Fram 2 Field Development Environmental Statement - Shell

Fram 2 Field Development Environmental Statement D/4198/2017

Shearwater ‘A’ Platform Shearwater ‘C’ PUQ H

33km P1

P2

STARLING

P3

15km G5

G3

FRAM

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT STANDARD INFORMATION SHEET

STANDARD INFORMATION SHEET Project Name Development Location Licence No. Project Reference Number Type of Project

Undertaker

Fram 2 Field Development Fram Field: Block 29/3a, 29/4c, 29/8a, 29/9c Shearwater Platform: Block 22/30b 29/3c, 29/8a P.012 29/4c, 29/9c P.1664 D/4198/2017 New field development Shell U.K. Limited 1 Altens Farm Road Nigg Aberdeen AB12 3FY P.012:

Licensees/Owners

Short Description

Key Dates Significant Environmental Effects Identified

P.1664:

Shell U.K. Limited (operator) 28% 50% Esso Exploration and Production UK Limited 72% 50% Shell propose to develop Fram as a gas and gas condensate field with two horizontal wells in the Drill Centre East (DCE) area. Produced fluids will be transported via a new flowline to the existing Starling manifold (approximately 15 km away), comingled with Starling production fluids and further transported via existing infrastructure to the Shearwater platform 33 km away. Fluids from the Shearwater platform are exported through the Shearwater Elgin Area Line (SEAL) and Forties Pipeline System (FPS) pipelines. No modifications are required to the Shearwater topsides hydrocarbon processing equipment. Minor topsides changes include an upgrade to the control system and modifications of the chemical injection system. Drilling: Q1 2019 – Q1 2020 Production: Q2 2020 No significant impacts identified after implementation of mitigation measures.

Statement Prepared by: Genesis Oil & Gas Consultants Limited and Shell UK Limited Company Genesis Oil & Gas Consultants Ltd

Shell UK Limited

Job Title Principle Environmental Engineer Environmental Specialist

Consultant/GIS

Senior Environmental Specialist/Impact Assessment and Biodiversity SME

Relevant Qualifications/Experience 20 years’ experience working in environmental science. 6 years working in oil & gas. 13 years’ experience working in environment/oil & gas Over 20 years’ experience working in environmental management and impact assessment in oil and gas.

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FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT STANDARD INFORMATION SHEET

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FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON-TECHNICAL SUMMARY

CONTENTS Standard Information Sheet............................................................................................

i

Non-Technical Summary................................................................................................

vii

Abbreviations ...............................................................................................................

xxii

Glossary .......................................................................................................................

xvi

1. Introduction ..................................................................................................................

1-1

1.1 Field History and Project Purpose ...................................................................................

1-1

1.2 Scope of Environmental Statement ..................................................................................

1-2

1.3 Legislative Overview ......................................................................................................

1-2

1.4 Shell UK Environmental Management System ..................................................................

1-4

1.5 Environmentally Critical Elements ...................................................................................

1-5

1.6 Consultation .................................................................................................................

1-5

1.7 Additional Studies .........................................................................................................

1-5

2. Project Description ........................................................................................................

2-1

2.1 Development Overview ..................................................................................................

2-1

2.2 Licences ........................................................................................................................

2-3

2.3 Schedule ......................................................................................................................

2-3

2.4 Field and Reservoir Characteristics .................................................................................

2-3

2.5 Production Profiles .........................................................................................................

2-5

2.6 Analysis of Alternatives..................................................................................................

2-9

2.7 Wells and Drilling ......................................................................................................... 2-13 2.8 Pipelines and Subsea Infrastructure ................................................................................. 2-21 2.9 Starling Subsea Facilities Overview ................................................................................ 2-29 2.10 Shearwater Process Facilities Overview ........................................................................... 2-28 2.11 Possible Future Expansion or Modification....................................................................... 2-33 2.12 Decommissioning .......................................................................................................... 2-34 3. Baseline Environment.....................................................................................................

3-1

3.1 Introduction ..................................................................................................................

3-1

3.2 Environmental Baseline Surveys ......................................................................................

3-1

3.3 Physical Environment .....................................................................................................

3-3

3.4 Biological Environment .................................................................................................. 3-18 3.5 Conservation ................................................................................................................ 3-33 3.6 Socio-Economic Environment ......................................................................................... 3-51 4. Impact Assessment Approach .........................................................................................

4-1

4.1 Impact Identification and Aspects ...................................................................................

4-1

4.2 Assessment of Impact Significance ..................................................................................

4-3

5. Physical Presence ..........................................................................................................

5-1

5.1 Presence of Vessels ........................................................................................................

5-1 iii

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON TECHNICAL SUMMARY

5.2 Presence of Subsea Infrastructure....................................................................................

5-3

6. Emissions to Air ............................................................................................................

6-1

6.1 Drilling and Well Clean-Up............................................................................................

6-1

6.2 Installation ....................................................................................................................

6-2

6.3 Production ....................................................................................................................

6-3

6.4 Decommissioning Phase.................................................................................................

6-5

6.5 Mitigation Measure and Controls ...................................................................................

6-6

6.6 Cumulative and Transboundary Effects............................................................................

6-6

7. Discharges to Sea .........................................................................................................

7-1

7.1 Drilling Phase ...............................................................................................................

7-1

7.2 Installation and Commissioning ......................................................................................

7-2

7.3 Production Phase...........................................................................................................

7-3

7.4 Decommissioning Phase................................................................................................. 7-12 7.5 Mitigation Measures, Safeguarding and Controls ............................................................ 7-13 7.6 Cumulative and Transboundary Effects............................................................................ 7-13 8. Seabed Disturbance ......................................................................................................

8-1

8.1 Drilling Phase ...............................................................................................................

8-1

8.2 Installation Phase ..........................................................................................................

8-3

8.3 Seabed Disturbance and Impact Assessment ...................................................................

8-4

8.4 Decommissioning Phase................................................................................................. 8-13 8.5 Mitigation Measures ...................................................................................................... 8-13 8.6 Cumulative and Transboundary Impacts.......................................................................... 8-14 9. Underwater Sound ........................................................................................................

9-1

9.1 Sound Sources Associated with the Fram 2 Field Development..........................................

9-1

9.2 Impact Assessment Methodology ....................................................................................

9-2

9.3 Assessment of Impacts ...................................................................................................

9-4

9.4 Decommissioning Phase.................................................................................................

9-9

9.5 Mitigation Measures ...................................................................................................... 9-10 9.6 Cumulative and Transboundary Impacts.......................................................................... 9-10 10. Waste Management ...................................................................................................... 10-1 10.1 Waste Generation ......................................................................................................... 10-1 10.2 Waste Management ...................................................................................................... 10-4 10.3 Decommissioning .......................................................................................................... 10-5 10.4 Waste Mitigation Measures ........................................................................................... 10-5 11. Accidental Events .......................................................................................................... 11-1 11.1 Overview of Potential Hydrocarbon Releases ................................................................... 11-1 11.2 Spill Modelling .............................................................................................................. 11-4 11.3 Potential Impacts ........................................................................................................... 11-4 iv


11.4 Major Environmental Incidents .......................................................................................11-19 11.5 Susceptibility to Natural Disasters ...................................................................................11-19 11.6 Decomissioning Phase ...................................................................................................11-20 11.7 Mitigation Measures ......................................................................................................11-20 11.8 Cumulative and Transboundary Effects............................................................................11-21 12. Environmental and Social Management Plan (Commitment Register) ................................. 12-1 12.1 Commitments Register.................................................................................................... 12-1 12.2 Monitoring ................................................................................................................... 12-1 13. Conclusions .................................................................................................................. 13-1 13.1 Environmental Impact Assessment: Requirements and Purpose .......................................... 13-1 13.2 Environmental Effects ..................................................................................................... 13-1 13.3 Overall Conclusion ........................................................................................................ 13-2 14. References .................................................................................................................... 14-1 Appendix A – Scottish Marine Plan ................................................................................ A-1 A.1 Scotland’s National Marine Plan .................................................................................... A-1 A.2 Marine Strategy Framework Directive ............................................................................. A-4 A.3 Oil and Gas Marine Planning Process ............................................................................ A-6 Appendix B – Consultation Register ................................................................................

B-1

Appendix C – EIA Matrix............................................................................................... C-1

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NON-TECHNICAL SUMMARY BACKGROUND Shell UK Limited (Shell) is planning to develop the Fram hydrocarbon field located in blocks 29/3c, 29/8a, 29/4c and 29/9c of the United Kingdom Continental Shelf (UKCS) approximately 221 km east of Aberdeen and 50 km from the UK/Norway median line (Figure 1).

Figure 1 Location of the Fram Field. Following initial appraisal in 2009, Fram was planned to be developed as an oil and gas field via eight subsea production wells at two drilling centres. The drill centres were to be connected by a flowline bundle including two towhead manifolds and two midline structures. Oil and gas was to be processed on a new FPSO with oil exported via shuttle tanker and gas via a new export pipeline tied to the existing Fulmar Gas Line. An Environmental Statement (ES) supporting the Fram Field development DECC Ref. D/4137/2012 (Shell UK Limited, 2012) was approved in September 2012. During the 2012 – 2013 drilling campaign, unexpected reservoir results were produced that led to the suspension and subsequent re-framing of the project concept. Following re-appraisal, Shell propose to develop Fram as a gas and gas condensate field with two horizontal wells in the Drill Centre East (DCE) area. Produced fluids will be transported via a new flowline to the existing Starling manifold (approximately 15 km away), comingled with Starling production fluids and further transported via existing infrastructure to the Shearwater platform 33 km away. Fluids from the Shearwater platform are exported through the Shearwater Elgin Area Line (SEAL) and Forties Pipeline System (FPS) pipelines.

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FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON TECHNICAL SUMMARY No modifications are required to the Shearwater topsides hydrocarbon processing equipment although there is a small amount of scope to upgrade the Master Control System (MCS) and the subsea chemical injection system will be modified. Shell as operator and on behalf of their Co-Venturers has selected a tried and tested concept for the proposed Fram 2 Project which reflects current best practices and technologies and makes use of existing infrastructure where possible.

ENVIRONMENTAL STATEMENT SCOPE The scope of the Environmental Impact Assessment (EIA) and resultant ES includes all activities associated with the proposed Fram 2 Field Development Project and comprises: 

Drilling and completion of two new development wells;



Installation of subsea equipment on the seabed;



Installation of a new pipeline and umbilical;



Operation via the Shearwater Platform; and



Decommissioning.

This document provides details of the EIA that has been undertaken to support Shell and their Co-Venturers’ application for consent to undertake the proposed project. This process includes a public consultation followed by a comprehensive review by various bodies including the Department for Business, Energy and Industrial Strategy (BEIS). The ES presents the results of the EIA conducted to evaluate the environmental impacts of the proposed project. These include: the physical presence of vessels and infrastructure, atmospheric emissions, discharges to sea, impacts on the seabed, the effects of underwater noise and an evaluation of the potential impacts from accidental events, as well as vulnerability of the proposed activities to the natural disasters. In addition, potential impacts on designated protected sites, sensitive habitats, and cumulative and transboundary impacts are assessed. The full list of potential environmental aspects of the proposed project and their potential significance are documented in Appendix C. Arran Subsea Tieback Arran is a proposed subsea tieback to the Shearwater Platform with Dana Petroleum Plc (Dana) as the operator of the field. Dana are planning to submit an ES for the Arran Field to BEIS in Q4 2017. If the project goes ahead, Dana are anticipating starting production from the Arran Field in 2021, one year after the proposed Fram start-up. Due to both Fields tying back to Shearwater, where appropriate, the cumulative impacts of both the Fram and Arran Fields (emissions to air and discharges to sea) have been considered within this ES.

OPTION SELECTION Following suspension in 2013 of the original Fram development and further field studies, the Fram opportunity was re-evaluated to identify technically and economically feasible options that would allow developing the field with reduced recoverable volumes. The option selection process for the proposed Fram 2 Field Development Project involved the analysis of a number of subsurface development alternatives and several host/facilities concepts. These considered potential environmental and social consequences alongside other critical evaluation factors such as technical, economic, commercial and safety implications. Several host and tie-in location alternatives were considered to receive Fram fluids, including:

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

Tie-in to Curlew FPSO via one of the Curlew subsea tie-backs;



Tie-in to Shearwater via the Starling subsea manifold; and



Tie-in directly to the Shearwater platform.

The results of the concept analysis showed that there were no environmental or social showstoppers identified for any of the alternatives and hence option selection was further refined in relation to the technical feasibility, risk, schedule, capital and operating costs, project economics, availability and operability. Based on these differentiators, the tie-back to the Shearwater platform via Starling option was selected, as it is the least technically complex solution, has the smallest footprint, reuses existing infrastructure and is the most economically viable. Further concept refinement included: 

Gas development more economically viable than combined oil and gas;



Two wells drilled in the core eastern area provide the best economic option. A third well would provide limited incremental production;



Deviated well design (as opposed to vertical) to enhance production;



Re-use of existing well top-hole reduces surface footprint and volume of cuttings generated. Existing and new wells located close together allows drilling rig to use the same anchor pattern for both, reducing seabed disturbance;



Surface laid pipeline minimizes seabed disturbance, reduces the snagging hazard for fishing (as opposed to clay berms from trenching), and is less likely to require rock dump in comparison with a trenched pipeline where rock would be required to prevent upheaval buckling; and



The risk of hydrate formation will be mitigated with the use kinetic hydrate inhibitors (KHI).

FRAM 2 FIELD DEVELOPMENT PROJECT The proposed Fram 2 Field Development can be summarised as follows: 

Re-entry and completion of one existing well (G3) and drilling of one new well (G5) in the DCE area of the Fram field using a semi-submersible (semi-sub) drilling rig;



Installation of a new Fram manifold using a standard manifold design with three wellbays (two for use and one spare as part of the standard design);



A new 15.2 km 10”/16” surface laid pipe-in-pipe (PIP) production pipeline from the existing Starling manifold to the new Fram manifold;



A 15.2 km trenched umbilical from the Starling manifold to the Fram manifold; and



Topside modifications to chemical injection and control systems.

The two wells will be drilled using a semi-sub drilling rig which will be located within a 500 m exclusion zone at the proposed Fram manifold location. Once on location, the semi-sub will be held in position using an eight-point mooring system. Following completion of the first well, the rig will be skidded to the second well without repositioning the anchors. The well heads and trees will be protected using fishing-friendly ‘cocoon’ structures that allow nets to ride up and over the tree, reducing the risk of snagging. A new Fram manifold will be installed to connect the two new wells and will be secured to the seabed using four corner piles. A new surface laid production pipeline will connect the new Fram manifold to the existing Starling manifold. A controls umbilical will also run between the two manifolds and will be trenched to a depth of 0.6 m to provide protection from damage. Following installation of the pipeline, a small quantity of rockdump may be used to stabilise the pipeline should any props or spans be identified, or if there is a risk of local buckling/pipeline walking.

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FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON TECHNICAL SUMMARY No modifications are planned for the Shearwater topsides hydrocarbon equipment, however, there is a requirement to replace the MCS and the existing subsea chemical injection system will be modified to provide a Low Dose Hydrate Inhibition (LDHI) system.

SCHEDULE The proposed schedule of activities is as follows: 

Fram drilling campaign



Subsea installation



Subsea tie in and commissioning



Top-sides modifications



Anticipated first hydrocarbons

Q4 2019 – Q1 2020 Q2 – Q3 2019 Q2 - 2020 Q2 – Q3 2019 Q2 2020

It should be noted that the schedule is not fixed and is liable to change as the project develops.

BASELINE ENVIRONMENT Wind speeds at Fram range from 5.3 m/s up to a maximum of 19.8 m/s. Average sea surface and seabed temperatures within the area of the proposed project are approximately 9-10°C and 7-8°C respectively. The predominant regional current in the Central North Sea (CNS) originates from the Fair Isle/Dooley current and the project area is influence by the northern North Sea water and the Dooley current. General water depths within the area range from 93.5 m Lowest Astronomical Tide (LAT) at the north end of the pipeline route to 99.8 m LAT in the south. A number of environmental surveys have been undertaken across the proposed Fram 2 Project area between 2010 and 2016. The seabed survey along the Fram to Starling pipeline route found sediments consisting of muddy sand with a mosaic of gravel, cobbles and boulders. Patches of coarser material including gravel, cobbles and boulders were found throughout the pipeline survey corridor, with more extensive patches found at the northern end of the survey route. Other previous surveys of the Fram area have described the sediments as fine silty sand with occasional clay outcrops and areas of numerous clay outcrops. The European Nature Information System (EUNIS) biotope ‘Paramphinome jeffreysii, Thyasira spp. and Amphiura filiformis in offshore circalittoral sandy mud’ (A5.376) was identified for the majority of the pipeline route survey area, representing the muddy sand with occasional shell fragments, pebbles and cobbles. The EUNIS biotope complex ‘Circalittoral mixed sediment’ (A5.44) represented the coarser patches of material observed. Numerous isolated seabed depressions with depths up to 1.1 m were located along the proposed Fram to Starling pipeline route survey corridor. A number of these were interpreted as drill rig anchor pull out pits. Numerous boulders with a maximum height of 2.3 m were identified within 100 m of the proposed pipeline route. An unchartered wreck was found within 5 m of the proposed pipeline route. Contaminant levels found in surface sediments of the Fram 2 Project area can be considered to be typical of background levels in the North Sea. The most abundant of the faunal species encountered were Annelida, Mollusca, Crustacea and Echinodermata. The most abundant taxon observed was the polychaete Paramphinome jeffreysii followed by the bivalve Axinulus croulinensis and polychaete Spiophanes bombyx. Only one adult individual (> 10 mm diameter) Arctica islandica was observed along the pipeline route. However, A. islandica juveniles (< 10 mm diameter) were observed at every grab sampling station along the pipeline route. x

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON-TECHNICAL SUMMARY Spawning grounds for a number of fish species have been identified within the proposed project area including Norway pout, lemon sole, cod, sandeel and mackerel. In addition, the area also coincides with nursery grounds for Norway pout, plaice, mackerel, haddock, cod, whiting, blue whiting, herring, sandeel, ling, anglerfish, hake and spurdog. Marine Scotland has registered a ‘period of concern’ for seismic survey in the vicinity of the proposed project area from May to August due to fish spawning. Based on the Seabird Oil Sensitivity Index (SOSI) the sensitivity of seabirds to surface oil pollution in the vicinity of the proposed Fram 2 Field Development is low for most of the year with the except of May and June in block 29/9 when seabird sensitivity has been assessed as medium. Various whale and dolphin species are known to occur in the area of the proposed project, with data suggesting that high abundances of harbour porpoise, white-beaked dolphin, Atlantic white-sided dolphin and minke whale may occur the vicinity of the Fram 2 Field Development. Low numbers of common dolphin and pilot whale may be also present nearby. Harbour seals are unlikely to occur in the area although low densities of grey seal may be found in the vicinity of Fram. The closest offshore protected area is the East of Gannet and Montrose Fields Nature Conservation Marine Protected Area (NCMPA) which is approximately 6 km north of the Fram Field and within c. 282 m of the tie in location at the Starling manifold. The East of Gannet and Montrose Fields NCMPA is designated for the protection of both ocean quahog (Artica islandica) aggregations, their supporting sands and gravel habitats and offshore deep sea muds. The nearest Marine Conservation Zone (MCZ) is Fulmar (designated for subtidal sand, mud and mixed sediment habitats and the presence of A Islandica) and is located c. 32 km southeast of Fram. Although not confirmed, it is likely that the two patches of Methane Derived Authigenic Carbonates (MDAC) found along the proposed Fram to Starling pipeline route could represent the Annex I habitat ‘Submarine structures made by leaking gases’ and there is evidence of MDAC in the wider Fram area from previous surveys. Megafaunal burrows and/or seapens were observed throughout the area of the pipeline route survey with most stations and transects noted to have areas of ‘frequent’, ‘common’ or ‘abundant’ burrow densities with the potential to represent the OSPAR threatened and/or declining habitat ‘seapens and burrowing megafauna’. The results of a ‘Reefiness’ assessment carried out for survey areas identified as consisting of coarse sediment with cobbles and boulders showed that the areas did not meet the criteria for stony reef as defined by the Habitats Directive. The potential areas of ‘submarine structure made by leaking gases’ (MDAC) and ‘seapens and burrowing megafauna communities’ habitat, as well as several species of fish, dolphin and whale found with the vicinity of Fram are all listed as Priority Marine Features (PMFs) which are considered to be of particular importance to Scotland’s seas. For management purposes the International Council for the Exploration of the Sea (ICES) collates fisheries information for area units termed ICES rectangles. The importance of an area to the fishing industry is assessed by measuring the fishing effort within each ICES rectangle. The Fram 2 Field Development occurs within ICES rectangle 42F1. UK commercial fishing effort within this rectangle varies throughout the year and is considered to be of relatively low importance with an average fishing effort of 0.12 % of total number of days fished and 0.07 % of total UK landings between 2011 and 2015. Shipping in the area is considered to be very low to moderate. There are no military activities associated with the Fram 2 Field Development area and there are no functioning or disused submarine cables in the immediate vicinity of the proposed project. Fram is within a highly developed oil and gas area of the North Sea. Three offshore wrecks lie within the proposed project area, all confirmed as non-dangerous and not of historic value. A potential new wreck was discovered close to the proposed pipeline route during the pipeline route survey. Following further investigation, the wreck has been assigned as medium archaeological significance and medium archaeological potential and has been assigned an Archaeological Exclusion Zone (AEZ) of 100 m radius.

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IMPACTS AND SPECIFIC COMMITMENTS A summary of the key findings of the proposed Fram 2 Field Development Project impact assessment is presented below.

PHYSICAL PRESENCE The physical presence of the project vessels, the drilling rig and the subsea infrastructure has the potential to be a navigational hazard, to restrict fishing operations in the area and/or to cause disturbance to marine fauna. However, taking account of the mitigation measures outlined in Section 12, which include early consultation with the Scottish Fishermen’s Federation (SFF) for all operations, and notification to other users of the sea regarding the project’s activities, the overall significance of the environmental impact of the physical presence of the vessels and infrastructure on other sea users and animals other than the benthic communities in the area is considered slight/minor.

EMISSIONS TO AIR Activities associated with the proposed development and operation of Fram, including drilling, installation, production and decommissioning will all result in the release of various gases into the atmosphere. These include carbon dioxide (CO2), methane (CH4), nitrogen oxides (NOx) and sulphur oxides (SOx) which can contribute to global atmospheric concentrations of greenhouse gases and regional acid loads. It is anticipated that, as a worst-case scenario, the average CO2 emissions associated with the drilling rig during drilling of the 2 Fram wells represents approximately 0.68 % of CO2 produced by diesel combustion on drilling rigs in the UKCS in 2015. Average annual CO2 emissions from other vessels required during the drilling campaign amount to approximately 0.03 % of CO2 generated by domestic and international shipping in 2014. Well clean-up is necessary to ensure that wells no longer contain any drilling and completion related debris (mud, brine, cuttings) which could potentially damage the topsides when commissioning and production begins. Based on preliminary details of the well clean-up operations available at the time of writing, the predicted annual CO2 emissions is estimated to be 0.008 % of the 2015 reported flaring emissions associated with well clean-up and testing. CO2 emissions from the subsea installation of the pipeline and subsea infrastructure is predicted to be 0.02 % of CO2 emissions generated by domestic and international shipping in 2014. The introduction of Fram fluids will results in an increase in production processing at the Shearwater platform and also a slight increase to the overall atmospheric emissions from Shearwater. This can be attributed to changes in fuel gas consumption, flaring of amine regeneration column overheads and flaring of pipeline inventory during start-up and shutdowns. It is anticipated that a peak incremental CO2 equivalent emission of approximately 5,547 Te/yr will occur in 2022, while in other years a slight net decrease in total CO2 emissions from Shearwater platform is also predicted, attributed to the natural composition of the Fram gas. Introduction of the Fram production to Shearwater will result in slight reduction in overall greenhouse gas (GHG) intensity and energy intensity at Shearwater. In 2015, offshore emissions of CO2 on the UCKS were 13.2 million tonnes (Oil & Gas UK, 2016). The total maximum predicted emissions from Fram and Shearwater production are estimated to represent approximately 1.6 % of the reported UKCS total CO2 emissions from offshore activities in 2015, with Fram representing approximately 0.07% of this total. It is not anticipated that rig days or vessel days associated with decommissioning activities will exceed those for drilling and installation activities, and the impact of vessel emissions associated with decommissioning of the Fram 2 Field Development infrastructure are anticipated to be less than those of the drilling and installation phases.

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FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON-TECHNICAL SUMMARY A range of mitigation measures to minimise emissions to air is proposed, as outlined in Section 12. In summary, due to the localised and relatively short duration of drilling and construction activities, a small incremental increase in emissions from the host installation during the operational period, and with the mitigation measures in place, the overall significance of the impact of atmospheric emissions arising from the proposed Fram 2 Field Development is considered to be minor/slight. The proposed Arran tieback will also result in a further increase in emissions at Shearwater and the additional production volumes associated with Arran will contribute to a net decrease of GHG and Energy intensity or the production process at Shearwater.

DISCHARGES TO SEA There will be a number of planned and permitted discharges to sea associated with the project. Planned and permitted discharges to sea during drilling operations include seawater and viscous bentonite sweeps, cement and associated chemicals. At the time of this submission, the base case was that all Oil Based Mud (OBM) contaminated cuttings would be skipped and shipped and processed onshore. An estimated 326 m3 / 726 Te of cuttings drilled with sea water and viscous bentonite sweeps will be discharged to the seabed. The planned discharges of drill cuttings will result in some impacts to benthic marine organisms resulting primarily from oxygen depletion and smothering. Recovery of the seabed and the associated benthic communities is likely to begin once drilling has been completed, while risk to the water column is intermittent throughout the drilling campaign and disperses as soon as drilling finishes. The discharge of the drilling fluids and drill cuttings is considered to have a minor environmental impact on the seabed but with mitigation measures in place the significance of this impact will be reduced to slight. During cementing of the G5 well some of the cement will be discharged to the seabed. The cement mixture is designed to set rapidly and the majority will set into an inert solid and smother a small area of seabed near to the well. The significance of the environmental impact of discharge of cements on the seabed is considered to be slight. During clean‐up operations there is the potential for flare drop‐out (unburned hydrocarbons) to fall from the flare, potentially causing an oily sheen to form on the sea surface. This could impact the water quality and marine wildlife, particularly seabirds that may be in the vicinity. Given the use of high efficiency burners and regular observations for the detection of a sheen, the significance of the environmental impact of flare drop‐out is considered to be minor but with mitigation measures put in place this impact is reduced to slight. Planned and permitted discharges to sea during the installation and commissioning phase are primarily associated with testing the pipeline. All chemicals associated with pipeline testing will be risk assessed and permitted in accordance with the Offshore Chemicals Regulations 2002 (as amended). Marine flora and fauna may be affected on a localised level, but populations will be expected to rapidly recover. The significance of the environmental impact is considered to be minor but with the mitigation measures put in place this is reduced to slight. Discharges to sea during the production phase are primarily associated with the discharge of Produced Water (PW). PW may comprise dispersed oil, metals and organic compounds such as dissolved hydrocarbons, organic acids and phenols. The proposed Fram 2 Field Development will result in an increase in production processing at Shearwater and a resultant incremental increase in chemical and oil in produced water (OiPW) discharges. Produced Water Re-injection (PWRI) has been discounted as an option for the Fram 2 Field Development on its own due to economic reasons. The Fram produced fluids will be comingled with Starling and Shearwater fluids and treated using the existing Shearwater PW treatment system. The PW will be processed on Shearwater to minimise the OiPW concentration and will be within the 30 mg/l monthly average set out by OSPAR. In addition, the PW discharge will comply with the UK legal limits for Oil in Water (OiW). xiii

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON TECHNICAL SUMMARY There is a high risk of hydrate formation in the Fram pipeline due to the low flow rates, low arrival temperature and the long (15 km) production pipeline to Starling and the 32 km pipeline from Starling to the Shearwater Platform. It is predicted that hydrates management will be required for the Fram development after approximately 2 years of production. The other tiebacks to the Shearwater platform currently do not require hydrates management. It is proposed that a kinetic hydrate inhibitor (KHI) be used for hydrates management. KHIs do not prevent the formation of hydrates but they delay formation for a certain length of time. Corrosion Inhibitor (CI) will be dosed into the Fram pipeline system in order to coat the pipeline interior and inhibit microbial action that causes corrosion of the pipeline. Testing of eight different potential KHIs with the existing CI in use in the Shearwater operations was undertaken. Only one of the KHIs performed satisfactorily in the presence of Shearwater production fluids, and was selected. None of the chemicals performed satisfactorily in the presence of the existing CI. Consequently, the choice of KHI also required an alternative choice of CI for the other tiebacks in the Shearwater system where CI is used. While the volumes of produced water predicted for Fram are modest in relation to the Shearwater Cluster, the changes in chemical dosage and their expected partitioning in the system lead to increases in risk to the marine environment. These risks have therefore been assessed in more detail using a standard risk-based approach (RBA) to the assessment of potential risks to the environment from natural components in the produced water and from added production chemicals. This follows principles laid out in the UK RBA Implementation Programme and incorporates dispersion modelling using the Dose-related Risk and Effects Assessment Model (DREAM). The modelling has shown that the corrosion inhibitor is by far the largest contributor to environmental risk. Risks associated with the Shearwater produced water discharge, as a result of changes brought about by the proposed Fram tieback, are focussed on the choice of corrosion inhibitor, while natural components and KHI are predicted to be a minor source of risk. Shell’s commitment to testing and accurate risk assessment of alternative corrosion inhibitor chemicals will enable BAT/BEP to be demonstrated for management of the produced water stream. Some discharges to sea are likely to occur during the decommissioning of the Fram facilities at the end of field life. These will be described in the EIA submitted in support of the Decommissioning Programme. Given the localised, and short duration or intermittent nature of the activities, and with the identified mitigation measures in place, the overall significance of the impact of discharges and releases to sea as a result of the proposed Fram 2 Field Development is considered to be minor.

SEABED DISTURBANCE A number of activities associated with the proposed Fram 2 Field Development have the potential to impact on the seabed habitats populated by benthic communities in the area. The semi-submersible drilling rig will be held in place by an anchor spread consisting of eight anchors and chains. Several types of infrastructure will also be installed on the seabed including a new manifold, the production pipeline and control umbilical, tie in spools, jumpers, potential rockdump, grout/sandbags and mattresses. Overall, in the worst case scenario, it is anticipated that a maximum seabed area of approximately 1.757 km2 will be temporarily impacted through installation activities while approximately 0.014 km2 is expected to be long term or permanently impacted. The physical disturbance resulting from installation may cause some mortality or displacement of motile benthic species and sessile seabed organisms that cannot move away from the contact area, as well as direct loss of habitat. Sediment resuspension will also occur in the immediate area when the structures are initially positioned.

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FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON-TECHNICAL SUMMARY Approximately 326 m3 of drill cuttings and 1,100 m3 of weighted bentonite mud will be discharged to the seabed from the G5 well. The discharge of Water Based Mud (WBM) and cuttings will smother sediments and fauna and release pollutants into the marine environment. Two areas of potential MDAC have been found approximately 30-40 m from the original Fram pipeline route and approximately 7.4 km north west of the proposed Fram manifold/DCE. Sediment re-deposition due to trenching activities is likely to affect the potential MDAC areas and the pipeline route has been optimised to give a clearance of 150 m from the potential MDAC. The East of Gannet and Montrose Fields NCMPA is designated for the protection of Ocean quahog (A. islandica) aggregations and offshore deep-sea muds. The nearest direct impacts of the proposed development will be at the Starling manifold location which is c. 282 m from the boundary of the NCMPA. There will be no activity within the MPA that causes physical change of the seabed to another type, physical removal of sediment, or sub-surface abrasion/penetration. There may be indirect impacts associated with drill cuttings deposition and re-deposition of sediments disturbed during trenching, however, the change in grain size would be below a 5% risk threshold identified during modelling studies. A. Islandica are unlikely to be affected by burial through sediment deposition, however, suspended sediment could result in potential clogging or abrasion of their sensitive feeding and respiratory apparatus. Sediment resuspension from trenching and infrastructure will be short-term (less than 24 hours after cessation of activities) and slightly longer for drilling activities which will take place over several months. The ‘Offshore Deep Sea Muds’ habitat and associated ‘Seapen and Burrowing Megafauna Communities’ biotope are both potentially found in the area of the Fram 2 Field development and will be impacted within the areas of sediment disturbance and beneath the footprint of the infrastructure. Smothering impacts may occur as a result of sediment re-deposition and drill cuttings discharges. Studies into the impact of fishing gear on seapens has shown them to be relatively resilient to being smothered, dragged or uprooted, however, changes in sediment grain size may affect biodiversity in the immediate vicinity of the development. Given the small footprint of the Fram infrastructure and the wide distribution of seapen, these changes are not considered to be significant. A previously uncharted wreck was identified approximately 9 km from the proposed Fram manifold and approximately 113 m from the proposed Fram to Starling pipeline route survey, and has been assessed as being of medium archaeological significance. An Archaeological Exclusion Zone (AEZ) of 100 m radius was recommended to protect the wreck from trenching and rock dumping activities and the proposed pipeline route amended to provide a clear zone of 200 m between the pipeline/umbilical and the wreck location to ensure that it remains undisturbed. Decommissioning activities at Fram will result in some temporary disturbance to the seabed. However, it is anticipated that this will be less than that disturbed by the drilling and installation activities and mostly be within the area disturbed by the installation activities. A range of mitigation measures to minimise the impact of disturbance to the seabed are proposed as outlined in Section 12. Given the localised impact of the disturbance, general widespread distribution, short life cycles and rapid reproduction rates and recovery times of most benthic species in the area; the significance of the environmental impact on the seabed is considered to be minor/moderate.

UNDERWATER SOUND The main sources of underwater sound associated with the proposed Fram 2 Field Development Project will primarily result from: 

Drilling operations;



Pipe laying operations, including trenching and rock dumping; and



Manifold installation (including piling).

xv

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON TECHNICAL SUMMARY Many marine organisms use sound for navigation, communication and prey detection. Therefore, the introduction of man-made sources of underwater sound has the potential to impact marine animals if it interferes with their ability to receive and use sound. Types of impact include temporary avoidance or behavioural changes, the masking of biological sounds, auditory and other injuries. Modelling was carried out to assess the impact of sound from the project on marine mammals and fish. The modelling determined the changes in the sound levels with increasing distance from the source for piling which is considered to be the activity that will produce the highest levels of sound in the marine environment. Results of the modelling indicate that sound levels would be below the Sound Pressure Level (SPL) injury thresholds for cetaceans beyond the immediate vicinity (< 2 m) of piling activities to install the manifold piles. The injury threshold was not exceeded for pinnipeds and for fish, including eggs and larvae. Although the sound from the proposed Fram 2 Field Development does have the potential to cause disturbance to marine mammals and fish spawning it is not expected to have a significant impact on any cetacean or fish species. Taking this into account and considering the mitigation measures outlined in Section 12, the overall significance of the environmental impact of underwater sound generated during the proposed development of the Fram 2 Field is considered to be slight.

WASTE Shell is committed to reducing waste production and managing all produced waste by applying approved and practical methods. In accordance with Shell’s waste management philosophy, emphasis is placed on waste prevention and source reduction measures. Waste will be managed by means of waste management plans and procedures which the contractors will put in place to align with Shell’s requirements. Detailed procedures will govern key responsibilities, reporting requirements and method for the collection, storage, processing and disposal of waste. A programme of planned internal and third party audits will assess the effectiveness of, and conformity to, waste management procedures on a regular basis. A Decommissioning Programme will be developed by Shell which will address waste management during the decommissioning phase. With the application of the above control measures the impact of waste generated during the development and production of the Fram 2 Field will be minimised. The overall residual environmental impact of waste generation is considered to be slight.

ACCIDENTAL HYDROCARBON RELEASES Oil spill modelling was carried out by RPS Applied Science Associates using their OILMAPDeep, OILMAP and SIMAP modelling software. There is a potential risk to several environmental receptors from oil spills, including internationally protected areas, the magnitude of which is dependent on the size of the spill. The modelling study evaluated subsea releases of condensate and a surface release of diesel from the semi-sub drilling rig with a total of five different scenarios. From these it was predicted that subsea releases of condensate would result in a minimal mass of hydrocarbons at the water surface due to high evaporation rates. The diesel spill is predicted to have a greater effect on the water column, compared to the condensate spills or relatively similar volumes released. Based on the location of the spill sites and the properties of the oil types released, there was no shoreline or sediment oiling for the scenarios modelled. There was a relatively low probability of oil crossing the median line during a well blowout and a high probability for surface oil and oil in the water column to overlap with the boundaries of the East of Gannet and Montrose Field NCMPA from a well blowout (relief well 134 days) and pipeline fissure release. The greatest area of mortality across most receptors is generally associated with the relief well blowout scenario (particularly for surface diving birds), with the exception of the pipeline releases which are shown to have a particular impact on demersal species.

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FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON-TECHNICAL SUMMARY The project has conducted an initial assessment of a potential accidental release from a well blow out, a Major Accident Hazard (MAH), to evaluate whether it has a potential to constitute a Major Environmental Incident (MEI). Based on the results oil spill modelling carried out, it is considered that an accidental release from a well blow out is not likely at this stage to result in an MEI. The probability of a major natural disaster (such as an earthquake or tsunami) occurring in UK waters which could impact the Fram 2 Field Development is extremely low, although seismic events of severity sufficient to cause damage to offshore structures and equipment have occurred (HSE, 2006). To mitigate the potential for damage, offshore structures are designed to withstand seismic forces and vibrations with a reasonably low likelihood of exceedance during their lifetime, with little or no damage, and can maintain integrity without major collapse or loss of life. During decommissioning activities, the impact of the worst case hydrocarbon spills is anticipated to be within the impacts discussed above. However, the volumes and rate of flow from the wells, would be greatly reduced compared to normal operations. In addition, the pipelines will have been emptied of hydrocarbons, which would lower the overall environmental impact. In consideration of the control measures detailed in Section 12, the overall risk of an accidental spill from the proposed Fram 2 Field Development is considered to be minor. However, should an uncontrolled release occur there will be robust measures in place to ensure a co-ordinated and co-operative response.

CONCLUSIONS Overall, it is concluded that the proposed Fram 2 Development Project as described is not expected to lead to any significant environmental effects. The proposed development is located in an area of existing oil and gas infratructure with habitat and marine life typical of the central North Sea. The proposed Fram 2 Development Project will be developed using proven technology incorporating current best practices and latest generation equipment. A robust design, strong operating practices and a highly trained workforce will ensure the proposed project does not result in any significant long-term environmental, cumulative or transboundary effects. Additional measures will also be in place during the operating phase to effectively respond to potential emergency scenarios. Where possible, mitigation measures / project specific commitments to reduce impacts have been identified (see below). These will be captured in the project’s Environmental Management Plan, which will include roles and responsibilities for their implementation (see Section 12).

MITIGATION MEASURES, SAFEGUARDS AND CONTROLS Physical Presence Proposed Control Measures 

Consultation with SFF for all phases and operations;



Notice will be sent to the NLB of any MODU moves and vessel mobilisation associated with the mobilisation and demobilisation of the MODU;



Notice to Mariners will be circulated;



A Vessel Traffic Survey (VTS) will be undertaken;



A Collision Risk Management Plan will be commissioned if required;



Optimise vessel use by minimising number of vessels require and length of time vessels are on site;



Use of navigational aids, including radar, lighting and AIS (Automatic Identification System);



Fishing friendly subsea infrastructure will be used;



Minimum distance between pipeline and umbilical of 70m; and xvii




Size of rockdump and rockdump profiles, if required, will be in accordance with industry practice which is also the preferred SFF / industry best practice.

Emissions to Air Standard industry practice and legislative requirements: 

Adherence to good operating practice and maintenance programmes;



Optimize well test duration where feasible;



Minimise emergency shutdowns resulting in flaring;



Combustion emissions and flaring and venting subject to regulatory control via permitted allowances; and



The Shearwater combustion equipment has been subject to a previous BAT assessment under the existing PPC.

Discharges to Sea Standard industry practice and legislative requirements: 

Drilling rig and vessels will be subject to audits to ensure compliance with UK legislation;



OBMs and cuttings shipped to shore for disposal;



Low toxicity and/or PLONOR chemicals will be used where possible; and



All chemical and OiPW discharges are subject to risk assessment and permitting.

Project specific measures: 

The planned corrosion inhibitor will be chosen from a set of alternatives that are undergoing detailed testing. The optimum chemical in terms of chemical and environmental performance will be chosen to demonstrate the application of BAT/BEP.



Specific discussions will be held with BEIS on the testing and selection of optimum chemicals for performance and environmental responsibility.



Supplemental information on chemical testing results will be provided to BEIS to support this document consideration.



Produced water stream WET testing will be carried out on start-up to validate the predicted impact assessment



Monitoring survey prior to and after start-up to validate impact prediction, should only CI-1 is found effective.

Seabed Disturbance Proposed Control Measures

xviii



Pipeline and umbilical routes amended to avoid potential MDAC;



Pipeline and umbilical routes amended to avoid the wreck locations (AEZs);



If further archaeological features are discovered during the installation, operation, maintenance and decommissioning phases of the project, these will be reported in line with the Protocol for Archaeological Discoveries (The Crown Estate, 2014);



Surface lay method minimises the footprint of the pipeline and seabed/habitat disturbance during installation;



Re-use of well G3 top hole section minimises seabed disturbance;



Jet-trenching, if selected, will allow burying the umbilical closer to the manifolds thus reducing the amount of protection materials;



Pre-deployment surveys will be undertaken to identify suitable locations for the drilling rig anchors;


 The use of mattresses, rockdump and grout/sand bags will be minimised through optimal project design; and

 The use of dynamically positioned vessels where possible will minimise anchor use. Underwater Sound Proposed Control Measures 

Avoiding piling during sensitive periods for marine receptors in the area, e.g. migration, breeding, calving or pupping;



Use of properly qualified, trained and equipped marine mammal observers (MMOs) to detect marine mammals within a “mitigation zone” and potentially recommend a delay to piling operations. The mitigation zone should be at least 500 m. MMOs should carry out a 30 minute pre-piling survey and if an animal is detected then work should be delayed until it has left the area;



Soft-start of piling, whereby there is an incremental increase in power and, therefore, sound level. This should be carried out over a minimum period of 20 minutes. This is believed to allow any marine mammals to move away from the noise source and reduce the likelihood of exposing the animal to sounds which can cause injury;



Repeat of the pre-piling survey and soft-start whenever there is a break in piling of more than 10 minutes; and



Avoiding commencing piling at night or in poor visibility when marine mammals cannot reliably be detected.

Waste Management Proposed Control Measures 

Shell will ensure the principles of the Waste Management Hierarchy are followed during all activities;



Reuse of the tophole section at the G3 well reduces drilling wastes;



Existing asset and vessel WMPs will be followed;



A WMP will be developed for the Project; and



Duty of Care audits will be carried out.

Accidental Events Drilling: General 

Shell Well Engineering Manuals document the safeguards to mitigate the major hazards and cover traditional ‘high risk’ areas such as Barrier Requirements, Casing Design, Drilling / Well Intervention/Well Control, Borehole Surveying, etc.;



Shell will have an approved OPEP in place to respond to an accidental hydrocarbon release;

Well design 

The Fram wells are designed as per the requirements laid out in Shell Well Design Standards.



None of the wells are HPHT;



Double barrier principle;



While drilling, the primary well control barrier will be weighted mud and the secondary barrier will be the BOP equipment;



Shell has access to OSRL’s cap and contain system to restore tertiary well control in the event of a blow out;



The reservoir will at all times be overbalanced during the completion operation; xix




The production casing is designed to withstand gas pressure to surface;



Seal assemblies will be locked to the wellhead and tested;

Well control 

Shell Well Control Procedures will be in place during execution of the well operations;



Training and competency of relevant staff is assured via Shell training systems, which will enable personnel critical for monitoring well parameters and for responding to any unplanned influxes to be ready to safely respond to a well control situation;



The drilling contractor key personnel will be audited for their well control qualification and monitored during operation by the Shell supervision and tested with drills, all recorded and monitored in eWCAT online system;



The high pressure components of the BOP system, comprising the topside BOP stack, control system, choke and kill lines and surface lines through to the choke manifold will be rated in excess of the maximum, worst case possible surface pressure. The BOP stack will have all of the functionality expected for this duty and this functionality and condition will be verified by Shell prior to running the BOP stack.



Specific Drilling Contractor’s procedures will be reviewed and aligned with Shell standards;

Contractor/ rig management 

The rig will have a UK Safety Case and will be Class certified;



Shell will perform assurance audits prior to rig acceptance to confirm all critical systems are fully certified and working as designed. Critical systems for ensuring well containment are the BOP equipment, surface blow out prevention equipment, drilling fluid circulating and processing systems;



Fuel handling, transfer and monitoring procedures will be put in place;



Procedures for bulk storage, transfer and mud handling will be in place to minimize risk of spillage;



Drums and storage tanks will be secured and have secondary containment; and



Operational restrictions for other approaching vessels and transfer operations will be defined prior to operations.

Subsea Pipelines and Facilities: Design / installation

xx



Design of the pipeline to appropriate integrity standards taking account of the fluids being carried and the environmental conditions;



Fully rated pipeline with a design pressure of 264 barg - The design of the pipeline to more than the closed-in tubing head pressure of the Fram wells (245 barg);



The surface laid 10” in 16” pipe-in-pipe system has been designed to meet the required load and impact cases determined by the design standards.



A recommended internal corrosion allowance of 5 mm, based on a minimum corrosion inhibitor availability of 97 % will be used to provide a 10 year design life.



Pipelines strength tested and pipeline system fully leak tested prior to hydrocarbon introduction;



Subsea structures are fishing friendly design to meet possible fishing impact or dropped object loads;



Protection of the umbilical from impact by trench/burying;



Use of experienced design and installation contractors;



Quality management during construction;

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT NON-TECHNICAL SUMMARY Operation 

Proactive monitoring - risk-based pipeline integrity management system for inspection and maintenance;



Planned pipeline surveys will ensure any potential damage is picked up at the earliest opportunity.



Pressure and temperature sensors in system for monitoring conditions;



Control system is closed loop hydraulic design;



The pipeline will be designed to be piggable from Fram subsea to topside through the Starling manifold via a removable subsea pig launcher/ receiver;



Pipeline leak detection systems will be via pressure monitoring from topsides.



DSV required to intervene on locked open valve to isolate the Fram pipeline from the Starling pipeline.

xxi

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT ABBREVIATIONS

ABBREVIATIONS % °API °C °F µg/l μm μm (km2) μPa AAHI AAI AEZ AHD AHV AIS ALARP AMAAA AOU ASA AUV BAT BAT bbl bbls/day BEIS BEP BOD BODC BOP BP CCS CEFAS CERCLA

CERFACS CFC CFU CH4 CHARM CI CIfA cm CM CMS CNS

xxii

Percent American Petroleum Institute gravity Degrees Celsius Degrees Fahrenheit Micrograms per Litre Micro metre Micrometre per kilometre squared Micro Pascal Anti-agglomerate Hydrate Inhibitors Areas of Archaeological Importance Archaeological Exclusion Zone Along Hole Depth Anchor Handling Vessel Automatic Identification System As Low As Reasonably Practicable Ancient Monuments and Archaeological Areas Act Apparent Oxygen Utilisation Applied Science Associates Automated Underwater Vehicle Best Available Technology Best Available Techniques Barrels of Oil Barrels of Oil per Day The Department of Business, Energy and Industrial Strategy Best Environmental Practices Biological Oxygen Demand British Oceanographic Data Centre Blowout Preventer Before Preset Carbon Capture and Storage Centre for Environment, Fisheries and Aquaculture Science Comprehensive Environmental response, Compensation and Liability Act Centre Europeen de Recherche et de Formation Avancee en Calcul Scientifique Chlorofluorocarbons Compact Floatation Unit Methane Chemical Hazard Assessment and Risk Management Corrosion Inhibitor Chartered Institute for Archaeologists Centimetre Choke Module Corporate Management System Central North Sea

CO CO2 COLREGS CoP COSHH CPA CPA (NM) CPR CR CRA CRO CSIP CtL D dB dB re μPa-m dB re μPa Db re 1 μPa2 S DCE DCMS DDV DECC DEFRA DepCon DHPG DP DREAM DSV DTI DWT EBS ECE ECMWF EDU EEMS EGN EHC EIA EMS ENVID EOFL EPS ERRV

Carbon Monoxide Carbon Dioxide International Regulations for the Prevention of Collisions at Sea Cessation of Production Control of Substances Hazardous to Health Closest Point of Approach Closest Point of Approach in Nautical Miles continuous plankton recorder Corrosion Resistant Corrosion Resistant Alloy Control Room Operator Cetaceans Strandings Investigation Programme Consent to Locate Demersal Decibel Decibel relative to Micro Pascal to a metre Decibel relative to pascal Decibel relative to 1 squared Micro Pascal per second Drill Centre East Department for Culture, Media and Sport Drop Down Video Department of Energy and Climate Change Department for Environment Food and Rural Affairs Deposits Consent Down Hole Pressure/Temperature Gauge Dynamic Positioning Data and Research for Environmental Applications Dive Support Vessel Department of Trade and Industry Deadweight Tonnage Environmental Baseline Survey Environmentally Critical Elements European Centre for MediumRange Weather Forecast Electrical Distribution Unit Environmental and Emissions Monitoring System Empirical Gain Normalisation Electro-Hydraulic-Chemical Environmental Impact Assessment Environmental Management System Environmental Impact Identification Workshop End of Field Life European Protected Species Emergency Response and Rescue


ES ESE ESRI EU EU ETS EUNIS EWT eWCAT FDP FEAST FEED FGAT FOAM FOCI FPS FPSO FSLTD Ft g/m2 GAEL GEBCO GEL GES GHG GIS GOR H H2S HCFC HDJU HISC HNO3 HP HPHT HQ HRA Hrs HS&E HSE HSSE-SP HYCOM Hz IA ICES ID IMO

Vessel Environmental Statement Environmental, Social and Ethical Environmental Systems Research Institute European Union European Union Emission Trading Scheme European Identification System Extended Well Test Electronic Well Control Assurance Tool Field Development Plan Feature Activity Sensitivity Tool Front End Engineering and Design First Guess at Appropriate Time Forecasting Ocean Assimilation Model Features of Conservation Importance Forties Pipeline System Floating Production Storage and Offloading Fugro Survey Limited Foot Grams per square metre Graben Area Export Line General Bathymetry Chart of the Oceans Gardline Environmental Ltd Good Environmental Status Greenhouse Gases Geographic Information System Gas to Oil Ratio Height Hydrogen Sulphide Hydrochloroflurocarbons Heavy Duty Jack Up Hydrogen Induced Stress Cracking Nitric Acid High Pressure High Pressure High Temperature Hazard Quotient Habitats Regulation Assessment Hours Health, Safety & Environment Health and Safety Executive Health, Safety, Security, Environment and Social Performance Hybrid Coordinate Ocean Model Hertz Impact Assessment International Council for the Exploration of the Sea Internal Diameter International Maritime

INRIA-LJK IOGP IPIECA IUCN JNAPC JNCC kg kg/l Kg/m3 KHI kHz km Km2 KP KPI kV kW/m l L LAT LCM LDHI LP LSA Ltd LTOBM m m/s m2/te m3 m3/day MAH MAHs MARPOL MAT mb MBES MCAA MCS MCZ MDAC MEG MEI Mg/g Mg/kg Mg/l MHW

Organisation French Institue for Research in Computer Science and AutomationJean Kuntzmann Laboratory International Association of Oil & Gas Producers The International Petroleum Industry Environmental Conservation Association International Union for Conservation of Nature Joint Nautical Archaeology Policy Committee Joint Nature Conservation Committee Kilograms Kilograms per Litre Kilograms per cubic metre Kinetic Hydrate Inhibitor Kilohertz Kilometres Kilometres squared Kilometre Point Key Performance Indicator Kilovolt Kilowatts per metre Litres Length Lowest Astronomical Tide Lost Circulation Material Low Dose Hydrate Inhibitor Low Pressure Low Specific Activity Limited Low Toxicity Oil Based Mud Metres Metres per Second Metres squared per tonne Cubic Metres Cubic Metres per Day Major Accident Hazard Monoaromatic Hydrocarbons Marine Pollution Master Application Template Millibar Multibeam Echosounder Marine and Coastal Access Act Master Control System Marine Conservation Zone Methane-Derived Authigenic Carbonate Monoethylene Glycol Major Environmental Incident Milograms/gram Milligrams per kilogam Milligrams per litre Mean High Water

xxiii


mm MMO MMscf MoD MODU mol MPA MSA MSDS MSFD MSL MSS MT MW N/A N/m2 NAO NATO NB NCEP CFSR NCMPA NCOF NEMO NEMOVAR ng/l Ng/m3 NGL NLB nm nm NMFS NMP NMPi NNS NNS NOAA NORM NOOS NOx NPNT NRDA

NRDAM/CME OBM OCR

xxiv

Millimetres Marine Mammal Observer Million Standard Cubic Feet Ministry of Defence Mobile Offshore Drilling Unit Mole Marine Protected Area Merchant Shipping Act Material Safety Data Sheets Marine Strategy Framework Directive mean sea level Marine Scotland Science Metric Tonnes Mud Weight Not Applicable Newton per square metre North Atlantic Oscillation North Atlantic Treaty Organisation Nominal Bore National Centres for Environmental Prediction, Climate Forecast System Reanalysis National Conservation MPA National Centre for Ocean Forecasting Nucleus for European Modelling of the Ocean ECMWF Nanograms per Litre Nanograms per metre cubed Natural Gas Liquids Northern Lighthouse Board Nanometres Nautical Miles National Marine Fisheries Services National Marine Plan National Marine Plan Interactive North Sea Standard Northern North Sea National Oceanic and Atmospheric Administration Naturally Occurring Radioactive Material North-West Shelf Operational Oceanographic System Nitrogen Oxides Normal Temperature Normal Pressure Natural Resource Damage Assessment Natural Resource Damage Assessment Models for Coastal and Marine and Great Lakes Environments Oil Based Mud Offshore Chemical Regulations

ODS ODU OESEA OGA OGP OGUK OHGP OILMAP OILMAPDeep OiPW OiW OOS OPEP OPOL OPPC ORC OSPAR OSRL P Pa PAH PCB PE PETS PEXA PIP PLONOR PMF PML PMRA PON1 ppb PPC ppm ppmv ppt PROTEUS PSI psia psu PT PT/TT PTS PU PUQ PW PWA PWRI

Ozone Depleting Substance Offshore Development Unit Offshore Energy Strategic Environmental Assessment Oil and Gas Authority International Association of Oil and Gas Producers Oil & Gas UK Open Hole Gravel Pack Oil Spill Model and Response System Oil Spill Model and Response System in Deep Water Oil in Produced Water Oil in Water Out of Straightness Oil Pollution Emergency Plan Offshore Pollution Liability Association Oil Pollution Prevention and Control Offshore Chemicals Regulations Oslo/Paris Convention Oil Spill Response Limited Pelagic Pascal Polycyclic Aromatic Hydrocarbons Polychlorinated Biphenyl Parabolic Equation Portal Environmental Tracking System Practice and Exercise Areas Pipe in Pipe Poses Little or No Risk Priority Marine Features Plymouth Marine Laboratory Protection of Military Remains Act Petroleum Operations Notice Parts Per Billion Pollution Prevention and Control Parts Per Million Parts Per Million by Volume Parts Per Thousand Pollution Risk Offshore Technical Evaluation System Pounds per Square Inch Pounds Per Square Inch Absolute Practical Salinity Unit Pressure Transmitter Pressure Transmitter/Temperature Transmitter Permanent Threshold Shift Polyurethane Process, Utilities and Quarters Produced Water Protection of Wrecks Act Produced Water Reinjection


RAM RBA RGB RHC rms Rms SPL ROV ROVSV RoW RQ SAC SACFOR SAHFOS SAP SARF SAST SAT SCANS SCI SCOS SDM SDU SEA SEAL SEL SFF sg SIMAP SINTEF SMR SMRU SMTZ SNH SO2 SO3 SOP SOPEP SoS SOSI SOx SPA SPL SRM SSS SSSI SWA Te

Range-Dependent Acoustic Model Risk Based Approach Red Blue Green Rapid Hardening Cement Root mean square Root Mean Square Over Sound Pressure Level Remotely Operated Vehicle Remotely Operated Vehicle Support Vessel Receiver of Wreck Risk Quotient Special Area of Conservation Super-abundant, Abundant, Common, Frequent, Occasional, Rare Sir Alister Hardy Foundation for Ocean Science Systems Applications and Products Scotland Archaeological Research Framework Seabirds at Sea Team Subsidiary Application Templates Small Cetacean Abundance in the North Sea Site of Community Importance Special Committee on Seals Species Distribution Modelling Subsea Distribution Unit Strategic Environmental Assessment Shearwater Elgin Area Line Sound Exposure Level Scottish Fishermen’s Federation

Te/day THC THI TOM TR

Spill Impact Model Application Package Stiftelsen for industriell og teknisk forskning (The Foundation for Scientific and Industrial Research) Sea Mammal Research Sea Mammal Research Unit Sulphate-Methane Transition Zones Scottish Natural Heritage Sulphur Dioxide Sulfur Trioxide Standard Operating Procedure Ship Oil Pollution Emergency Plan Secretary of State Seabird Oil Sensitivity Index Sulphur Oxides Special Protected Area Sound Pressure Level Subsea Repeater Module Side Scan Sonar Sites of Special Scientific Interest Shearwater A Tonnes

WHP WHRU WMP WOA Wt % WWI WWII

TRSSSV TSCJ TT TVD TVDBDF TVP UK UK BAP UKCS UKDMAP UKHO UKOOA US USDOI USEPA UTA VMS VOC VTS WBM WEEE

Tonnes per day Total Hydrocarbons Thermodynamic Hydrate Inhibitor Total Organic Matter Transect Tubing Retrievable Sub-Surface Safety Valve Tree Supply Control Jumper Temperature Transmitter True Vertical Depth True Vertical Depth Below Drill Floor True Vapour Pressure United Kingdom United Kingdom Biodiversity Action Plan United Kingdom Continental Shelf United Kingdom Digital Marine Atlas United Kingdom Hydrographic Office UK Offshore Operators Association United States Unites States Department of the Interior United States Environmental Protection Agency Umbilical Termnation Assembly Vessell Monitoring System Volatile Organic Compound Vessel Traffic Survey Water Based Mud Waste Electrical and Electronic Equipment Directive Well Head Platform Waste Heat Recovery Unit Waste Management Plan World Ocean Atlas Weigt Percentage World War One World War Two

xxv

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT CONTENTS

GLOSSARY Annex I Habitat

Habitat, listed on the Habitats Directive, considered most in need of conservation within Europe.

Annex II Species

Species (not including birds), listed on the Habitats Directive, considered most in need of conservation within Europe.

Bioturbation

The mixing of sediments or particles by fauna.

Birds Directive

European directive to protect habitats of wild bird species through the designation of SPAs. The directive provides a framework for the conservation and management of, and human interactions with, wild birds in Europe. The objective is to create a coherent network of protected sites which meets the protection requirements of endangered and migratory bird species.

Blowout

An incident where formation fluids flow out of the well or between formation layers after all the predefined technical well barriers or the activation of the same have failed.

Blowout Preventer

A large valve at the top of a well that may be closed as a precaution or if there is a loss of well control.

Bonn Agreement

Following several oil spills in 1969, the coastal nations of the North Sea formed the Bonn Agreement to ensure mutual cooperation in the avoidance and combating of environmental pollution. The agreement was revised in 1983 to include the European Union. Members of the Bonn Agreement are Belgium, Denmark, the European Community, France, Germany, Ireland, the Netherlands, Norway, Sweden, and the United Kingdom.

Commissioning

Preparatory testing work, servicing, etc., usually on newly installed equipment prior to coming into full production.

Dynamic Positioning

Use of thrusters (instead of anchors) to maintain the position of a vessel.

Environmental Impact Assessment (EIA)

Systematic review of the environmental effects a proposed project may have on its surrounding environment.

European Protected Species (EPS)

European Protected Species are animals and plants that receive protection under the Conservation of Habitats and Species Regulations 2010, in addition to the Wildlife and Countryside Act 1981 (as amended).

Fishing Friendly design

This design does not allow fishing gear to travel over a structure. However, the design prevents trawl gear becoming snagged or penetrating the structure. Any voids in the structure are sized to be smaller than trawl gear. This allows the fishing vessel to reverse and unsnag the fishing gear.

Habitats Directive

The Habitats Directive (together with the Birds Directive) forms the cornerstone of Europe's nature conservation policy. It is built around two pillars: the Natura 2000 network of protected sites and the strict system of species protection. All in all the directive protects over 1,000 animal and plant species and over 200 so called "habitat types" (e.g. special types of forests, meadows, wetlands, etc.) which are of European importance.

ICES rectangles

A statistical area of the sea that is 0.5° latitude by 1° longitude, defined by the

xxvi


International Council for the Exploration of the Seas. Each ICES rectangle covers 15 licence blocks. Marine Conservation Zone (MCZ)

Designated under the Marine and Coastal Access Act (2009), they protect a range of nationally important wildlife, habitats, geology and geomorphology in English and Welsh territorial and UK offshore waters.

Nature Conservation Marine Protected Area (NCMPA)

Designated under the Marine (Scotland) Act (2010) and the Marine and Coastal Access Act (2009), they protect a wide range of marine wildlife, habitats and geology in the sea around Scotland.

Overtrawlable Design

Design of subsea structures that allows fishing gear to travel over the structure without snagging. Generally structures have sloped sides and this gives them a large subsea footprint.

Permanent Threshold Shift (PTS)

Plume

A permanent decrease in hearing sensitivity caused by exposure to loud noise.

Term used to describe the dispersion of oil in the water column following an uncontrolled oil release. Turbulence causes the oil to be broken up at the exit. As a result the oil spreads out as it rises, mixing with the water around it. Areas considered important for certain habitats and non-bird species of interest in a European context. One of the main mechanisms by which the EC Habitats and Species Directive 1992 is implemented. In addition, there are four designations below full SAC status:

Special Area of Conservation (SAC)

Sites of Community Importance (SCIs) are sites that have been adopted by the European Commission but not yet formally designated by the government of each country; Candidate SACs (cSACs) are sites that have been submitted to the European Commission, but not yet formally adopted; Possible SACs (pSACs) are sites that have been formally advised to UK Government, but not yet submitted to the European Commission; and Draft SACs (dSACs) are areas that have been formally advised to UK government as suitable for selection as SACs, but have not been formally approved by government as sites for public consultation.

Special Protection Area (SPA)

Sites designated under the EU Birds Directive as a Special Protection Area.

Temporary Threshold Shift (TTS)

A temporary decrease in hearing sensitivity caused by exposure to loud noise.

Thruster

A propulsive device used by vessels for station keeping, attitude control, or long duration low acceleration.

Topsides

Describes the equipment situated on a platform including, for example, the oil production plant, accommodation block and drilling rig.

UK barrels

The traditional unit of measure of oil volume, equivalent to 159 litres (0.159 m3) or approximately 42 US Gallons.

Umbilical

Any of various external electrical lines or fluid tubes which connect one portion of a system to another.

xxvii

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT CONTENTS


xxviii

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT INTRODUCTION

1.

INTRODUCTION

This Environmental Statement (ES) presents the findings of the Environmental Impact Assessment (EIA) conducted by Genesis Oil and Gas Consultants on behalf of Shell U.K. Limited (Shell) for the proposed development of the Fram 2 Field.

1.1. FIELD HISTORY AND PROJECT PURPOSE The Fram 2 Field Development is situated in blocks 29/3c, 29/8a, 29/4c and 29/9c of the United Kingdom Continental Shelf (UKCS) approximately 221 km east of Aberdeen, 50 km from the UK/Norway median line and in a water depth of approximately 97 m (Figure 1-1).

Figure 1-1 Location of the Fram Field. Following initial appraisal in 2009, Fram was planned to be developed as an oil and gas field via eight subsea production wells at two drilling centres. The drilling centres were to be connected by an integral flowline bundle including two towhead manifolds and two midline structures. Oil and gas was to be processed on a new FPSO with oil exported via shuttle tanker and gas via a new export pipeline tied-in to the existing Fulmar Gas Line. An Environmental Statement (ES) supporting the Fram Field development DECC Ref. D/4137/2012 (Shell UK Limited, 2012) was approved in September 2012. During the 2012 – 2013 drilling campaign, unexpected reservoir results were produced that led to the suspension and subsequent re-framing of the project concept. Following re-appraisal, the proposed Fram 2 Field Development can be summarised as follows: 

1-1

Re-entry and completion of one existing well (G3) and drilling of one new well (G5) in the Drill Centre East (DCE) area of the Fram Field using a semi-submersible (semi-sub) drilling rig;




Installation of a new Fram manifold using a standard 4-slot manifold design with three wellbays (two for use and one spare as part of the standard design);



A new 15.2 km 10”/16” surface laid pipe-in-pipe production pipeline between the existing Starling manifold and the new Fram manifold;



A 15.2 km umbilical from the Starling manifold to the Fram manifold; and



Topsides modifications to chemical injection and control systems.

1.2. SCOPE OF ENVIRONMENTAL STATEMENT The scope of the ES includes: 

Drilling and completion of new development wells;



Installation of subsea equipment on the seabed; and



Installation of a new pipeline and umbilical;



Operation via the Shearwater Platform; and



Decommissioning.

The EIA sets out to investigate and evaluate the impacts of any emissions to air, discharges to sea, seabed disturbance, noise, waste production and resource use resulting from the Fram 2 Field Development on a range of receptors including, flora, fauna, the seabed, water, air, climate and other sea users. These aspects are considered for both planned and unplanned events.

1.2.1. Arran subsea tie back Arran is a proposed subsea tie back to the Shearwater Platform with Dana Petroleum Plc (Dana) as the operator of the field. The location of the Arran Field is shown in Figure 1-1. Dana are planning to submit an ES for the Arran Field to BEIS in Q4 2017. At the time of writing, Arran is an un-sanctioned project however if the project goes ahead, Dana are anticipating starting production from the Arran Field in 2021, one year after the proposed Fram start-up. Due to both Fields tying back to Shearwater, where appropriate, the cumulative impacts of both the Fram and Arran Fields (emissions to air and discharges to sea) have been considered within this ES.

1.3. LEGISLATIVE OVERVIEW This section provides a summary of the current environmental legislation applicable to the project.

1.3.1. Environmental Impact Assessment Environmental Impact Assessment (EIA) has been a legal requirement for offshore developments since 1998. Current requirements are set out in the Offshore Petroleum Production and Pipelines (Environmental Impact Assessment and other Miscellaneous Provisions) (Amendment) regulations 2017, hereafter referred to as the EIA Regulations. The purpose of the Regulations is to require the Secretary of State (SoS) for Business, Energy and Industrial Strategy to take into consideration environmental information before making decisions on whether or not to consent certain offshore activities.

1.3.2. Protected Sites and Species The EIA must consider impacts to the surrounding environment including any protected areas. Many protected areas have been developed as a result of EU Directives, in particular the Habitats Directive (92/43/EEC) and the Birds Directive (2009/147/EC) which have been enacted in the UK by a number of pieces of legislation.

1-2


1.3.3. Discharges to Water

1.3.3.1. Oil discharges Under the Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 (as amended) (OPPC Regulations) all offshore installations are required to have an oil discharge permit. This includes a 30 mg/l monthly average concentration of oil discharged in produced water. The installation permit also includes drains and oil in sand. A permit is also required for discharges during drilling of wells, discharges from pipelines and discharges made during decommissioning. The permits include Best Available Techniques (BAT) assessment to provide justification for the chosen discharge and pollution management options along with any improvement programmes that are being implemented.

1.3.3.2. Chemical discharges Under the Offshore Chemicals Regulations 2002 (as amended) (OCR) a chemical permit is required for the use and/or discharge of chemicals used offshore. All offshore activities are covered by the Regulations including oil and gas production, drilling of wells, discharges from pipelines and discharges made during decommissioning. As part of the application process, a risk assessment of the discharge of chemicals to the marine environment is required. There are some exemptions, for example maintenance products used solely within accommodation areas.

1.3.3.3. Risk Based Approach OSPAR Recommendation 2012/5 for a Risk-based Approach to the Management of Produced Water Discharges from Offshore Installations (RBA) aims to produce a method for prioritising mitigation actions for those discharges and substances that pose the greatest risk to the environment. The objective is that by 2020 all offshore installations with produced water discharges in the OSPAR maritime area will have been assessed to determine the level of the risk and that, where appropriate, measures will have been taken to reduce the risk posed by the most hazardous substances (Scottish Government, 2013). The Department for Business, Energy and Industrial Strategy (BEIS) (formally DECC) have recently issued guidance on the RBA for UK installations (DECC, 2014a). The RBA is scheduled for implementation on the Shearwater platform in 2018.

1.3.4. Atmospheric Emissions Combustion installations on oil and gas platforms with a rated thermal input of 20 MW(th) or more require permitting under the EU’s Emissions Trading Scheme (EU ETS) and implementing UK regulations, the Greenhouse Gas ETS Regulations 2005 (as amended 2007) and the Greenhouse Gas Emissions Trading (Nitrous Oxide) Regulations 2011. This includes emission allowances for carbon dioxide (CO2). Combustion installations on oil and gas platforms with a rated thermal input of 50 MW(th) or more require permitting under the Offshore Combustion Installations (Prevention and Control of Pollution) Regulations 2001 (as amended) and the Offshore Combustion Installations (Pollution Prevention and Control) Regulations 2013. This includes emission allowances for carbon monoxide (CO), oxides of nitrogen (NOx), oxides of sulphur (SOx), methane (CH4) and volatile organic compounds (VOCs) and demonstration of BAT.

1.3.5. Accidental Events Oil Pollution Emergency Plans (OPEPs) are required under the Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998. The regulations require the arrangements for responding to incidents which cause, or may cause, marine pollution by oil to be in place and the consequence of incidents to be assessed, including the potential environmental and socio-economic impacts. 1-3

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT INTRODUCTION The regulations have been amended by the introduction of the EU Offshore Safety Directive (2013/30/EU). This includes, but is not limited to: 

A review of the effectiveness of the different response techniques available while operating at different locations in the North Sea and at different times of the year;



Revised spill modelling guidance to include seasonal modelling and sub-surface modelling to be undertaken where appropriate; and,



Reference included within OPEPs to the worst case major accident hazard (MAH) as identified within the Safety Case.

1.3.6. Marine and Coastal Access Act (2009) The Marine and Coastal Access Act 2009 (MCAA) and the Marine (Scotland) Act 2010 provides the legal mechanism to help ensure clean, healthy, safe, productive and biologically diverse oceans and seas by putting in place a new system for improved management and protection of the marine and coastal environmental. The MCAA covers English and Welsh territorial waters and certain activities in UK offshore waters whilst the Marine (Scotland) Act covers Scottish territorial waters. The licensable activities under the MCAA are principally related, but not limited, to decommissioning operations including activities such as seabed disturbance, the depositing and removal of materials and the use of explosives. The MCAA enables the designation of Marine Conservation Zones (MCZs) in the territorial waters adjacent to England and Wales and UK offshore waters. In Scotland offshore MCZs are referred to as Scottish Marine Protected Areas (MPAs) in order to be consistent with the designation of MPAs within Scottish Territorial waters under the Marine (Scotland) Act.

1.3.7. Scotland’s National Marine Plan Scotland’s National Marine Plan (NMP) (Marine Scotland, 2015) covers the management of both Scottish inshore waters (out to 12 nautical miles) and offshore waters (12 to 200 nautical miles). The aim of the NMP is to help ensure the sustainable development of the marine area through informing and guiding regulation, management, use and protection of the NMP areas. One of the Oil & Gas marine planning policies requires that ‘activity should be carried out using the principles of Best Available Technology (BAT) and Best Environmental Practice. Consideration should be given to key environmental risks including the impacts of noise, oil and chemical contamination and habitat change’. The proposed Fram 2 Development Project activities have been assessed against each of the NMP objectives details of which can be found in Appendix A; 

General policies and objectives;



Good Environmental Status (GES) descriptors; and



Oil and Gas specific marine planning policies.

1.4. SHELL UK ENVIRONMENTAL MANAGEMENT SYSTEM Shell’s Environmental Management System (EMS) is embedded in its Corporate Management System (CMS). The EMS is a system of internal controls that demonstrates how Shell complies with laws and regulations, and which facilitates the implementation of the company’s HSE policy. The EMS is independently verified to ISO 14001, which meets the requirements of OSPAR Recommendation 2003/5 to promote the use and implementation of EMSs by the offshore industry. A brief description of the Shell EMS is given in the Environmental Management Section of the Shell annual environmental statement, which is available for download at www.shell.co.uk/sustainability/reporting . A copy of the Shell Policy on Health, Safety, Security, Environment and Social Performance (HSSE-SP) is available in the annual environmental statement (link above). This Policy contains a commitment to protect 1-4

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT INTRODUCTION the environment and states that Shell has a systematic approach to HSSE-SP management designed to ensure compliance with the law and to achieve continuous performance improvement. Shell’s Commitment and Policy is underpinned by mandatory internal standards and accompanying manuals. The HSSE-SP Control Framework covers the commitments, standards and performance levels that must be taken into account by all operations. The Environmental Manual of the HSSE-SP Control Framework sets out specific requirements relating to: 

Biodiversity;



Continuous Flaring and Venting;



Greenhouse Gas and Energy Management;



Ozone Depleting Substances;



Soil and Groundwater;



Sulphur Oxides (SOx) and Nitrogen Oxides (NOx);



Volatile Organic Compounds;



Waste; and



Water in the Environment.

The relevant requirements of the control framework are taken into account during development of a project. All companies contracted to Shell are required to work to similar, consistent high standards and to achieve comparable levels of performance adopted by Shell UK Limited. Project and Contractor employees, on their part, have a clear responsibility to exercise discipline, maintain a high level of awareness, prevent injury to themselves and others, protect the environment and comply with all statutory obligations. As a requirement of ISO 14001, environmental considerations are integrated into audit programmes that address all aspects of Shell’s business. Management of Fram environmental aspects and impacts will be integrated into the existing plans and procedures for the UK assets and any Shearwater specific plans.

1.5. ENVIRONMENTALLY CRITICAL ELEMENTS Environmentally Critical Elements (ECE) are defined as systems/equipment the failure of which could cause, or contribute to, a significant impact to the environment. Shell manages the inspection and maintenance of their process equipment through a robust risk based process linked into their maintenance system provided by SAP (Systems Applications and Products). The specific identification and management of ECEs has not yet been implemented within the Shell organisation, however, a pilot has been initiated in one of Shell’s offshore platforms which will enable Shell to have a better understanding of how to incorporate ECE into its processes. A full roll out programme for offshore facilities and projects will be conducted after completion of this pilot.

1.6. CONSULTATION During the process to assess the environmental impact of the proposed Fram development, Shell, on behalf of their Co-Venturers, consulted a number of organisations such as BEIS, Marine Scotland, the Joint Nature Conservation Committee (JNCC) and the Scottish Fishermen’s Federation (SFF). The concerns and recommendations raised have been taken into account in project design, decisions and assessment of impacts. The details of these consultations with reference to the relevant ES chapters are given in Appendix B. The process of consultation will continue throughout the project.

1.7. ADDITIONAL STUDIES A number of studies have been undertaken to help inform the Fram 2 Field Development ES:

1-5




Fram to Starling Pipeline Route Survey UKCS Block 29/3. Environmental Baseline Survey and Habitat Assessment. Ref: 150404.5. Fugro (2016);



Fram Project: Uncharted Wreck. Archaeological Desk-based Assessment. Maritime Archaeology Ltd (2017);



Fram DREAM Modelling Study. Genesis (2017a);



Fram 2 Field Development. Underwater Noise Modelling. Genesis (2017b); and



Fram Spill Risk Assessment Modelling. RPS Applied Science Associates (2017).

Information from these studies has been included within relevant chapters where appropriate.

1-6

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION

2.

PROJECT DESCRIPTION

2.1. DEVELOPMENT OVERVIEW The Fram discovery is a gas condensate accumulation with a small discontinuous oil rim and will be developed as a gas and gas condensate field with two horizontal wells in the Drill Centre East (DCE) area (the core area in the eastern part of the field). The first well will be a continuation of the G3 (29/3C-A3) well currently suspended at the 13 ⅝” casing shoe. The second well (G5) will be a new well drilled from the DCE, 30 m from the G3 wellhead. The G3 and G5 wells will be tied back to a new Fram manifold. Fluids will then be transported via a new production flowline to the existing Starling subsea manifold approximately 15.2 km away (Figure 2-1). At the Starling manifold, the Fram and Starling production fluids will be comingled and further transported, via the existing Starling subsea infrastructure to the Shearwater platform 33 km away (Figure 2-1). As per the existing Starling production, the Fram and Starling fluids will be further commingled with other fluids on the Shearwater platform before being processed and subsequently exported through the Shearwater Elgin Area Line (SEAL) and Forties Pipeline System (FPS) pipelines. The umbilical will be extended from the Starling manifold to Fram to provide the required control, power and chemical injection. Fram production will act as ullage filler to the Shearwater platform. The Shearwater complex comprises Shearwater A, the well-head platform and Shearwater C, a normally manned integrated Process, Utilities and Quarters (PUQ) platform. The two platforms are linked via an 80 m bridge. While no modifications are needed to the Shearwater topsides hydrocarbon equipment, there is a small amount of scope to replace the current subsea Master Control System (MCS) with an upgraded MCS that is capable of controlling all current and future subsea fields. Additionally, the existing subsea chemical injection system will be modified to provide a Low Dose Hydrate Inhibition (LDHI) system. Fram will also need to be connected into the platform control and safeguarding system.

2-1


Figure 2-1 The original and Fram 2 Field Development options.

2-2

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION The proposed Fram 2 Field Development can be summarised as follows: 

Re-entry and completion of one existing well (G3) and drilling of one new well (G5) in the DCE area of the Fram field using a semi-submersible (semi-sub) drilling rig;



Installation of a new Fram manifold using a standard manifold design with three wellbays (two for use and one spare as part of the standard design);



A new 15.2 km 10”/16” surface laid pipe-in-pipe (PIP) production pipeline from the existing Starling manifold to the new Fram manifold;



A 15.2 km trenched umbilical from the Starling manifold to the Fram manifold; and



Topside modifications to chemical injection and control systems.

2.2. LICENCES Shell operates licence P.012 (blocks 29/3c and 29/8a) awarded in 1964 and P.1664 (blocks 29/4c and 29/9c) awarded in 2009. In March 2012, unit equities for the Fram field were agreed between Shell (32%) and Esso Exploration and Production UK Limited (68%).

2.3. SCHEDULE A high level schedule for the Fram 2 Field Development is provided in Table 2-1. Production at the proposed Fram 2 Field Development is anticipated to commence in Q1 2020 and continue until around 2027. The actual Cessation of Production (CoP) will be determined by field life, operating cost, and oil price. Drilling operations will likely commence in 2019 with exact timing to be confirmed subject to rig contracting, and will last approximately 140 days in total. Subsea installation activities will take place from Q2 2019 through to Q3 2019 coinciding with any topsides modifications at Shearwater which will be undertaken in Q2/Q3 2019. It is anticipated that production from both wells will commence in Q2 2020. Field life expectancy is approximately 7 years with end of field life (EOFL) in 2027. Table 2-1 Fram 2 Field Development base case schedule of activities. ACTIVITY

2019 Q1

Q2

2020 Q3

Q4

Q1

Q2

Q3

Q4

2027

Fram drilling Subsea installation Subsea tie in and commissioning Top-sides modification Fram first hydrocarbons EOFL

2.4. FIELD AND RESERVOIR CHARACTERISTICS The Fram field is located in the West Central Graben to the southwest of the Forties-Montrose High. The field consists of a gas cap and small discontinuous oil rim within Palaeocene age Forties reservoir sands around a pierced salt diapir structure (Figure 2-2). Fram is planned to be developed with two wells in the core or Eastern area of the field which is bounded by the fault west of the 29/3c-8/8z wellbore and by the fault south of the 29/3A-6 well.

2-3


Figure 2-2 Fram gas accumulation with in place volumes. The Forties fan system is well developed across much of the CNS and represents a major hydrocarbon reservoir. It is principally sourced from the north-west becoming more distal towards the southeast. Situated more distally and marginally, Fram is composed of a thinner lower net-to-gross interval of two stacked lobe complexes. The primary Fram reservoir fluid properties are summarised in Table 2-2 while gas properties are provided in Table 2-3. Fram has a low CO2 content and when processed at Shearwater will take on some CO2 during treatment in order to meet export production requirements. Table 2-2 Fram primary reservoir fluid properties. PROPERTY Fluid Type Initial Reservoir Pressure (psia) Initial Reservoir Temperature (°F) Density at 15°C (kg/m3) Gravity (°API) Min Pour Point (°C) Asphaltene Content (wt%) Wax Content (wt%)

2-4

VALUE Gas - condensate 4,150 @ 8,600 ft TVDSS 235 @ 8,600 ft TVDSS 756 56 -39 85°) in the reservoir. The G3 well is currently suspended at the 13 ⅝” casing shoe (Figure 2-6). Shell intend to extend the G3 well and drill a new G5 well approximately 30 m from the G3 location. The G3 extension and G5 well will be drilled to total depths of approximately 8,939 ft (2,725 m) and 8,787 ft (2,678 m) True Vertical Depth Below Drill Floor (TVDBDF) for the subsurface targets and will step out approximately 8,930 ft (2,722 m) and 6,297 ft (1,919 m) from the seabed locations. Each well will have five hole sections, four with cemented casing and an 8 ½” open-hole section in which a gravel pack completion will be run. The basic well profiles for each well are summarised in Table 2-11. Schematics for the well designs are shown in Figure 2-7 and Figure 2-8.

2-14

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION Table 2-11 Basic well profile for the G3 and G5 wells. HOLE SIZE (inches) 36 26 17 ½ 12 ¼ 8½ 36 26 16 12 ¼ 8½

CASING SIZE (inches) G3 well 30 20 13 ⅝ 10 ¾ x 9 ⅝ N/A G5 well 30 20 13-5/8 10 ¾ x 9 ⅝ N/A

Shoe AHDBDF (ft) (ft) (m) 655 3,014 7,520 11,590 14,414

200 919 2,292 3,533 4,393

655 3,020 6,000 10,500 13,541

200 920 1,829 3,200 4,127

2-15


Figure 2-6 G3 current well status.

2-16


Figure 2-7 G3 well design.

2-17


Figure 2-8 G5 well design.

2.7.4. Drilling Mud and Cuttings Drilling mud (also known as drilling fluid) is added to the wellbore to facilitate the drilling process. It is required for a number of reasons including: 

Managing hydrostatic pressure and primary well control;



Transportation of the cuttings to the surface;



Preservation of the wellbore to facilitate casing/completion installation; and



Cooling and lubrication of the drill bit.

2-18

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION Drilling fluid is continuously pumped down the drill string to the drill bit and returns to the surface through the annular space between the drill string and the sides of the well. Different mud formulations are required at different stages in the drilling operation because of variations in pressure, temperature and the physical characteristics of the rock being drilled. Sea water and viscous bentonite sweeps will be used to drill the 36” and 26” hole sections on the G5 well (already drilled on G3). The anticipated mud requirements and the cuttings volume and fate of cuttings required for each well is shown in Table 2-12. Table 2-12 Anticipated mud requirements and cuttings volume/mass associated with the wells. HOLE SIZE (“)

DRILLING FLUID

VOLUME OF 3 MUD (m )

VOLUME OF CUTTINGS (m3) G3 well

MASS OF CUTTINGS (Te)

FATE OF CUTTINGS

36

N/A

N/A

N/A

N/A

N/A

26

N/A

N/A

N/A

N/A

N/A

17 ½

N/A

N/A

N/A

N/A

N/A

12 ¼

700-710 pptf OBM

579

104

231

8½

630 pptf OBM

437

35

77

Skipped and shipped, processed onshore Skipped and shipped, processed onshore

G5 well 36

Sea Water

N/A

54

120

26

Sea Water

N/A

272

606

16

680 pptf OBM

507

130

289

12 ¼

700 pptf OBM

568

115

256

8½

630 pptf OBM

434

37

83

Section drilled riserless, discharged to seabed Section drilled riserless, discharged to seabed Skipped and shipped, processed onshore Skipped and shipped, processed onshore Skipped and shipped, processed onshore

The 36” and 26” holes for the G5 well will be drilled riserless with the cuttings discharged to the seabed. Cuttings from the 16” hole on the G5 well, and the 12 ¼” and 8 ½” holes for both wells will be skipped and shipped to shore for processing and disposal. There will be no discharge of oil-based or OBM contaminated cuttings to the seabed. The 36” and 26” holes will be displaced with weighted bentonite mud for running the conductor and surface casing and the fluid will be circulated out to sea prior to cementing both strings in place. Approximately 1,100 m3 of bentonite mud is required for sweeps, displacement fluid and reserves in total.

2.7.5. Well Casing and Cementing Chemicals Steel well casings will be cemented in place in the wellbores to provide structural strength and to isolate unstable formations, different formation fluids and separate different wellbore pressure regimes. The 30” conductor on G5 (already in place on G3) will be cemented using Rapid Hardening Cement (RHC) whereas the 20” surface casing, 13 ⅝” intermediate casing (20” and 13 ⅝” casing already in place on G3) and 10 ¾” x 9 ⅝” production casing will be cemented using Class G + 35 % silica cement. The conductor and surface casing will be fully cemented therefore some of the cement will be discharged to the seabed. The anticipated total volume of cement to be used on G3 is 123 bbl (19.6m3) with an excess of 25 bbl (4 m3) or 20 % (10 ¾” x 9 ⅝” casing only). On G5, the anticipated total volume of cement to be used is 1,037 bbl (165 m3) with an excess of 1,030 bbl (164 m3) or 440 %.

2-19


2.7.6. Sand Production and Control Fram reservoirs have a low average permeability and the production of sand could affect the productivity of the planned wells. Although there is potential for sand production from the Fram reservoir, it is not expected that there will be a high sand production volume. An Open Hole Gravel Pack (OHGP) using Exxon Mobil’s NAFPac (non-aqueous fluid) method is recommended for the proposed Fram development to reduce the risk of sand production. Real-time surveillance will be used to mitigate against sand production post-startup and to determine whether choking back the well is required to prevent damage to the gravel screens. A Sand Management Strategy will be developed for Fram before the field goes online. In addition, the following steps are proposed to monitor any sand production on Fram: 

“Taggants” – a unique chemical marker, will be run as part of the completion to determine if there is a failure of OHGP;



Resman tracers will be run to indicate formation water production (as water breakthrough can increase the risk of sand production); and



Clamp-on monitors on the wells to determine if and when sand is being produced.

The OHGP screen wrap size will be designed to prevent the sand being produced but to allow fines to flow through without plugging. Solids production will be monitored using acoustic gauges so that sand events are responded to promptly. Well start-up and other events will also be managed carefully to ensure that any changes which could affect sand production are not made too quickly.

2.7.7. Water Production and Control Water breakthrough is not expected during the economic life of the project although there is potential to experience very early formation water development which can affect the value of the project. Well placement will be important in mitigating this uncertainty and the completion design will also provide flexibility for future data gathering and to isolate zones that may produce water. Water sensitive chemical tracers will be installed at strategic points along the sand screen completion and the information from the tracers will be used to ensure full clean-up of the wells during well-testing, as well as monitoring break-through during production.

2.7.8. Well Completion Due to the risk of sand production (Section 2.7.6), the lower completion will be an OHGP to control fines production. The base pipe for the screens will be 4.5“ with a screen mesh size of 200 µm or 300 µm. The screens will be installed with an Alternate Path system (shunts) to facilitate the gravel pack operation if there are any open-hole stability issues. A Fluid Loss Valve will be installed above the screens which will be used as a barrier for installing the upper completion. The screens and the Fluid Loss Valve will be hung off a gravel pack packer installed in the 9 ⅝” casing. A 4 ½” upper completion is proposed for both the Fram wells. The completion on both wells will incorporate a surface-controlled Tubing Retrievable Sub-Surface Safety Valve (TRSSSV) at a depth of ~2,000 ft. Two downhole pressure/temperature gauges (DHPG) will be separated by ~300 ft True Vertical Depth (TVD) and will be located above the production packer. A production packer will be set in the 9 ⅝” production casing at ~10,500 ft (3,200 m) Along Hole Depth (AHD) in the G3 well and ~9,900 ft (3,018 m) AHD in the G5 well. To facilitate this type of completion, one hydraulic penetration (TRSSSV control line) and one electrical penetration (DHPG cable) of the tubing hanger is required.

2-20


2.7.9. Well Clean-up and Testing Prior to production, each well will be cleaned to remove any waste and debris remaining in the well in order to prevent damage to the pipeline or topsides production facilities. A well test will also be conducted to obtain reservoir information and fluid samples. The current basis of design is for well clean-up to the drilling rig, as opposed to flow-to-host (Shearwater facilities). Table 2-13 presents an estimate of hydrocarbons to be flared during well clean-up and testing at each of the Fram wells. It is expected that the total flow period per well will be approximately 66 hours. No extended well testing is anticipated. Table 2-13 Well Clean-up and Test Tonnages.

1

WELL

WELL CLEAN UP DURATION (Max hrs)

TOTAL OIL FLARED 1 (Te)

TOTAL GAS FLARED (Million Sm3)1

G3 G5 Total

66 hrs (2.75 days) 66 hrs (2.75 days) 132

41.4 41.4 82.8

0.2 0.2 0.4

High Case (P10)

2.7.10. Drilling Vessels Various support vessels will be associated with drilling operations. These include anchor handling vessels (AHVs), tugs, supply vessels and guard vessels. Table 2-14 summarises the estimated duration that each vessel will be on site and estimated fuel use. This is based on the indicative drilling schedule and drilling durations provided in Section 2.3. Helicopter trips twice per week are assumed with a round trip of 3 hours from Aberdeen. Table 2-14 Estimated vessel and helicopter use during drilling operations. VESSEL TYPE MODU (drilling) AHVs (x3) Standby vessel (transit) Standby vessel (working) Supply vessel (transit) Supply vessel (working) Helicopter (te/hr)

DURATION (Days) 140 36 9 140 46 78 5 twice a week (40 trips, 3hrs each) = 5 days

Total fuel use

WORKING FUEL 1 CONSUMPTION (te/d) 10 54 3 2 6 6 0.7

TOTAL FUEL USE (te) 1,400 1,944 27 280 276 468 4 4,399

NOTES: 1 Historical logistics data

2.8. PIPELINES AND SUBSEA INFRASTRUCTURE Table 2-15 summarises the subsea infrastructure required for production of the Fram Field via the existing Starling subsea facilities approximately 15 km away. Figure 2-9 shows the preliminary Fram Field layout with the proposed new subsea facilities.

2-21

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION Table 2-15 Subsea infrastructure for the proposed Fram 2 Field Development. EQUIPMENT TYPE

DESCRIPTION

Christmas Trees

2 x subsea Christmas Trees for wells G3 and G5 c/w cocoon protection covers.

Manifold

1 x 3-slot Standard Manifold at Fram.

Pipeline

A 15.2 km 10”/16” pipe-in-pipe (PIP) production pipeline from the Fram manifold to the Starling manifold.

Umbilical

A 15.2 km electro-hydraulic-chemical (EHC) umbilical from the Starling manifold to the Fram manifold.

Tie-in Spools

Jumpers

10” tie-in spools from the Fram manifold to the Fram pipeline. 10” tie-in spool from the Fram pipeline to the Starling manifold. 6” Nominal Bore (NB) well production jumpers connecting the wells to the Fram manifold. Well chemical/control umbilical jumpers connecting the wells to the Fram manifold. Umbilical termination assembly (UTA).

Subsea Controls – Fram manifold

Subsea distribution unit (SDU). Electrical distribution unit (EDU). Fram umbilical termination assembly (UTA).

Subsea Controls – Starling manifold

Subsea repeater module (SRM). New Pressure Transmitter / Temperature Transmitter (PT/TT)

Subsea Controls - wells

2 x subsea control modules (one at each tree).

A new manifold will be located in the vicinity of the two Fram wells. A single PIP production pipeline is to be run between the Fram manifold and the Starling manifold. The base case for the pipeline is that it will be surface laid with spot rockdump. A single static main subsea EHC umbilical system will be installed from the Starling manifold to the Fram manifold and will be trenched and buried.

2-22

FRAM FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION

Figure 2-9 Fram subsea layout drawing. 2-23


2.8.1. Well Heads and Trees It is proposed that Fram 2 Field Development will use two trees which were procured as part of the earlier Fram development project. The key functionalities of the trees include: 

Production choke;



One chemical injection point for scale inhibitor and one methanol injection point for methanol injection;



Acoustic sand detectors installed on the production flowbase; and



Subsea “cocoon” protective structure and deflection skirt.

Hydraulic supplies and chemicals along with electrical power and data signal communication to the production trees will be carried within a diverless-installable/retrievable Tree Supply Control Jumper (TSCJ). The fishing-friendly ‘cocoon’ protective structure has a smooth frame that helps to reduce the risk of snagging by fishing nets or penetration by fishing gear (Figure 2-10). The cocoons that will be used each have dimensions of 5 m (L) x 5 m (W) when closed and 14 m (L) x 6 m (W) when open. Rigid well jumper spools will be used to tie-in each of the trees to the Fram manifold.

Figure 2-10 Examples of the subsea protective cocoon structure for subsea trees, closed (left) and open (right).

2.8.2. Manifold A new Fram manifold will be installed to connect two new wells, combine their fluids, provide protection to the control systems and give future tie-ins location. Preliminary coordinates for the location of the manifold are given in Table 2-16. The proposed Fram manifold will be a Standard manifold design measuring c. 9 m (L) x 6 m (W) x 5.15 m (H) and weighing c. 85 te. It will use a standard slab-sided box providing protection from accidental loads (fishing gear interaction) and dropped objects, and support for internal piping, valves and control equipment (Figure 2-11). The manifold will be secured to the seabed by four 0.61 m diameter corner piles which will be piled to approximately 16 m depth. A Remotely Operated Vehicle Support Vessel (ROVSV) will be used to install the manifold structure and piles. The manifold will be designed to be lifted as one complete structure, as opposed to two structures joined together, to minimise the risks of being dislodged by fishing gear capture. Its external faces will be designed to prevent fishing gear penetration, while maximising free-flow of water through the structure. As the trees and manifold will be located within the existing 500 m safety zone (which excludes fishing), a fully overtrawlable design is not

2-24

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION used, as this would involve a larger, heavier and costlier design with bigger seabed footprint and larger vessels for installation.

10” Production Starling Figure 2-11 Representative schematic of the new Fram manifold. Table 2-16 Preliminary Fram manifold location coordinates (ED50 UTM Zone 0N). LOCATION

NORTHING (m)

EASTING (m)

LATITUDE

LONGITUDE

Fram manifold

6,301,760

597,312

56° 50' 53.400" N

1° 35' 43.484" E

The manifold will have three wellbays, two of which will be used initially with the remaining one for future well tie-in. Within the manifold there are two chemical injection points, a connection for a temporary pig launching and a receiving unit. The manifold will also house the Umbilical Termination Assembly (UTA) and Electrical Distribution Unit (EDU) for subsea control.

2.8.3. Gas Production Pipeline, Umbilical and Tie-in Spools 2.8.3.1. PIPELINE A 10’’/16’’ pipe-in-pipe (PIP) configuration has been selected for the Fram gas production pipeline. The pipeline will be constructed using carbon steel, the same material used for the Starling – Shearwater pipeline. A recommended internal corrosion allowance of 5 mm, based on a minimum corrosion inhibitor availability of 97 % will be used to provide a 10 year design life. Corrosion protection will be provided by a 3-layer protection coating with sacrificial anodes used to provide additional protection to account for coating breakdown. The PIP annulus insulation system will either be a branded aerogel type material (Aspen or Cabot) or Polyurethane (PU) foam depending on the annulus space. The new proposed Fram to Starling pipeline will be piggable. The base case is for the pipeline to be surface laid, with potential spot rock dumping as required to provide pipeline anchoring. The snake-laid method will also avoid lateral buckling through expansion. The pipeline will be designed to meet potential impact loads in line with design standards. Lateral buckling design will be in accordance with the latest industry guidance. There are no crossings or interactions with other installations anticipated along the proposed route.

2-25

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION 2.8.3.2. UMBILICAL One Electro-Hydraulic-Chemical (EHC) umbilical will be installed between the proposed Fram manifold and the existing Starling manifold. The umbilical will be of a common design configuration to the current umbilical from Shearwater to Starling, comprising of super duplex stainless steel hydraulic fluid and chemical tubes, quad cables for electrical power and data (signal) transmission and a fibre optic cable for generic future telemetry applications (Figure 2-12). The umbilical will be terminated at the Fram and Starling manifolds with an Umbilical Termination Assembly (UTA).

Figure 2-12 Fram umbilical cross section (based on Starling). The control umbilical will be laid with a 70 m separation between it and the pipeline, coming in to 25 m at the ends within the 500 m safety zones. The corridor width will be 10 m each side of the umbilical. The base case is for the umbilical to be trenched to a depth of 0.6 m to provide protection from damage, for example from fishing gear. The trenching method used will be determined by the installation contractor during detailed design. Typical trenching and backfilling methods are: 

Jetting/Cutting – a non-contact tool that does not pick up a line during trenching. Instead, high pressure water jets are pumped into the seabed to fluidise the soil. The line then sinks under its own weight into the base of the trench, eliminating the need to mobilise additional backfilling equipment. Cutting technology can also be considered to aid the jetting system if required. The trench width for a Jet Trencher is in the region of 2-2.5m



Plough and mechanical backfill – pipeline ploughs are towed through the seabed by a suitable vessel cutting a V shaped trench with spoil pushed to the sides. The pipeline is left exposed in the trench until a backfill plough is deployed to scrape the spoil heaps back into the trench. Some minor seabed disturbance may still be present after backfilling. Plough trenching methods have a wider trench 4.55m.

2-26

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION No rock is required for protection. The jet trencher allows closer access to the infrastructure resulting in less rock / mattresses requirements for protection. Numerous boulders have been identified during the pipeline route survey and this information has been used to identify a suitable pipeline and umbilical route. 2.8.3.3. TIE-IN SPOOLS Tie-in spools from the Fram manifold will be required to connect the manifold to the wellheads, and also from the manifold to the Fram-Starling pipeline. The wellheads for wells G3 and G5 will be connected to the Fram manifold by 6” diameter tie-in spools. A protection cover will be installed over the Fram / Starling manifold tie-in spool and umbilical, with estimated dimensions of 4 m (L) x 3 m (W). The Fram pipeline will be connected to the manifolds at either end with 10” tie-in spools, although to match the 12” Starling pipeline a 10” to 12” transition is required in the Starling manifold tie-in spool. All the Fram spools will be fabricated from 25 % corrosion resistant (CR) Duplex Stainless Steel to help mitigate corrosion as the Corrosion Inhibitor (CI) needs a minimum length of mixing before becoming effective. They will also be designed to take into account hydrogen induced stress cracking (HISC). The tie-in spools will be installed using Diving Support Vessel (DSV) and will be protected from fishing gear by concrete mattresses. The wellhead to manifold tie-in spools are not required to be piggable.

2.8.4. Stabilisation and Protection Materials The Fram pipeline will be surface laid between the Fram and Starling drill centres using a snake-lay operation. The snake lay configuration is designed to prevent local buckling without the requirement for additional weight of rockdump, although the pipelines ends will need to be checked for stabilisation. On completion of pipelay, the post lay route will be subject to an out of straightness (OOS) survey. Any props, spans, etc highlighted during the OOS survey will be analysed against the design and only if there is a risk of local buckling/pipeline walking, will rockdump be required. It is currently anticipated that up to 9,800 te of spot rockdump may be required along the pipeline route to provide stabilisation local to the crown of the lateral buckles of the layout. In the worst case scenario a maximum of seven locations will be protected with an anticipated berm’s width of 7 m and length of 100 m, resulting in approximately 4,900 m2 of seabed being covered by the protection material. Graded crushed rock (1” – 6” in diameter) will be used. No rock dumping is anticipated on the umbilical route, which will be trenched and buried. A small length of pipeline end section, the pipeline tie-in spools and the well tie-in spools (unless located within the confines of a protection structure) will be protected with concrete mattresses. As a worst case, it is anticipated that a maximum of 150 mattresses measuring 6 m (L) x 3 m (W) x 0.15 m (H), will be required. An estimated 100 te of grout and/or sand bags (25 kg each) will be used for remedial work along the pipeline length with an additional 100 te for tie-in support split evenly between the Fram manifold and the Starling manifold Table 2-17. Table 2-17 Anticipated quantities of rockdump, mattress and grout bags required at the proposed development. ITEM

NUMBER / MASS

Number of mattresses at the proposed Fram manifold location (360 m)1

80

Number of mattresses at the existing Starling manifold location (360 m)1

70

Mass of rockdump

9,800 te

Mass of grout bags

200 te

1

Where each mattress is laid length ways across the tie-in spool / pipeline + 10% contingency.

Final quantities of rockdump will be defined during detail design.

2-27


2.8.5. Subsea Installation Vessels Various support vessels will be associated with the subsea installation phases of the Fram 2 Field Development. Vessel type, duration and fuel usage by vessels during installation are given in Table 2-18. Table 2-18 Vessel type and fuel usage during installation of the subsea infrastructure at the Fram 2 Field Development. VESSEL TYPE ROVSV (manifold installation) Pipelay route boulder clearing (DSV) Pipelay (transit and working) Pipelay support vessel Trenching vessel Umbilical installation vessel (ROVSV) Rockdump vessel DSV for tie-in / testing Total fuel use

DURATION (Days) 8 5 26 31 10 14 8 41

WORKING FUEL CONSUMPTION (Te/d)1 10 18 23 7 17 10 15 18

TOTAL FUEL USE (Te) 80 90 598 217 170 140 120 738 1,335

1

The Institute of Petroleum, 2000

2.8.6. Commissioning Once the manifold, pipeline, umbilical and tie-in spools have been installed, pre-commissioning and commissioning will be carried out to ensure system integrity, to test for any leaks, to dewater the pipeline system and to prepare the subsea control and chemical injection system for introduction of hydrocarbons. During all operations, any chemicals used and/or discharged to sea (either directly or through the produced water stream) will be subject to a permit under the Offshore Chemical Regulations 2002.

2.8.7. Utilities 2.8.7.1. Drains System Drainage at the Shearwater system consists of three systems: open hazardous drains, open non-hazardous drains and closed drains. The open drains system is segregated into the hazardous and non-hazardous open drains each with separate collection headers and seal pots. 2.8.7.2. Power Generation The combustion equipment on Shearwater includes: 

Three Solar Mars 100 gas turbines for main power generation;



Three Solar Mars 100 gas turbines for compressor drive;



One MTU diesel engine for emergency/black start power requirements;



Two diesel engines for driving fire pumps; and



One Airpac diesel engine for emergency air compression.

Normal electrical load on Shearwater is approximately 13.7 MW. Diesel oil is supplied by boat to the Shearwater A platform and stored in the ‘A’ platform crane pedestal diesel tank. 2.8.7.3. Production Chemicals Chemicals are used during the production of hydrocarbons to maintain process efficiency, for example demulsifiers improve the separation of oil and water; corrosion inhibitors protect the plant; scale inhibitors slow down the build-up of scale in pipework and valves; biocides reduce microbial growth.

2-28

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION Chemical injection supply for the Fram 2 Field Development will be via an extension of the Starling umbilical, with supply from the existing topsides Starling chemical injection pumps and tanks. The pumps have sufficient capacity and head to inject at Fram and the storage tanks have sufficient capacity based on a 14 days resupply schedule and therefore no modifications to the injection facilities are required. The system however will require topsides modifications for injection of KHI (see 2.6.3). Chemicals for the proposed Fram 2 Field Development are envisaged to be the same as used for Starling production and will include: 

Methanol – to prevent hydrate formation in the system during the start-up only;



Corrosion inhibitor – to prevent interior corrosion of the pipeline;



Scale inhibitor – to prevent scale deposits forming in the system, and



Kinetic hydrate inhibitor – to reduce the risk of hydrate formation in the Fram and Starling pipelines.

Hydrates management, and associated change of current corrosion inhibitor are discussed further in Section 7, Discharges to Sea.

2.8.8. Inspection and Maintenance During Operations No operational pigging is planned for the Fram pipeline and no permanent pigging facilities will be provided in the pipeline system. The components of the subsea pipeline will be designed to allow passage of an intelligent pig should it be required to determine the extent of any damage or internal corrosion.

2.9. STARLING SUBSEA FACILITIES OVERVIEW The Starling Field is located approximately 15 km away from the Fram Field. It was developed in 2008 and consists of three gas-condensate subsea wells. The wells are tied back to a common manifold and connected through a 33 km multiphase flowline to the Shearwater platform where the fluids are processed and then exported. Coordinates for the location of the manifold are given in Table 2-19. Table 2-19 Starling manifold location coordinates (ED50 UTM Zone 0N). LOCATION

NORTHING (m)

EASTING (m)

LATITUDE

LONGITUDE

Starling manifold

6,313,399

587,449

56° 57’ 16.744” N

1° 26’ 16.015” E

The Starling flowline is a 12”/20” carbon steel pipe-in-pipe configuration. Corrosion is managed through the injection of corrosion inhibitor at the subsea manifold. The Fram pipeline will be tied in directly to the existing 12” Starling manifold main header. The remote actuation of the main header isolation valve will be removed and the valve will be locked open to prevent formation of hydrates in the locked-in volume of the Fram pipeline should the valve fail. PT/TT instrumentation will be added to monitor the Fram pipeline manifold arrival conditions. A Subsea Repeater Module (SRM) will be added to enable communication with the field. A 2” DBB valve will be installed to permit precommissioning of the Fram pipeline.

2.10. SHEARWATER PROCESS FACILITIES OVERVIEW The Shearwater complex is located in Block 22/30 of the CNS approximately 25 km north east of the Fram Field. The complex comprises Shearwater A, the well-head platform and Shearwater C, a normally manned integrated Process, Utilities and Quarters (PUQ) platform. The two platforms are linked via an 80 m bridge. Shearwater is the host platform for the Shearwater reservoir platform based wells and the Scoter, Merganser and Starling subsea satellite tiebacks. The Shearwater facilities were originally designed for production from high pressure/high temperature (HP/HT) platform wells drilled over Shearwater A with an operating pressure of 80 – 90 barg. Since the original design, subsea tiebacks of the normal pressure and normal temperature (NPNT) gas condensate fields Scoter, Merganser and Starling have been added to Shearwater. In addition to these subsea tie-backs, 2-29

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION a low pressure (LP) compression project was undertaken to enable a reduction in the first stage separator pressure. The design capacity for Shearwater is provided in Table 2-20. Table 2-20 Shearwater Design Capacity. PARAMETER Shearwater capacity Shearwater historic peak

PRODUCTION FLUID OIL (tonnes/day)

GAS (m3/day)

WATER (m3/day)

11,792

11,583,376

795

1

1

3822

7,972

10,376,000

NOTES: 1 Oil and gas production peaked in 2004 2 Water production maximum capacity reached in 2016.

The Shearwater C platform is capable of operating in either high pressure (HP) or low pressure (LP) mode. HP mode is considered to be when the first stage separator is operating at approximately 80 barg and was the case when only the platform wells were producing. Fram fluids will arrive at SWA via the Starling riser. Upon arriving at the Shearwater platform, production from Starling and Fram will be commingled with that from the Shearwater wells and other satellites, separated and processed before being exported. Gas is exported through the SEAL pipeline system to the Bacton Gas Plant and condensate is exported through FPS to the Kinneil Terminal.

2.10.1. Process Overview Well stream fluids from Shearwater A are transferred across a pipe bridge to the main processing facilities on Shearwater C. The Shearwater C platform has a single process train as shown in Figure 2-13. Produced fluids are received topsides where the pressure is reduced through chokes before being directed to the 1st stage separator (V-1010). This vessel operates as a High Pressure (HP) three phase (gas/condensate/water) separator; condensate is routed to the 2nd stage separator (V-1210); gas is routed to the dehydration and amine systems; and water is directed to the produced water system. Within the 2nd stage separator further three-phase separation takes place at Low Pressure (LP). 2.10.1.1. Produced Condensate Water and gas are removed from the produced condensate in the 1st and 2nd stage separators. Condensate leaving the 2nd stage separator is pumped via booster pumps to the liquid metering package, prior to export. The export temperature is controlled by the condensate cooling system.

2-30


Figure 2-13 Shearwater process flow diagram. 2.10.1.2. Produced Gas Gas is separated from the produced fluids at the 1st and 2nd stage separators. Separated gas flows via the amine system, which is the primary mechanism for the removal of corrosive gases (i.e. H2S and CO2), to the gas dehydration system where water is removed, then to export. 2.10.1.3. Produced Water The original produced water treatment package was designed for a maximum of 5,000 bbls/day (795 m3/day) and consists of an HP hydrocyclone, two LP hydrocyclones, a produced water degasser, and a produced water recycle pump. Produced water from the 1st stage separator is routed to the HP hydrocyclone (V-4015) whilst produced water from the 2nd stage separator is routed to the LP hydrocyclones (V-4016 and V-4017). Produced water from all hydrocyclones is then routed to the degasser vessel (V-4030). Gas separated at this point is routed to the LP flare drum. From the degasser vessel produced water could either undergo further treatment in the new treatment package, can be discharged overboard via the PW caisson (V-4010), or can be routed back to the 2nd stage separator via the recycle pump (P-4041). Recycling of produced water enables to maintain a minimum flow through the hydrocyclones. The new treatment package was installed and commissioned on Shearwater in 2016. The package consists of membrane system and the Compact Flotation Unit (CFU), and its total maximum capacity is 4,400 bpd, however the planned water debottlenecking will increase this to ~8,000 bpd. Depending on the treatment requirements, produced water leaving degasser can either flow through membrane and CFU, or can bypass either of these two elements. If fluids are of sufficient cleanliness, they can be discharged directly overboard downstream of the degasser via the PW caisson, bypassing the entire package.

2-31


Figure 2-14 Simplified process sketch of Shearwater produced water system. 2.10.1.4. Sand Any sand which is produced to surface at Shearwater is allowed to settle in the separators. The sand is periodically removed and shipped to shore for disposal. Therefore, there is no discharge of sand to sea from Shearwater.

2.10.2. Flaring and Venting The HP flare system is designed to collect and dispose of hydrocarbon releases from all sources with a design pressure greater than 16 barg. The LP flare system is designed to collect and dispose of hydrocarbon releases below 16 barg. An atmospheric vent is provided for maintenance purging of the pressure vessels connected to it. It is not intended for vessel depressurisation, only for purging at atmospheric pressure. Liquids are collected and drained and the vent system is routed up the flare tower for emissions disposal.

2.10.3. Fram Production 2.10.3.1. Hydrocarbon Processing At the Starling manifold, the Fram and Starling production fluids will be comingled and further transported to the Shearwater platform, via the existing Starling subsea infrastructure. As per the existing Starling production, the Fram and Starling fluids will be further comingled with other productions on the Shearwater platform before being processed and subsequently exported through the SEAL and FPS pipelines. At Shearwater, Fram fluids will be processed through the existing first stage separator (expected to be operating in LP mode) with gas being processed through the LP compressor and gas plant. The capacity of the LP compressor and processing train will remain within the current operating envelope with the additional gas production from Fram. It is also expected that the condensate handling and produced water systems will have sufficient handling capacity to accommodate the incremental condensate and water production from Fram. Fram (and Starling) production fluids cannot be processed across the Shearwater platform without being commingled with the existing satellite developments (Scoter, Merganser), the platform wells, or a combination of both satellite and platform wells. This is because there is insufficient heat in the Fram (and Starling) only fluids to achieve the export condensate true vapour pressure (TVP). 2-32

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PROJECT DESCRIPTION 2.10.3.2. Produced Water An evaluation of PW discharge options has been carried out for Fram, including produced water re-injection PWRI and overboard disposal at Shearwater. Given the very low risk of water breakthrough in Fram, it is forecast that the proposed development will only produce condensed water in low volumes, with a maximum of 17.4 m3/day. Water production is anticipated to be less than 2 % of the total liquid production rate. It has been concluded that a PWRI option is not suitable for the project due to technical and economic reasons. Fram produced fluids will be commingled with Starling and Shearwater fluids, treated and discharged using the existing Shearwater PW treatment system. 2.10.3.3. Sand No modifications required. For a discussion of sand production, see Section 2.10.1.4. 2.10.3.4. Flaring and Venting As no additional equipment is being added to the Shearwater topsides there is no requirement to implement measures to manage the peak topsides blowdown rate which should be within the existing flare capacity. An additional amount of non-continuous flaring is predicted during well testing, field start-up and pipeline depressurisation. 2.10.3.5. Utilities 2.10.3.5.1. Drains No modifications to the drains system of the Shearwater platform are required to accommodate Fram fluids. 2.10.3.5.2. Metering and Control The combined Fram and Starling production will be continuously measured by the existing Starling wet gas meter which is located on Shearwater before the fluid is commingled with the other production from the Shearwater platform. 2.10.3.5.3. Power Generation No new combustion equipment is required in order to process Fram. There may be an incremental increase in combustion emissions due to increased processing requirements at Shearwater associated with Fram Emissions associated with the bringing online of Fram are discussed in Section 6, Emissions to air.

2.10.4. Operations Once Fram is transferred to the Operate phase, it will be managed by the existing Shearwater operational organisation. The Shearwater Maintenance Reference Plan will be updated to include the Fram project. The Subsea Inspection, Maintenance and Repair team will be responsible for maintaining the integrity of the subsea system. Umbilical management will be carried out in line with the Subsea Umbilical Integrity Management Strategy. The addition of the Fram subsea wells will require minimal intervention from the Control Room Operator (CRO) during normal operations. Similar to other Shearwater satellites, intervention will be required for well clean-up operations and during any process upsets.

2.11. POSSIBLE FUTURE EXPANSION OR MODIFICATION The proposed Fram subsea system is not specifically designed for future expansion however, adequate isolation will be provided in the manifold to allow for future well tie-in via the spare manifold slot and a future tie-in via the main production header. The suitability of the pipeline and materials chosen for production at Fram will need to be assessed on a case by case basis for any future expansion or modification.

2-33


2.12. DECOMMISSIONING As Fram is a separate field, this section does not explore the decommissioning of the existing host facilities or export pipeline infrastructure. At EOFL a decommissioning programme and associated EIA will be prepared in support of any decommissioning activities as per regulations. As a result, the development design is based on the following assumptions for decommissioning: 

The wells will be plugged and abandoned;



Recovery of the manifold and tie-in spools; and



The umbilical to be left in-situ, surface laid pipeline may be removed.

Pipeline and subsea structures At this time, it is anticipated that the subsea activities would involve the disconnection of the pipeline from the manifold and that the pipeline will be flushed and capped, and may be removed. The proposed design and installation method of the pipeline do not preclude future removal. However, decommissioning of the surface laid pipeline will be the subject of comparative assessment to determine the best option on the basis of 5 main criteria (Safety, Environment, Technical, Societal and Economic). The manifold piles will be cut off below the seabed level for retrieval. In accordance with current legislation, it is expected that the manifold and subsea structures will be returned to shore for reuse/recycling/disposal. There will be third party confirmation of seabed clearance. Wells The production wells will be plugged and permanently abandoned in accordance with the OGUK Guidelines for Suspension and Abandonment of wells (or applicable guidance at that time). All well programmes will have been reviewed by the HSE Offshore Safety Department as required under the Design and Construction Regulations. On completion of the well abandonment programme each conductor and internal tubing will thereafter be cut below the seabed. The subsea Wellheads will then be recovered at location utilising either a DSV or semisubmersible mobile drilling unit. Nearer the time of EOFL, a full decommissioning plan will be developed in consultation with the relevant statutory authorities. The plan will be designed to ensure that potential effects on the environment resulting from the decommissioning of the facilities are considered and minimised.

2-34



2-35

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT BASELINE ENVIRONMENT

3.

BASELINE ENVIRONMENT

3.1. INTRODUCTION An understanding of the baseline environment is required in order to identify the potential environmental impacts of the development and to provide a basis for assessing the potential interactions of the proposed project with the environment. The environmental receptors considered include benthos, birds, fish, marine mammals and other sea users.

3.2. ENVIRONMENTAL BASELINE SURVEYS The Fram Field is situated in blocks 29/3c, 29/8a, 29/4c and 29/9c of the CNS approximately 221 km east of Aberdeen, 50 km from the UK/Norway median line in water depths of approximately 97 m (Figure 3-1). In order to understand potential environmental impacts from the Fram Project, a number of environmental baseline surveys were carried out to inform the understanding of the main physical, biological and human characteristics in the area. The main surveys referenced listed below and their location shown in Figure 3-1. 

Gardline Environmental Ltd (GEL) (2010) Fram Development Environmental Baseline Survey (EBS) United Kingdom Continental Shelf (UKCS) Blocks 29/3c, 29/08a, 29/4c and 29/9c, conducted 9th to 21st March 2010;



Fugro Survey Limited (FSLTD) (2011) Drilling centre site survey and pipeline routes survey UKCS Block 29/3C conducted 25th to 29th June 2011;



Fugro (2013) Fram to Curlew pipeline route survey in Blocks 29/3, 29/7 and 29/8 Habitat Investigation Results conducted in 5th to 16th October 2013; and



Fugro (2016) Fram to Starling pipeline route survey in Block 29/3 (EBS and Habitat Assessment) conducted in 23rd July to 6th August 2015 by FSLTD and Fugro EMU Limited.

3-1


Figure 3-1 Location of the Fram Field and Fram environmental surveys. 3-2


3.3. PHYSICAL ENVIRONMENT The type and distribution of marine life is influenced by the physical conditions of the surrounding environment, biological interactions and anthropogenic activities. These physical factors, which include, currents and tides, wave, temperature, salinity and wind also help set the design parameters for offshore facilities and influence the fate and behaviour of any emissions and discharges from an installation and the risk associated with them.

3.3.1. Meteorology The CNS area has an average wind speed of around 9 m/s at 10 m above mean sea level. Although the prevailing wind direction is from the south west, winds do occur from all directions throughout the region and there is some seasonality to the directional distribution. Low pressure systems cause the strongest winds and these usually track from approximately south-west to north-east across the north-west European Continental Shelf and have central pressures in the range 950 to 1,040 mb. Any low with a central pressure below 990 mb may result in gales. There is a strong seasonal trend, with generally calmer winds during the period June to August, and the highest probability of strong winds in the period November to March. Occasional strong winds may occur in September and October due to extra-tropical storms (Shell, 2013). Analysis of the wind rose shows the occurrence of winds from all directions, although winds from the southsouth-west and west dominate in the vicinity of the proposed project (Figure 3-2), with little seasonal variation. Wind speeds exceed 5.3 m/s for 75 % of the year, 8.1 m/s for 50 % of the year and can reach 19.8 m/s for 1 % of the year at 10 m above sea level. The hourly average wind speed with an average recurrence of 100 years is 35 m/s at 10 m above mean sea level (Shell, 2013).

Figure 3-2 Hourly Mean Wind Speed Rose and Directional Distribution for the Fram Field (Shell, 2013).

3.3.2. Temperature and Salinity Information from the National Marine Plan Interactive (NMPi) Map (Scottish Government NMPi, 2016) indicates that annual mean surface temperatures within the area range between 9 and 10 °C whilst annual mean seabed temperatures range from 7 to 8 °C. 3-3

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT BASELINE ENVIRONMENT Salinity varies with season and variations in ocean currents. The annual mean surface and seabed salinity range is approximately 34 to 35 ‰ (Scottish Government NMPI, 2016).

3.3.3. Water Masses, Currents and Tides Water masses, local current speeds and direction influence the transport, dispersion and ultimate fate of marine discharges, nutrients, plankton and larvae (OSPAR, 2010). Cyclonical circulation in the North Sea is driven by a combination of winds, tidal forcing and topographicallysteered inflows. The predominant regional current in the CNS originates from the vertically well-mixed coastal water and Atlantic water inflow of the Fair Isle/Dooley current, which flows around the north of the Orkney Islands and into the North Sea (BMT Cordah, 1998; North Sea Task Force, 1993). The background, or residual, flow in the CNS (associated with North Sea circulation patterns) is typically 0.2 m/s towards the south (DTI, 2001). The proposed project is located in an area influenced by northern North Sea water and the Dooley current (Figure 3-3) (DTI, 2001; Baxter et al., 2011).

Figure 3-3 Prevailing Ocean Currents in the North Sea. Semi-diurnal currents are relatively weak in the offshore CNS (DTI, 2001; Baxter et al., 2011). Total current is a combination of “residual” (oceanic circulation and surges) and tidal induced currents. In an area such as the CNS the oceanic circulation is small and therefore the residual current is dominated by storm surges. In the area of the Fram Project there is approximately equal contribution to the extreme currents from surge currents and tidal effects. At the Fram location tidal currents dominate and the dominant current flow direction is approximately north-south (Shell, 2013). The total current speed in the Fram Project area that is exceeded, on average, 75 % of the time is 0.06 m/s in the upper half of the water column. The total current speed at 1 meter above the seabed that is exceeded, on average, 75 % of the time is 0.04 m/s. The tidal currents in the vicinity of the Fram Project area are typical of the CNS with a mean spring tidal current speed at the surface

3-4

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT BASELINE ENVIRONMENT of 0.36 m/s and at one metre above the seabed 0.20 m/s (Shell, 2013). Residual current speed and total current speed are given in Figure 3-4 and Figure 3-5.

Figure 3-4 Operational mean-depth residual current speed versus direction (towards which currents are flowing).

3-5

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT BASELINE ENVIRONMENT Figure 3-5 Operational mean-depth total current speed versus direction (towards which currents are flowing). The average wave height in the CNS region follows a gradient decreasing from the northern area of the Fladen/Witch Ground to the southern area of the Dogger Bank. The annual mean wave height within the Fram Field ranges from 2.11 – 2.40 m with an annual mean power which ranges from 18.1-24.0 kW/m (Scottish Government NMPI, 2016).

3.3.4. Bathymetry Water depths, within the geophysical survey area, ranged from 93.5 m LAT at the north end of the pipeline route to 99.8 m LAT in the south. The surveyed pipeline route sloped gradually (10 m in length in ICES rectangle 42F1) (Scottish Government, 2016).

YEAR

J

F

M

A

M

J

J

A

S

O

N

D

TOTAL (including disclosive days)

2015 2014 2013 2012 2011

D D 38 D

D D -

D D 45 24

14 D D D 25

23 D D 27

20 48 16 16 14

24 D 86 D

D D 41 7

39 D D D D

37 D 21 53

51 D 19 25 69

D D D D D

195 147 90 296 282

UK TOTAL

42F1 as a % of UK

126,406 129,850 183,413 185,182 188,389

0.15 0.11 0.05 0.16 0.15

Effort data is shown for rectangles where five or more UK >10m vessels undertook fishing activity in a given year. Rectangles in which less than five >10m vessels undertook fishing activity are identified but the data is disclosive (D) so not shown. The absence of an ICES rectangle for each data set indicates that no UK >10m vessel undertook fishing activity in the given rectangle in the given year.

The fishing effort by UK vessels for ICES rectangle 42F1 and the surrounding area is shown in Figure 3-28. While fishing effort in ICES rectangle 42F1 is generally higher than the fishing effort in neighbouring ICES rectangles, it is relatively low in comparison to other ICES rectangles within the UKCS. For example, in ICES rectangle 37E4 in the Irish Sea, fishing effort was 6,534 days in 2015. Fishing effort in 42F1 by foreign vessels is low. In 2015, ~99% of fishing effort in 42F1 was carried out by UK vessels (Marine Scotland Science, pers comm, May 2017).

3-52


Figure 3-28 Fishing effort in the vicinity of Blocks 29/3, 29/8, 29/4 and 29/9. The annual value of landings for fish and shellfish in each ICES rectangle in and around the development area for the years 2011 to 2015 by value (£) is shown in Figure 3-29. It can be seen that there was variation the value of landings between years and that shellfish made up the majority of the value of the catch in this area.

3-53


Figure 3-29 Fisheries landings (£) by species type (Scottish Government, 2016). The average weight landings of pelagic, demersal and shellfish species in 42F1 was 107, 239 and 93 tonnes respectively (Table 3-13). These landings equate to 0.07 % of total UK reported landings of demersal, pelagic and shellfish species respectively. The overall total landings contributed to 0.07 % of the average total recorded UK landings 2011 to 2015, again suggesting the area is of relatively low importance as a fishing ground to the UK fishing industry.

3-54

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT BASELINE ENVIRONMENT Table 3-13 Average annual weight of landings from ICES blocks as a percentage of the average UK total landings 2011 to 2015 (Scottish Government, 2016). SPECIES TYPE

ICES RECTANGLE

Average annual weight of landings 2011-2015 (Tonnes)

Demersal

Pelagic

Shellfish

Total

41F1

58

53

74

185

42F0

420

1,444

140

2,005

42F1

107

239

93

440

42F2

108

27

1

135

43F1

88

345

11

444

156,432

330,163

132,157

618,752

41F1

0.04

0.02

0.06

0.03

42F0

0.27

0.44

0.11

0.32

42F1

0.07

0.07

0.07

0.07

42F2

0.07

0.01

0.00

0.02

43F1

0.06

0.10

0.01

0.07

Total annual average weight of landings in the UK 2011-2015 (Tonnes)

Average annual weight of landings as a % of UK total 2011-2015 (%)

Scotland’s seas support diverse commercial fisheries, including both bigger vessels (length ≥15 m) and smaller vessels (length 15m in length in the North Sea using demersal mobile gears, Nephrops mobile gears and pelagic herring gears (Kafas et al., 2012). 3-56


3.6.2. Shipping Shipping activities in the North Sea are categorised by the Oil and Gas Authority (OGA) (2016b) to have either: very low; low; moderate; high; or very high shipping density. Figure 3-31 shows the level of shipping activity is very low in Block 29/3, low in Blocks 29/4 and 29/8 and moderate in Block 29/9. Data from the Marine Management Organisation (MMO) shows the annual average shipping density around the Fram Field area was generally moderate to very low in 2014 (Figure 3-32) (MMO, 2016).

Figure 3-31 Shipping density in the vicinity of the Fram Field as categorised by OGA (OGA, 2016b).

3-57


Figure 3-32 Average annual shipping density in 2014 (MMO, 2016). Shell commissioned Anatec Limited (Anatec) to assess the ship routing and risk of collision at the proposed Fram location (Anatec, 2012) The shipping routes identified by a 10 nm search of ShipRoutes around the Fram location are presented in Table 3-14 and Figure 3-33 in ascending order of Closest Point of Approach (CPA) (Anatec, 2012). ShipRoutes identified a total of 17 shipping routes passing within 10 nm of the Fram location, which are trafficked by an estimated 512 ships per year. This corresponds to an average of 1 to 2 vessels per day (Anatec, 2012) which is considered to be “low” to “moderate” traffic for this area in the North Sea (DECC, 2014). Table 3-14 Ship Routes Passing within 10 nm of Fram (Anatec, 2012). ROUTE NO. 1 2 3 4 5 6 7 8 9 10 11 12 13

3-58

DESCRIPTION Forth-Norway S* Tees-Bomlafjorden* Aberdeen-Jade/Judy b* N Norway/Russia-Humber Kattegat-Tay* Aberdeen-Judy/ Jade Field* Lerwick-Dover Strait* Boknafjorden-Tyne b* Humber-Froysjoen* Aberdeen-Jade/Judy a* Forth-Norway S N* Anasuria-Hamburg* Boknafjorden-Tyne a*

CPA (NM)

BEARING (°)

SHIPS PER YEAR

% OF TOTAL

0.7 0.8 2.0 2.0 2.3 2.4 3.4 4.4 4.6 5.2 5.4 5.7 6.8

163 303 7 105 350 186 69 312 105 190 346 38 134

35 15 12 95 95 26 35 6 15 48 10 12 19

7 3 2 19 19 5 7 1 3 9 2 2 4


ROUTE NO. 14 15 16 17

DESCRIPTION Aberdeen-Ekofisk* Hamburg-Kirkwall Kattegat-Forth N2* Tay-Norway S

CPA (NM)

BEARING (°)

7.0 7.8 8.0 9.4

191 44 166 344

TOTAL

SHIPS PER YEAR 26 15 43 5 512

% OF TOTAL 5 3 8 1 100

* Where two or more routes have identical Closest Point of Approach (CPA) and bearing they have been grouped together. In this case, the description lists the sub-route with the most ships per year.

Figure 3-33 Shipping Route Positions within 10 nm of Fram (Anatec, 2012). The overall breakdown of traffic by vessel type is presented in Figure 3-34. It can be seen that almost half of all vessels passing within 10 nm of the Fram location are cargo vessels accounting for 47 % of the vessel movements per year. Tankers and Offshore support vessels make up the majority of all other shipping in the area, with 25 % and 22 % respectively. Ferry routes are rare in the area and account for only 6 % of the traffic. It can also be noted that the majority of vessels fall into the size range 1,500 - 5,000 DWT accounting for approximately 62 % of shipping in the area (Anatec, 2012).

3-59


Offshore Support Vessels 22% Cargo Vessel 47%

Ferry 6% Tanker 25%

Figure 3-34 Vessel Type Distribution within 10 nm of the Fram development (Anatec, 2012). The Anatec ship density model was used to calculate the density of shipping with each cell based on the ship routeing database. A thematic map showing the estimated variation in shipping density around the location is presented in Figure 3-35. It can be seen that the higher density of shipping is predominantly concentrated to the east and the south of the Fram location. The higher density to the east is representative of traffic transiting between Norway/ Russia and Humber Ports (Routes 4 and 9). The higher density in the south is representative of offshore support vessels transiting from Aberdeen to the Jade and Judy Platforms (Route 10). Lower levels of shipping were recorded in North West of the Fram location (Anatec, 2012).

Figure 3-35 Shipping Density Grid at Fram (Anatec, 2012).

3-60


3.6.3. Submarine Cables There are no functioning or disused telecommunications and electricity transmission cables in the immediate vicinity of the proposed project. A Telecom Community Network Services (CNS) fibre optic cable is located approximately 55 km to the northeast (KISORCA, 2016).

3.6.4. Oil and Gas Exploration The proposed development lies within a highly developed oil and gas area in the North Sea (Figure 3-36). The closest installations to the Fram Field are the; the Total West Franklin Well Head Platform (WHP) platform approximately 18 km northeast; the Shell Curlew FPSO approximately 22 km southwest and the CNR Banff FPSO approximately 25 km northeast.

Figure 3-36 Oil and gas installations within the vicinity of the proposed development.

3.6.5. Military Activities The North Sea is used as a training ground and for routine operations by aircraft, surface craft and submarines from a number of countries. Practice and Exercise Areas (PEXA) charts, produced by the UK Hydrographic Office, provide information relating to military activity within the UKCS. These are kept up to date through the Admiralty Notices to Mariners service and show areas which are in use or available for use by the Ministry of Defence for military practice and exercises (DECC, 2009; Baxter et al., 2011). An aircraft PEXA is located 15 km to the west of the proposed project (Figure 3-37). Based on the available public knowledge about the location of the MoD submarine exercise areas, Fram does not coincide with any submarine craft exercise areas (Baxter et al., 2011), although the area might be occasionally used by NATO exercises (DECC, 2009).

3-61


Figure 3-37 Location of wrecks and the PEXA in the vicinity of the proposed Fram field development.

3.6.6. Wrecks A number of wrecks exist within the CNS (Cordah, 2001). There are 1,157 confirmed wrecks within the SEA 2 area mainly located in the central and southern sections of the North Sea. Historic wrecks are protected under the Protection of Wrecks Act, 1973. Three offshore wrecks lie within the proposed project area, all confirmed as non-dangerous wrecks and not of historic value. A possible submarine wreck and a possible obstruction wreck have been recorded 12 km and 7.5 km respectively from the Fram development area. The trawler wreck (Bishop Burton) has been also identified in the area and it is located 9 km from the proposed Fram manifold (Figure 3-37). Following the discovery of a possible wreck during the Fugro (2016) survey (Figure 3-38), Shell commissioned Maritime Archaeology Ltd to carry out an archaeological assessment of the area (Maritime Archaeology Ltd, 2017). The desk-based assessment identified 39 known shipping losses by utilising a 75 km search radius for the wreck centre. This large search area was used in order to counter issues of accurate fixing of marine losses, particularly in times of war; some positions are accurate but the majority are unconfirmed, very general locations. All losses have been provided with an accuracy rating based on the method of positioning used. Assessment of side scan and multibeam bathymetry data revealed a site between 36 and 37 m in length and standing 2.5 metres off the seabed. The photographic data enabled a copper sheathed and (inferred) wooden hull to be identified, indicative of a sailing vessel. Further, an iron flywheel featuring S-shaped spokes of the type commonly fitted to mid-19th century sailing vessels dates the wreck to the 1860s -1880s. Of the 39 losses identified, three match these details: Neptunus, M. Rossval and Harboe, all three-masted barques built in the 1870s and all marine casualties in 1915, a single year of the First World War and the first period of unrestricted maritime warfare.

3-62

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT BASELINE ENVIRONMENT Based on the proportions and the reported position, the best match for the uncharted wreck in question is the Swedish sailing barque M. Roosval, built in 1874. Though the precise dimensions are currently unknown, crude measurements can be extracted from a surviving painting of this vessel. These, and the overall tonnage, indicate that the wreck is more likely to be M. Roosval than Neptunus or Harboe. Further site investigation work would be required to positively identify this wreck. The wreck has been assessed as medium archaeological significance according to the Department for Culture, Media and Sport (DCMS) assessment criteria, and medium archaeological potential according to assessment criteria. Due to its location and the extent of scour visible in the bathymetry, the wreck site has been assigned an Archaeological Exclusion Zone (AEZ) of 100 m radius from the visible outline of the wreck. With the implementation of the proposed mitigation measures, any impacts the Fram Field Project might otherwise have had on the identified wreck are either avoided completely or are considered to be negligible.

3-63


Figure 3-38 TR18 and TR18a area of the newly identified wreck and anthropogenic debris (Fugro, 2016).

3-64

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT IMPACT ASSESSMENT APPROACH

4.

IMPACT ASSESSMENT APPROACH

In order to determine the impact the offshore scope of the proposed Fram 2 Field Development may have on the environment an Environmental Impact Identification workshop (ENVID) was undertaken following a structured methodology. The purpose of the ENVID is to identify potential environmental impacts, from both planned activities and unplanned events, associated with the project. The significance of each impact is determined and then appropriate mitigation measures, controls and safeguards to minimise the impact identified. Implicit in the ENVID is a clear and documented assessment of the impacts from each phase of the proposed project. The significance of the potential impacts of the proposed project are assessed in terms of: 

Magnitude based on the size, extent and duration of the impact;



The sensitivity of the receiving receptors; and



The likelihood of an unplanned event occurring.

4.1. IMPACT IDENTIFICATION AND ASPECTS Firstly, potential impacts are identified using the environmental aspects listed in Table 4-1. For example, impacts associated with gaseous emissions include contributions to global warming. Emissions are caused by a number of project activities these sources include both planned activities, e.g. combustion emissions during production, and unplanned events, e.g. well blow out. Table 4-1 Environmental aspects used for the ENVID. ENVIRONMENTAL ASPECT Emissions to air NO

1

Gaseous Emissions

DEFINITIONS/COMMENTS The emission of hazardous gases (such as but not limited to CO2, NOx, SOx, CO, SO2, H2S, CH4) resulting from flaring off, venting, heating, leaks, transport, etc. Comment: this concerns continuous emissions (flares, vents, heating installations, losses through leaks), discontinuous emissions (well tests, depressurising installations), leaks of HCFCs from cooling installations and emissions arising from accidental fires and explosions.

Discharges to water The controlled discharge to surface water of production water, household waste water, decontamination water, drainage water at well points, (contaminated) Fluids and other rainwater and discharge to sewer as part of normal operations. 2 materials into The discharge of oil, chemicals and other materials as a result of incidents including water for example vessel collision and dropped objects. Comment: this concerns both discharges offshore and to surface waters onshore. Effects on land including groundwater The controlled or uncontrolled discharge of liquids such as rainwater, oil and condensate into the soil (soil and groundwater). Includes discharges and spills 3 Fluids into soil arising as a result of accidental events e.g. fire and explosion. Comment: the surface water can also become contaminated as a result of infiltration and runoff. All materials that the holder disposes of, with the intention of permanent removal. Waste includes hazardous waste, operational waste, office waste, domestic waste, 4 Waste Materials clinical waste, WEEE, batteries and small volumes of chemical waste. Important waste materials are drilling fluid / drilling dust, production water, waste water, contaminated soil and waste contaminated with mercury and LSA. 1) Disruption to the subsoil resulting from product extraction with the possible Disruption to the 5 consequence being earth tremors and subsidence. soil and subsoil 2) Disruption to soil layers as a result of drilling, pile driving and seismic shot holes

4-1


NO

ENVIRONMENTAL ASPECT

DEFINITIONS/COMMENTS

with the possible consequence being the lowering of the water table, seepage, etc. Extraction and consumption of resources Raw materials, The use of (depletable or regulated) raw materials additives and materials for 6 additives and operational purposes. materials Comment: including chemicals; excluding water. The operational and incidental consumption of water for instance for combating emergencies (killing wells, fighting fires), cooling, rinsing, cleaning activities, 7 Water consumption catering, making shot holes. Comment: this concerns seawater, fresh surface water, groundwater and mains water. Energy The use of energy carriers such as natural gas, diesel oil, petrol, kerosene, electricity 8 consumption for operating installations, transport and (office) buildings. The temporary or permanent use of space that has an influence on the flora, fauna and the appearance of the landscape. Also includes physical presence in the context 9 Usage of space of other stakeholders including fishing vessels and other shipping movements. Examples: installations, pipelines, buildings, transport, survey operations. The extraction of oil, gas, condensate and sulphur (as depletable resources). 10 Product extraction Comment: subsidence and earth tremors as effects of this are included in a separate environmental aspect (no. 5). Others Disruption to the surroundings resulting from heat radiation and ionising radiation from natural and unnatural sources. Radiation (heat Example of heat radiation: flaring during production activities and well testing. 11 and ionising) Example of ionising radiation: the settling of LSA in sludge and parts of an installation (and as a result in materials and equipment), and radiation emitted by measuring equipment (drilling tools, x-ray equipment). Disruption to the surroundings as a result of operational and incidental noise and Noise and vibration resulting from operational activities. 12 vibrations Examples: seismic vibration vehicles and explosives, pile driving activities, drilling activities, etc. Disruption to the surroundings resulting from operational activities. 13 Smell / odour Examples: ammonia, H2S, combustion gases, hydrocarbons Disruption to the surroundings (mainly at night) by light radiated from locations and 14 Light operational activities. Examples: drilling rigs, offshore platforms and seismic vehicles. Disruption to the surroundings from dust particles such as those created by construction and abandoning activities and during the execution of sandblasting and 15 Dust painting activities. Examples: grit, asbestos, blown sand. The intended or unintended introduction of liquids and gases in deep layers of the Materials to earth, including associated earth tremors and subsistence. subsurface/disturb 16 For instance: the injecting of production water into layers of the earth intended for it: ance to the soil or the undesired leaking into formations of drilling fluid and possibly the future injection subsoil of CO2. Disruption to local residents and visitors to an area. 17 Aesthetics Examples: landscape and visual effects. Disruption to flora, fauna and ecosystems both onshore and offshore including seabed disturbance. 18* Biodiversity Examples: effects on local, national and internationally important ecological interests including protected habitats and species. *For impact assessment Biodiversity is considered in terms of receptor sensitivity for aspects 1 - 17.

4-2


4.2. ASSESSMENT OF IMPACT SIGNIFICANCE The significance of environmental impacts is assessed in terms of: 

Magnitude based on the size, extent and duration of the impact;



The sensitivity of the receiving receptors;



The likelihood of an unplanned event occurring.

4.2.1. Magnitude Levels of magnitude of environmental impacts are outlined in Table 4-2. The magnitude of an impact or predicted change takes into account the following: 

Nature of the impact and its reversibility;



Duration and frequency of an impact;



Extent of the change; and



Potential for cumulative impacts.

The impact magnitude is defined differently according to the type of impact. For readily quantifiable impacts, such as noise or plume extent, numerical values can be used whereas for other topics (e.g. ecology) a more qualitative definition may be necessary. These criteria capture high level definitions, and according to the nature of a project some additional factors could be included. Other more suitable definitions can be added according to the project being pursued but they must be equivalent. Table 4-2 Magnitude. LEVEL 0

DEFINITION No effect

1

Slight effect

2

Minor effect

3

Moderate effect

4

Major effect

ENVIRONMENTAL IMPACT  No environmental damage or effects.  Slight environmental damage contained within the premises. Example: Small spill in process area or tank farm area that readily evaporates;  Effects unlikely to be discernible or measurable;  No contribution to transboundary or cumulative effects;  Short-term or localised decrease in the availability or quality of a resource, not effecting usage.  Minor environmental damage, but no lasting effects;  Change in habitats or species which can be seen and measured but is at same scale as natural variability;  Unlikely to contribute to trans-boundary or cumulative effects;  Short-term or localised decrease in the availability or quality of a resource, likely to be noticed by users.  Environmental damage that will persist or require cleaning up;  Widespread change in habitats or species beyond natural variability;  Observed off-site effects or damage, e.g. fish kill or damaged vegetation;  Groundwater contamination;  Localised or decrease in the short-term (1-2 years) availability or quality of a resource affecting usage;  Local or regional stakeholders’ concerns leading to complaints;  Minor transboundary and cumulative effects.  Severe environmental damage that will require extensive measures to restore beneficial uses of the environment;  Widespread degradation to the quality or availability of habitats and/or wildlife requiring significant long-term restoration effort;  Major oil spill over a wide area leading to campaigns and major stakeholders’ concerns;  Transboundary effects or major contribution to cumulative effects;  Mid-term (2-5 year) decrease in the availability or quality of a resource affecting usage;

4-3


LEVEL

DEFINITION

ENVIRONMENTAL IMPACT  National Stakeholders’ concern leading to campaigns affecting Company’s reputation.  Persistent severe environmental damage that will lead to loss of use or loss of natural resources over a wide area;  Widespread long-term degradation to the quality or availability of habitats that cannot be readily rectified;  Major impact on the conservation objectives of internationally/nationally 5 Massive Effect* protected sites;  Major trans-boundary or cumulative effects;  Long-term (>5 year) decrease in the availability or quality of a resource affecting usage;  International public concern. * To be used for unplanned events only

4.2.2. Receptor Sensitivity Receptors could be categorised into different groups: 

Atmosphere;



Water (Marine, Estuarine, river or groundwater);



Habitat or species;



Community; and



Soil or seabed.

Receptor sensitivity criteria are based on the following key factors: 

Importance of the receptor at local, national or international level: for instance, a receptor will be of high importance at international level if it is categorised as a designated protected area (such as Ramsar site or SAC). Areas that may potentially contain e.g. Annex I Habitats are of medium importance if their presence/extent has not yet been confirmed.



Sensitivity/vulnerability of a receptor and its ability to recovery: for instance, certain species could adapt to changes easily or recover from an impact within a short period of time. Thus, as part of the receptor sensitivity criteria (Table 4-3), experts should consider immediate or long term recovery of a receptor from identified impacts. Should also consider if the receptor is under stress already.



Sensitivity of the receptor to certain impacts: for instance, flaring emissions will potentially cause air quality impacts and do not affect other receptors such as seabed.

Table 4-3 Sensitivity. LEVEL

SENSITIVITY

A

Low

B

Medium

C

High

4-4

DEFINITION Receptor with low value or importance attached to them, e.g. habitat or species which is abundant and not of conservation significance. Immediate recovery and easily adaptable to changes. Receptor of importance e.g. recognised as an area/species of potential conservation significance for example, Annex I Habitats of Annex II species. Recovery likely within 1-2 years following cessation of activities, or localised medium-term degradation with recovery in 2-5 years. Receptor of key importance e.g. recognised as an area/species of potential conservation significance with development restrictions for example SACs, MPAs. Recovery not expected for an extended period (>5 years following cessation of activity) or that cannot be readily rectified.


4.2.3. Evaluation of Significance

4.2.3.1. Planned Events The magnitude of the impact and sensitivity of receptor is then combined to determine the impact significance as shown in Table 4-4. Mitigation measures are then identified to reduce the impact. The residual impact following mitigation is then determined. Table 4-4 Evaluation of significance – planned events. SENSITIVITY A - Low

B - Medium

C - High

No effect

No effect

No effect

1 - Slight effect

Slight

Slight

Minor

2 - Minor effect

Minor

Minor

Moderate

3 – Moderate effect

Minor

Moderate

Major

Moderate

Major

Major

MAGNITUDE

0 - No effect

4 - Major effect

4.2.3.2. Unplanned Events For unplanned events, the likelihood of such an event occurring also requires consideration, for example, based on magnitude and sensitivity alone a hydrocarbon spill associated with a well blowout would be classed as having major impact significance, however, the likelihood of such an event occurring is very low. Thus unplanned events also require assessment in terms of environmental risk. As with planned activities, the potential impacts of unplanned events will be identified and their magnitude and the sensitivity of the environment defined and combined in order to determine the impact significance. The significance of the impact will then be combined with the likelihood of the event occurring (Table 4-5) in order to determine its overall environmental risk as summarised in Table 4-6. Mitigation measures will then be identified to reduce the risk of such an event occurring in order to determine residual risk. Table 4-5 Likelihood criteria. LIKELIHOOD A

B

C

D

E

DEFINITION  Never heard of in the industry - Extremely remote;  1 per year;  Event likely to occur more than once at the facility.

4-5

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT IMPACT ASSESSMENT APPROACH Table 4-6 Evaluation of significance – unplanned events. LIKELIHOOD

IMPACT SIGNFICANCE

A

4-6

B

0 - No effect

C

D

E

No effect

1 - Slight effect

Negligible

Negligible

Minor

Minor

Minor

2 - Minor effect

Negligible

Minor

Minor

Moderate

Moderate

Minor

Minor

Moderate

Moderate

Major

Moderate

Moderate

Moderate

Major

Major

Major

Major

Massive

Massive

Massive

3 – Moderate effect 4 - Major effect 5 – Massive effect

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PHYSICAL PRESENCE

5. PHYSICAL PRESENCE The proposed Fram 2 Field Development will result in obstructions to other users of the marine environment (e.g. fishing and shipping) and marine fauna during all of its phases, as a result of the project’s physical infrastructure and vessel activity. This section discusses the potential impacts associated with the physical presence of: 

The vessels associated with drilling and the installation of the subsea infrastructure;



The Mobile Offshore Drilling Unit (MODU); and



The trees, manifold, production pipeline, electro-hydraulic-chemical (EHC) umbilical and all other subsea infrastructure.

on other sea users and animals (other than benthic species) using the risk assessment methodology presented in Section 4. The impacts on the seabed and the local benthic communities are discussed in Section 8; Seabed Disturbance.

5.1. PRESENCE OF VESSELS Vessels associated with the drilling, installation and commissioning phases of the proposed Fram 2 Field Development include, MODUs, AHVs, supply, standby, ROVSV, pipelay and umbilical installation, trenching and rock dumping vessels and a DSV. The physical presence of these vessels at the proposed Fram 2 Field Development location may result in navigational hazards, a restriction of fishing operations, and disturbance to birds and marine mammals.

5.1.1.

Impact of Vessels on Other Sea Users

All vessels engaged in the project operations will have markings and lightings as per the International Regulations for the Prevention of Collisions at Sea (COLREGS) (International Maritime Organisation, 1972). Shell as operator will consult with the SFF for all operations. Vessel use will be optimised where possible. Shipping in the area can be considered to be very low to moderate with 512 vessels per year (1-2 vessels per day) within 10 nm of the Fram area (Anatec, 2012). As the proposed project is located in close proximity to a well-developed oil and gas area, the increase in vessel traffic is not anticipated to result in a significant change to existing levels. As other sea users (including fishermen) in the area are already adapted to the current levels of vessel movement, the receptor sensitivity is considered low and the significance of socio-economic impact of the additional vessels is considered to be slight . Visual and audible navigational aids will be provided on the MODU in accordance with the relevant regulations. The MODU will be provided with marine navigational aids and aviation obstruction lights system, as per the Standard Marking Schedule for Offshore Installations (HSE, 2009), to warn ships and aircraft of their position. The systems shall comprise: 

Marine navigation lights;



Fog-horns;



Fog-lights;



Fog detector;



Aviation obstruction lights;



Helideck lighting;



Helideck beacons (helideck status light system); and



Radar beacons. 5-1

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PHYSICAL PRESENCE As required by HSE Operations Notice 6 (HSE, 2016), a rig warning communication will be issued at least 48 hours before any rig movement. Notice will be sent to the Northern Lighthouse Board (NLB) of any MODU moves and vessel mobilisation associated with the mobilisation and demobilisation of the MODU. The MODU routes will be selected in consultation with other users of the sea, with the aim of minimising interference to other vessels and the risk of collision. Prior to moving the rig on location, Shell will arrange for a collision risk assessment to be carried out if the vessel traffic surveys (VTS) show it is required; the results of which will be used to implement a collision risk management plan. As discussed in Section 3.6.1, fishing effort in ICES rectangle 42F1, within which the proposed project occurs, is considered to be low. An exclusion zone is already in place at the DCE where the Fram manifold will be located. ICES rectangle 42F1 is an important Nephrops fishing area as shown in Figure 3-30; however, the average annual landing of shellfish from 42F1 only made up 0.07 % of UK shellfish landings between 2011 and 2015 (Table 3-14). The ICES rectangle is also relatively important to the pelagic industry; however, given that the proposed project will not result in any new exclusion zones the significance of the impacts on the fishing industry is considered to be slight whilst the overall receptor sensitivity is considered low. Shell holds semi-annual meetings with SFF where all offshore projects are discussed, allowing any potential concerns from the fishing industry to be raised. Given the use of navigational aids, the submission of a CtL, the location of the proposed project within a relatively well developed oil and gas area and Shell’s commitment to keeping the NLB up to date on any MODU moves and potential schedule changes, the impact significance of the physical presence of the MODU is considered to be slight whilst the receptor sensitivity is considered low.

5.1.2.

Impact of Vessels on Marine Mammals

The increase in vessel traffic may cause disturbance and increase the risk of injury to marine mammals through vessel strikes. The evidence for lethal injury from boat collisions to marine mammals suggests that collisions with vessels are very rare (CSIP, 2011). Out of 478 post mortem examinations of harbour porpoise in the UK carried out between 2005 and 2010, only four (0.8 %) were attributed to boat collisions. In addition, it is likely that the noise generated by the vessels will deter marine mammals from the immediate vicinity and therefore collisions with vessels are unlikely. Marine mammals known to occur in the area of the proposed project include harbour porpoise, bottlenose dolphin, white-beaked dolphin, white sided dolphin and minke whale (Section 3.4.5). Vessel traffic within the vicinity of Fram is estimated at c. 512 vessels per year, (Anatac, 2012; see also Section 3.6.2) and the additional vessel transits associated with the proposed project are considered to be a relatively small increase compared to the existing level of vessel activity in the area. No significant impacts from the increase in vessel traffic associated with Fram are predicted. Marine mammals may be attracted to installations such as the MODU due to increased prey abundance (Todd et al., 2009); however, no evidence of impacts of installations on marine mammals within the North Sea have been reported and no significant impacts are predicted. Given the vessel activity currently associated with the area, the significance of the environmental impact of vessel presence (excluding noise impacts, which are considered in Section 9) associated with the proposed project, on marine mammals is considered to be slight and the overall receptor sensitivity is considered to be low. Cetaceans are anticipated to quickly adapt to the presence of the MODU, which will occupy a very small proportion of their overall available habitat such that the significance of the environmental impact of the presence of the MODU is considered slight whilst the receptor sensitivity is considered low.

5.1.3.

Impact of Vessels on Birds

Disturbance from vessels has the potential to cause displacement of seabirds from foraging habitat and may cause flying birds to detour from their flight routes. For example, auks (guillemot, razorbill and puffin)

5-2

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PHYSICAL PRESENCE are believed to avoid vessels by up to 200 to 300 m but gulls (e.g. kittiwake, herring gull and great blackbacked gull) are attracted to the presence of them (Furness & Wade 2012). Auks and gulls are known to occur in the area (Section 3.5.4) however the short term behavioural responses associated with avoidance of / attraction to the vessels are not considered significant; therefore, the significance of the environmental impact of the vessels is considered to be slight whilst the receptor sensitivity is considered low. The physical presence of a platform or MODU is known to attract seabirds, with seabird density in the North Sea reported to be seven times greater within 500 m of a platform. The attraction of seabirds to installations may be due to increased food availability at the installation and the availability of roost sites (Weise et al., 2001). Lights are also known to attract seabirds. The MODU will have lighting to ensure safe and effective working conditions to meet legal requirements. Studies undertaken in the North Sea and Gulf of Mexico indicate that migrating birds, particularly land birds, are at risk of being attracted to the lights of a platform or MODU, such that they become disorientated and collide with the installation (Bruinzeel and Belle, 2010; Russell, 2005). This attraction to lights occurs most frequently during the autumn, in poor weather conditions of low cloud and reduced visibility. Although a wide variety of species may be attracted, in the North Sea it predominantly affects seven species of bird: blackbird (Turdus merula), fieldfare (Turdus pilaris), song thrush (Turdus philomelos), redwing (Turdus iliacus), starling (Sturnus vulgaris), chaffinch (Fringilla coelebs) and brambling (Fringilla montifringilla) (Cork Ecology, 2009). Species most likely to be impacted have large European breeding populations, in excess of 10 million pairs (Birdlife International, accessed 2016) and the weather conditions during which relatively large scale attractions potentially occur are infrequent, with an estimated one large scale event per autumn (Cork Ecology, 2009). Seabirds are anticipated to quickly adapt to the presence of the MODU, which will occupy a very small proportion of their overall available habitat such that the significance of the environmental impact of the presence of the MODU is considered slight and the receptor sensitivity is considered low. No significant impacts on seabirds attracted to offshore installations are predicted to occur. The presence of the MODU will be temporary over a short period of time (one season) and as such the significance of the impact on migratory birds potentially attracted by the vessel lighting is also considered slight.

5.2. PRESENCE OF SUBSEA INFRASTRUCTURE All subsea infrastructure including Xmas trees, manifolds, pipelines, umbilicals, tie-in spools and jumpers have the potential to impact on fishing operations and marine animals and birds as a result of their physical presence. Consultation and notification to other sea users will be carried out prior to the installation of the subsea infrastructure. In addition to being located within a 500 m exclusion zone the wellheads, Xmas Trees, and manifolds will be “fishing friendly” i.e. non-snaggable but not overtrawlable (Section 2.8.1 and 2.8.2). Tie-in spools and jumpers will be protected from fishing interaction by the use of concrete protection mattresses. The nontrenched umbilical ends will be protected by concrete mattresses to mitigate against fishing interaction and / or dropped objects. Similarly, if trenched and buried the pipeline ends will be protected by concrete mattresses to mitigate against fishing interaction and / or dropped objects. The Fram manifold will use a slab-sided box (Figure 2-11) providing protection from accidental loads (fishing gear interaction) and dropped objects. It is designed as one complete structure to minimise the risks of being dislodged by fishing gear capture. One rigid pipeline and one EHC umbilical will be installed between the proposed Fram manifold and the existing Starling manifold. The base case for the production pipeline is for it to be surface laid, with 5-3

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT PHYSICAL PRESENCE potential spot rock dumping as required to provide pipeline anchoring. The umbilical will be trenched and buried to a depth of 0.6 m to provide protection from damage, for example from fishing gear. VMS data showing the fishing intensity by fishing vessels >15 m in length using demersal mobile gears and Nephrops gears (Figure 3-30) between 2009 and 2013 shows that fishing intensity is mainly focused to the north-west of the proposed Fram 2 Field Development along the route of the proposed Fram to Starling pipeline. VMS data for the Scottish demersal fleet have been analysed with spatial data on pipelines. Approximately one-third (36.1%) of trips fished within 200 m of a pipeline over a 5-year period, suggesting that pipelines are subjected to regular interaction with fishing gear (Rouse et al., 2017). The proposed Fram to Starling pipeline will be designed to meet potential impact loads (such as fishing gear impacts) in line with design standards. Marine mammals and fish in the area are anticipated to adapt to the presence of the subsea infrastructure, which will occupy a very small proportion of their overall available habitat. The significance of the impacts associated with the physical presence of the subsea infrastructure on other sea users, and animals (excluding benthic communities) in the area has been assessed as being slight. The impact on the benthic communities is discussed separately in Section 8 ‘Seabed Disturbance’.

5.2.1.

Non-Native Species

More than 90 marine non-native species have been identified in British and Irish waters (including Republic of Ireland and Northern Ireland), of which seventeen are now established in Scotland (SNH, 2014). Their arrival is believed to be principally due to shipping, including ballast waters and sediments, fouling of hulls and other associated hard structures, and imported consignments of cultured species. Most marine nonnative species in Britain originate from parts of the world with a similar latitude to the North Sea (e.g., North Pacific, North-west Atlantic). The installation of the Fram subsea infrastructure to the marine environment has the potential to provide substrate on which invasive species could become established. However, due to the minimal quantity of subsea infrastructure to be installed significance of the impacts associated with this are thought to be slight.

5.3. DECOMMISSIONING PHASE Currently vessel activity in the area is considered low to moderate; however, at the commencement of the decommissioning activities, vessel activity in the area will increase relative to the number of vessels associated with the development during production. At the time of decommissioning Shell will commission a new VTS and Collision Risk Assessment if required. Following decommissioning it is likely that the trenched umbilical will be decommissioned in situ while the surface-laid pipeline may be removed. The tie-in spools and manifold will be recovered along with mattresses and grout bags. Surveys will be carried out along the pipeline route to determine depth of burial of the umbilical and if any remedial work is required to ensure that it remains buried. Following consultation with BEIS and their recommended consultees, this remedial work will be carried out if required. Following decommissioning of the Fram 2 Field Development over-trawlability surveys will subsequently be carried out.

5.4. MANAGEMENT AND MITIGATION MEASURES The following management and mitigation measures are proposed to minimise the impacts associated with the physical presence of the MODU, vessels and infrastructure associated with the proposed Fram 2 Field Development.

5-4


MITIGATION MEASURES Proposed Control Measures 

Consultation with SFF for all phases and operations;



Notice will be sent to the NLB of any MODU moves and vessel mobilisation associated with the mobilisation and demobilisation of the MODU;



Notice to Mariners will be circulated;



A Vessel Traffic Survey (VTS) will be undertaken;



A Collision Risk Management Plan will be commissioned if required;



Optimise vessel use by minimising number of vessels require and length of time vessels are on site;



Use of navigational aids, including radar, lighting and AIS (Automatic Identification System);



Fishing friendly subsea infrastructure will be used;



Minimum distance between pipeline and umbilical of 70m; and



Size of rockdump and rockdump profiles, if required, will be in accordance with industry practice which is also the preferred SFF / industry best practice.

In consideration of the above control measures, the overall significance of the environmental impact of the physical presence of the vessels and infrastructure on other sea users and animals other than the benthic communities in the area is considered slight/minor.

5.5. CUMULATIVE AND TRANSBOUNDARY EFFECTS The effects resulting from the physical presence of the proposed Fram 2 Field Development have the potential to act cumulatively with both existing and new developments and other activities. The project will be located in an already well-developed area of the North Sea, therefore the presence of the Fram pipeline and manifold is unlikely to have any significant cumulative impact on the area. The temporary vessel presence during the Fram installation and commissioning activities is expected to result in a small increase to vessel traffic. The physical presence of the proposed Fram 2 Field Development is not expected to have any significant cumulative effects. The subsea equipment will be installed within UK waters so there will be no transboundary effects.

5-5



5-6

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT EMISSIONS TO AIR

6.

EMISSIONS TO AIR

Activities associated with the proposed development and operation of Fram will result in the release of various gases into the atmosphere which may have several impacts, including: 

Anthropogenic global warming – attributable to greenhouse gas emissions, mainly CO2 and methane (CH4);



Stratospheric ozone depletion – caused by Halon and chlorofluorocarbons (CFCs), known collectively as Ozone Depleting Substances (ODS) (these are used in relatively small amounts offshore and are not considered further here);



Ground level ozone formation – caused by Volatile Organic Compounds (VOCs) and nitrogen oxides (NOx); and



Acidification – caused by emissions of NOx and sulphur oxides (SOx) (Oil and Gas UK, 2009).

This section describes and quantifies the sources of emissions during each phase of the proposed Fram 2 Field Development which include: 

Drilling and Well Clean-up – emissions associated with the drilling rig, drilling support vessels and with the well clean-up operations;



Installation – emissions from vessels used for the installation of the pipeline and subsea infrastructure;



Production – the introduction of Fram will result in an increase in emissions as a result of increased production at Shearwater; and



Decommissioning – potential decommissioning activities may see an increase in the number of vessels (and associated emissions) at Fram and Shearwater relative to those present during the production phase.

Having described and quantified the sources of emissions, the potential significance of the impact from emissions are then determined using the impact significance assessment matrix presented in Section 4.

6.1. DRILLING AND WELL CLEAN-UP Section 2.3 discusses the maximum predicted duration of drilling at the proposed Fram 2 Field Development whilst Section 2.7.11 describes the drilling rig and associated vessels used to drill the wells. Table 6-1summarises the emissions associated with the drilling rig, drilling support from vessels and helicopters, and emissions associated with flaring from the well clean-up operations. It is anticipated that drilling will take place in Q4 2019 and Q1 2020 with a total duration of 140 days and that well clean-up will last for a maximum of 66 days per well. The total support vessel days for the duration of drilling totals c. 314 days. It can be seen from Table 6-1that in a worst case scenario the total emissions from the drilling rig amount to c. 0.68 % of CO2 produced by diesel combustion on drilling rigs in the UKCS in 2015. The approximate total emissions associated with the drilling support vessels during the drilling campaign amounts to c. 0.03 % of CO2 generated by domestic and international shipping in 2014. Given the relatively small volumes of emissions produced during drilling and the rapid dispersion envisaged, the magnitude is considered minor and the sensitivity low, therefore the significance of the environmental impacts are considered to be minor. Section 2.7.9 describes the well clean-up and testing activities to be undertaken at the proposed Fram 2 Field Development. Well clean-up is necessary to ensure that wells no longer contain any drilling and completion related debris (mud, brine, cuttings) which could potentially damage the topsides when commissioning and production begins. 6-1

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT EMISSIONS TO AIR Following completion activities, the two production wells will be flowed to clean-up the well bore and establish a sand-free production rate prior to final hook-up to the production facilities. It is currently anticipated that well clean-up will be to the drilling rig as opposed to the host (Shearwater). During cleanup and well testing it is anticipated that the wells will be flowed for a maximum period of 66 hours each, with an expected maximum of 0.4 Million Sm3 of gas and 82.8 te of oil being flared. Atmospheric emissions resulting from clean‐up have been calculated using emission factors from the EEMS Atmospheric Calculations Issue 1.10 (EEMS, 2008) and are presented in Table 6-1. In total the well clean‐ up and test CO2 emissions equate to a maximum of 0.008 % of the 2015 reported flaring emissions associated with well clean‐up and testing. The significance of the environmental impact of the emissions resulting from the well clean‐up operations may be considered slight given the low percentage of the calculated ‘worst case’ emissions in relation to overall UKCS emissions. Emissions are expected to be quickly dispersed resulting in no significant local air quality impact. Table 6-1 Drilling atmospheric emissions (tonnes).

SOURCE

DAYS

TOTAL FUEL USE / TOTAL FLARED (te) 1,400

Drilling Rig 140 Support Vessels & 314 2,999 Helicopter Oil and gas flared 5.5 82.80 (2 wells) Emissions from diesel use on drill ships, semi-submersibles 1 and HDJUs on the UKCS 2015 Total rig emissions as a % of the 2015 UKCS total Approximate shipping emissions 2 in UK waters 2014 Annual emissions from drilling support vessels as a % of shipping emissions in UK waters, 2014 1 2015 UKCS totals for flaring Total emissions from flaring as a % of the 2015 UKCS total 1 EEMS data, 2015 2 Committee on Climate Change, 2016.

CO2

NOx

N2O

SO2

CO

CH4

VOC

4,480

83.16

0.31

5.60

21.98

0.25

2.80

9,595

178.11

0.66

11.99

47.08

0.54

6.00

264.96

0.31

0.007

0.001

1.49

2.07

2.07

656,181

12,064

66

724

3,140

45

700

0.68

0.69

0.46

0.77

0.70

0.56

0.40

9,900,000

-

-

-

-

-

-

0.03

-

-

-

-

-

-

3,176,722

1,526

94

260

8,174

14,279

14,076

0.008

0.020

0.007

0.000

0.018

0.014

0.015

6.2. INSTALLATION Various different vessels will be required for the installation of the pipeline and subsea infrastructure at the proposed Fram 2 Field Development (Section 2.8.5). The anticipated emissions associated with these vessels are shown in Table 6-2. The predicted CO2 emissions associated with the installation activity is c. 6,890 te. To put these CO2 emissions into context, they are presented as a percentage of the overall CO2 emissions from domestic and international shipping in UK waters and are anticipated to represent approximately 0.02 % of CO2 emissions from shipping. Given the relatively small volumes of emissions produced during installation activities and the rapid dispersion envisaged, the magnitude is considered minor and the sensitivity low, therefore the significance of the environmental impacts are considered to be minor.

6-2

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT EMISSIONS TO AIR Table 6-2 Estimated vessel emissions associated with the subsea installation activities. SOURCE

DAYS

FUEL USE / DAY (Te) 2,153

Total vessels 143 Approximate shipping emissions in UK waters 1 2014 Annual emissions from installation vessels as a % of shipping emissions in UK waters 1 Committee on Climate Change, 2016.

CO2

NOx

N2 O

SO2

CO

CH4

VOC

6,890

409

0.09

0.04 µm (visible sheen) and

-

> 0.3 µm (ability to respond).

Hydrocarbon concentrations in water: -



> 50 ppb - a conservative threshold for significant acute toxic effects within the water column (described as a mid-range level causing sub-lethal effects (Patin, 2004)).

Hydrocarbon concentrations in sediment: -

Total Hydrocarbons (THC) – 50 mg/kg;

-

Central North Sea (CNS) background – UKOOA mean THC 9.5 mg/kg; and

11-5

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT ACCIDENTAL EVENTS

-

United States Environmental Protection Agency (USEPA) Polycyclic Aromatic Hydrocarbons (PAHs) – OSPAR Effects Range-Low (ERLs) (2014) for individual PAH.

11.2.2. Hydrocarbon properties The fate and effect of a spill is dependent on the chemical and physical properties of the hydrocarbons. Hydrocarbons used in, or produced by the Fram Field include diesel and condensate. Fram condensate is characterized as a low viscosity condensate, and will not form a thick mousse at the sea surface in moderate to turbulent conditions. A significant proportion of total hydrocarbon content is classified within the volatile fraction (aromatics that include Monoaromatic Hydrocarbons (MAHs), aliphatics that include C4-C10). The evaporative loss of volatile hydrocarbons for Fram Condensate is greater than that of heavy crudes that are predominantly composed of high molecular weight hydrocarbons. The properties of the Fram condensate and the diesel fuel oil used in the surface release scenario from the MODU are provided in Table 11-4. Table 11-4 Oil properties OIL TYPE

API GRAVITY

Condensate

56

Diesel

38.8

VISCOSITY at 30 °C (cP) 0.703 at 25 °C (cP) 2.760

POUR POINT (°C)

WAX CONTENT (WT%)

ASPHALTENE CONTENT (WT%)

-39

0.04

50 ppb of approximately 330 km3 (Figure 11-2). The MODU diesel spill is predicted to have a greater effect on the water column, compared to the condensate spills of relatively similar volumes released (pipeline releases). During the course of the spill, the diesel both entrained and evaporated while condensate primarily evaporated, entering the atmosphere too quickly for a volume of oil to entrain in the water column. This can be observed by comparing the stochastic modelling results for the water column where the Fram Condensate Pipeline Fissure Release volume oiled is 4 km3 and for the Fram Diesel Loss of Inventory, volume oiled is 22 km3 (Figure 11-4, Figure 11-5 and Table 11-5). Only two well blowout scenarios, with 134 and 15 days duration, may result in the surface oil crossing the median line, although the probability is relatively low, 16 % (Figure 11-1) and 6 % respectively. There is a higher probability in these scenarios for hydrocarbons entrained in the water column (>50 ppb) to cross the median line, 64 % (Figure 11-2) and 24 % respectively (Table 11-6). There is a high probability for surface oil and oil in the water column to overlap with the boundaries of the East of Gannet and Montrose Field NCMPA, with the 100 % probability for 134 days well blowout (Figure 11-6

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT ACCIDENTAL EVENTS 11-1 and Figure 11-2) and pipeline fissure release scenarios (Figure 11-3 and Figure 11-4) (see also Table 11-6). Based on the location of the spill sites and the properties of the oil types released, oiling of the shoreline and contamination of the seabed sediment is not predicted to occur.

11-7


Figure 11-1 Fram Condensate Blowout Relief Well - stochastic model results: probability of a surface sheen greater than 0.04 µm (visible sheen).

11-8


Figure 11-2 Fram Condensate Blowout Relief Well subsea oiling stochastic results for water column concentrations above 50 ppb.

11-9


Figure 11-3 Fram Condensate Pipeline Fissure Release - stochastic model results: probability of a surface sheen greater than 0.04 µm (visible sheen).

11-10


Figure 11-4 Fram Condensate Pipeline Fissure Release subsea oiling stochastic results for water column concentrations above 50 ppb.

11-11


Figure 11-5 Fram Diesel Surface Release subsea oiling stochastic results for water column concentrations above 50 ppb.

11-12

FRAM 2 FIELD DEVELOPMENT ENVIRONMENTAL STATEMENT ACCIDENTAL EVENTS Table 11-5 Summary of results for stochastic, deterministic and biological exposure modelling. STOCHASTIC MODELLING RESULTS SCENARIO (SPILL VOLUME) Fram Condensate Blowout 3 Relief Well (73,050 m ) Fram Condensate Blowout Capping Device (7,875 m3) Fram Condensate Pipeline 3 Fissure Release (614 m ) Fram Condensate Pipeline Instantaneous Release 3 (614 m ) Fram Diesel Loss of Inventory 3 (2,500 m )

DETERMINISTIC MODELLING RESULTS

Cumulative Water Surface Oiled >0.04 µm (km2)

Maximum Water Column Volume Oiled >50 ppb 3 (km )

Maximum distance 50 ppb exceeded from spill site (km)

Max exposure time in water column (days)

5,667

326

63

144

2,474

67

36

20

929

4

7

14

413

8

11

7

720

22

54

7

BIOLOGICAL EXPOSURE MODELLING RESULTS 2 Area (km ) of 100 % mortality for most affected behaviour group 1,339 (surface diving birds) 69 (surface diving birds) 8 (surface diving birds) 9 (demersal fish and invertebrates) 14 (surface diving birds)

11-13


Table 11-6 Probability and arrival time of oil reaching key locations. MEDIAN LINE

Blowout 134 days Surface oil (0.04 µm) Oil in water column (50 ppb) Blowout 15 days Capped Surface oil (0.04 µm) Oil in water column (50 ppb) Pipeline fissure release Surface oil (0.04 µm) Oil in water column (50 ppb) Pipeline continuous release Surface oil (0.04 µm) Oil in water column (50 ppb) MODU Diesel Inventory Surface oil (0.04 µm) Oil in water column (50 ppb)

11-14

SHORELINE

EAST OF GANNET & MONTROSE MPA

FULMAR MCZ

Probability of Overlap (%)

Minimum Arrival Time (hrs)







16 64

192 138

0 0

n/a n/a

48 62

183 138

100 100

9 12

6 24

117 105

0 0

n/a n/a

6 24

131 113

63 85

8 9

0 0

n/a n/a

0 0

n/a n/a

0 0

n/a n/a

100 100

3.5 4

0 0

n/a n/a

0 0

n/a n/a

1 0

162 n/a

13 76

51 4

0 1

n/a 145

0 0

n/a n/a

2 6

77 66

22 28

6 8


11.3. POTENTIAL IMPACTS The biological exposure model in SIMAP estimates the area, volume or proportion of a stock or population affected by surface oil, concentrations of oil components in the water, and sediment concentration. The model calculates the extent and duration of exposure based on the outputs of the oil fates model. The results from the exposure model provide a quantitative comparison of the potential impact to fish and wildlife from each spill scenario in relation to their behaviour type, defined by the habitats that they use and movements characteristics. The following sections discuss the biological receptors (and behaviour groups) that may be impacted from a potential oil spill incident in the Fram Field, based upon the scenarios modelled. Table 11-7 summarizes the biological receptors/behaviour groups expected to be most affected (area of 100% mortality) and these are discussed in more detail below. The greatest area of mortality across most receptors, is generally associated with the well blowout scenario requiring a relief well. This is with the exception of the pipeline releases which are shown to have a particular impact on demersal species compared to other receptors/behavioural groups. Table 11-7 Area (km2) of 100% Mortality for Various Biological Receptors (Behaviour Group) Estimated Under Each Modelling Scenario. BIOLOGICAL RECEPTOR (Behaviour Group)

AREA (km2) OF 100% MORTALITY Blowout 134 d

Blowout 15 d

Fissure release

Instantaneous pipeline

MODU Diesel

Dabbling waterfowl

0

0

0

0

0

Nearshore aerial birds

0

0

0

0

0

1,339.4

69.3

7.9

0

14.2

Aerial seabirds

68.1

3.5

0.4

0

0.7

Wetland wildlife

0

0

0

0

0

Terrestrial wildlife

0

0

0

0

0

Cetaceans

1

Fram 2 Field Development Environmental Statement - Shell

Fram 2 Field Development Environmental Statement - Shell

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