thick layer of insulating blubber, so oil is unlikely to adhere persistently or cause a breakdown in insulation. Marine mammals must surface to breathe and they may inhale vapours given off the spilt oil and their eyes may be vulnerable to major pollution. Indirect effects may also be caused through contamination and depletion of food resources. Due to the transient nature of cetaceans, it is likely that individuals not in the immediate area of the spill when it occurs will avoid the area and it is possible that the number of individuals affected could be small. However, if a substantial number of a population where affected there could be knock on effects to breeding and the longterm viability of the population. Recovery rates of land based marine mammals such as seals could be longer particularly if a spill affected a breeding season.  All cetaceans are protected under the EC Habitats Directive as EPS and are classed as ecologically important. Although a major oil spill could have a significant impact on marine mammals the EIA concluded that the significance of the impact was minor based on the fact that a spill of this magnitude is extremely unlikely to occur.

    l    e     k     i     l    n    m     U    i    u    r    y     d    o    r    n    e    e     i     V    M    M

REPORT REF: P1459BA_RN2525_REV0

    l    e     k     i     l    n     U    y    r    e     V

A-43

   e    e     t    v    a     i    s    r    n    e    e     d     t    o    x     M     E

    h    g     i     H    y    r    e     V

   e     t    a    r    e     d    o     M

   r    o    n     5     i  .     M     9

21/07/2011

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Determination of Potential Impact Project  Activity

 Aspect

EIA Potential Impact

   n    o     i     t    c    e     S

Consideration of Mitigation Measures Mitigation Measures

Identification of Residual Impact Considering Mitigation Measures

   e    c     d    n    o    a    o    i    c     t     i     h     f     i    r     i     l    e    e    v    n     k     i    e    i     L    S    S

Residual Impact Assessment Severity Factors     )     N     /     Y     (     ?     A     I     R

    d    o    o     h     i     l    e     k     i     L

   n    o     i     t    a    r    u     D

    t    n    e     t    x     E     l    a     i     t    a    p     S

   y     t     i    v     i     t     i    s    n    e     S

   y     t     i     l     i     b    a    r    e    v    o    c    e     R

   e    c    n    a    c     i     f     i    n    g     i     S

   n    o     i     t    c    e    s     t    r    o    p    e     R

H - Marine protected sites and species H-2

H-3

Chemical / hydrocarbon release (< 1 tonne)

Chemical / hydrocarbon release (1-10 tonnes)

Diesel, crude or chemical spill (including OBMs) Diesel, crude or chemical spill (including OBMs)

REPORT REF: P1459BA_RN2525_REV0

Smothering of protected species Potential effects on integrity of a protected site Smothering of protected species Potential effects on integrity of a protected site

 As per Section A-1

There are no protected sites within 40km of the Alma development area and a spill of 10 tonnes)

Diesel, crude or chemical spill (including OBMs)

Damage to vessels

Consideration of Mitigation Measures Mitigation Measures

Identification of Residual Impact Considering Mitigation Measures

   e    c     d    n    o    a    o    i    c     t     i     h     f     i    r     i     l    e    e    v    n     k     i    e    i     L    S    S  As per Section A-3

Residual Impact Assessment Severity Factors     )     N     /     Y     (     ?     A     I     R

    d    o    o     h     i     l    e     k     i     L

    Y

   y     l    e     k     i     l    n     U    y    r    e V

   n    o     i     t    a    r    u     D

    t    n    e     t    x     E     l    a     i     t    a    p     S

   y     t     i    v     i     t     i    s    n    e     S

   y     t     i     l     i     b    a    r    e    v    o    c    e     R

   e    c    n    a    c     i     f     i    n    g     i     S

   n    o     i     t    c    e    s     t    r    o    p    e     R

    t    r    o     h     S

   e    v     i    s    n    e     t    x     E

   m    u     t     i    r     d    o    e     h     M     S

   r    o    n     i     M

    3  .     0     1

  -

    5  .     0     1

Modelling shows that in the event of a total loss of containment from the FPSO and/or export tanker there is the potential for an extensive area of the North Sea to be affected. However, an incident of this magnitude is unlikely. A well blow out is unlikely to occur due to low reservoir pressures.

Restricted access

If crude oil reaches the coastline, nearshore activities could be affected if restrictions are imposed to assist with the response operation. There may also be knock-on effects on the tourist industry if the spill beaches in substantial quantities. As the likelihood of such an event occurring is Very Unlikely, the EIA concluded that the residual impact is of minor significance.

   y     l    e     k     i     l    n    m     U    i    u    r    y     d    o    r    n    e    e     i     V    M    M

L - Archaeology L-1

Overboard loss of equipment or waste

Dropped objects

REPORT REF: P1459BA_RN2525_REV0

Physical damage to undiscovered archaeology

    l    e     k     i     l    n    r     U    o    y    r    w    i    n    e    o     V    L     M

Follow BMAPA protocol for reporting finds of archaeological significance

A-49

The surveys did not identify any sites of archaeological importance. However, there is the potential for undiscovered subsurface archaeological sites to be impacted by dropped objects. As the site has previously been subject to oil and gas activity it is assumed the potential for such sites to be present is low. Should a feature be identified, then mitigation measures will be revisited to ensure that the site is not disturbed.

    N

-

-

-

-

-

21/07/2011

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Appendix B Oil Spill Modelling

REPORT REF: P1459BA_RN2525_REV0

B-1

21/07/2011

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

B.1

Introduction This report is to support the Environmental Statement for the Alma Development Area (DECC ref no. D/4110/2011) and to meet the latest Department of Energy and Climate Change (DECC) guidance letter regarding hydrocarbon release assessment recently released to industry (23 December 2010). The guidance states that the ES assessment of potential impacts from hydrocarbon releases must be extended to match the scope of the recently amended oil pollution emergency plan (OPEP) guidelines.

B.2

Alma Field Development The Alma Field development is a small development located in the UKCS Blocks 30/24 and 30/25, in the Central North Sea (CNS). It lies in water depths of approximately 80m and is 274km east of the nearest landfall on the Northumberland coastline and 18.5km west of the UK/Norwegian international boundary (median line). Nearby fields include Orion and Auk (to the northwest) and Flora, Fife and Angus (to the south-east).  A total of eight wells are to be as part of the field development, six production wells (northern drill centre) and two water injection wells (southern drill centre). The coordinates for the wells are provided in Table B-1 below. Drilling will be conducted from a semi-submersible mobile drilling unit (MoDU). EnQuest have a number of rig options that they are considering. They currently have the Transocean John Shaw semi-submersible MoDU on contract and it is possible that this rig could be used at Alma. If it is not available, due to EnQuest’s other drilling commitments, a semi-submersible with a similar specification could be used. Table B-1: Project co-ordinates

Structure

Easting (E)

Northing (N)

Latitude (N)

Longitude (E)

Uisge Gorm FPSO

488 250

6 227 000

56° 11' 16.16"

02° 48' 38.45"

Northern drill centre (production wells)

485 469

6 228 541

56° 12' 05.72"

02° 45' 56.84"

Southern drill centre (water-injection wells) Datum: WGS84

485 858

6 224 891

56° 10' 07.71"

02° 46' 20.12"

The two drill centres will be tied-back to the Uisge Gorm floating, production, storage and offloading (FPSO) vessel. Two new 3km, 10-inch buried production flowlines and one 2.5km 10-inch buried water-injection flowline will be installed.  A chemical umbilical will also be installed out to both drill centres and a power cable will be laid out to the production drill centre. A shuttle tanker will visit the FPSO once every two weeks to offload crude oil via a loading hose and tanker mooring system. EnQuest will submit an OPEP to the DECC Offshore Inspectorate for approval to cover the drilling and production activities on the field. The OPEP will comply with the requirements of The Offshore Installations (Emergency Pollution Control) Regulations 2002 and The Merchant Shipping (Oil Pollution Preparedness, Response Co-operation Convention) Regulations 1998 and take into consideration recent revised guidance from the DECC following the Gulf of Mexico Macondo incident.

REPORT REF: P1459BA_RN2525_REV0

B-2

21/07/2011

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

B.3

Worst Case Oil Spill Modelling Three scenarios have been identified within the project scope as potential sources for a major spill of hydrocarbons: Loss of diesel inventory from the FPSO and tanker through collision – 2,400m3 (2,016 tonnes) from the FPSO and 3,430m3 (2,881 tonnes) from the export tanker Loss of crude oil inventory from the FPSO and tanker through collision –  A maximum of 94,500m3 (81,0901 tonnes) from the FPSO and a maximum of 100,000m3  (87,000 tonnes) from the export tanker ( note: neither vessel will be full at the same time) Loss of diesel inventory from the drilling rig – 1,665m 3 (1,399 tonnes) The most recent UK guidance on oil pollution emergency response requires Operators to model a loss of well control (blow out), as this although an extremely rare occurrence in the UK is considered to be the worst case volume of crude oil that could be spilt from a development. After consultation with the DECC Offshore Inspectorate this modelling has not be run for the Alma development due to the low reservoir pressure. From the very start of field life, reservoir pressure is such that ESPs will be required to pump crude oil out of the reservoir. In the event that well control is lost the wells will effectively selfkill. Instead, the worst case crude spill was considered to be if the FPSO and export tanker collided, with a total loss of containment. During production from Alma the worst case scenario is for full loss of containment from both the FPSO and export tanker due to collision (with each other). If this were to happen, a maximum of 5,830m3 (4,897 tonnes) of diesel (from FPSO and tanker combined) and 100,000m 3 (87,000 tonnes) of crude oil would be released instantaneously. The 100,000m 3  of crude oil represents the maximum (larger) capacity of the export tanker as neither vessel will be full at the same time. The diesel volume is the combined inventory of both vessels. Modelling was not undertaken for a diesel spill from the drilling rig as it was a smaller volume than that of the combined FPSO and export tanker volume. Therefore it can be inferred that the extent of the spill would be less. Oil Spill Response (OSR) was commissioned to undertake oil spill modelling of these scenarios using OSIS 5.0 software (OSR 2011). The Oil Spill Information System (OSIS), developed by BMT Cordah Ltd, is an oil spill model that predicts the movement of oil on the water surface and the distribution of oil in the marine environment. It is a fully validated and calibrated oil spill model based upon extensive research conducted by Warren Spring Laboratories and subsequently AEA Technology plc. The weathering model within OSIS has been validated against controlled actual spills at sea and real spill events supported with laboratory calibration. The model has a number of limitations that should be considered when interpreting the results: Modelling results are for guidance purposes only and response strategies should not be based solely on modelling results alone. The resolution / quality of tidal and oceanic current data varies between regions and models. As with any other model, results are dependent on the quality of the environmental parameters and scenario inputs used.

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The properties of the oil in the model’s database may not precisely match those of the product spilled. If the same scenario was conducted in another oil spill modelling programme, with identical parameters and inputs, the results may show a degree of variance. This is expected as the different fate and weathering models have been developed and programmed independently. In addition the following assumptions were made when commissioning the models:  A ‘worst case’ air temperature of -6°C and sea temperature of 6°C were used as representative of temperatures in January to depict the fate of the spilled oil in its most viscous and persistent form. Wind data was taken from the Met Office European model (56.0°N 3.14°E Jan 1998 - Nov 2008). The January wind rose selected as the closest representative example was compiled from a historical data set sourced by the Admiralty from the UK Met Office and covers a period between 1998 and 2008. The principal tidal current data used was taken http://www.visitmyharbour.com/articles/article.asp?arturn=1314.

from

The oils specified for modelling were marine diesel and Ardmore crude.  Ardmore crude is not in the OSIS oil database but oil matching was undertaken to find suitable substitute oil within the OSIS database. Auk has a similar density (API 38.16), specific gravity (0.834) and geographical location to the Ardmore crude (API 38 and SG 0.8329) and so was selected as the most appropriate oil.  As the worst case spill was based on an instantaneous release, the model was run for a period of 417 days, which for planning purposes is believed to be more than sufficient. It is likely that beaching will occur within this period for the worst case scenarios in the UKCS (depending upon the oil type, meteorological conditions and location of the spill release point).

B.4

Spill Scenarios and Modelling Results In accordance with the DECC guidelines on oil spill modelling for OPEPs, the scenarios were modelled using two types of models: Stochastic - A stochastic model, also known as a probability model shows the probability of where an oil spill may impact for defined periods of time for a range of prevailing wind directions. The model uses historical wind data to run a series of trajectories for the various wind directions. It then combines the results to produce an overall illustration of the probability of where oil might travel to in the defined period of time. This type of modelling is an important tool for determining the areas of coastline that could potentially be affected by a spill and therefore the best locations to place oil spill response equipment. However, this type of diagram is typically the most misunderstood part of an Environmental Statement or Oil Pollution Emergency Plan. The most important thing to note is that it does not illustrate the extent of an oil spill, should a collision occur. Trajectory - A trajectory or deterministic model are used to predict the route of an oil slick over time and under certain metocean conditions. UK legislation requires two trajectory models are undertaken for each spill scenario

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investigated by the oil and gas industry; one trajectory using a 30 knot wind blowing towards the nearest stretch of UK coastline; and one trajectory using a 30 knot wind blowing towards the closest international boundary. For the Alma development two stochastic and four trajectory models were commissioned. The scenarios and volumes modelled are presented in Table B-1 below. Table B-2 presents a summary of the fates of the spills as illustrated in Figures B-1 to B-6. For the trajectory models, the red lines show the direction of the leading edge of the spill where as the black dots show the areas which the oil is likely to spread to. Table B-2: Spill scenarios mo delled Scenario

Hydrocarbon

Type of spill

Crude oil

Loss of entire inventory e.g. during a collision

1 2 3 4 5 Diesel 6

Loss of entire inventory

Quantity (m3)

100,000 (Instantaneous)

5,830 (Instantaneous)

Model run type

Conditions

Stochastic

N/A

Trajectory

30 knot onshore wind (towards UK) 30 knot offshore wind (towards nearest international boundary e.g. UK/Norway) N/A 30 knot onshore wind (towards UK) 30 knot offshore wind (towards nearest international boundary e.g. UK/Norway)

Trajectory Stochastic Trajectory Trajectory

Table B-3: Modelling results Scenario

Model run type

1

Stochastic

2

Trajectory towards UK

3

Trajectory towards closest international boundary

4

Stochastic

Fate of spill , as modelled Figure B-1 Depending on the prevailing wind conditions at the time of the spill, there is a1% chance of oil beaching along the coastlines of one of the countries that border the North Sea. Modelling indicates that the spill will have naturally dispersed within the water column or beached within 417 days. There are numerous protected sites that could be affected by a spill of this size (see Section 9.6 for assessment). Figure B-2 There is the potential that crude oil will beach on the north Yorkshire coastline within 8 days and 10 hours of the incident. Modelling indicates that approximately 86,393m3 would beach, 38,972m3 will evaporate and 43,750m3 will disperse naturally. On this trajectory possible beaching locations are within the Teesland and Cleveland Coast Ramsar site and the Beast Cliff - Whitby (Robin Hood’s Bay) SAC protected area. Figures B-3 There is the potential that the spill will cross the UK/Norway international boundary (median line) within 5 hours of the incident. On this trajectory the spill path will continue and cross the Norway/Denmark median line within 31 hours of the incident. Modelling indicates that approximately 161,742m3 (emulsified) of crude oil could beach on the Danish coast after 5 days and 12 hours. It is estimated that approximately 35,166m3 will evaporate and 32,486m3 will disperse naturally within the water column. On this trajectory possible beaching locations are within numerous protected areas along the Danish and Norwegian coastlines (see Figure 8-3). Figures B-4 Modelling indicates that it is unlikely that the spill will beach on the coastline. The leading edge of the spill travels 6 miles from the Alma development after 10 hours. This is still 171 miles from shore. It is estimated that 2,086m3 will evaporate and 3,744m3 will disperse naturally in the water column (none will beach).

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Scenario

Model run type

5

Trajectory towards UK

6

Trajectory towards closest international boundary

Fate of spill , as modelled Figures B-5 Modelling indicates that on this trajectory it is unlikely that the spill will beach on the UK coastline. The leading edge of the spill travels 6 miles from the Alma development after 10 hours. This is still 171 miles from shore. It is estimated that 2,086m3 will evaporate and 3,744m3 will disperse naturally in the water column (none will beach). Figures B-6 Modelling indicates that on this trajectory it is unlikely that the spill will beach on a coastline. The leading edge of spill travels 20 miles from the Alma development after 10 hours and will cross the UK/Norway median line within 6 hours. It is estimated that 2,235m3 will evaporate and 3,595m3 will disperse naturally (none will beach).

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Figure B-2- Scenario 1-Worst case crude oil spill of 100,000m3 Key for wind rose

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B-7

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Figure B-3-Scenario 2- Worse case crude oil spill trajectory with 30 knot wind towards the UK

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B-8

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Figure B-4-Scenario 3- Worse case crude oil spill trajectory with 30 knot win d towards the clo sest international boundary (and Denmark)

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B-9

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Figure B-5- Scenario 4- Instantaneous diesel spill of 5,830m3 Key for wind rose

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B-10

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Figure B-6- Scenario 5- Worst case diesel sp ill t rajectory with 30 knot wind towards the UK

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B-11

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Figure B-7- Scenario 6- Worst c ase diesel spi ll trajectory with 30 knot wind to wards the closest international boundary

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B.5

Environmental Impact Assessment

B.5.1

Seabirds  A diesel spill will rapidly evaporate on release and will naturally disperse in the high energy offshore environment. Modelling, presented in Figures B-4, B-5 and B-6, indicates that a diesel spill of 5,830m 3 i.e., from a combined loss of inventory from the FPSO and export tanker, will naturally disperse and evaporate within 10 hours. As such, it is not considered that diesel will pose a significant threat to seabirds. There is the potential that seabirds could be significantly affected if a large crude oil spill was to occur. The worst case scenarios modelled i.e., loss of containment from both the FPSO and export tanker due to collision, has the potential to affect a large area of the marine environment and depending on the prevailing wind condition at the time beach on the coastline of one of the countries bordering the North Sea. These results of the modelling area provided in Table B-2 above.  A spill of the magnitude modelled above is likely to significantly impact populations of seabirds. Seabirds that spend majority of the time on sea surface are most vulnerable as birds can be smothered by oil or their feathers can become contaminated with hydrocarbons, which in turn may be ingested. Seabird vulnerability to hydrocarbon pollution is highest in January and October.  As the drilling rig will be on-site from December 2011 until January 2013, there will be overlap with the sensitive periods for seabirds. In addition, the FPSO will offload crude oil every two weeks throughout the year and therefore at some point each year operations will overlap with the sensitive periods identified. In the event of a spill occurring, the required intervention response will be implemented to minimise the risk of smothering and species injury.

B.5.2

Marine Mammals There is the potential that marine mammals could be significantly affected if a large crude oil spill was to occur. Although the region surrounding the  Alma development is not considered to be particularly important for marine mammals, pods and individuals have been observed throughout the year. Should a major release of crude oil occur, there is the potential that individuals could be affected. In addition should any oil reach the shoreline, haul-out sites for pinnipeds may be impacted. Pinnipeds are particularly sensitive between October and January when they are on land pupping and again between February and March during their annual moult. Neonatal pups are particularly at risk from oil coming ashore. Cetaceans have smooth hairless skins over a thick layer of insulating blubber, so oil is unlikely to adhere persistently or cause a breakdown in insulation. Marine mammals must surface to breathe and they may inhale vapours given off the spilt oil and their eyes may be vulnerable to major pollution. Indirect effects may also be caused through contamination and depletion of food resources.

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Due to the transient nature of cetaceans, it is likely that individuals not in the immediate area of the spill when it occurs will avoid the area and it is possible that the number of individuals affected could be small. However, if a substantial number of a population where affected there could be knock on effects to breeding and the long-term viability of the population. Recovery rates of land based marine mammals such as seals could be longer particularly if a spill affected a breeding season.

B.5.3

Protected Sites There is the potential that protected sites and species could be significantly affected if a large crude oil spill was to occur.  Although there are no designated protected sites within 40km of the Alma field a major crude oil spill could beach on the coastline as summarised in Table B-2 and Figure B-1. Modelling indicates that the probability of the spill beaching is 1%. There are numerous coastal and marine protected sites designated along the coast of the North Sea that could be affected. These are illustrated in Figure 8-3. Should a spill occur that could potentially affect a protected area an intervention response would be required.

B.6

References OSR (2011). Oil Spill Modelling for Knightsbridge Field Development. Prepared for Metoc Ltd. Project Number 4558.

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Appendix C Summary of chemicals

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C-1

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Please note:  All chemicals provided in the following tables are for one well (five sections) and one well tie-in only. Full chemical requirements will be confirmed in the relevant PON15B or PON15C chemical permit application to be submitted to the DECC at least 28 days before operations start. Chemicals to be used on the FPSO had not been confirmed at the time of ES submission but will be included in a PON15D chemical permit. This will be available for public review approximately 2 months prior to production operations commencing.

C.1

Drilling Chemicals

C.1.1

36" Section

Chemical Name

HQ

Caustic Soda

E

DEFOAM NS

Gold

Drispac® Plus Superlo ™ Polymer

E

DUO-TEC

Estimated Use (tonnes)

Estimated Discharge (tonnes)

0.60

0.60

SUB

4.00

4.00

PLO

6.39

6.39

Gold

3.00

3.00

DUO-VIS

Gold

3.00

3.00

GUAR GUM

E

PLO

20.00

20.00

Lime

E

PLO

1.00

1.00

M-I BAR (All Grades)

E

PLO

210.00

210.00

M-I Gel

E

PLO

72.00

72.00

Mica

E

PLO

2.00

2.00

Nutshells (All Grades)

E

PLO

2.00

2.00

POLYPAC (All Grades)

E

PLO

4.10

4.10

SAFE-CIDE

Gold

1.10

1.10

SAFE-SCAV HSB

Silver

1.00

1.00

Soda Ash

E

PLO

0.60

0.60

Sodium Bicarbonate

E

PLO

2.00

2.00

Chemical Name

HQ

Chemical Label

Estimated Use (tonnes)

Estimated Discharge (tonnes)

Caustic Soda

E

0.60

0.60

DEFOAM NS

Gold

SUB

4.00

4.00

Drispac® Plus Superlo ™ Polymer

E

PLO

6.39

6.39

DUO-TEC

Gold

3.00

3.00

DUO-VIS

Gold

3.00

3.00

GUAR GUM

E

PLO

20.00

20.00

Lime

E

PLO

1.00

1.00

M-I BAR (All Grades)

E

PLO

210.00

210.00

M-I Gel

E

PLO

72.00

72.00

Mica

E

PLO

2.00

2.00

Nutshells (All Grades)

E

PLO

2.00

2.00

C.1.2

Chemical Label

26" Section

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C-2

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Chemical Name

HQ

Chemical Label

Estimated Use (tonnes)

Estimated Discharge (tonnes)

POLYPAC (All Grades)

E

PLO

4.10

4.10

SAFE-CIDE

Gold

1.10

1.10

SAFE-SCAV HSB

Silver

1.00

1.00

Soda Ash

E

PLO

0.60

0.60

Sodium Bicarbonate

E

PLO

2.00

2.00

Chemical Label

Estimated Use (tonnes)

Estimated Discharge (tonnes)

5.40

5.40

C.1.3

17 ½" Section

Chemical Name

HQ

CAUSTIC SODA

E

Citric Acid

E

PLO

4.00

4.00

DEFOAM NS

Gold

SUB

4.00

4.00

DRILLING STARCH

E

PLO

3.00

3.00

Drispac® Plus Superlo ™ Polymer

E

PLO

19.17

19.17

DUO-TEC

Gold

7.75

7.75

DUO-VIS

Gold

4.00

4.00

Dynared ™ Seepage Control Fiber

E

8.00

8.00

GLYDRIL MC

Gold

20.00

20.00

G-SEAL PLUS

E

PLO

6.00

6.00

GUAR GUM

E

PLO

19.00

19.00

KWIK-SEAL (All Grades)

E

6.00

6.00

Lime

E

PLO

1.00

1.00

M-I BAR (All Grades)

E

PLO

450.00

450.00

M-I GEL

E

PLO

460.00

460.00

Nutshells (All Grades)

E

PLO

2.00

2.00

POLYPAC (All Grades)

E

PLO

8.15

8.15

POTASSIUM CHLORIDE

E

PLO

6.00

6.00

Potassium Chloride brine

E

PLO

20.00

20.00

SAFE-CARB (All Grades)

E

PLO

15.00

15.00

SAFE-CIDE

Gold

1.10

1.10

SAFE-SCAV HSB

Silver

1.00

1.00

SAPP

E

PLO

2.00

2.00

SODA ASH

E

PLO

5.40

5.40

Sodium Bicarbonate

E

PLO

4.00

4.00

REPORT REF: P1459BA_RN2525_REV0

PLO

C-3

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C.1.4

12 ¼" Section

Chemical Name

HQ

BENTONE 920

E

Calcium Chloride (All Grades)

E

CAUSTIC SODA

E

Citric Acid

E

DF1

Estimated Use (tonnes)

Estimated Discharge (tonnes)

18.86

0.00

24.36

0.00

1.00

0.00

4.00

0.00

E

500.39

0.00

DUO-TEC

Gold

3.00

0.00

DUO-VIS

Gold

3.00

0.00

Dynared ™ Seepage Control Fiber

E

PLO

6.00

0.00

ECOTROL RD

E

SUB

11.07

0.00

EMI-1017

C

18.15

0.00

FORM-A-SQUEEZE

E

PLO

8.00

0.00

G-Seal

E

PLO

16.00

0.00

G-SEAL PLUS

E

PLO

16.00

0.00

KOPLUS LO

Gold

8.00

0.00

KWIK-SEAL (All Grades)

E

6.00

0.00

LIME

E

PLO

28.00

0.00

M-I BAR (All Grades)

E

PLO

646.60

0.00

Mica

E

PLO

6.00

0.00

NUTSHELLS (All Grades)

E

PLO

6.00

0.00

Potassium Chloride

E

PLO

5.00

0.00

SAFECARB (All Grades)

E

PLO

50.00

0.00

SAFES-CAV HSB

Gold

1.00

0.00

SAFE-SURF E

Gold

SUB

4.00

0.00

SAFE-SURF NS

Gold

SUB

6.00

0.00

SAPP

E

PLO

2.00

0.00

Sodium Bicarbonate

E

PLO

4.00

0.00

SPERSENE CFI

E

PLO

5.00

0.00

SUPER SWEEP

Gold

SUB

1.00

0.00

SWA EH

A

SUB

4.00

0.00

TRUVIS

E

17.34

0.00

Ven-chem 222

E

16.00

0.00

VERSACLEAN CBE

B

SUB

18.00

0.00

Versaclean FL

B

SUB

18.00

0.00

Versaclean VB

B

SUB

18.00

0.00

VERSAGEL HT

E

30.00

0.00

VERSATROL

E

SUB

17.58

0.00

VERSATROL HT

D

SUB

16.00

0.00

VERSATROL M

E

SUB

9.00

0.00

VG-SUPREME

E

18.09

0.00

REPORT REF: P1459BA_RN2525_REV0

Chemical Label PLO PLO

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ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

C.1.5

8 ½" Section

Chemical Name

HQ

BENTONE 920

E

Calcium Chloride (All Grades)

E

CAUSTIC SODA

E

Citric Acid

E

DF1

Estimated Use (tonnes)

Estimated Discharge (tonnes)

18.86

0.00

26.74

0.00

1.00

0.00

4.00

0.00

E

818.27

0.00

DUO-TEC

Gold

3.00

0.00

DUO-VIS

Gold

3.00

0.00

Dynared ™ Seepage Control Fiber

E

PLO

6.00

0.00

ECOTROL RD

E

SUB

16.88

0.00

EMI-1017

C

30.92

0.00

FORM-A-SQUEEZE

E

PLO

8.00

0.00

G-Seal

E

PLO

16.00

0.00

G-SEAL PLUS

E

PLO

16.00

0.00

KOPLUS LO

Gold

8.00

0.00

KWIK-SEAL (All Grades)

E

6.00

0.00

Lime

E

PLO

27.00

0.00

M-I BAR (All Grades)

E

PLO

906.45

0.00

Mica

E

PLO

6.00

0.00

NUTSHELLS (All Grades)

E

PLO

6.00

0.00

Potassium Chloride

E

PLO

5.00

0.00

SAFECARB (All Grades)

E

PLO

80.00

0.00

SAFE-SCAV HSB

Gold

1.00

0.00

SAFE-SURF E

Gold

SUB

4.00

0.00

SAFE-SURF NS

Gold

SUB

6.00

0.00

SAPP

E

PLO

2.00

0.00

Sodium Bicarbonate

E

PLO

4.00

0.00

SPERSENE CFI

E

PLO

5.00

0.00

SWA EH

A

SUB

4.00

0.00

TRUVIS

E

21.06

0.00

Ven-chem 222

E

16.00

0.00

VERSACLEAN CBE

B

SUB

22.00

0.00

Versaclean FL

B

SUB

20.20

0.00

Versaclean VB

B

SUB

20.20

0.00

VERSAGEL HT

E

26.58

0.00

VERSATROL

E

SUB

15.86

0.00

VERSATROL HT

D

SUB

25.50

0.00

VERSATROL M

E

SUB

21.50

0.00

VG-SUPREME

E

21.56

0.00

REPORT REF: P1459BA_RN2525_REV0

Chemical Label PLO PLO

C-5

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ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

C.2

Cementing Chemicals

Chemical Name

HQ

Chemical Label

Estimated Use (tonnes)

Estimated Discharge (tonnes)

Barite

E

PLO

408.16

40.816

Calcium Chloride - Liquid

E

PLO

15.42

1.542

CEMENT - CLASS G

E

PLO

948

94.8

CFR-8L

Gold

8.52

0.852

ECONOLITE LIQUID

E

30.67

3.067

Fluorodye UC

Gold

0.12

0.012

GASSTOP LIQUID

Gold

8.68

0.868

HALAD-300L NS

Gold

22.24

2.224

HR-25L

Gold

4.67

0.467

HR-4L

E

PLO

14.12

1.412

HR-601L NS

E

PLO

4.61

0.461

MUSOL SOLVENT

Gold

11.04

1.104

NF-6

Gold

0.84

0.084

SA-533

Gold

2.04

0.204

SCR-100L

Gold

10.71

1.071

SCR-500 L

Gold

15.51

1.551

SEM 8

Gold

25.38

2.538

SILICALITE LIQUID

E

PLO

46.08

4.608

SSA-1

E

PLO

333

33.3

TUNED LIGHT XL

E

240

24

TUNED SPACER E+

E

PLO

20.4

2.04

WellLife 734

E

PLO

1.36

0.136

C.3

PLO SUB

SUB SUB

Completion and Other Chemicals

Chemical Name

HQ

Chemical Label

Estimated Use (tonnes)

Estimated Discharge (tonnes)

 Aqueous Degreaser 2000

Gold

SUB

12.00

12.00

Bestolife 2010 NM ULTRA (version 1)

C

O-VII SUB

1.50

0.15

Bestolife 3010 ULTRA (version 1)

E

2.20

0.22

Calcium Bromide Brine

E

PLO

2437.96

2437.96

Calcium Chloride Brine

E

PLO

1991.58

1991.58

Caustic Soda

E

2.00

2.00

Celatom Diatomite-All FW Grades

E

3.41

0.00

Celatom Perlite-All Grades

E

0.29

0.00

Cesium Formate Brine (unbuffered)

Gold

12.50

12.50

CLEENOL OD HEAVY DUTY

Gold

34.00

34.00

DEFOAM NS

Gold

0.40

0.40

DF1

E

763.14

0.00

DI BALANCE

E

2.00

0.00

REPORT REF: P1459BA_RN2525_REV0

PLO

SUB PLO

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ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Chemical Name

HQ

Chemical Label

Estimated Use (tonnes)

Estimated Discharge (tonnes)

DI TROL

E

PLO

4.00

0.00

DUAL-FLO

Gold

2.00

2.00

DUO-TEC

Gold

4.00

4.00

DUO-VIS

Gold

4.00

4.00

EB-8035

Gold

2.00

2.00

EMI-1705

C

1.00

0.00

EMR-961

Silver

SUB

10.00

0.00

EZEFLO* Surfactant B197

Gold

SUB

1.00

1.00

FLO-VIS PLUS

Gold

1.00

1.00

HEC

E

PLO

2.00

2.00

JET-LUBE® API-MODIFIED

C

Cu Pb Zn SUB

0.80

0.08

JET-LUBE® NCS-30™ ECF

E

3.00

0.30

JET-LUBE®SEAL-GUARD™ECF

E

0.50

0.05

MAGNESIUM OXIDE

E

PLO

1.00

1.00

M-I BAR (All Grades)

E

PLO

300.00

300.00

Monoethylene Glycol

E

PLO

10.00

10.00

Potassium Formate Brine

E

PLO

115.40

115.40

SAFE COR 220X

Gold

16.00

16.00

SAFE-CARB (ALL GRADES)

E

12.00

12.00

SAFE-CIDE

Gold

2.00

2.00

Safe-Cor HT

C

0.82

0.82

SAFE-SCAV CA

Gold

8.00

8.00

SAFE-SCAV HSB

Silver

2.00

2.00

SAFE-SCAV NA

E

PLO

8.00

8.00

SAFE-SURF E

Gold

SUB

8.00

8.00

SAFE-SURF NS

Gold

SUB

18.00

18.00

SI-414N

Gold

3.00

3.00

Sodium Chloride Brine

E

1991.58

1991.58

Stack-Magic ECO-F v2

D

12.00

12.00

System Cleaner G

D

0.04

0.04

REPORT REF: P1459BA_RN2525_REV0

SUB

PLO

PLO

C-7

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ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

C.4

Pipeline Chemicals

Chemic al Name

HQ

Castrol Transaqua HT2

Chemical Label

Estimated Use (kgs)

Estimated Discharge (kgs)

D

0

101.6

DYESTICK RX-9034A

Gold

0.4

0.25

MEG

E

445.2

1227.2

RX-9022

Gold

23.6

17.8

RX-5227

Gold

103.4

81.4

PLO

Note:   Chemical discharge exceeds chemical use as some sections of spool piece or chemical umbilical are pre-filled onshore.

REPORT REF: P1459BA_RN2525_REV0

C-8

21/07/2011

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT=

Appendix D JNCC Risk Assessment Flow Charts

REPORT REF: P1459BA_RN2525_REV0

D-1

21/07/2011

ENQUEST HEATHER LIMITED  ALMA FIELD DEVELOPMENT

Figure D-1: Risk assessment flow chart for deliberate injury

Source: JNCC (2009)

Figure D-2: Risk assessment flow c hart for non-trivi al disturbance

Source: JNCC (2009)

REPORT REF: P1459BA_RN2525_REV0

D-2

21/07/2011