Liberator Field Development Environmental Statement ......Liberator Field Development Environmental...

Liberator Field Development

Environmental Statement

January 2019

BEIS Reference Number: D/4228/2018



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Contents

Contents ......................................................................................................................... 3

Environmental Statement Details .................................................................................. 5

Non-Technical Summary ............................................................................................... 9

1 Introduction .......................................................................................................... 23

1.1 The Liberator Field Development ................................................................. 23

1.2 Development Background and Purpose ........................................................ 24

1.3 i3 Energy’s Environmental Awareness ......................................................... 27

1.4 Environmental assessment process ............................................................... 27

1.5 Scope of the EIA ........................................................................................... 28

1.6 Consultation .................................................................................................. 28

1.7 Legislation and policy ................................................................................... 31

1.8 The Environmental Statement ....................................................................... 36

2 Development Description .................................................................................... 39

2.1 Consideration of Alternatives........................................................................ 39

2.2 Key components of the development ............................................................ 43

2.3 Field reservoir fluid composition .................................................................. 44

2.4 Liberator production profiles ........................................................................ 45

2.5 Drilling and completion programme ............................................................. 47

2.6 Subsea............................................................................................................ 56

2.7 Pipeline and Umbilical .................................................................................. 56

2.8 Host Modifications ........................................................................................ 68

2.9 Vessel Requirements ..................................................................................... 75

2.10 Decommissioning .......................................................................................... 76

3 Environmental Description .................................................................................. 79

3.1 Introduction and surveys ............................................................................... 79

3.2 Physical Environment ................................................................................... 80

3.3 Biological Environment ................................................................................ 86

3.4 Conservation.................................................................................................. 99

3.5 Socio-Economic Environment .................................................................... 105

3.6 Summary of Environmental Sensitivities and Seasonality ......................... 111

4 EIA Methodology .............................................................................................. 113



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4.1 EIA Overview ............................................................................................. 113

4.2 Sources of potential environmental effects ................................................. 113

4.3 Environmental Significance ........................................................................ 115

4.4 Cumulative and In-Combination Impact Assessment ................................. 125

4.5 Transboundary Impact Assessment ............................................................. 125

4.6 Habitats Regulation Appraisal (HRA) ........................................................ 125

4.7 Data Gaps and Uncertainties ....................................................................... 126

5 Impact Assessment............................................................................................. 127

5.1 Introduction ................................................................................................. 127

5.2 Discharges to Sea ........................................................................................ 127

5.3 Physical Disturbance ................................................................................... 139

5.4 Underwater Noise ........................................................................................ 146

5.5 Physical presence ........................................................................................ 154

5.6 Atmospheric Emissions ............................................................................... 158

5.7 Accidental Events ........................................................................................ 164

6 Environmental Management .............................................................................. 185

7 Conclusion ......................................................................................................... 189

7.1 Scottish National Marine Plan..................................................................... 189

7.2 Protected Sites ............................................................................................. 190

7.3 Cumulative/In-combination and Transboundary Impacts ........................... 191

7.4 Overall Conclusion ...................................................................................... 191

References .................................................................................................................. 193

Appendix A Abbreviations..................................................................................... 205

Appendix B Supporting Data for Accidental Events Assessment ......................... 211



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Environmental Statement Details

Section A: Administrative Information

A1 – Project Reference Number

Number: D/4228/2018

A2 - Applicant Contact Details

Company name: i3 Energy

Contact name: Stuart McIlroy

Contact title: HSEQ Manager

A3 - ES Contact Details (if different from above)

Company name:

Contact name:

Contact title:

A4 - ES Preparation

Please confirm the key expert staff involved in the preparation of the ES:

Name Company Title Relevant Qualifications/Experience

Stuart McIlroy i3 Energy HSEQ

Manager

Chartered Member of The Institution of

Occupational Safety and Health

36 years’ experience in HSE in oil and gas

MSc in health, safety and risk with

environmental management

Lizzie Whiteley RPS Energy Senior

Environmental

Consultant

8 years’ experience as environmental

consultant

Undergraduate and postgraduate degrees in

environmental discipline

A5 - Licence Details

a) Please confirm licence(s) covering proposed activity or activities

Licence number(s): P1987 (13/23d) and P2358 (13/23c)

b) Please confirm licensees and current equity

Licensee Percentage Equity

i3 Energy 100%



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Section B: Project Information

B1 - Nature of Project

a) Please specify the name of the project.

Name: Liberator Field Development

b) Please specify the name of the ES (if different from the project name).

Name:

c) Please provide a brief description of the project.

The Liberator Field Development comprises three development wells and an appraisal well

located in UKCS Blocks 13/23c and 13/23d, approximately 64 km from the south Moray coast

in the South Halibut Basin of the Moray Firth. i3 Energy is proposing to develop the Liberator

field via the three development wells, tied back to the Ross DCA manifold 10 km to the south

east in Block 13/29 and will be processed by the existing Repsol Sinopec Resources UK Ltd

operated Bleo Holm Floating Production, Storage and Offloading vessel. The single appraisal

well will be drilled in the Liberator West reservoir, with 3 discrete periods of drilling activity

covering the 4 wells.

B2 - Project Location

a) Please indicate the offshore location(s) of the main project elements (for pipeline projects

please provide information for both the start and end locations).

Quadrant number(s): 13

Block number(s): 23c, 23d, 28, 29

Latitude: Longitude: 58° 11' 35.177" N, 1° 27' 10.724" W (drill centre)

Distance to nearest UK coastline (km): 64

Which coast? England / Wales / Scotland / NI

Distance to nearest international median line (km): 174

Which line? UK / Norway

B3 - Previous Applications

If the project, or an element of the project, was the subject of a previous consent application

supported by an ES, please provide details of the original project

Name of project: Liberator Phase 1 Field Development

Date of submission of ES: September 2017

Identification number of ES: D/4199/2017



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EIA Quality Mark

This Environmental Statement (ES), and the Environmental Impact Assessment (EIA) carried

out to identify the significant environmental effects of the proposed development, was

undertaken in line with the EIA Quality Mark Commitments.

The EIA Quality Mark is a voluntary scheme, operated by the Institute of Environmental

Management and Assessment (IEMA), through which EIA activity is independently reviewed,

on an annual basis, to ensure it delivers excellence in the following areas:

• EIA Management;

• EIA Team Capabilities;

• EIA Regulatory Compliance;

• EIA Context & Influence;

• EIA Content;

• EIA Presentation; and

• Improving EIA Practice.

To find out more about the EIA Quality Mark please visit www.iema.net/qmark.



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Non-Technical Summary

Introduction

This Environmental Statement (ES) presents the findings of the Environmental Impact

Assessment (EIA) conducted by i3 Energy (hereafter referred to as i3) for the development of

the Liberator Field. The Liberator Field is located in United Kingdom Continental Shelf

(UKCS) Blocks 13/23c and 13/23d, approximately 64 km north east of the south Moray coast

in the South Halibut Basin of the Moray Firth, and 174 km from the UK and Norwegian median

line. It was discovered in 2013 and is not currently exploited for the production of oil and gas.

The Liberator Field shares the same Captain sand reservoir, oil type (undersaturated oil), and

initial oil water contact as the adjacent producing Blake reservoir.

Location of the Liberator field



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In 2017 an Environmental Statement (ES) was submitted to the Department of Business,

Energy and Industrial Strategy (BEIS) (Reference D/4199/2017) and a Field Development Plan

(FDP) drafted for the Liberator Phase I Field Development. This included two production wells

being drilled in Blocks 13/23d and 13/24a, tied-back to the existing Blake manifold and

processed through the existing Bleo Holm Floating Production Storage and Offloading unit

(FPSO) operated by Repsol Sinopec Resources UK Ltd (RSRUK). These documents were

however subsequently withdrawn as further field evaluation and technical studies showed that

the project design would need to change significantly.

Proposed Liberator Field Development Layout

The updated Liberator Field development detailed in this ES, now includes the drilling of three

production wells from a single drill centre in Block 13/23c and a single appraisal well from a

drill centre 0.9 km to the north-east. A new 9.8 km oil pipeline will run between the wells and

the Ross Drill Centre A (DCA) manifold. It is planned to tie Liberator into the Ross DCA



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manifold, where Liberator fluids would replace the Ross fluids for the duration of the field life.

From the Ross DCA the existing pipeline will transport fluids onwards to the Bleo Holm FPSO

for processing and export via the existing gas export pipeline and oil offtake tanker. The

Liberator field has an anticipated ten-year life.

The EIA process evaluated various alternatives available for achieving the project objectives.

During initial screening, a stand-alone facility was discounted based on economic feasibility

and vessel availability and was not assessed further. The remaining high-level options related

to a subsea tie back to a host facility, using an existing facility for processing. The initial

preferred option of a tie-back to the existing Blake manifold and Bleo Holm FPSO had to be

discounted during further field evaluation and alternative options were required.

A number of tie-in options to the Bleo Holm FPSO for the Liberator production, gas lift and

umbilical lines were assessed. The best options involved tie-in of the production and gas lift

pipeline at the DCA and tie-in of the umbilical at the Ross distribution manifold

Proposed activities

The key elements of the proposed development are:

• First drilling campaign (Q3-Q4 2019):

o A semi-submersible rig will be used to drill 1 horizontal oil production well at

the Liberator Captain Sands reservoir from the Liberator drill centre. The well

will potentially be tested, and then completed ready for subsea infrastructure

installation, including a fishing friendly wellhead protection structure (7.87 m

x 7.87 m x 5.08 m).

o The drill rig will move to the appraisal well location, 0.9 km to north east, and

drill one vertical appraisal well into the Liberator west reservoir. The appraisal

well will be logged and sampled and then abandoned.

• Second drilling campaign (Q2 2020):

o A semi-submersible rig will be used to drill 1 horizontal oil production well at

the Liberator Captain Sands reservoir from the Liberator drill centre, with the

exact target location dependent on the results of the appraisal well. The well

will potentially be tested, and then completed ready for subsea infrastructure

installation, including a fishing friendly wellhead protection structure (7.87 m

x 7.87 m x 5.08 m).

• Subsea infrastructure installation (Q2-Q3 2020)

o The two production wells will be linked together using 2 x 100 m long hard

spools and pipework. One well will then tie in directly to the production and

gas lift pipelines through 2 x 120 m long spools without the need for a manifold.

The spools will be protected using mattresses with tapered fishing friendly

edges and there will be no permanent exclusion zone in place around the wells

and pipeline tie-in area during production.

o A 10ʺ rigid, trenched and buried 9.8 km production pipeline and a 4ʺ, rigid 9.8

km gas lift line will be installed to connect the wells to the Ross Drill Centre A

(DCA) manifold for tie-in.



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o A 4ʺ, trenched and buried 10.85 km control umbilical will be installed to

connect the wells to the Ross distribution manifold (DM) within the Bleo Holm

500 m exclusion zone.

o An umbilical Subsea Umbilical Termination Unit (SUTU) will be installed on

a mattress (8 m x 4 m x 0.3 m) at the wells end of the pipeline underneath the

wellhead protection structure of a production well.

o Two crossings of existing pipeline/umbilical infrastructure will be required.

The maximum crossing height anticipated is 1.8 m for the production and gas

lift lines and 1 m for the umbilical line. Both crossings are anticipated to be

fishing friendly design using graded materials and mattresses for additional

protection.

• First hydrocarbons expected in Q3 2020

• Third drilling campaign (Q2 2021):

o A semi-submersible rig will return to the Liberator drill centre to drill 1

horizontal oil production well at the Liberator Captain Sands reservoir.

o This will tie-in to one of the previously drilled production wells through hard

pipework and spools and protected using mattresses.

2019 2020 2021

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2

Site and pipeline route

survey

Drill, evaluate and complete

first production well

Drill, evaluate and abandon

appraisal well


second production well

Subsea infrastructure

installation and pipelay

Subsea hook up to Bleo

Holm and commissioning

First Oil


third production well

The Liberator production and gas lift pipelines and umbilical will most likely tie in to existing

flanges / slots on the Ross DCA manifold and Ross DM. There will be a requirement for some

modifications on Bleo Holm topsides to facilitate the master controls for Liberator, but the



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produced fluids will use the existing Ross production and separation equipment with no

expected modifications required.

The processing of produced fluids from the Liberator field may result in changes in fuel use,

flaring, venting, chemical use and produced water discharge from the Bleo Holm FPSO.

Whilst the Liberator Field Development has a projected field life of ten years, RSRUK are

currently only projecting production of Blake/Ross through to 2024. The Bleo Holm FPSO

itself does not currently have an anticipated cessation of production date and the vessel is

maintained on an ongoing basis to remain fit for service. Discussions are ongoing on the

potential of keeping the Bleo Holm FPSO operational and onsite post 2024.

Document Scope and Objectives

This non-technical summary encapsulates the Liberator Field Development Environmental

Statement (ES), a formal document presenting the findings of the Environmental Assessment

carried out by i3 for the proposed project. The projected combined oil and gas production rates

from the Liberator development make submission of an ES mandatory under the Offshore

Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999,

as amended (including by the Offshore Production and Pipe-lines (Environmental Impact

Assessment) (Amendment) Regulations 2017).

The Environmental Assessment is a systematic assessment of the environmental effects the

proposed project may have on its surrounding environment, including accidents and effects

cumulative to those of existing developments and activities. During the assessment process,

consultations were conducted with a range of government and other bodies by letter, phone and

meetings.

The Existing Environment

A combination of data sources was used to inform the Environmental Statement, including site

specific survey data collected during historical environmental baseline surveys undertaken in

the Blake, Ross and Liberator field areas. In relation to the current Liberator development,

these surveys cover the Liberator drill centre and Ross DCA areas, and the northern and

southern ends of the pipeline route. Only the A3 appraisal well location and central 4.5km of

the pipeline route is not covered by existing survey data. A new environmental baseline survey

will be undertaken in Q1 2019 covering the updated drill centre and appraisal well locations,

and the full pipeline route corridor to the Ross DCA, however, this will not be available to

inform this Environmental Impact Assessment. A high-level summary of the environmental

sensitivities within the vicinity of the proposed field development area is provided below.

Physical environment

The proposed Liberator Field Development is located in the South Halibut Basin of the Moray

Firth, approximately 64 km from the south Moray coast. The nearest transboundary line,

between the UK and Norway, is located approximately 174 km to the north east.

The water depth at the proposed development area is approximately 100.1 m below Lowest

Astronomical Tide in the east to 135 m below Lowest Astronomical Tide in the southwest. The



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seabed is irregular across the wider Liberator area, with some prominent NNW-SSE orientated

linear shoals and a pockmark 19 m in circumference and 1.2 m in depth 47 m to the southeast

of the Ross DM.

Sediment found over the Liberator drill centre area was predominantly silty sand. Hydrocarbon

and metal concentrations in the area are generally representative of background concentrations

of very fine sandy sediments of the central North Sea and strongly correlated with sediment

characteristics, indicating natural variations associated with sediment type. It is likely that

there will be some oil-based mud contaminated cuttings piles within the Ross area, however,

these are not thought to be sited close to the Liberator pipeline route and if identified during

the 2019 survey will be further investigated.

Tides in the central North Sea flood in a north to south-easterly direction. The average mean

significant wave height in the vicinity of the Liberator field ranges from 1.81 m to 2.1 m. Winds

in the central North Sea are dominated by those from the south south-west and south, but they

can occur from all directions.

Biodiversity

Benthos describes the organisms that live within and on the seabed. Seabed imagery, acoustic

data and seabed samples identified the predominant habitats in the area as Continental shelf

muds and Continental shelf sands. Polychaetes were found to be abundant across the area,

which is typical of North Sea sediments. Three species of polychaete typically sensitive to

hydrocarbon and metal contamination were present across the Liberator area, indicating the

absence of significant contamination in the sediments sampled. Juvenile ophiuroid brittlestars

and molluscs were also abundant. Juvenile ocean quahogs (an OSPAR (2008)

threatened/declining species, Feature of Conservation Importance and Priority Marine Feature)

were recorded in the area in historical surveys, however, no adult/juveniles were recorded in

latest survey. Seapens were recorded but only a few burrows and mobile epifauna were present.

Fish species known to spawn within the area during the proposed drilling operations (Q3-Q4

2019, Q2 2020 and Q2 2021) include herring, lemon sole, Norway lobster, sandeel and sprat.

Peak spawning of Norway lobster and sprat, and spawning of cod, lemon sole, Norway pout

and whiting will occur during proposed subsea infrastructure installation (Q2 2020). A herring

spawning ground assessment indicated that the Liberator field area is not suitable for herring

spawning. The waters in the vicinity of the proposed development area also act as a high

intensity nursery area for anglerfish and whiting, and provide nursery grounds for blue whiting,

cod, European hake, haddock, herring, lemon sole, ling, mackerel, Norway lobster, Norway

pout, sandeel, spotted ray, sprat and spurdog.

Much of the North Sea and its surrounding coastline and offshore waters are internationally

important breeding and feeding habitats for seabirds. Seabirds are not normally adversely

affected by routine offshore oil and gas operations on the UK Continental Shelf; however, in

the unlikely event of an oil spill, birds are vulnerable to oiling from surface pollution. In

general, seabirds feeding or resting on the sea surface are those most vulnerable to water-borne

pollution. The most abundant seabird species found in the Liberator field area are northern

fulmar, black-legged kittiwake and common guillemot, with herring gull, glaucous gull and



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great black backed gulls using the area in winter. The periods of highest sensitivity to surface

oil pollution in Block 13/23 are February (extremely high), April to June (medium to high),

September to October (medium) and December (high). The proposed Liberator field

development area is located approximately 64 km from the nearest coastline so is therefore

remote from sensitive seabird breeding areas on the coast.

JNCC has issued a period of concern for birds relating to drilling activities in Block 13/23 for

May to September. However, updated sensitivity to surface oil pollution data suggests that

there are no 2 sequential months of very high seabird sensitivity in Block 13/23 and therefore

the period of May to September is not deemed of concern based on the current criteria.

Species most likely present in the vicinity of the Liberator field include harbour porpoise, white

beaked dolphin, bottlenose dolphin, minke whale, Atlantic white-sided dolphin, killer whale.

The Moray Firth and north-east coast of Scotland is home to the only resident population of

bottlenose dolphins in the North Sea, with the inner Moray Firth designated as a Special Area

of Conservation (SAC) due to the presence of the species, however, sightings in and around

the Liberator field have only been recorded in low numbers. Other species which may be

present include fin whale, long finned pilot whale, Risso’s dolphin and short beaked common

dolphin, but sightings are rare. As the Liberator drill centre is located approximately 64 km

from the nearest landfall, grey or harbour seals may be present in the area, but their presence

is likely to be low in numbers.

Conservation

The closest site of conservation interest to the Liberator field is the proposed Southern Trench

Nature Conservation Marine Protected Area which is located on the south Moray Firth coast

37 km south west of the Liberator field. It has been proposed for Marine Protected Area

designation for presence of minke whale, frontal zones, shelf deeps representing potential

nursery areas for fish species, and burrowed muds. There are no other sites of conservation

interest within 70 km of the Liberator field. The closest coastal designated site of conservation

interest is the Troup, Pennan and Lions Head Special Protection Area (72 km to the south west

of the Liberator field) which is designated for guillemots and seabird assemblages during the

breeding season. No Annex 1 species have been identified in any of the surveys within the

wider area.

Human Environment

Fishing effort in the vicinity of the Liberator field is moderate, with trawls being the dominant

gear type used in the area. Landings are dominated by pelagic fish, after a recent switch in

dominance from demersal to pelagic landings due to increased pelagic fishing. Mackerel was

the most important species in terms of landed weight and value in 2017, with Norway lobster

and haddock also important species in terms of value. In the vicinity of the Captain field and

gas export line and to the immediate west of the Liberator field, fishing intensity is moderate

to high with the central to northern end of the pipeline route used for turning and transiting

fishing vessels accessing the fishing grounds. Historically, the area is most heavily fished in

June and early July, with the potential for a substantial number of fishing vessels passing



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through the development area. The area south of the Liberator field along the pipeline corridor

to Ross is however an area of very low usage by fishing vessels.

Eight wells have been previously drilled in vicinity of the Liberator field. Twelve wells have

been drilled in the Blake development (5 km from Liberator), and 9 wells have been drilled in

of the Ross development (10 km from Liberator). The Liberator pipeline passes within 500 m

of a cluster of the Ross wells.

There are four offshore windfarms in the outer Moray Firth: Telford, MacColl, Stevenson and

Beatrice forming the Moray Offshore Renewables Ltd Area, approximately 68 km west of the

Liberator field.

The Liberator field is located in an area defined as having low to moderate shipping density,

with a number of ferry and cargo routes passing ca. 5 km to the west of the Liberator drill

centre. The supply vessels to the Bleo Holm approach the FPSO from the south and there is

limited vessel traffic in the Liberator and Blake area, although there is the potential for supply

vessels for other offshore installations to transit through the area.

Discussions with the SFF identified a number of obstructions adjacent to the Liberator pipeline

route area. Whilst it is not currently known whether any of the obstructions are wrecks,

anything close to the pipeline route corridor will be fully investigated during the Q1 2019

survey.

Potential sources of effect

Discharges to sea

Discharges to sea during the drilling phase of the Project will include mud, cuttings, cement

and wellbore completion and well test chemicals. The production wells will be drilled using a

combination of seawater, water-based mud and possibly low toxicity oil-based mud. As the

oil-based mud and cuttings will be contained and returned to shore for treatment and disposal,

the mud and cuttings to be discharged to the seabed will comprise material from the two surface

hole sections of the wells. This material will form a low, oval mound of 9-10 m radius around

each well, which will be re-mobilised over time by water currents and burrowing faunal

activity. This will total a seabed footprint of 1,256 m2 for the three production wells and

appraisal well.

Cuttings from drilling the 12¼ʺ and 8½ʺ sections for the production wells and just the 8½ʺ

section on the A3 appraisal well (drilled using WBM) will be discharged to sea from the rig.

This will total 1,250 tonnes in total for the 3 production wells and 80 tonnes for the appraisal

well. Previous modelling carried out to determine the impact of the discharge of cuttings at

the nearby Blake development was used to assess the impact of such discharges at the Liberator

development. Given the nature and volume of the drilling muds and drill cuttings to be

discharged, the comparatively small area of impact, the relatively rapid recovery rate of the

water column and seabed and the absence of Annex I habitats no significant ecological effects

through smothering or physical disturbance are expected.



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Discharges due to installation of subsea infrastructure will include chemicals used in pipeline

flooding and cleaning, and installation and commissioning of spools and the umbilical. All

associated chemicals will be risk assessed and permitted in accordance with the Offshore

Chemicals Regulations 2002 (as amended). When combined with the physical and biological

conditions in the vicinity of the development the environmental impact of any discharges

associated with the subsea installation and commissioning phase is considered low. This also

applies for incremental increases in process chemicals required on the Bleo Holm FPSO during

production operations. It is also supported by a number of studies of the effects of subsea and

FPSO production operations in the North Sea and elsewhere.

Incremental discharges from the Bleo Holm FPSO during production, resulting from the

Liberator field will include produced water. An annual increase of 2-23% is predicted (based

on the low case production profiles), equating to an additional discharge of between 0.72 and

7.09 tonnes/year of oil. This small increase in produced water volumes are not expected to

affect the performance of the Bleo Holm produced water treatment facilities or their ability to

meet best BAT or BEP, as detailed in the Bleo Holm OPPC permit. The minor increase in

produced water discharge from the Bleo Holm resulting from the Liberator development is not

predicted to result in a significant spatial area of effect. As a result, any impact on biota will be

very localised, probably within the 500 m safety zone area with no significant wider impact.

Physical disturbance

The proposed field development activities have the potential to cause disturbance to the seabed

from the footprint of the drill rig anchors and wellheads, placement of mattresses and rock, and

sediment disturbance during installation of the pipelines. Impacts to the marine environment

include physical trauma to organisms, smothering of organisms and habitats, and habitat loss

due to a change in physio-chemical characteristics. It is expected that 0.68 km2 of seabed will

be impacted due to the proposed activities. However, this is extremely small considering the

seabed habitat types and associated communities are widespread over the wider Liberator area

and there are no protected habitats/species found in the vicinity. The majority of this impacted

area is likely to be affected only in the short term, with most seabed species found in the area

having short life spans and high reproduction rates, so population recovery is expected to be

relatively rapid. Placement of hard substrates such as mattresses may result in a slight change

in species distribution in the area from those that favour the sandy sediments to those that

require a hard attachment point. Sediment suspension and re-settlement may affect obligate

filter feeders, however, as the proposed activities are short term and one-off in nature, it is not

expected that an increase in suspended solids will persist for more than a day following

cessation of operations. Overall, the consequence is low and there will be no significant

residual adverse effects expected as a result of the disturbance to the seabed from the proposed

Liberator Field Development activities.

Underwater noise

Noise sources that have been identified as likely to occur during the Liberator Field

Development are limited to drill rig, vessel use and potential VSP activity. The probability of

exposure of any individual marine mammal within the Liberator area is low especially given



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the low density of sensitive species within the area. Fish spawning in the area may be affected

by VSP activity, with VSPs potentially taking place during a Marine Scotland period of concern

for seismic surveys between February and June. VSPs will be used only for a short duration,

limited to 36 hours per well, and mitigation measures such as soft start will be used to further

reduce impacts on marine mammals and fish. Installation and support vessels will be slow

moving and will not produce any sudden bursts of sound, allowing marine mammals and fish

to move away, thus avoiding injury. Any impacts from exposure to underwater noise will only

affect individual marine mammals within a very limited range of the VSP source (<20 m for

pinnipeds and low and mid frequency cetaceans and 126 m for high frequency cetaceans) and

for a very short duration These will cause at most behavioural modifications, so will not have

significant effects at a population scale, or over and individual lifespan. Similarly, with fish

species, if injury were to be caused to individuals by the VSPs, it is unlikely that this would

result in any significant impact at a population level, and any movement away from the area

due to noise emissions will be short term and unlikely to result in any population level impacts.

Overall, the consequence is low and there will be no significant residual adverse effects

expected as a result of noise emissions in the Liberator area.

Physical presence

The physical presence of the drill rig, installation vessels, pipelines and subsea facilities have

been identified as a potential cause of effect, primarily for fisheries and navigation. The drill

rig and associated temporary 500 m exclusion zone has the potential to displace any vessels

from regular routes and lead to extended passage times and increased fuel use, however, as the

Liberator area is not widely used by commercial and passenger vessels it is unlikely to be

significantly impacted by the presence of the drill rig, pipelay and associated vessels. There is

also adequate sea room to allow minor route alterations to be made without significant impact.

Commercial fishing vessels will be temporarily displaced from an area of 0.8 km2 whilst the

drill rig is on site, but this is for a very short duration and will impact a very small area of the

wider fishing grounds. It is also likely that vessels will be able to switch to other fishing grounds

in the short-term if required, as the fish stock present in the vicinity of the proposed Liberator

Field Development is not exclusive to this area. Any fishing vessels using the Liberator area

for transit or turning in relation to the deep fishing grounds to the west will not be impacted

out with the duration of the drilling programme as no permanent exclusion zones will be

applied for. Subsea infrastructure will be designed to be fishing friendly so as to minimise the

risk of snagging and post lay surveys will identify any clay berms or potential hazards to fishing

activities, with the potential for post installation remedial action in consultation with SFF.

Overall, the consequence is low and there will be no significant residual adverse effects

expected as a result of physical presence in the Liberator area.

Atmospheric emissions

The major sources of emissions from the Liberator Field Development during the drilling and

installation phases will be from fuel consumption by the drill rig, installation vessels and

helicopters, and flaring activities if well testing is carried out. Emissions associated with

operation of the field can be split into incremental increases in flaring and venting on the Bleo

Holm, increased vessel use and incremental requirements of fuel gas and diesel for power



19

generation. Atmospheric emissions from the development and operation of the Liberator field

may impact on air quality at a local level, with the potential to contribute on a wider scale to

global warming. Any releases from drilling, installation and commissioning will be transitory,

and emissions from operational activities will be intermittent throughout the life of the field.

On a local, regional and transboundary level, there will be no significant impacts due to the

remote location of the field from other industrial/oil and gas activities and from coastal areas

and the UK/Norway median line. On a wider scale, the emissions will account for 0.003% of

the whole UK carbon budget, which is a very small component of the overall emissions in the

UK. Overall, the consequence is negligible and there will be no significant residual adverse

effects expected as a result of atmospheric emissions released during the development of the

Liberator field.

Accidental events

The risk of an accidental hydrocarbon spillage to the sea is often one of the main environmental

concerns associated with oil-industry activities. At Liberator the expected hydrocarbon is

undersaturated oil.

The current planned wells originate from a surface location some 3 km from the original

planned layout. However, they are of very similar design and access the same reservoir and oil

as the original plan. Hence the blowout modelling remains valid.

As the site is >60 km from the nearest coastline it is not expected that a 3 km difference in well

release location will affect the outcome of the oil spill modelling.

An uncontrolled well blow-out at Liberator L2 over 84 days at a variable flowrate resulted in:

• The shortest arrival time for oil to beach in the UK was 2 days in the spring season;

• There was a high probability (90-100%) of oil crossing the UK/Norway transboundary

line within three days in the winter season;

• The probability of shoreline oiling was generally less than 30% for most areas; and

• The areas at most risk are expected to be in Scotland, specifically Grampian (up to 70%

probability within 2 days) and Orkney (up to 40% probability within 2.5 days).

Whilst the potential consequences of a well blowout are severe, the likelihood of a well blowout

occurring during operations in the Liberator field is remote. The most likely spill risk is

associated with hose failure during transfer of drilling mud, diesel and chemicals during drilling

operations. These spills are expected to be small in volume and procedures will be in place to

reduce the risk and consequence of any spill, in particular written procedures, regular

inspection of equipment and provision of spill kits.

Even with comprehensive prevention measures in place (including a device called a blowout

preventer, which can seal, control and monitor a well), the residual risk of a spill remains, and

integral to offshore operations is the formulation of detailed and fully tested emergency

response plans. i3 Energy has in place a range of response/mitigation measures to address such

risks. All drilling activities will be covered by approved Oil Pollution Emergency Plans. The



20

Oil Pollution Emergency Plan sets out the responses required and the available resources for

dealing with all spills.

The planning, design and support of all activities for the Liberator Field Development will aim

to eliminate or minimise potential environmental risks. As described, these impacts are being

mitigated through the equipment design, spill risk reduction measures and provision of

appropriate spill response arrangements. i3 Energy’s Integrated Management System (IMS)

processes are in place to ensure that these mitigation commitments are implemented and

monitored.

Considering the controls described above and the mitigation measures that will be put in place,

the residual risk will be very low and is therefore considered to be not significant.

Cumulative Effects

Incremental, cumulative and synergistic effects have been reviewed, with incremental effects

possible in the event of a major oil spill from hydrocarbon exploration or production activities.

Minor incremental or cumulative risks (i.e. effects acting additively or in combination with

those of other human activities) were identified in relation to noise, discharges, physical

presence and disturbance of the seabed, oil spills and emissions to atmosphere. No significant

major cumulative or synergistic effects – where joint effect of two or more processes is greater

than the sum of individual effects – are predicted.

Decommissioning

i3 will review decommissioning best practice closer to the point at which the Development will

be decommissioned. Full consideration will be given to available decommissioning options,

including reuse and removal. Decommissioning of the Liberator Field Development will be

post 2024.

Summary of Mitigation and Controls

A number of commitments and mitigation measures have been developed to ensure that the

potential impact from the Development is not significant. Development of mitigation measures

has considered whether seasonal sensitivities are sufficiently great to drive scheduling

commitments. The commitments register identified as part of this environmental impact

assessment will be incorporated into an Environmental Management Plan for the project.

Conclusions

The Liberator Field Development EIA has considered the objectives and marine planning

policies of the Scottish National Marine Plan across the range of policy topics including natural

heritage, air quality, cumulative impacts and oil and gas. i3 Energy considers that the Liberator

Field Development is in broad alignment with such objectives and policies.

Overall, it is concluded that the limited geographical scale of the Development, the location of

the Development (out with any protected site and a significant distance from the coastline) and

the limited temporal scale of the Development (field life is 10 years), combined with the



21

proposed mitigation measures, mean the Development will not result in any significant long-

term impacts.



23

1 Introduction

1.1 The Liberator Field Development

This Environmental Statement presents the findings of the Environmental Impact Assessment

conducted by i3 Energy (hereafter referred to as i3) for the development of the Liberator field.

The Liberator field is located in United Kingdom Continental Shelf (UKCS) Blocks 13/23c

and 13/23d, approximately 64 km north east of the south Moray coast in the South Halibut

Basin of the Moray Firth (Figure 1-1), and 174 km from the UK and Norwegian median line.

The Liberator field was discovered in 2013 and is not currently exploited for the production of

oil and gas.

Figure 1-1 Location of the Liberator field



24

1.2 Development Background and Purpose

An appraisal well (13/23d-8) was drilled in Block 13/23 in the Liberator Field in 2013 by Dana

Petroleum, confirming the presence of oil (30˚ API) within the Cretaceous Captain sands

reservoir. In 2015 oil and gas production and development company i3 Energy acquired 100%

of the operating licence and working interest in License P1987 covering Block 13/23d (the

eastern end of the Liberator Field) from Dana Petroleum. The Liberator Phase 1 development

was progressed, with a drafted Field Development Plan (FDP) and an Environmental Statement

(ES – reference D/4199/2017) submitted in September 2017 based on two wells (L1 and L2)

being drilled in Blocks 13/23d and 13/24a, tied-back to the existing Blake manifold and

processed through the existing Bleo Holm Floating Production Storage and Offloading unit

(FPSO) operated by Repsol Sinopec Resources UK Ltd (RSRUK) (Figure 1-2).

Figure 1-2 Initial proposed Liberator wells and tieback to existing Blake manifold and Bleo Holm FPSO

During further technical work an alternative tie-in option for the Liberator field was identified

(see Section 2.1 for further information). Subsequent work by i3 mapped a westward extension

of the Liberator reservoir (Liberator West) into the adjacent block, Block 13/23c, and as a result

i3 submitted a bid for the block in the UK’s 30th Offshore Licensing Round in November 2017.

In May 2018 i3 was awarded Block 13/23c under license P2358 and decided to modify the

Liberator FDP and ES to allow the development to include the larger reservoir area therefore

maximising hydrocarbon recovery. With the addition of Block 13/23c, Liberator and Liberator



25

West form a single elongate structure, 10 km long and 4 km wide, and which potentially

contains up to 310.3 million barrels of oil initially in place

The extended development now includes the drilling of three production wells from a single

drill centre in Block 13/23c, tied back via a 9.8 km production pipeline to the Ross Drill Centre

A (DCA) manifold and onward transport to the Bleo Holm FPSO for processing and export

(Figures 1-3 and 1-4). An additional appraisal well, known as A3, at Liberator West will also

be drilled, in order to fully appraise the western area of the reservoir structure and validate the

current mapping of the field extension. The appraisal well has been included in this assessment

to ensure the environmental impacts associated with the well are accounted for, as it is i3’s

intention to drill the appraisal well in the same campaign as the first production well (known

as L2). The results of the appraisal well will then be used to determine the location of the

second production well (L4) which will be drilled in a separate drilling campaign. Both wells

will be produced from at first oil. Post first oil, a third development well (L1) will be drilled

from the same drill centre location in a third drilling campaign.

Depending on reservoir performance post first oil, i3 will consider the possibility of further

development of Liberator, including additional seismic processing, through a Phase 2. Such a

development would be subject to further field development planning and environmental

assessment process and is not discussed further in this document.

The expected field life of the Liberator development described in this ES is ten years.

Figure 1-3 The existing Bleo Holm FPSO, on which produced fluids will be processed (Bluewater, 2017)



26

Figure 1-4 Revised Liberator development layout



27

The Liberator Field Development has a number of potential economic benefits for the UK:

• Generation of additional revenue to the UK Government from increased oil and gas

production;

• Contribution to the security of the UK’s energy supply;

• On a local and national scale, the Development may secure or add to the onshore and

offshore employment in the area, in particular during the drilling and installation

phases; and

• Extended use of the existing production infrastructure which may facilitate future

developments in the area.

1.3 i3 Energy’s Environmental Awareness

The management of environmental risks associated with i3’s activities is integral to the

business decision making process. Environmental hazards are identified at all stages for the

Liberator Field Development and are assessed and managed via ongoing monitoring and the

integrated management system (IMS). Managing environmental issues associated with the

Liberator Field Development are important to i3; as a new operator in the North Sea, the

company is keen to demonstrate awareness of the environmental requirements and to have an

environmental management system that supports the development and commitments

associated with the submission of a formal Environmental Statement. The i3 environmental

policy is provided in Section 1.7 below. Further details on how environmental commitments

made in this ES will be taken forward into execution of the Liberator Field Development are

given in Section 6.

1.4 Environmental assessment process

This Environmental Statement (ES) documents the results of the EIA process highlighting

environmental sensitivities, identifying potential hazards, assessing/predicting risks to the

environment and identifying practical mitigation and monitoring measures to be carried

forward into detailed field operations. The ES has been produced in accordance with the

Offshore Petroleum Production and Pipelines (assessment of Environmental Effects)

Regulations 1999 (as amended) under which the submission of an ES to the Secretary of State

for the Department for Business, Energy and Industrial Strategy may be required for the

development of hydrocarbon reservoirs.

For this ES, the interactions between the proposed activities and the environment (in its broad

sense) together with issues raised during previous consultations with government bodies and

others were identified at the screening and scoping stages of the EIA process, using defined

severity criteria (see Section 4); those interactions with the potential to result in significant

environmental effects were then assessed in more detail (see Section 5). Where appropriate,

mitigation measures were identified to reduce effects and to ensure compliance with i3 internal

process and legal standards. An Environmental Issues Identification (ENVID) workshop was

conducted during the EIA process for the initial Environmental Statement. The outputs of the



28

ENVID were considered in a subsequent workshop designed to identify project changes, with

the outputs being integrated into this Environmental Statement.

1.5 Scope of the EIA

The overall aim of the EIA is to assess the potential environmental impacts that may arise from

the Liberator Field Development and to identify the measures that will be put in place to reduce

these potential impacts. The EIA process is integral to the Development, assessing potential

impacts and alternatives, and identifying design and operational elements to help reduce the

potential impacts of the Development as far as reasonably practical. The process also provides

for stakeholder involvement so that issues can be identified and addressed as appropriate at an

early stage and helps to ensure planned activities comply with environmental legislative

requirements and with i3’s environmental policy.

The EIA scope covers drilling, installation, commissioning and operational activities, and

decommissioning of the Development over which i3 has operational control. Specifically, the

EIA has considered routine and accidental events associated with:

• Drilling, potential well test and production from the three Liberator development wells;

• Drilling, logging, sampling and abandonment of the Liberator A3 appraisal well

• Installation, operation and maintenance of the new production pipeline, gas lift pipeline,

umbilical and spools;

• Installation, operation and maintenance of the subsea umbilical connector pieces;

• Incremental impacts at the Bleo Holm FPSO as a result of production from the Liberator

field; and

• Decommissioning of the Liberator field (including the wells, gas pipeline and

umbilical).

1.6 Consultation

During the scoping stage of both the original and revised EIA processes, and to inform ES

preparation, scoping meetings were held with the Department of Business, Energy and

Industrial Strategy (BEIS), Joint Nature Conservation Council (JNCC), Marine Scotland (MS)

and Scottish Fisherman’s Federation (SFF). Meetings were undertaken in May 2017 for the

original project description and again in October and November 2018 to discuss the revised

development.

Issues and information identified during the 2017 and 2018 consultations of relevance to the

proposed development in Block 13/23c and 13/23d are addressed in this Environmental

Statement and summarised in Table 1-1 below. Issues identified in the 2017 consultation

phase, where still relevant, were incorporated into the revised documents along with

stakeholder and public comments from the statutory review period.



29

Table 1-1 Comments and issues raised in scoping meetings

2017 Consultation

Organisation Comments / Issues

ES Section

(if still

applicable)

Department of

Business, Energy and

Industrial Strategy

ES needs to include a discussion of the alternatives considered for

the project

Justification of the use of historical surveys in lieu of the 2017

baseline survey results, and, once available, the 2017 results should

be used to inform future permits

The production figures over the life of the field must be the same

as those quoted in the Final Development Plan (FDP), presenting

best case (i.e. highest) predicted production levels for any

emissions and discharges

A likely significant effect assessment for major accidents arising

from the development should be provided. Any modelling should

describe the worst-case scenario and present relevant mitigation

A cumulative impact assessment at both the project level and in

relation to neighbouring development should be included

i3 will use the most appropriate mattress for the timescale and

environment, if used. BEIS expects polypropylene mattresses to be

recovered at the time of decommissioning, if these are used

ES should reference human health issues, and predicted effects of

climate change

ES should include a table outlining environmental commitments

and details of how these will be monitored/audited to ensure

compliance

Information on how decommissioning plans have been

incorporated in to the design process should be presented

2.1

N/A

2.4

5.7

5.1-5.7 / 7.3

2.7.8

5.6

6

2.10

Marine Scotland Any literature review used in drill cutting discharge impact

assessment should include information of the relative volumes and

types of cuttings discharges, and of similarities in environmental

conditions

ES should include information on the type of protection around the

infrastructure (i.e. fishing friendly or over-trawlable)

ES should note if the integrity of the Blake pipelines is suited to an

extended field life or if these are likely to require replacement

Use should be made of the NMPi online data resource

ES should use the Feature Activity Sensitivity Tool (FEAST) to

assist in describing likely impacts on species of conservation

concern of species indicative of conservation habitats

5.2

2.6 / 2.7

N/A

Multiple

Sections

5.1 – 5.7



30

Joint Nature

Conservation

Committee

Noted the availability of the Ocean Biogeographic Information

System Spatial Ecological Analysis of Megavertebrate Populations

(OBIS SEAMAP).

Latest seabird sensitivity to oil pollution data should be used

3.3

3.3.3

Scottish Fishermen’s

Federation

Area is most heavily fished June to early July with potential for a

lot of fishing vessel movement

Advised that the wellhead protection structure is expected to be

fishing friendly rather than over-trawlable

Advised that the underlying seabed material could be clay and if

disturbed by ‘V’ trenching, could create a high clay berm that is

problematic to fishing

Noted that there is a potential wreck positioned on the proposed

pipeline route

3.5.3

2.6.1 / 2.7.7 /

5.5.2 / 6

2.7.8 / 5.5.2

N/A

All i3 propose to scope out impacts resulting from produced water

discharge, emissions to atmosphere from operational fuel use and

flaring on the FPSO, and operational waste generation by FPSO, if

reported volumes and characteristics are no different or less that

existing figures

i3 propose to carry out a qualitative assessment of underwater noise

impacts rather than undertaking propagation modelling

i3 propose to carry out oil spill modelling for worst-case oil spill

incident (well blowout) plus loss of marine diesel fuel inventory

(rig or FPSO), and proposal to not model loss of containment from

the ~2 km pipeline from Well L2 to Blake.

If bringing Liberator on stream extends the life of the FPSO this

should be made clear in the ES and impacts should be assessed.

The environment baseline should include information on other sea

users, specifically cultural heritage information (including

wrecks), military practice and exercise areas, and shipping/other

vessels.

N/A

5.4

5.7

5.2 / 5.3 / 5.5

/ 5.6

3.5

2018 Consultation

Organisation Comments / Issues ES Section

Joint Nature

Conservation

Committee

Needs to be clear what survey results the environmental

description is based on and to provide information on when / how

information from the 2019 survey will be included.

Submit results of 2019 survey to consultees as soon as possible.

Keep consultees up to date with ES submission schedule.

3.1 / 3.3.1 /

2.7.8 / 2.7.5

N/A

N/A

Marine Scotland ES needs to include pipeline design and crossing information,

including material, mattress and rock dump options sections and

reasoning.

Large shift in regional fishing effort from demersal to pelagic

since 2016 needs to be acknowledged and discussed.

2.7

3.5.3



31

Scottish Fisherman’s

Federation

Noted that trenching and backfill can leave a berm when the soil

is heavy clay following the installation of offshore pipelines. This

can create difficulties for fishing vessels and have in the past

proven dangerous for trawling. SFF can undertake

overtrawlability trials immediately after installation of subsea

equipment as a means of providing assurance to fishermen that it

is safe to return to fish in an area. This is seen as mitigation.

A number of seabed obstructions / wrecks are noted close to the

pipeline route corridor

The drill centre and northern end of the pipeline route corridor are

in an area used by fishing vessels for turning and accessing deep

fishing grounds to the west of the drill centre.

Advised that fishing vessel days and value of landings data needs

to be carefully used as pelagic fishing can catch a large number of

fish in a small number of days.

2.7 / 5.3.3 / 6

3.5.7

3.5.3 / 5.5.2

3.5.3

Department of

Business, Energy and

Industrial Strategy

Request a summary of the 2019 survey results and confirmation

that they are in line with results from other surveys which have

been documented in the baseline, particularly noting any

environmental sensitivities. Likely to be done as a request for

further information following receipt of the ES.

The Captain area has high levels of fishing effort, impacts on

which needs to be discussed.

Keep Offshore Inspectorate up to date with rig selection process

and may require a pre-spud audit of drill rig

There has been concern over Repsol’s produced water (PW)

handling capabilities. Further information / assessment is required

in the ES on Liberators impact and general Bleo Holm PW

philosophy and clean up capability.

ES needs to include a discussion on the change in the development

and further information on alternatives

The updated 2017 OPEP guidance needs to be considered

All relevant consultee comments from the 2017 Liberator ES to be

addressed in the 2018 ES.

N/A

3.5.3 / 5.5.2

N/A

2.8.1 / 5.2.5

2.1

5.7

1.6

1.7 Legislation and policy

i3 Environmental Policy

The Liberator Development programme will be conducted in a manner consistent with i3

Energy Environmental policy, reproduced overleaf. The policy is endorsed by the Chief

Executive Officer of i3 Energy PLC and i3 Energy North Sea Limited on behalf of the Board

of Directors. The policy acknowledges i3’s Environmental responsibilities in relation to its

business activities and includes commitments to continual improvement, to assessment and

management of the risks and impacts associated with operations, meet legislative requirements

and accepted best practice and a willingness to openly communicate these principles to

company personnel, contractors and suppliers.



32

Figure 1-5 i3 Energy environmental policy

i3 recognises its policy and legal obligations to identify, assess and mitigate environmental

risks and actively manage environmental performance of field operations. To achieve this, i3

is using the ISO 14001:2015 standard as the model to manage the company environmental

commitments. The EMS manual documents the processes implemented by i3 to meet all

applicable principals of ISO 14001 and relevant elements of the integrated management system

(IMS). The EMS manual sets out the framework for environmental management that enables

the implementation of the processes needed to deliver continuous improvement and to meet



33

the company’s obligations as a field licensee. These processes and procedures documents are

found in the company IMS.

Drilling rig and other contractors environmental policies and systems

A semi-submersible rig will be used to drill the wells as part of the Liberator development.

Whilst the rig is yet to be identified, it is an i3 requirement that the rig operator and associated

contractors will have environmental management systems complying with ISO 14001 standard

or guidelines.

Legislation

Block licenses may contain specific seasonal or other conditions on the advice of JNCC,

Marine Scotland or other advisors. The following block specific issues shown in Table 1-2

were identified for Blocks 13/23c and 13/23d. As these relate to seismic survey and drilling

activity, which will both be undertaken at the drill centre location, only block specific issues

for Block 13/23 have been included.

Table 1-2 Block specific issues (BEIS, 2018b)

Seasonal concerns 4. Special

conditions Block or sub-

block

1. Period of concern

for seismic surveys

2. Period of concern

for drilling

3. Spawning sites

13/23 February to June May to September - -

The months of concern for seismic survey and drilling operations detailed above for the block

relate to periods of the year where Marine Scotland and JNCC has indicated concerns about

possible environmental effects of seismic surveys or drilling operations in the area (e.g. because

of potential adverse effects on fish spawning or bird migration respectively). It is presumed

that seismic surveys cannot be undertaken during these months in the area, however it may be

possible to agree with Marine Scotland appropriate mitigation methods to minimise potential

adverse effects. Periods of concern for drilling are generally based on two or more sequential

months of very high seabird sensitivity, as indicated by the Offshore Vulnerability Index (OVI)

(JNCC, 1999). A revised Seabird Oil Sensitivity Index (SOSI) was published in 2015 (JNCC,

2016) and BEIS recommends that operators check any periods of concern using the SOSI

information. The SOSI results shown and discussed in Section 3.3.3, indicate that in Block

13/23 there are no sequential months of very high seabird sensitivity.

The EIA reported in this ES has been carried out in accordance with the requirements of the

Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects)

Regulations 1999, as amended (including by the Offshore Production and Pipe-lines

(Environmental Impact Assessment) (Amendment) Regulations 2017). These Regulations

require the undertaking of an EIA and the production of an ES for certain types of offshore oil

and gas developments likely to have a significant impact on the environment. An EIA is

mandatory for any offshore oil and gas development that is expected to produce more than 500

tonnes of oil per day or more than 500,000 m3 gas per day. An EIA is also required for pipelines

greater than 40 km in length or with an overall diameter of more than 800 mm. The Liberator



34

Field Development triggers an EIA on the grounds of reaching the oil production threshold of

500 tonnes of oil per day.

There are a number of other key regulatory drivers applicable to the Development, with the

key legislation being:

• The Petroleum Act 1998;

• The Petroleum Licensing (Production) (Seaward Areas) Regulations 2008;

• Energy Act 2008, as amended;

• The Offshore Petroleum Activities (Conservation of Habitats) Regulations 2001, as

amended;

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

amended;

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

2005, as amended;

• The Offshore Chemical Regulations 2002, as amended;

• The Merchant Shipping (Prevention of Pollution by Garbage) Regulations 1998;

• The Merchant Shipping (Oil Pollution Preparedness, Response & Co-operation

Convention) Regulations 1998;

• The Merchant Shipping (Prevention of Air Pollution from Ships) Regulations 2008 (as

amended);

• Oil Pollution Preparedness, Response and Co-operation Convention Regulations 1998

as amended;

• The Offshore Installations (Emergency Pollution Control) Regulations 2002;

• The Marine and Coastal Access Act 2009;

• The Marine (Scotland) Act 2010;

• The Marine Strategy Regulations 2010 (which implement the European Marine

Strategy Framework Directive); and

• Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015.

The EIA Regulations require that the EIA should consider the likely significant impacts of a

project on the environment. The scope of the EIA is informed by a number of different

processes, including an environmental issues identification (ENVID) workshop and

consultation with stakeholders. Following this, the decision-making process related to defining

whether or not a project has the potential to cause significant impact on the environment, this

is the core principle of the EIA process. The EIA Regulations themselves do not provide a

specific definition of significance, but they indicate that the methods used for identifying and



35

assessing potential impacts should be transparent and verifiable. A defined methodology has

been adopted by i3 to make the assessment as objective as possible.

In addition, European Union Directive 92/43/EEC on the conservation of natural habitats and

of wild flora and fauna, more commonly known as the Habitats Directive, provides protection

to European sites (Special Areas of Conservation, SACs), and the Birds Directive (Special

Protection Areas, SPAs), collectively referred to as Natura 2000 or European sites. Under

Article 6(3) of the Habitats Directive, “any plan or project which is not directly connected with

or necessary to the management of a European site but would be likely to have a significant

impact on such a site, either individually or in-combination with other plans and projects, shall

be subject to an appropriate assessment of its implications for the European site in view of the

site’s conservation objectives.”

The Habitats Directive applies the precautionary principle to these sites and projects can only

be permitted when it is ascertained that there will be no adverse impact on the integrity of any

European-designated site(s). Where adverse impacts are identified a project may only be

permitted in the absence of alternative solutions if there is an Imperative Reason of Overriding

Public Interest (IROPI) for the project to go ahead. Where this is the case, Member States are

required to take all compensatory measures necessary to ensure that the overall coherence of

the Natura 2000 network is protected. The requirements of the Habitats Directive are

implemented for offshore oil and gas activities, beyond 12 nautical miles but within the United

Kingdom’s Continental Shelf, under the Offshore Petroleum Activities (Conservation of

Habitats) Regulations 2001. The Offshore Marine Conservation Natural Habitats Regulations

(2007) also ensure that certain activities with potential impacts on species and habitats are

managed. In accordance with these Regulations, the impacts of a project on the integrity of a

European site are assessed and evaluated as part of the Habitat Regulations Appraisal (HRA)

process. Relevant information required for the HRA process is provided in Chapter 5. In

addition, the Marine (Scotland) Act and the Marine and Coastal Access Act require the

potential for significant risk to the conservation objectives of Nature Conservation Marine

Protected Areas (NCMPAs) and Marine Conservation Zones (MCZs) respectively, to be

assessed. As for the HRA process, the relevant information is presented in Chapter 5.

The UK Marine Policy Statement (UK wide) underpins Marine Plans produced in the UK and

further embeds sustainable development. The Scottish Government adopted the National

Marine Plan in early 2015 (Scottish Government, 2015) to provide an overarching framework

for marine activity in Scottish waters, with an aim to enable sustainable development and the

use of the marine area in a way that protects and enhances the marine environment whilst

promoting both existing and emerging industries. This is underpinned by a core set of general

policies which apply across existing and future development and use of the marine

environment; policies of particular relevance to the Liberator Field Development include:

• General planning principle: There is a presumption in favour of sustainable

development and use of the marine environment when consistent with the policies and

objectives of the Plan;



36

• Economic benefit: Sustainable development and use which provides economic benefit

to Scottish communities is encouraged when consistent with the objectives and policies

of this Plan;

• Natural heritage: Development and use of the marine environment must:

o Comply with legal requirements for protected areas and protected species.

o Not result in significant impact on the national status of Priority Marine

Features.

o Protect and, where appropriate, enhance the health of the marine area.

• Noise: Development and use in the marine environment should avoid significant

adverse effects of manmade noise and vibration, especially on species sensitive to such

effects;

• Air quality: Development and use of the marine environment should not result in the

deterioration of air quality and should not breach any statutory air quality limits;

• Engagement: Early and effective engagement should be undertaken with the general

public and interested stakeholders to facilitate planning and consenting processes; and

• Cumulative impacts: Cumulative impacts affecting the ecosystem of the Marine Plan

area should be addressed in decision-making and Plan implementation.

Sectoral policies are also outlined in the Plan where a particular industry brings with it issues

beyond those set out in the general policies.

1.8 The Environmental Statement

Key elements of this ES include the following:

• A non-technical summary of the ES;

• Description of the background to the Development; purpose of the EIA and legislative

context (this chapter);

• Description of the Development and alternatives considered (Chapter 2);

• Description of the environment and identification of the key environmental sensitivities

which may be impacted by the Development (Chapter 3);

• Description of the methods used to identify and evaluate the potential environmental

impacts (Chapter 4);

• Detailed assessment of key potential impacts, including assessment of potential

cumulative and transboundary impacts (Chapter 5);

• Description of the environmental management measures (Chapter 6); and

• Conclusions (Chapter 7).

• Appendix A – Acronyms



37

• Appendix B – Supporting data for accidental events assessment

The ES is submitted to The Offshore Petroleum Regulator for Environment and

Decommissioning (OPRED), part of the Department for Business, Energy and Industrial

Strategy (BEIS) to inform the decision on whether or not the Development may proceed, based

on the residual levels of potential impact. This ES is subject to formal public consultation.



39

2 Development Description

2.1 Consideration of Alternatives

Process

The development option selection for the Liberator Field Development was based on

minimising environmental, health and safety, technical, project execution and commercial risks

and impacts. Although the Development EIA did not commence until later in the design

process, environmental considerations were part of the concept selection process.

High level options screening

Of the three high-level concept development options initially identified (Table 2-1 below), one

was discounted on economic feasibility and the other two were taken forward for further

evaluation.

Table 2-1 Summary of initial high-level options screening

High level concept option Carried forward / Discounted Notes

Wells to be tied in to existing

infrastructure with fluids

returned to an existing facility

for processing

Carried forward Further evaluated – see below

Wells to be tied in to new

subsea infrastructure with fluids

returned to as existing facility

for processing

Carried forward Further evaluated – see below

Wells to be tied in to a new

subsea infrastructure with fluids

returned to a new FPSO or fixed

platform for processing.

Option discounted Relatively moderate reserves

and flow rates preclude

significant capital investment in

stand-alone facilities

An investigation into a stand-alone tie back to a dedicated FPSO included a market review of

available vessels. Only one vessel was deemed suitable and definitely available, and this came

with project funding and technical issues which made it an unfavorable option. A further

scenario of a jack-up rig permanently placed at Liberator with oil and gas export via the Bleo

Holm (oil) and either Bleo Holm or Captain gas line (gas) was developed and discounted. An

alternative, of placing the jack up on a subsea storage tank, was also considered and discounted.

These three options demonstrated significantly reduced financial returns and major investment

obstacles and were rejected on the basis that they are not economically feasible for the project

to progress.

Producing via an existing facility offered a number of economic and other advantages, although

this part of the outer Moray Firth is sparsely developed in relation to oil and gas compared with

other oil and gas areas of the UKCS. The nearest existing oil and gas facilities to Liberator are

the Captain FPSO, operated by Chevron, 20 km to the north west and the Bleo Holm FPSO,

operated by Repsol, 9 km to the south.



40

Two options for producing via an existing facility were investigated. Firstly, a direct tie-in to

the existing Blake subsea infrastructure and onward processing and export via the Bleo Holm

FPSO. Secondly either a direct tie-in to Ross subsea infrastructure or new subsea infrastructure

and tie-back to Ross, with onward processing and export via the Bleo Holm FPSO.

It should be noted that at the time of submitting this ES commercial discussions between i3

and RSRUK are ongoing to reach a commercial agreement that allows Liberator production

fluids to be processed via the Bleo Holm FPSO.

Initially, well engineering studies suggested that two drill centres were optimal for the

Development, balancing drilling cost and risk against subsea infrastructure costs. The chosen

well locations (L1 and L2 in Figure 2-1) were proximal to the existing Blake manifold (within

2km), which tied back to the Repsol operated Bleo Holm FPSO. The proximity to this existing

structure and the option for direct tie-in to the Blake manifold meant that this was the preferred

and chosen option for the field development, with no requirement for new subsea infrastructure

other than two short pipelines. The development progressed with this option, with a drafted

Field Development Plan (FDP) and an Environmental Statement (ES) submitted in September

2017 (BEIS reference: D/4199/2007).

Figure 2-1 Initial chosen layout for the Liberator field prior to field layout re-design

As the development progressed a further review of tie-in locations and development options

identified the Ross field infrastructure as a potential route to taking Liberator fluids to the Bleo

Holm FPSO. The mapping of a westwards extension of the Liberator reservoir into Block

13/23c and the award of this Block to i3 in the 30th Offshore Licensing Round prompted a

reconsideration of the location of the Liberator drill centre. As a result, a single Liberator drill

centre was seen as the preferred option, relocated to the north west of the Blake Manifold in

open water and positioned to allow more effective recovery of the larger Liberator reservoir.

As a result, a new FDP and ES were required.



41

There was no alternative option for tying directly into the existing Blake subsea infrastructure,

which was considered unsuitable for the new development. So, either a direct tie-in to the Ross

subsea infrastructure was required or new infrastructure connected directly to the Bleo Holm

FPSO.

A number of tie-in options to the Bleo Holm for the Liberator production, gas lift and umbilical

lines were assessed and are outlined in Table 2-2 below. Locations discussed are shown in

Figure 2-2, along with options 3 and 6, the preferred tie-in options. Option 3 was deemed to

provide the most robust solution for the production and gas lift pipelines, minimising the risk

of damage to the existing 9ʺ production flowline back to the FPSO, minimising disturbance to

existing subsea equipment and allowing the construction vessel to operate in open water away

from the FPSO anchor pattern. Further information on the chosen option is provided in Section

2.7. Options 5 and 6 for the umbilical were both technically feasible and had similar equipment

requirements but from an ongoing integrity point of view the Ross Distribution Manifold (DM)

was chosen as a better tie-in location.

Figure 2-2 Schematic of the proposed Liberator field development with tie-back to the Bleo Holm FPSO



42

Table 2-2 Options screening for pipeline and umbilical tie-in to Bleo Holm FPSO, with chosen options highlighted

Option

No.

Tie-in location

of production

pipeline

Tie-in location of

gas lift pipeline

Tie-in location

of umbilical

Positives of option Negatives of option

1 Ross DM Ross DM

-

• Shortest and best pipeline insulated route • The potential to damage the production riser,

• Crossings near riser/flowline connection

• Restricted diver access

• Live Blake production / gas lift lines

• Working within the FPSO anchor pattern

• Heading control tug required, with additional cost

2 Ross DCA – DCA

to DM side

Ross DCA –

replacing DCA to

DCD gas lift line

-

• No need to route through DCA manifold • Congested tie-in location

• Potential to damage DCA to DM flowlines

3 Ross DCA – DCD

to DCA side at

production header

Ross DCA –

replacing DCA to

DCD gas lift line -

• Less congestion compared to DM side

• No need to disturb DCA-DM flowline

• Less concern over damage to existing lines as

they will be redundant

• Won’t result in pressurized production header

• Removal of mattresses required

• Longer than DM tie-in route

• Operation to flush/de-oil DCD to DCA production line

4 Ross DCA – DCD

to DCA side at far

side of production

header

Ross DCA –

replacing DCA to

DCD gas lift line -

• Less congestion compared to DM side

• No need to disturb DCA-DM flowline

• Less concern over damage to existing lines as

they will be redundant

• Longer than DM tie-in

• Removal of mattresses required

• Operation to flush/de-oil DCD to DCA production line

• Longer than DM tie-in route

• Flow restriction and pressurized production header.

5

- -

Ross DCB • No diving required close to FPSO

• Space for Liberator SUTU

• All DCB services transferred to Liberator

• Inability to monitor some Ross wells

• Reliance on existing umbilical which already has a

number of failed cores

6

- -

Ross DM • Minimal impact on Ross

• Larger number of umbilical cores available

• Less reliance on ageing infrastructure

• New SUTU structure needed

• Diving complicated by being within FPSO anchor

pattern



43

The relatively short field life and hence the comparative closeness of the decommissioning

liabilities has ensured that reduction of scope has played a significant part in the concept

selection for the Liberator development. The principle impacts have been on minimising the

equipment to be installed. This contributed to the decision to progress the option of the tie in

to existing infrastructure at the Ross DCA manifold.

2.2 Key components of the development

It is proposed that the Liberator field is developed over a period of 1-2 years with:

• First drilling campaign - a semi-submersible rig drilling 1 horizontal oil production

wells into the Liberator Captain Sands reservoir from the Liberator drill centre and 1

vertical appraisal well drilled into the Liberator west reservoir, which will be logged

and sampled and then abandoned;

• Second drilling campaign - a semi-submersible rig drilling 1 horizontal oil production

well into the Liberator Captain Sands reservoir from the Liberator drill centre, with

exact target location dependent on results of appraisal well;

• Installation of a 10ʺ rigid, trenched and buried 9.8 km production pipeline and 4ʺ, rigid

9.8 km gas lift line from the wells to the Ross DCA manifold for tie-in;

• Installation of a 4ʺ, trenched and buried 10.85 km control umbilical from the wells to

the Ross distribution manifold (DM) within the Bleo Holm 500 m exclusion zone;

• Installation of an umbilical Subsea Umbilical Termination Unit (SUTU) on a mattress

at the wells end of the pipeline;

• First hydrocarbons are expected in Q3 2020

• Third drilling campaign - a semi-submersible drill rig will return to the Liberator drill

centre to drill a third production well into the Liberator Captain Sands reservoir.

The design, fabrication and installation of the new facilities required will be carried out in

accordance with accepted industry standards, including the most recent revisions of the relevant

international codes and specifications.

Location

Location of Liberator Drill Centre 58° 11' 35.177" N, 1° 27' 10.724" W

Location of Liberator appraisal well1 58° 12' 19.328" N, 1° 28' 05.165" W

Location of Ross DCA manifold 58° 05' 50.321" N, 1° 23' 48.979" W

Location of Bleo Holm FPSO 58° 06' 05.641" N, 1° 26' 18.468" W

Water depth at Liberator drill centre 130 m

Notes: 1 = top hole location

Development Schedule

An indicative schedule of work for the Liberator development is shown in Table 2-3 below,

although it may be subject to change, depending on drill rig/pipelay vessel availability.



44

Table 2-3 Summary schedule for the Liberator development

2019 2020 2021

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2

Site and pipeline route survey


first production well

Drill, evaluate and abandon

appraisal well


second production well

Subsea infrastructure

installation and pipelay

Subsea hook up to Bleo Holm

and commissioning

First Oil


third production well

2.3 Field reservoir fluid composition

The Liberator field is located 1 km west of the Blake Channel Field and shares the same high-

quality Captain sand reservoir, oil type, and initial oil water contact (Table 2-4). The Blake

and Liberator fluids are from the same wider reservoir and are therefore very similar in

properties. The reservoir quality of the Captain sandstone is exceptional, with an estimated

95% of the reservoir producing economically recoverable oil, an average porosity of 30% and

permeability in the 2,000 – 3,000 m depth range. It is not considered a high pressure/high

temperature reservoir. In the area beyond the Liberator field, the Captain channel is oriented

NNW-SSE and is around 3 km wide. The Liberator field is an elongated NW-SE reservoir

with an expected maximum oil column of approximately 24 metres above the oil water contact.

An extension of the Liberator reservoir, named Liberator West lies just 1.5 km to the northwest

within the same Captain sand channel. It is within this reservoir that the A3 appraisal well will

be drilled.

The Liberator Field Development discussed in this document, 3 production wells, is planned

to recover approximately 20 MMstb of oil from an estimated 55 MMstb in place. There is a

potential that up to 310 MMbls of oil may be contained within the wider Liberator reservoir

and the western extension, but this would be subject to further development, contingent on the

success of the initial development and is not covered by this assessment.

The Liberator field is underlain by a massive and very high-quality aquifer which supports

production from a number of fields in the Outer Moray Firth area, including Ross and Blake.



45

Initially reservoir pressure will remain sufficiently close to original pressure for production to

continue, although gas lift lines will be installed to aid production in later life if required.

Table 2-4 Properties of Liberator & Ross/Blake Captain sands reservoir

Captain Sand Liberator Properties Blake Properties

Hydrocarbon Type Undersaturated oil Undersaturated oil

Gas-Oil Ratio 340 scf/stb 500 scf/stb

Stock Tank Oil Gravity 30.3 API 30.8 API

Wax Content 10.7% 10.7 %

Wax appearance temperature 33 ˚C 35.5 ˚C

Asphaltene content 0.15 %wt 0.15 %wt

Specific gravity @ 15˚C 0.87 g/ml 0.87 g/ml

2.4 Liberator production profiles

Production will come online in 2020, with approximately 12,623 barrels (1,757 tonnes1) of oil

and 120,600 Sm3 of gas produced per day (Table 2-5). Production will peak in 2021 at

approximately 18,988 barrels of oil (2,643 tonnes) and 180,789 Sm3 of gas per day, before

steadily declining over the remainder of the projected field life of ten years.

Table 2-5 Liberator Field Development production figures (high case)

Year Oil rate (t/d) Gas rate (Sm3/d) Water rate (m3/d)

2020 1,757 120,600 4

2021 2,643 180,789 273

2022 1,638 111,945 514

2023 1,196 81,623 618

2024 912 62,157 639

2025 748 50,956 649

2026 633 43,121 649

2027 552 37,641 649

2028 501 34,157 660

2029 212 14,444 300

The production profiles presented herein are the highest predictions (called ‘P10’), which

includes the three development wells. Daily production is averaged for each calendar year

presented.

1 Oil conversions calculated using i3 supplied conversion factor of 7.185286726 stb per tonne.



46

It is planned to tie Liberator into the Ross DCA manifold, where Liberator fluids would replace

the Ross fluids for the duration of the field life. Currently the Ross field produces ca. 300

barrels a day of oil so the cumulative increase in production to the Bleo Holm will be smaller

than the production profiles of the Liberator fluids alone. The predicted combined production

profiles for the Bleo Holm once the Liberator field comes online is shown and discussed in

Section 2.8.1.

Figure 2-3 Liberator Field Development high case oil production profile

Figure 2-4 Liberator Field Development high case gas production profile



47

2.5 Drilling and completion programme

Drilling strategy

Liberator will be developed by the drilling of one, horizontal, production well (L2) from the

Liberator drill centre, targeting the Cretaceous Captain sands reservoir, spudding in Q3 2019.

The drilling and clean-up of the well is expected to take 69 days. The rig will then move 0.9

km to the north east (over a period of 3 days) and a vertical appraisal well, A3, will be drilled

in the Liberator west reservoir, then logged, sampled and abandoned. The expected duration of

the appraisal well activities is 28 days. The drill rig will then demobilise.

Following a review of the appraisal well the drill rig will return in Q2 2020 to the Liberator

drill centre and drill a second, horizontal, production well (L4) in the Captain sands reservoir

over a period of 50 days. Whilst the target location for the L4 well is dependent on the results

of the appraisal well, it will be drilled from the same surface drill centre location as L2.

After first oil, reservoir performance will be appraised and an additional production well (L1),

will be drilled from the Liberator drill centre in Q2 2021 over a period of ca. 74 days.

Drill rig

Whilst the exact drilling rig is unknown it will be a standard North Sea semi-submersible unit.

The selected rig will have in place all the necessary permits and certification to allow it to

operate in the UKCS. This type of rig uses an eight chain anchor pattern to remain in a fixed

position whilst drilling. The exact mooring pattern and rig orientation will be determined

nearer the time based on the seabed conditions, currents, water depth and prevailing winds at

the drill centre location. Each anchor weighs approximately 12 tonnes and once laid into the

seabed. The anchors will be attached to the drill rig by approximately 1.5 km of chains,

although the length will vary depending on water depth and physical conditions at the time.

Whilst in position, a statutory 500 m exclusion zone will be established around the drilling rig

in accordance with safety legislation. Unauthorised vessels including fishing vessels and

commercial shipping are not permitted to access this area. An Emergency Response and

Rescue Vessel (ERRV) will be on station throughout the drilling operations in case of any

emergency necessitating evacuation or in the case of a man-overboard situation and to warn

non-authorised vessels approaching the exclusion zone.

Typical power generation for this rig is based on three 2,500 KW diesel generators, with the

rig having the capacity to store up to 2400 tonnes of fuel oil. During routine drilling operations

the rig will use approximately 10 tonnes of fuel per day. All bunkering operations will be

undertaken during favourable sea conditions and as far as practicable during daylight hours.

Routine discharges from the drilling rig include rainwater run-off, sewage and galley waste.

Additional ad hoc discharges include rig wash and sea water from firewater pumps. The rig

will have both open and closed drain systems. Closed drains occur in areas where there is the

risk of oil contamination. The waste water entering the drains is treated to remove any oil to a

level below 30 mg/l (monthly average) prior to the water being discharged. Open drain systems

occur in areas where there is little or no risk of oil contamination and waste water entering

these drains is discharged without treatment. The rig will have a sewage treatment system to

manage sewage waste prior to discharge.



48

The drill rig will carry a blowout preventer (BOP) which will be installed on the wellhead when

drilling with a riser in place and during well completion and testing. The function of the BOP

is to prevent uncontrolled flow from the well by closing in the well at the seabed if required.

The BOP is made up of a series of hydraulically operated rams that in the event of a well control

situation can be closed from the control panel on the drill floor and from an alternative safe

location elsewhere on the drill rig.

Three anchor handler tug vessels will be used to tow the rig to the well location and lay the

anchors, and supply vessels will support the rig whilst it is on site. There will be three

mobilisations, demobilisations and one intra-field rig movement which will require up to 75

vessel days for the anchor handlers (see Section 2.9 for summary of vessels and fuel usage).

The drilling rig has been assumed to have a supply vessel requirement of around 4-5 return

trips per week for the duration of the three drilling programmes, from a supply base of

Peterhead/Aberdeen. Therefore, it is estimated that there will be a total of approximately 43

supply vessel days in transit during the drilling periods (based on 3 trips per week and a 10.8

hour round trip to Peterhead). An estimated 3-4 helicopter trips per week will make the rig

personnel transfers to and from Aberdeen, totalling 5.3 days (based on an average of 4 flights

per week and a flight time of 1 hr). An ERRV will be on location for the entire drilling phases,

estimated at a total of 224 days.

Production well selection and design

Within Blocks 13/23 and 13/24 a number of wells have previously been drilled (Figure 1-4),

including the original Liberator appraisal well drilled in 2013 (13/23d-8) 1000 m to the east of

the proposed Liberator drill centre.

A review of the design of nearby wells showed that the most common well architecture was a

slim hole design consisting of a 30″ conductor, 13⅜″ surface casing and 9⅝″ production casing.

The advantage of a slim hole design is that fewer casing strings are required and thus fewer

days required for drilling. An alternative full hole design incorporating a 20″ surface casing

was also considered but the increased time and cost due to the requirement for an additional

casing string and the larger hole size made this option unattractive.

Formation instability can occur in the surface hole section where the well builds to a high angle.

This section is typically drilled with seawater and sweeps, however as inclination increases the

mud weight required to prevent wellbore instability increases. This cannot be achieved using

seawater. Typically, the well is being drilled riserless and all the returns are going to the seabed

making maintaining sufficient pressure overbalance problematic. A solution to this is to run

the Low Pressure and High Pressure wellhead housings together, which enables the BOP’s to

be run prior to drilling the surface hole section rather than post the surface hole sections as in

standard well designs. This creates a closed mud system, with returns going back to the rig

rather than the seafloor. The mud is then able to be conditioned and maintained at a required

mud weight to prevent wellbore instability. Top hole instability issues were observed on a

number of nearby wells, which had been drilled with seawater and sweeps, suggesting that the

Liberator production wells may need additional overburden inhibition. The Blake manifold



49

wells, which were drilled directionally with a weighted mud system (the BOP was run in a

similar manner to that being proposed here) did not encounter wellbore stability issues.

Whilst the Liberator wells will use the slim hole design and will likely use a contained system,

with no discharge of mud and cuttings to seabed, except for the Conductor string, there is a

possibility that the top-hole section will be drilled riserless as in standard well designs. As

being drilled riserless would result in discharge to seabed of mud and cuttings this is the

approach that has been assessed in this ES as worst case. The vertical A3 appraisal well will

be drilled riserless down to the 13⅜″ surface casing, as there are not thought to be any wellbore

stability issues.

The Liberator reservoir is expected to be uniform in nature and the three production wells will

therefore be of a similar slim hole design. The Liberator production wells will all be drilled

from the single drill centre and deviated to land in the Liberator reservoir approximately 12.2

m (40 ft) above the oil water contact. It is intended to complete the wells horizontally into the

reservoir sections in the reservoir. 5½ʺ sand screens will be installed across the reservoir

section to prevent sand entering the wellbore whilst allowing fluids to flow, and a simple flow

control system may be installed to encourage flow from the toe of the well (the very end of a

horizontal well) initially. Table 2-6 provides the average expected diameter, length and drilling

rate for the Liberator wells whilst Figure 2-5 shows the expected well design.

Table 2-6 Expected average parameters for the Liberator development wells

Drilling parameter Well section

1 2 3 4

Diameter (inches) 36 17 ½ 12 ¼ 8 ½

Casing size (inches) 30 13 ⅜ 9 ⅝ 5 ½

Length (feet) 232 2,985 4,470 4,297

Length (m) 71 910 1,363 1,310

Drilling rate (m per hour) 6 25 12 11



50

Figure 2-5 Liberator well casing design

Notes: 83ft relates to the height of the rotary table relative to mean sea level and not mean sea level to seabed



51

Appraisal well design

The A3 appraisal well will be a vertical well drilled into the Lower Cretaceous Captain sands

at 5,161ft TVDSS, with an expected 80ft hydrocarbon reservoir section. The well will consist

of a top hole, 36ʺ section, drilled riserless using seawater with occasional ‘sweeps’ of bentonite

(a clay mineral used to increase the viscosity of the fluid) to flush cuttings out of the hole.

Sediment and rock cuttings discharged directly to the seabed form a low, oval mound of 5-10

m radius around the well.

The 17 ½ʺ hole will be drilled with a water-based mud (WBM), with fluid and cuttings returned

to the rig and the cuttings discharged to sea. Once the BOP has been installed after setting the

13⅜ʺ casing, the 8 ½ʺ hole will also be drilled using WBM with the mud returned to the rig,

separated, cleaned up and cuttings discharged overboard, under an OPPC permit.

Table 2-7 Expected parameters for the Liberator A3 appraisal well

Drilling parameter Well section

1 2 3

Diameter (inches) 36 17 ½ 8 ½

Casing size (inches) 30 13 ⅜ 5 ½

Length (feet) 232 2,985 2,283

Length (m) 71 910 696

Drilling rate (m per hour) 6 25 11

Mud system and cuttings

Muds used to drill the various hole sections of a well have a number of functions, including:

• Maintenance of downhole pressure to avoid formation fluids flowing into the wellbore

(also called “a kick”);

• Removal of drill cuttings from the drill bit to permit further drilling and transporting

cuttings to the surface cuttings handling equipment;

• Lubricating and cooling the drill bit, bottom hole assembly and drilling string; and

• Deposition of an impermeable mudcake on the walls of the well bore, which seals and

stabilises the open hole formations.

Drilling fluids can consist of various materials including weighting agents and other chemicals

to achieve the required weight, viscosity, gel strength, fluid loss control and other

characteristics to meet the technical requirements of drilling and completing the

well. Generally, drilling fluids can be divided into two categories based on their base fluid

types:

• Water-based mud (WBM), where the base fluid is water; and

• Oil-based mud (OBM), where the base fluid is an emulsion of water droplets distributed

within an oil (includes low toxicity oil-based mud (LTOBM)).



52

Various chemicals can be added to either type of drilling fluid to achieve specific results, which

are mainly driven by formation pore pressures and fracture gradients, downhole temperatures,

geological characteristics etc.

For the Liberator wells different types of mud are planned to be used for different well sections.

Whilst it is expected that the wells will be drilled entirely under a contained system with no

discharges to sea, there is a small possibility that the top holes will need to be drilled open-

holed and therefore this has been assessed below as worst case.

As discussed above, the top two sections of all the Liberator wells (36" and 17½") may be

drilled open-hole, without a riser in place. Seawater and regular bentonite sweeps will be

pumped downhole to aid cuttings removal and keep the hole clean. A weighted mud system

may be required for the 17 ½ʺ hole and cuttings from both these sections will be discharged

directly to the seabed. Subsequent sections will be drilled with a riser in place, meaning mud

and cuttings will be returned to the drilling rig topsides, where they will be separated from the

mud using shale shakers so that the mud can be re-used. The 12¼" section will be drilled with

either WBM or LTOBM. If WBM is used, the separated cuttings will be discharged overboard.

If LTOBM is used, separated cuttings will be stored in a bunded area of the rig in purpose

designed lidded skips pending shipment to shore for treatment, recovery of base oil and

disposal via an authorised facility. The 8½" section will be drilled with WBM, with separated

cuttings discharged overboard. Table 2-8 details the drilling mud requirements for one well;

the requirements for L1, L2 and L4 are expected to be the same. It is assumed that WBM will

be used for all sections as this is a worst case in terms of discharges to sea (i.e. LTOBM would

not be discharged to sea if used).

As discussed above, the A3 appraisal well will be drilled with WBM with the estimated

discharges to sea of cuttings detailed in Table 2-9.

Table 2-8 Estimated tonnages of drilling mud components per production well

Component Discharges per section

30" 17½" 12¼" 8½"

Mud/fluid (name) Seawater

with

sweeps

KCl WBM KCl glycol

WBM

KCl WBM

Bentonite (t) 20 0 0 0

Barite (t) 14 50 57 0

Calcium carbonate (t) 0 0 0 60

Total mud discharges for one well (t) 175 650 750 450

Total cuttings discharges for one well (t) 150 400 300 150



53

Table 2-9 Estimated tonnages of drilling mud components for the A3 appraisal well

Component Discharges per section

30" 17½" 8½"

Mud/fluid (name) Seawater

with sweeps

KCl

WBM

KCl

WBM

Bentonite (t) 20 0 0

Barite (t) 14 50 0

Calcium carbonate (t) 0 0 32

Total mud discharges for the well (t) 175 650 239

Total cuttings discharges for the well

(t) 150 400 80

Cementing and other chemicals

Steel casings will be installed in each well section to provide structural strength to support the

subsea trees, isolate unstable formations and different formation fluids and separate different

wellbore pressure regimes. Each steel casing will be cemented into place, which will provide

a structural bond and an effective seal between the casing and surrounding rock formation. The

majority of the cement remains between the casing and rock but some of the cement used in

setting the top sections in place may be discharged to the seabed around the wellhead. To limit

unnecessary discharge of cement, it is anticipated that all cement will be mixed as required.

A range of other chemicals may be selected for contingency use to deal with unplanned drilling

events such as stuck pipe or loss of drilling mud circulation. A proportion of these chemicals

may be discharged with the cuttings dependent on their nature and function. There will also

be a small suite of chemicals used in the completion of the wells, for example oxygen

scavengers, lost circulation material and well bore clean up chemicals. Although final chemical

selection is still to be completed, a full inventory of all chemicals, together with their

environmental risks, will be provided by the submission of a Drilling MAT and associated

SAT’s to BEIS prior to drilling commencing. All chemicals to be used within the cement,

drilling, clean-up, utility and for contingency will be selected based on their technical

specifications and environmental performance. Chemicals with substitution warnings (i.e.

those identified by UK authorities as requiring phase out over time) will be avoided where

technically possible. The cementing chemicals to be used have not yet been determined but

will be selected using the well operator’s chemical management and selection policy.

Production well testing and clean up

The completion will be run in two phases, with sand screens installed across the reservoir and

an upper completion consisting of a permanent packer, production tubing, gauges and

downhole safety valve set inside the casing with the hanger landing on the subsea tree. Gas

lift mandrels will also be installed to allow gas injection to bring wells back on stream after a

shut down, and so that at later stages in field life continuous gas injection can be considered.



54

Prior to production, all three wells will be cleaned up to remove any waste and debris and

prevent damage to the pipeline or topsides production facilities. It is likely that the wells will

be cleaned up using a combination of high density brines and clean up chemicals. Clean brines

will be discharged to sea. The brine will be initially collected in a gauge tank to check for

cleanliness before being discharged. An OPPC Term Permit will be applied for from BEIS.

Any interface will be left to separate in the gauge tank, with hydrocarbon residues being flared

or contained and the debris collected for onshore disposal.

Whilst a clean-up flow only is planned, there is a possibility that a well test may be required

and therefore contingent well testing operations have been included. Well tests may be

conducted to obtain reservoir information and fluid samples. Fluids produced from well testing

will flow back to the semi-submersible drilling rig and processed on the rig, through a surge

tank and a test separator. Any hydrocarbons produced would most likely be burned using a

high efficiency, green burner on the rig. The test equipment will be selected to promote efficient

burning of hydrocarbons within the flare and to prevent discharge of unburned hydrocarbons

from the flare.

The likely sequence of events for well testing and clean-up will be as follows:

• Open well and flow;

• Capture and test water/hydrocarbon interface fluids. If oil in water concentration is

equal to or below 30 mg/l, discharge fluid overboard in accordance with the oil

discharge permit that will be in place. If oil in water concentration is above 30 mg/l,

filter fluids until they are below 30 mg/l for overboard discharge;

• Monitor and record the amount of water and suspended solids in the produced fluids to

calculate the basic sediment and water specification;

• Flow well for a test period of up to 96 hours; and

• Close well in, ready for production.

During well clean up and testing, an estimated 696 tonnes of oil may be produced per well. Oil

produced during well testing will be flared over a maximum period of 48 hours. Any gas

produced during well testing will also be flared; flared gas is not expected to exceed 200 tonnes

per well.

After completion the wells will be isolated with Xmas tree and downhole valves shut in, ready

for flowline tie-in.

Appraisal well logging and sampling

After drilling on the appraisal well is completed, the well will be logged and sampled before

being permanently plugged and abandoned. No flow of hydrocarbons or well test is expected.

The well logging and sampling will consist of:

• GR resistivity neutron density

• Shear-wave sonic

• Pressure and fluid samples



55

• Rig source VSP (see below)

• Contingent sidewall core

The well will then be cut below the seabed and abandoned to Industry (Oil and Gas UK)

standards. This requires a combination of compliant cement barriers that meet the requirements

laid out within the i3 Appointed Well Operator’s (WO) Well Abandonment Procedure and the

aforementioned Oil & Gas UK Guidelines on the Abandonment of Wells.

Vertical seismic profiling (VSP)

VSP is included as contingency only and will only be used on the production wells if it becomes

apparent during drilling that the reservoir conditions are significantly different from what is

expected. It will be known if VSP is required once approximately 2,500 ft (762 m) of the final,

horizontal well section has been drilled. If a VSP is required, a geophone (noise detector)

would be conducted into the hole on drill-pipe and an air-gun (noise source) would be

suspended in the water below a support vessel. The geophone would be run into the hole and

periodically locked against the side of the wellbore to record impulses from the air-gun. For

the vertical part of the well, the support vessel would be located next to the rig. As the well

deviates from vertical, the vessel would track above it to ensure the source remains in the

vertical position above the geophone in the well. It is expected that up to 25 stations would be

required, with one shot fired per station. VSP operations are expected to take up to 36 hours

per well. The VSP noise source is typically comprised of a system of three 250 inch airguns

with a total volume of 750 cubic inch of compressed nitrogen at about 1800 psi or two 250 inch

airguns with a total volume of 500 cubic inches. Peak sound pressure levels for a 500 cubic

inch VSP are recorded as 237 re 1 µPa@1m (DECC, 2011b). These volumes and the energy

they release into the marine environment are significantly smaller than that generated during

exploration seismic surveys, discussed further in Chapter 5.

Well workovers and interventions

The Liberator wells have been designed with a minimum planned intervention philosophy for

the anticipated ten-year life of the wells. However, it is recognised that remedial well

interventions could be necessary in the case of equipment failure. In this case, wireline

intervention using a slickline or electrical cable to lower tools into the well may be performed

from a light well intervention vessel (this is a smaller vessel than a traditional semi-submersible

drill rig or ship). Coiled tubing intervention, where a long metal pipe instead of an electrical

cable is used, would require a semi-submersible drill rig. A flow assurance study has suggested

that there may be a requirement for chemical intervention during well life, although again one

of the development objectives is to design the wells for no intervention.

As these are not planned activities they are not included in any further assessments in this ES.

All relevant permits for the workovers will be applied for, which will include risk assessment

covering vessel deployment, potential impacts and any mitigation methods.



56

2.6 Subsea

An overview of the proposed subsea layout is shown in Figure 1-4 and 2-2. Further detail on

each of the components is given in the subsequent sections of this chapter. Installation of

subsea structures, pipeline and umbilical is expected to commence and be completed with Q2

2020.

Subsea well infrastructure

Subsea trees, designed to control flow will be installed on top of the wellheads by the drilling

rig. The subsea tree is the main barrier between the reservoir and the environment, and also

provides a mechanism for flow control and well entry. All wells will have a sub-surface safety

valve installed which is an isolation device that is hydraulically operated and fail-safe closed.

During completion operations, the subsea trees will be controlled from the drill rig, whilst

during production the subsea trees will be remotely controlled from the Bleo Holm FPSO via

control umbilicals. Hydraulic fluid will be the same as is currently used in both the Ross and

Blake control systems: Pelagic 100, an E rated chemical on the Offshore Chemical Notification

System (OCNS).

The trees on both wells will incorporate an SFF approved fishing-friendly tree protection

structure able to resist the bollard pull (pulling force) generated by potential fishing gear

interactions whilst posing minimal risk to fishing vessels. Including the protection structures,

each tree will have a seabed footprint of 7.87 m x 7.87 m and have a height above the seabed

of 5.08 m.

The two production wells (L2 and L4) will be linked together using 2 x 100 m long hard spools

and pipework. Well L2 will then tie in directly to the production and gas lift pipelines through

2 x 120 m long spools without the need for a manifold (see Section 2.7.6 for more information).

The spools will be protected using mattresses with tapered fishing friendly edges (see Section

2.7.6 for more information). The third production well, L1, will likely link to well L4 through

additional hard spools and pipework. Once the drill rig moves off location there will be no

permanent exclusion zone in place around the wells and pipeline tie-in area, as all the subsea

infrastructure will be protected by fishing friendly mattresses and structures.

As discussed in Section 2.5.8, the appraisal well will be cut and plugged below the surface on

completion of logging and sampling activities and will have no infrastructure on the seabed.

2.7 Pipeline and Umbilical

New pipeline

A 10" rigid production pipeline of approximately 9.8 km length will run between the wells and

the Ross DCA manifold (Table 2-10). From the Ross DCA the existing pipeline will transport

fluids onwards to the Bleo Holm for processing and export via the existing gas export pipeline

and oil offtake tanker.

All the rigid pipelines are to be externally coated with a 3-layer polypropylene (3LPP) anti-

corrosion coating, which will be applied onshore in either Scotland or mainland Europe prior

to installation. This coating will give an additional impact resistance as well as corrosion



57

protection and has a 15-year design life. All flexible lines are provided with a thick

polyethylene outer coating to provide additional impact resistance. Pipeline selection is based

on a technical, commercial, schedule and environmental evaluation. Final detailed pipeline

design, procurement, installation and commissioning will be completed during FEED.

Table 2-10 Pipelines design and construction

10ʺ Production pipeline 4ʺ Gas lift pipeline

Service Oil/Condensate/Gas Gas

Type Rigid Rigid

Nominal diameter 10-inch 4-inch

Wall thickness TBC TBC

Pipe steel grade ISO3183 L450 (API 5L X65) ISO3183 L450 (API 5L X65)

Impact resistance Trenched and backfilled Trenched and backfilled

Pipe coating 3LPP 3LPP

Safety valves Top of riser ESDV

SSIV on Production Riser

Top of riser ESDV

SSIV at Ross Drill Centre

Surface laid or trenched Trenched Trenched

Min pipeline trench depth (TOP

(m))

1 1

Pipeline backfill cover Mechanical backfill Mechanical backfill

Pigging facilities Temporary PLR attachment Temporary PLR attachment

Approximate length (km) 9.85 9.85

Start location Well L4 Bleo Holm DM

End location Ross DCA Manifold Wells

Design life (years) 10 10

Design codes PD 8010 Part 2 PD 8010 Part 2

Crossings Yes – 10ʺx 16ʺ PIP and 12ʺ

production lines from Blake to

Bleo Holm, 4ʺ OD control

umbilical, 6ʺ gas lift line and 12ʺ

water injection line.

Ross DCD to Bleo Holm via DCC

8ʺ production, 4ʺ gas lift line and

3ʺ OD control umbilical.

Yes – 10ʺx 16ʺ PIP and 12ʺ

production lines from Blake to

Bleo Holm, 4ʺ OD control

umbilical, 6ʺ gas lift line and 12ʺ

water injection line.

Ross DCD to Bleo Holm via DCC

8ʺ production, 4ʺ gas lift line and

3ʺ OD control umbilical.

Notes: 1 = Maximum allowable operating pressure

Anodes will be used for protection of all subsea pipeline systems and associated marine steel

structures from the corrosive action of seawater as they act as preferential sites for corrosion,

thereby protecting the steel. The sizing, quantity and spacing of the anodes will be finalised as

part of the detailed design phase, however they will be made of an aluminium-zinc-indium



58

alloy and fixed along the rigid pipelines, tie-in spoolpieces and subsea structures. Electric

continuity through the pipeline system will also be maintained to ensure correct operation of

the cathodic protection system.

Umbilical requirements

It is likely that a 4.5" control umbilical of approximately 10.85 km length will run between the

production wells and the Bleo Holm distribution manifold (DM) location (Table 2-10). The

umbilical would deliver the hydraulic, chemical, electrical, control and communications

services from the Bleo Holm to the wells.

The umbilical will terminate with a Subsea Umbilical Termination Unit (SUTU) at the wells

location (Figure 2-6), measuring 2 m long x 0.7 m in diameter. The SUTU will terminate all

hydraulic/chemical and electrical supply lines with a bulkhead plate to allow jumper

installation. Initially this SUTU will be connected to the first xmas tree (L4) directly and then

further xmas tree installation for well L2 will require a subsea distribution unit (SDU) for

hydraulic, power/signal and chemical distribution to be installed. Jumpers will connect the

SDU supplies to the xmas tree subsea control modules (SCMs)/tree valves & instruments. The

SUTU/SDU will be located under the tree protection structures and will each sit on a single

mattress placed on the seabed.

Figure 2-6 Subsea umbilical termination unit

Tie in of the control umbilical to the Bleo Holm DM would most likely be completed in the

subsea installation campaign in 2020.

Gas lift

The Liberator wells will be initially produced under natural reservoir pressure. i3 is

considering using gas lift to assist in maintaining production rates once the fluid column in the

wells is no longer able to flow at sufficient rates naturally (possibly after around 3 years) or if

the wells are no longer able to re-start naturally after any shutdown. Gas lift is already provided

by the Bleo Holm FPSO to the Ross DCA manifold. It is proposed that the Liberator gas lift

line will tie in to the DCA manifold at the slot currently occupied by the Ross DCA to DCD

gas lift line, the intention being to disconnect the Ross DCA to DCA gas lift line and make



59

safe. The new Liberator gas lift line will be installed in the same trench as the production

pipeline from Ross DCA up to the wells.

Seabed preparation

A geophysical and geotechnical survey will be carried out along all pipeline and umbilical

routes in Q1 2019 (see Section 3.1 for further details). The pipeline and umbilical routes and

installation method will be finalised prior to installation, considering topography, soils and any

seabed features that could obstruct or impede installation. A pre-lay remotely operated vehicle

(ROV) survey will be carried out prior to installation to determine whether any new

obstructions have appeared. During installation, boulders may need to be moved outside of the

pipeline and umbilical corridors.

Pipeline and umbilical lay

A typical pipeline installation sequence is given below. The final sequence will depend on the

selected installation contractor’s vessel spread and scheduling requirements.

• Lay pipeline

• Trench pipeline (if not already laid into a pre-cut trench)

• Backfill pipeline (and spot rock placement where required)

• Clean and strength test pipeline

• Install subsea structures

• Lay/trench umbilical

• Tie-in pipelines, umbilical and spools at Ross DCA manifold, Ross DM, wells SUTU

and wells

• Leak test entire system

• Provide mattress protection over spools and exposed sections of lines

• Pre-commissioning of system

From the wells it is anticipated that the pipeline and gas lift line will be laid in one trench and

the umbilical laid in a separate parallel trench, with 40-50 m of separation. After crossing the

Blake to Bleo Holm lines the Liberator production pipeline and gas lift line will continue south

east over the Ross DCD to DCC pipeline to the Ross DCA manifold. The umbilical will be

separately routed through the south west to the Ross DM for tie in (Figure 2-2).

The pipelines are expected to be laid by a reel-lay vessel (Figure 2-7) and the umbilical by a

dive support vessel (DSV) with cable lay facilities. The pipeline and umbilical will be wound

onto a reel on the quayside and transferred to site. The end of the pipeline and umbilical will

be temporarily anchored to the seabed at one end of the route, either at the Ross DCA manifold

or at Well L1, and the reel-lay vessel / DSV will move off. The pipeline and umbilical

(whichever is being installed at that point) unwinds from the reel on the vessel, passes down

through the water column, and comes to rest on the seabed. The installation vessel position

will be controlled by dynamic positioning (DP) and will not require anchors. The flowlines

will be installed in a single trip by a pipelay vessel and the umbilical will be laid in a single trip

by DSV. Estimates of duration of vessel activity is summarised in Table 2-17. Once the

pipeline has been laid, the lay vessel leaves and a DSV complete the construction works.



60

Following (or prior to) installation, the pipelines will be trenched for the majority of their

length, except for crossing points discussed further below and the ends. Trench depths,

assuming use of a plough, will be typically 1.4 -1.8 m to the trench bottom, with a 30o trench

angle, therefore producing a top width of around 6.5 m. Spoil will be set on the seabed at the

side of the trench for subsequent backfill after pipelay. The material excavated from the trench

will be mechanically backfilled with the displaced sediment to provide a downwards force to

mitigate upheaval buckling, afford some insulation and achieve a seabed profile similar to that

before pipelay. There will be a minimum backfill cover of 1 m. This will also reduce the

potential for damage to fishing gear and catches from excavated material.

Survey data within the area, discussed further in Section 3.2.2, show that the soil is silty sand

overlying possible areas of soft to stiff clays and sands. The Liberator survey scheduled for

Q1 2019 will include cone penetration tests (CPTs) and vibrocores at least at 1km intervals

along the pipeline route. This information on soils will be included in the detailed pipeline

design process, which will confirm the best method for pipelay once soil type, pipeline material

and fluid properties are taken into consideration. However, it is expected that trenching (either

by mechanical cutter or plough) and mechanical backfill will provide the most effective

installation method and therefore forms the basis of this EIA. The survey will also provide

seabed profile data which will be incorporated into the pipeline design to minimise any

upheaval buckling. The Liberator area has low bottom current speeds (see Section 3.2) and

therefore any upheaval buckling in the pipeline is likely to be due to changes in hydrocarbon

properties and flow parameters of the fluids being conveyed. The Liberator fluids are however

expected to be of low temperature, further reducing the likelihood of upheaval buckling.

At the ends of the trenches, the pipeline and umbilical will come out onto the seabed by way

of an open sloped end to the trench (the trench ends will be protected with mattresses).

Production spools and jumpers will cover the untrenched distances, with details of the spools

and mattress protection required shown in Section 2.7.8.

Figure 2-7 Illustration of a reel lay vessel in operation

On completion of pipeline installation and jetting, as laid (for pipelines and umbilical), post-

lay (for infrastructure), trench and crossing surveys will be conducted by the installation



61

contractor to accurately chart the subsea facilities and to identify any items of debris for

recover. This will also confirm the pipeline has been buried correctly and provide a visual

examination of the tie-in routes.

Tie-in installation

A dive support vessel (DSV) will carry out the installation of the spools and jumpers used to

tie the pipeline and umbilical in at each end. Due to the length of the spools and jumpers they

will be lifted in sections by the vessel crane and transferred to the seabed. Divers will then

complete the connections. Once the spools and jumpers are installed, concrete mattresses will

be placed along the length of the spools and jumpers to provide protection and to ensure they

remain in place, see Section 2.7.8 below for details. Well L4 will be connected to well L2

using 2 x 50 m long 10ʺ spools and 2 x 50 m long 4ʺ spools. Approximately 10 mattresses will

be required to provide continuous protection. Well L2 will be connected to the pipeline using

2 x 60 m long 10ʺ spools and 2 x 60 m long 4ʺ spools, with 30 mattresses required for

continuous protection. 30 mattresses have been included in this assessment for protection of

the hard spools for the third production well, L1. All of the 10ʺ spools will be made of NB

super duplex and the 4ʺ spools of NB carbon steel.

Figure 2-8 Illustration of likely tie-in of Liberator production and gas lift lines at the Ross DCA manifold

The proposal is that the tie in of the Liberator production and gas lift lines to the Ross DCA

manifold will take place at the production header (Option 3 as discussed in Section 2.1.2), for

illustration purposes this arrangement is shown in Figure 2.8. This arrangement would require

the disconnection of the existing production and gas lift flowlines from the Ross DCA to Ross



62

DCD manifold (Figure 2-8). As the xmas trees at Ross DCD would no longer be required for

production the existing production and gas lift lines will be flushed prior to being disconnected,

with the flowlines at the DCA end being placed on the seabed within the 500 m exclusion zone

and fitted with blinds. The DCD gas lift line would be flooded with MEG/water with gas

displaced into the production line, with full contents of the production line flushed to the FPSO

topsides. There would be a requirement to remove ca. 4 mattresses which currently protect the

DCD flowlines in order to tie in the Liberator flowlines within the same space. The mattresses

would preferentially be reused to protect the length of the DCD lines laid on the seabed.

Mattresses in use on the seabed have been known to break up when they are lifted and if that

was to occur then they would be placed on seabed next to the DCD lines and 4 new mattresses

would be used to protect the exposed lengths of the DCD lines on the seabed.

Tie-in of the Liberator production and gas lift lines to the DCA manifold will be via 3 x 100 m

long 10ʺ spools and 3x 100 m long 4ʺ spools. A total of 26 concrete mattresses will be required

to protect the spools. The spools will be within the existing Ross DCA manifold exclusion

zone. Full protection requirements for the new Liberator lines are discussed in Section 2.7.8

below.

Pipeline crossings

Crossing of existing pipeline/umbilical infrastructure will be required at 2 locations (Figures

2-2, 2-9 and 2-10), namely the Blake pipelines/umbilical route corridor and the Ross DCD

pipelines/umbilical route corridor. Both the Blake and Ross DCD pipelines / umbilicals are

trenched and buried. The Blake crossing will be in an open water location whilst the Ross

DCD crossing will be within the DCC subsea facility 500m exclusion zone. All pipeline

crossings will be undertaken as follows:

• Survey undertaken at crossing location to determine exact position, details and burial

status of the lines to be crossed.

• Prior to pipelay, pre-formed crossing support (mattress piers) will be placed at specific

spacing over the trenched and buried line to be crossed.

• Following pipelay rock placement will be used to cover the entire crossing area out

with the protection of the trench – to ensure that all raised sections of the new lines are

fully covered for long-term protection, stability and upheaval buckling mitigation.

The total crossing height above the seabed will vary in accordance with the profile of the

existing pipe within its trench. The maximum crossing height anticipated is 1.8 m for the

production and gas lift lines and 1 m for the umbilical line, with designs for both crossings

shown in Figures 2-9 and 2-10. For the Blake flowlines crossing (Figure 2-9) there will be one

crossing for the umbilical (200 m in length) and a separate one for the production and gas lift

pipelines (426 m in length), although both of those crossing will pass over the 3 trenched and

buried Ross lines in a single crossing. The DCD crossing (Figure 2-10) is simpler with a single

crossing for the production and gas lift lines, totalling 386 m.



63

Figure 2-9 Schematic of the Blake flowlines crossing

Figure 2-10 Schematic of the Ross DCD flowlines crossing



64

Both crossings are anticipated to be fishing friendly design using graded materials, designed to

remain stable under the action of environmental loading. A total of 50 mattresses are planned

to be used for the crossings, with the volume of rock to be placed in the order of 19,000 tonnes

to ensure a smooth 3 in 1 slope (Tables 2-11 and 2-12).

Rock and mattress placement

In addition to the mattresses required for the crossings, mattresses will be required for

stabilisation and protection of pipeline/umbilical tie-ins at Liberator wells, Ross DCA and Ross

DM locations (Table 2-11, Figure 2-11). Mattresses are typically 8 m long x 4 m wide and

0.15 m or 0.3 m high and made of concrete with polyprop rope, with a 15-year design life. All

mattresses will have tapered leading edges at locations out with any 500 m exclusion zones

where fishing interaction is a risk. It is likely that a total of ca.204 mattresses will be required

for the development.

Whilst the intention of the pipeline design and installation philosophy is to minimise the

requirement for further stabilisation through rock placement, once the pipeline installation has

been completed a post installation survey will take place. This may indicate the requirement

to supplement the pipeline burial with rock placement over one or more short sections of the

production pipeline to ensure adequate protective cover to prevent upheaval buckling. The

scale of rock placement required is dependent on the out-of-straightness (in the vertical or

horizontal plane) of the pipeline in the trench, as determined by the post-lay survey and

assessment. Efforts will be made to minimise the volume of rock required. Rock placement

would use graded, quarried material (nominal size range 1-5ʺ diameter) and the operation

would be conducted from a dedicated rock placement vessel.

All rock will be placed to such that the minimum design depth of cover necessary is met,

sufficient to provide the necessary protection and avoid upheaval buckling of the line.

Conditions on existing trenched and buried pipelines within the area will also be taken into

consideration as part of the detailed design assessment. RSRUK have confirmed that the Blake

production pipeline route does not have any ongoing issues with upheaval buckling, although

one historic spot rock placement of approximately 30 m in length is present ca. 7 km from the

Blake manifold. RSRUK have also confirmed that there is no issue with upheaval buckling

along any of the Ross production pipelines. Spot rock placement is anticipated to be minimal

based on the expected low operating temperature of the hydrocarbon in the pipeline and

mechanical backfill being undertaken, which should provide a standard depth of coverage and

insulation. For assessment purposes an indicative worst-case quantity of 5,000 tonnes (2,885

m3) has been estimated, based on the expected soils in the area, fluid temperature, backfill

insulation and evidence of upheaval buckling in the Ross and Blake development, although

final values are expected to be significantly smaller.

All rock deposits will be included in the DEPCON application as part of the Pipeline Works

Authorisation (PWA) application.



65

Figure 2-11 Location of mattress and rock placement

A considered alternative to rock placement is additional concrete mattresses. The choice of

mattresses is, however, considered to pose an increased risk in terms of snagging of fishing

gear, and in terms of the movement of the material itself. Given that some of the rock is

proposed for use on live third-party crossings, the potential for mattresses to move poses a



66

relatively greater risk to the underlying infrastructure. The pipeline detailed design will use

the soils and seabed profile data from the Q1 2019 pipeline survey to further investigate the

best method of additional protection for the pipelines and crossings. The investigation will

also include failure analysis for the rock berms and underlying soils, ways to minimise rock

usage and decommissioning strategies.

Table 2-11 Location and footprint of mattresses

Location Number of mattresses Footprint of mattresses (m2)

Liberator wells 94 3,008

Blake Crossing – production /

gas lift trench

34 1,088

Blake Crossing – umbilical

trench

6 192

Ross DCD Crossing 10 320

Ross DCA Manifold 30* 960

Ross DM 22 704

Total 196 6,272

Notes: Based on a mattress size of 8 m x 4 m x 0.3 m. * = total includes an additional 4 mattresses to cover the unprotected

DCD lines laid on the seabed after disconnection from the manifold. These are contingency as it is planned to reuse the

current mattresses unless they break during lifting (see Section 2.7.6).

Table 2-12 Location, volume and footprint of rock placement

Requirement

Dimension of

rock placement

(km)

Volume of

rock (m3)

Total seabed

footprint (m2)

Blake crossing – production / gas lift

trench 0.45 6,435 5,400

Blake crossing – umbilical trench 0.25 4,485 4,800

Ross DCD crossing 0.25 4,485 4,800

Spot placement1 - 2,885 3,100

Notes: 1 = exact spot placement volumes won’t be known until the post lay survey has been completed. Estimated volumes

are based on worst case.

Pipeline and spool pre-commissioning

In advance of the production pipeline being readied to carry produced fluids, a series of pre-

commissioning activities will be undertaken. The anticipated pipeline pre-commissioning

sequence in readiness for commissioning operations is as follows:

• Following pipelay, the pipelines will be flooded, cleaned and gauged to remove any

dirt/debris. Filtered treated seawater will be used for filling the pipelines. Chemical

treatments will include biocide, corrosion inhibitor, oxygen scavenger and fluorescent

dye.



67

• Hydrostatic testing of pipelines will be undertaken to confirm strength requirements to

the principal design code.

• Spool piece and any piping/valve assemblies will be strength tested onshore prior to

offshore deployment. Following spool piece and piping/valve assembly installation a

post tie-in hydrostatic leak test will be conducted to ensure integrity of flange joint

connections.

• The oil production pipeline may be dewatered during the commissioning phase using

produced oil to displace the treated seawater. Water will be displaced from Liberator

end and received at the FPSO separation train for subsequent disposal in the produced

water system. Mono-ethylene glycol (MEG) slugs may be required to be introduced to

separate the oil from seawater. Alternatively, the production line seawater may be

displaced by running a pig from the FPSO to the Liberator end with the water displaced

to sea via a temporary receiver. The 10ʺ oil production pipeline running from the

Liberator wells to the FPSO has an approximate volume of 420 m3.

• The gas lift pipeline will require to be dry prior to introduction of lift gas. Dewatering

will include displacement of the treated seawater with an 80/20% MEG/water mix and

will be either carried out prior to leak testing, with water displaced to sea, or post tie-in

from the FPSO to Liberator wells prior to production line dewatering. The 80/20%

MEG/water mix will be displaced with nitrogen into the production system. The gas lift

pipeline system FPSO to Liberator has an approximate volume of 110 m3.

The precise method, equipment and materials used for these operations will be selected and

developed during the detailed design phase. The application for a Term Permit (subsea

operations MAT and associated SATs) will include an assessment of the chemicals to be used.

Umbilical pre-commissioning

The hydraulic cores of the umbilical and jumpers will be filled with hydraulic control fluid,

Pelagic 100, prior to operation. The hydraulic fluid will remain in the umbilical and jumper

cores during operation of the Liberator field, with small, intermittent discharges occurring

during opening and closing of the hydraulic valves (these valves are opened and closed to start

and stop the flow of chemicals into the well/produced fluids). The use of the hydraulic fluid

would be managed via the Bleo Holm chemical permit.

The chemical cores of the umbilical and three jumpers will be filled prior to operation.

Chemicals will remain in the umbilical cores until production commences, at which point they

will be used to treat the produced fluids, entering the Bleo Holm process system for discharge

with produced water over the field life of ten years.

Operations and maintenance

During its anticipated ten year operational lifetime, the Liberator pipeline and umbilical will

be subject to a number of inspections to ensure continued integrity. External inspection will

be carried out using a combination of ROV/autonomous operated underwater vehicle and

towed sonar. The frequency of such maintenance will be determined by carrying out a risk

assessment as part of ongoing inspection, repair and maintenance programmes.



68

A discussion of the chemicals expected to be required for the operation of the Liberator

development is contained in Section 2.8.4.

2.8 Host Modifications

Flow assurance work has been carried out to assess the adequacy of the existing infrastructure

to handle the Liberator production fluids in addition to the existing Blake production. The

results of which have led to the tie-in options selection discussed above. The Liberator

production and gas lift pipelines will most likely tie in to existing flanges on the Ross DCA

manifold, once the current DCD to DCA lines have been, flushed and secured. The Liberator

umbilical will connect to a spare slot on the Ross DM.

Some modifications to facilitate master controls for Liberator will be required in the Bleo Holm

control room for Liberator, additional modifications will be considered at the topside umbilical

terminations (TUTUs) that retain the existing Ross subsea hydraulic supplies and would allow

Liberator and the three Ross drill centre groups to be individually isolated at the TUTUs.

Redundant equipment and space can be made on the Bleo Holm to accommodate Liberator.

There will be some improvements required in the metering facilities, including produced water

metering, to meet current regulatory requirements, but these have been identified and there are

no feasibility concerns identified with the installation of suitable equipment.

Whilst the Liberator Field Development has a projected field life of ten years, RSRUK are

currently only projecting production of Blake/Ross through to 2024. The Bleo Holm itself

does not currently have an anticipated cessation of production date and the vessel is maintained

on an ongoing basis to remain fit for service. Discussions are ongoing on the potential of

keeping the Bleo Holm onsite post 2024.

Figure 2-12 Oil production figures (tonnes/day) for the Bleo Holm



69

Production figures (P10) for the Liberator field and for the Bleo Holm are shown and discussed

in Section 2.4, with Figure 2-12 showing historical and future production for the Bleo Holm.

Only production up until 2024 is shown for Blake and Ross, as that is current limit of the

projected production.

The Liberator fluids are to be processed via the existing Ross separator and measured as three

single phase fluids at the separator outlets (oil, gas, water). The Liberator fluids will enter the

FPSO through the turret and will be routed to the 1st stage Ross separator, which has sand filters

installed before the separator. After first stage separation, the Liberator hydrocarbons will be

comingled with the Blake fluids and then processed together in the second stage separator.

After the second stage separator the comingled oil is transferred to storage tanks and on a

periodic basis the storage tanks are evacuated to tankers via an existing metering system

Currently a tanker empties the FPSO storage tanks on average once a month and transports the

oil to Rotterdam or Wilhelmshaven. The addition of Liberator fluids would mean that there

would be no increase in capacity of the tankers, just an increase in frequency of offloads to ca.

once every 3 weeks.

Gas from the separators goes through a compression before being used either for fuel, gas-lift

or sent for export. Gas export is by 6ʺ pipeline to St Fergus. It is believed that gas export

specifications would be maintained due to the similarity of the Blake and forecasted Liberator

hydrocarbons.

As the Liberator hydrocarbons are from the same wider reservoir as the Blake fluids, it is not

expected that there will be any flow assurance issues when the oil and gas are combined for

export / fuel use (see Section 2.8.4 for further discussion). Fluid modelling showed no changes

to topsides operating pressures or temperatures due to the introduction of Liberator fluids. The

FPSO will see an increase in hydrocarbon production once Liberator is online. Projected

flowrates for all existing oil and gas processing equipment will however be within the original

design basis and suitable for the change in production flowrates.

Produced water

The Bleo Holm OPPC permit (reference number: OLP/119/12) details the current produced

water process and how the measures in place on the installation to minimize pollution and limit

discharges of oil meet the standards of Best Available Techniques (BAT) and Best

Environmental Practice (BEP).

Produced water from the first stage Ross separator is treated by a hydrocyclone and then routed

to the Ross degasser for a final stage of treatment, then routed to the slops tank. The produced

water from the second stage separator is pumped to the LP hydrocyclones, where it is

comingled with water from the first stage Blake hydrocyclone on route to the HP degasser.

The produced water from the HP degasser is pumped to a slops tank and the reject oil streams

are routed to the hazardous closed drains tank. Within the hazardous drains tank the fluids are

separated with the water pumped to the slops tank and the oil stream returned to the separation

train. The produced water is finally discharged overboard from the slops tank. There are no

produced water reinjection (PWRI) facilities on the Bleo Holm and installing such facilities is



70

not deemed feasible. The OPPC permit has a monthly average dispersed oil in water limit of

30 mg/l and a maximum single concentration of 100 mg/l.

Table 2-13 shows historical produced water values and average oil in water concentrations and

Figure 2-13 shows the change in produced water volumes estimates once the Liberator field

comes into operation. Note that as with the production profiles, shown in Figure 2-12, only

projections up until 2024 are shown for Blake and Ross.

Table 2-13 Historical Bleo Holm produced water volume and oil in water (OIW) concentrations

Year Annual produced

water volume (m3)

Average annual OIW

concentration (mg/l)

Average monthly OIW

concentration range

(mg/l)

2015 850,960 30.1 21.7 - 46.9

2016 1,028,486 32.2 17.71 – 74.34

2017 1,012,803 32.0 14.48 – 78.29

2018* 1,174,560 22.16 16.27 – 30.96

Notes: * = 2018 data is up until end of September

Figure 2-13 Historical and projected produced water volumes for the Bleo Holm

Based on the P10 estimates, water production from the Liberator wells is expected to increase

from 4 m3/d in 2020, peaking at 660 m3/d in 2028. If as expected Liberator does replace Ross

production to the Bleo Holm there will be an increase in overall produced water volumes being

processed on the FPSO, of between 0.1 and 16.0%. The total produced water processed at the

Bleo Holm FPSO post liberator start-up will be within the existing capacity of the system (up



71

to approximately 15,900 m3 per day or 5,800,000 m3 per year), with no modifications to the

system required.

It should be noted that the addition of Liberator produced water is not expected to make a

material impact on the Bleo Holm oil in water performance despite slightly higher volumes

requiring processing. There will however be an ongoing requirement to monitor and assess the

effectiveness of produced water clean-up performance and any impact post Liberator start up.

A review of management measures will be undertaken if oil in water performance issues persist

with the addition of Liberator fluids. Full information on this process will be provided in a

variation to the Bleo Holm OPPC permit and associated BAT/BEP documents prior to

Liberator start up.

Drains

The Bleo Holm closed hazardous drains are routed to a collection vessel where oil is skimmed

off and returned to the process. The remaining fluids are routed to the slops tank.

The open hazardous drains are routed to a collection vessel and all fluids from this vessel are

routed to the slops tanks.

The inputs from the drainage systems to the slops tanks are commingled with the produced

water. There will be no changes to this process resulting from the addition of the Liberator

field production fluids.

Chemical usage

The Bleo Holm holds a production chemical permit under BEIS reference number CP/170/24.

Currently only the Ross field requires wax inhibitor to be injected as the fluids reach the FPSO

below the wax appearance temperature. There are no asphaltene deposition issues with either

Blake or Ross and no deposits have been recovered during intervention work.

Given the similarity of Blake and Liberator fluids, it is assumed that chemical requirements

will be analogous, with the addition of a wax inhibitor which may be required if the Liberator

fluids arrival temperature is below the wax appearance temperature. This will be confirmed

during further FEED studies. Table 2-14 details the likely chemical suite required for Liberator

produced fluids, based on those currently used for Blake and/or Ross.

A demulsifier will be required for Liberator produced fluids to aid separation of both water-in-

oil and oil-in-water emulsions and an antifoam will be required. Scale inhibitor will be required

to prevent low-mild carbonate scaling in the riser/topsides and will be injected through the

Liberator riser and corrosion inhibitor will be required to protect the Liberator carbon steel

pipelines, injected at the Ross manifold. All chemicals applied through the topsides are likely

to be continually dosed.

The Blake field has a propensity to form calcium naphthenate, which during initial production

resulted in deposition in topsides process vessels and which required extensive shutdowns to

clean out. A combination of calcium naphthenate inhibitor and acetic acid (Gyptron SD140) is

now injected to inhibit against calcium naphthenate formation. This chemical treatment has



72

proved successful and calcium naphthenate is now managed and under control. The same

process would be applied to the Liberator field, if the same issue arose.

Hydraulic fluid is required to control subsea control valves. When the control valves are

operated a small amount (0.2 kg) of hydraulic fluid is introduced to an umbilical line and then

discharged to sea on the operation of the control valve. The Liberator field will use the same

hydraulic fluid as currently used for Ross and Blake: Pelagic 100, an E rated chemical under

OCNS.

An initial assessment of the volume of chemicals required for Liberator suggests that there will

be a small increase (0.01-2.25 m3/d) in use of the chemicals detailed in Table 2-14. The

exception is the scale inhibitor SCALETREAT 8019, which will decrease in use once Ross

fluids are no longer being produced. Flowrates will not excess current chemical injection pump

designs.

Table 2-14 Likely chemical suite for Liberator production fluids

Chemical Function HQ

Band

Product

Warning

Sub

Label

Typical Dosage

Rate (ppm)

Cortron CK-292G

Wellhead

Corrosion

Inhibitor

Gold No Yes 50

SCALETREAT 8019 Scale

Inhibitor Gold No No 60

PHASETREAT 6284 Demulsifier Gold No No 4-15

Defoamer AF119M Antifoam Gold No Yes 10-15

Gyptron SD140 pH

Regulator Gold No Yes 600-700

PHASETREAT 6173 CN Inhibitor Gold No Yes 120

TBC Wax

Inhibitor - - - 200-500

Pelagic 100 Hydraulic

Fluid E No No -

A review of the required chemical usage once Liberator is producing compared to current on-

board storage capacity suggests that for acetic acid Gyptron SD140 the Bleo Holm currently

utilises all available storage for the chemical. The Bleo Holm receives weekly supply vessels,

which can be disrupted by weather so additional chemical storage would potentially be required

with regular monitoring by operations personnel.

The increase in chemical usage is however offset by the shut in of Ross production and resulting

decrease in Ross chemicals. Any small incremental increase in chemical requirements for

Liberator will necessitate additional space on the weekly supply vessels and at worst case

additional supply vessel trips. The increase is however very minor and so any increased

frequency would also be very minimal. For the purpose of this assessment, an additional one

supply vessel trip per 6 months has been assumed.

Power generation

Production at the Liberator field will slightly increase the overall power requirement at Bleo

Holm, resulting in increased fuel use. The Bleo Holm has two 11.1 MWe duel fuel Solar Mars



73

100 gas turbine generators which provide the main power generation, and two 4MW rated Solar

Taurus 60 duel fuel gas turbine driver which provide seawater injection for Blake. These run

off a combination of fuel gas and diesel. In addition, there are heaters, cranes, fire pumps, a

steam generation package and an emergency power generator which run off diesel. Table 2-

15 shows historical fuel use on the Bleo Holm split into fuel gas and diesel for the main power

generation and seawater injection turbines and diesel usage for all other engines and heaters

Once the Liberator field is producing, it will contribute additional gas to the Bleo Holm which

can potentially be used as fuel gas, reducing the need for diesel in the main gas turbines and

gas export compressors. The contribution of Liberator gas to the fuel mix won’t however be

known until after start-up and as a result the power generation figures shown post 2020 in Table

2-15 (so post Liberator start up) are based on an incremental increase in power requirements,

estimated at 10% of the 2017 levels (the last full year of data). As Liberator will not use

seawater injection, there will be no increase in fuel use requirement associated with this system.

There are no current production forecasts for Blake and Ross post 2024, and therefore, for the

purpose of this assessment, it is assumed that the fuel requirements for the Bleo Holm will

remain at 2024 levels until 2029. This represents a worst-case approach.

Table 2-15 Historical and projected annual fuel use for the Bleo Holm FPSO and change compared to 2017 data

Year Turbines

Fuel Gas

(t)

SW

Injection

Fuel Gas

(t)

Turbines

Diesel (t)

SW

Injection

Diesel (t)

Other

Engines &

Heaters

Diesel (t)

Total Fuel

Use (t)

% Change

Compared

to 2017

2015 16,029 2,541 6,144 0 4,304 29,017 -

2016 20,019 2,131 3,135 0 3,932 29,217 -

2017 23,272 5,660 2,802 0 4,591 36,325 -

2018* 21,331 7,397 2,336 0 4,965 36,029 -

2020 -

2029

25,599 6,226 3,082 0 5,050 39,957 10

Notes: * 2018 data is for months 1-9 only; Post 2020 data is based on production for that year relative to 2017 data.

Flaring and venting

The Bleo Holm has existing HP and LP flare systems which safely collect and dispose of excess

gas and emergency blowdown from all areas of the process plant. The HP flare system handles

all high-pressure releases; primarily process upset sources and the LP flare system handles all

lower pressure releases such as seal gas from the gas compression system. Equipment

connected to the HP flare vents to the HP flare knockout drum and passes from there to the

flare tip, where the gas is ignited for safe disposal. Equipment connected to the LP flare header

vents to the LP flare knockout drum and passes from there to the flare tip.

Apart from the base load flare required for the safe and efficient operation of the process and

flare systems under normal operating conditions, gas is flared on Bleo Holm during emergency



74

pressure relief, periods of process instability typically after start-up and shut down, or for brief

periods during unavailability of the gas compression system. In addition, the 2nd stage separator

floats on the LP flare pressure (atmospheric pressure) and so gas is routinely sent to the flare

from the 2nd stage separator. The Bleo Holm flare consent (reference number: FCON/4224/0)

has a maximum average daily limit of 22.14 tonnes and the vent consent (reference number:

VCON/4221/0) has an average daily limit of 2.04 tonnes.

The production from the Liberator field will not significantly change the current operating

conditions and philosophy at Bleo Holm with respect to flaring and venting. As with the

current process arrangement gas produced from Liberator will be split into fuel gas, gas lift,

export gas and flared gas. Currently gas which emanates from the 1st stage separator is

compressed for export or used as fuel or gas lift, whilst gas from the 2nd stage separator is

routinely sent to flare. As a result of increased gas production associated with Liberator, there

will therefore be an increase in total flaring. The quantities and flowrates will be determined

during FEED and therefore all discussion on flaring volumes and impacts are based on

historical Bleo Holm flaring volumes (using 2017 baseline) with an assumption that the flaring

will increase but remain within the permitted volumes.

The additional gas from Liberator will potentially reduce compressor recycle and create more

stability within process, reducing process upsets and associated flaring. Although additional

liquid volume will reduce response time to process upsets it is unlikely to impact process

stability, especially as experiments have suggested that the Liberator and Blake fluids are very

similar.

After a production start-up requiring the flare to be re-lit, a volume of unignited gas is vented.

For plant start-up the volume of gas vented takes into consideration start-up time to the time

the flare is lit, with an increase in gas production from Liberator likely to increase the gas

vented at each start-up.

Table 2-16 Historical and projected annual flare and vent volumes for the Bleo Holm

Year Total Flared (t) Total Vented (t)

2015 6,625 744.6

2016 7,108 744.6

2017 6,987 744.6

2018* 7,085 556.9

2020 – 2029 8,030 744.6

Notes: * 2018 data is for months 1-9 only; 2020; Post 2020 data is based on production for that year relative to 2017 data.

In addition, there is gas vented from crude storage tanks direct to the atmosphere, displaced as

the storage tanks fill with oil. Inert gas and hydrocarbon light ends are displaced to atmosphere,

with an assumed 50% hydrocarbon gas displaced along with the inert gas. As there will be a

production increase post Liberator start-up it can be expected that there will be proportional



75

increase in gas vented from the cargo tanks. As with the flaring estimates, volumes and impacts

are based on historical Bleo Holm venting volumes (2017 baseline) with the increase remaining

within permitted volumes.

2.9 Vessel Requirements

The vessels expected to be involved in the drilling, installation, commissioning and operation

of the Liberator field are described in Table 2-17. Helicopters will also be required for

transportation of personnel during installation and commissioning, and it is estimated that 128

flights will be required during the period it takes to drill and complete both production and the

appraisal wells. Due to the Bleo Holm person on board requirements, which are currently at

capacity, there will be no additional operational helicopter requirement beyond current demand

at Bleo Holm as a result of Liberator production coming on stream. As discussed in Section

2.8.1 it is assumed that there will be additional ca. 5 tankers per year required to export the

Liberator oil from the Bleo Holm and there will also be a very small increase in the number of

supply vessels required during operations, to cover the additional chemical use. Although this

increase is offset by the shut-in of Ross production.

Table 2-17 Estimated vessel types, number of days and fuel use required for the Liberator Field Development

Operation Vessel type Number of

day

Fuel

consumption

(t/day)

Fuel

consumed

(t)

Drilling

Rig move to location and mooring x 3

drilling campaigns

Anchor handling

vessel x 3

75 15 2,250

Drill rig on location Semi-submersible

drilling rig

224 10 2,240

Emergency response and rescue (ERRV) Standby vessel 224 5 (idle) 1,120

Supply1 Supply vessel 96 trips 18 778

Helicopter trips2 Helicopter 128 trips 0.47/hr 60.2

Subsea installation

Transit, mob / demob, pre-lay pipeline

survey, debris removal, crossing

preparation

Pipelay vessel,

trenching vessel &

rock placement vessel

20 23 460

Transit, mob/demob, pre-lay umbilical &

site survey & umbilical pick up from port

DSV 12 15 180

Pipeline, umbilical and gas lift line lay Pipelay vessel 4 23 92

Pipeline and umbilical trenching & burial Trenching vessel 7 17 119

Spool and daisy chain installation &

metrology

DSV 11.5 15 172.5

Mattress installation DSV 2.5 15 37.5

Rock placement Rock placement vessel 3 15 45

Hook-up and pre-commissioning activities DSV 7.5 15 112.5



76

Operation Vessel type Number of

day

Fuel

consumption

(t/day)

Fuel

consumed

(t)

Post lay and as laid surveys Survey vessel 3.5 11 38.5

Operation

Inspection and maintenance of subsea

structures3

Survey vessel 18 days over

ten years

11 198

Additional tanker for oil export4 Oil tanker 43 trips over

ten years

50 3,135

Additional supply vessels for Belo Holm5 Supply vessel 20 trips over

ten years

15 1,350

Additional helicopter flights for Bleo

Holm personnel6

Helicopter 0 0.47/hr 0

Notes: 1 = Rig will require 2-3 supply vessel trips per week (assuming an average of 3) for the duration of the drilling and

completion programme and 10.8 hrs round trip sailing (assuming Peterhead as a supply base);

2 = Average of 4 helicopter round trips per week (average 1 hr per flight);

3 = The frequency of inspection and maintenance will be defined as part of the Pipeline Integrity Management System process. However, for the purposes of this impact assessment, it has been assumed that one survey lasting three days will

occur shortly after production and every two years thereafter for a maximum of 10 years

4 = additional oil export tankers above current level, with Rotterdam (35 hrs transit) used as a destination

5 = additional supply vessel trips to Bleo Holm required, above current level, to service the Liberator development, 10.8 hrs round trip sailing (assuming Peterhead as a supply base);

6 = additional helicopter flights to Bleo Holm, above the current level, for Liberator operations personnel

2.10 Decommissioning

Once production from the Liberator field becomes irrevocably uneconomic, permission will be

sought for production to cease. Decommissioning of oil and gas facilities in the UK is regulated

under the Petroleum Act 1998, as amended by the Energy Act 1998. The UK’s international

obligations on decommissioning are governed principally by the Oslo-Paris Convention for the

Protection of the Marine Environment of the North-East Atlantic (OSPAR Convention).

BEIS’s “Guidance Notes on Decommissioning of Offshore Oil and Gas Installations and

Pipelines states “in accordance with the UK's international obligations, all installations

emplaced after 9 February 1999 must be completely removed to shore for reuse, recycling or

final disposal on land”. BEIS (2018a) provides specific guidance on decommissioning

activities; Figure 2-14 shows the process leading to approval of a decommissioning

programme. At the onset of the decommissioning phase i3 will adhere to the decommissioning

guidance that is current at the time.

Figure 2-14 Decommissioning approach



77

The three production wells will be plugged and abandoned at the end of field life (anticipated

to be ten years). It is likely that cement plugs will be set across the reservoir sections, across

casing shoes and in the conductor casing, and that the conductor casing will be cut below the

seabed. The well abandonment will follow legislation and guidelines applicable at the time.

i3 will recover the spools and any supporting structures (e.g. mattresses) at the end of field life.

The OSPAR provisions do not apply to pipelines; however, BEIS (2018a) guidance sets out

UK policy on pipeline decommissioning. The decommissioning strategy for the pipeline and

umbilical will depend on a number of factors including, the availability of suitable technology

and the potential environmental, safety and cost implications of decommissioning methods at

the end of field life, approximately ten years after production commences. The ultimate

intention is to leave the seabed of the development area in such a condition that it will pose no

risk to the marine environment or to other sea users, and the development has been designed

with this intention in mind. No development decisions have knowingly been taken that will

preclude this goal.

Prior to the end of field life there may well be changes to the statutory decommissioning

requirements as well as advances in technology and knowledge. i3 will aim to utilise

recognised industry standard environmental practice during all decommissioning operations in

line with the legislation and guidance in place at the time of decommissioning. Discussions on

what may be required will be held with the Regulator as early as possible before

decommissioning commences.

Prior to the decommissioning process, re-use and recycling alternatives will be considered

where feasible to reduce the potential for materials having to go to landfill. In advance of the

decommissioning process an inventory of Development equipment will be made and the

potential for further reuse will be investigated. As an integral component of the

decommissioning process, i3 will undertake a study to comparatively assess the technical,

financial, health, safety and environmental aspects of decommissioning options, for which a

further EIA may be required.

Responsibility for decommissioning the Ross DCA manifold, Ross DM, the pipelines and

umbilicals between the Ross DCA manifold and the Bleo Holm FPSO, and the Bleo Holm

FPSO itself will remain with the Blake/Ross field Operator (currently RSRUK) and the FPSO

owner (currently Bluewater).



79

3 Environmental Description

3.1 Introduction and surveys

This section describes the main characteristics of the offshore environment in the vicinity of

the Liberator field, with particular attention being given to those aspects that may be sensitive

to, or affected by, the proposed operations. This description draws on a number of data sources

including published papers on scientific research in the area and site-specific studies.

Figure 3-1 Seabed surveys for and in the vicinity of the Liberator field



80

A number of seabed surveys have been undertaken in the wider Liberator area (Figure 3-1),

including a 2013 survey which covers the drill centre area and northern end of the pipeline

route corridor and a 2017 survey at the original Liberator wells locations. A survey from 1997

covers the southern end of the pipeline and the Ross area, and whilst some of the data from this

survey will be obsolete some can still be used to characterise the environment. Only the central

4.5 km of the pipeline route is not currently covered by existing survey data.

A survey covering the updated drill centre and appraisal well locations and the full pipeline

route corridor to Ross DCA manifold is scheduled for Q1 2019. Data acquisition will include

geophysical and geotechnical methods alongside drop-down camera, video equipment and grab

sampling for environmental analysis. Ten sites in the site area and pipeline corridor will be

targeted for environmental analysis (photographs, video, 4-day grabs at each station for

macrofaunal, particle-size distribution, organic matter, organic carbon, metals and hydrocarbon

analysis). In addition, if any features of environmental interest or concern are identified in the

geophysical data, further environmental sampling and/or photographs and video will be taken.

Unfortunately, the survey results will not be available to inform this EIA, and therefore the

discussion below is based on results from the previous surveys shown in Figure 3-1. Once the

results of the Q1 2019 survey are available, i3 will submit the report to BEIS and statutory

consultees and detail similarities or differences with the seabed information presented in this

EIA and any resulting bearing on the impact assessment and conclusions in Sections 5 and 6.

3.2 Physical Environment

Weather and sea conditions

The anti-clockwise movement of water through the North Sea and around the CNS region is

driven largely through the influx of water from the Atlantic, entering the northern North Sea

(NNS) north of Shetland and via the Fair Isle Channel, and the main outflow northwards along

the Norwegian coast. This inflow from the Atlantic flows south along the Scottish and English

coasts, with offshoot currents heading off east across the North Sea. Against this background

of tidal flow, the direction of residual water movement in the CNS is generally to the south-

east (DTI, 2001a). Offshore tidal current velocities in the region are relatively consistent

between 0.5 knots and 1.0 knots (0.25 to 0.51 m/s) during mean spring tides (BODC, 1998).

Historical Meteorological Office wind data for the CNS region (1854 - 1994) show that winds

are dominated by those from the south south-west and south, although they can occur from all

directions. Speeds throughout the year equate to moderate to strong breezes (6 - 13 m/s) on

average, with speeds frequently reaching in excess of 17.5 m/s between November and March

(DTI, 2001a). 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. In the

North the mean wave height ranges from 2.26 - 2.50 m whilst in the south it ranges from 1.8 –

2.1 m. Wave heights remain low (0.91 – 1.50 m) along the CNS coastline (NMPI, 2017).

McBreen et al. (2011) shows wave energy at the seabed at the Liberator location to be ‘low’

(<1.2 N/m2) and tidal streams to be defined as ‘low’ (<0.5 m/s). The average mean significant

wave height in the vicinity of the Liberator field ranges from 1.81 to 2.1 m whilst the annual

mean wave power ranges from 18.1 to 24 kW/m (NMPI, 2017).



81

Bathymetry and seabed conditions

The North Sea is a large shallow sea with a surface area of around 750,000 km2. Water depths

gradually deepen from south to north (between approximately 40 m at the Dogger Bank and

100 m at the Fladen/Witch Ground (DTI, 2001a). The main topographic features in the CNS

are the Dogger Bank, a large sublittoral sandbank submerged through sea-level rise located in

the south-west corner of the region, marking a division between the southern North Sea (SNS)

and CNS, and the Fladen/Witch Ground, a large muddy depression generally considered to

define the northern extent of the CNS (DTI, 2001a). The Norwegian Trough, a deep water

channel extending from the mouth of the Baltic Sea to the Norwegian Sea occurs to the east of

the Norwegian/UK median line (DTI, 2001a).

Seabed sediments in the CNS generally comprise a veneer of unconsolidated terrigenous and

biogenic deposits, generally significantly less than 1 m thick (Andrews et al., 1990). DECC

(2009) reports that sand and slightly gravelly sand covers much of the bed of the CNS region

and occurs within a wide range of water depths from the shallow coastal zone to 110 m in the

north and to below 120 m in isolated deeps in the centre known as the Devil’s hole (DECC,

2009; JNCC, 2010). Sediments may have a significant mud content, particularly in basins and

in deeper waters to the north. Coastal areas in the region support a more varied range of

intertidal and seabed habitats (DTI, 2004). Recent mapped information (JNCC, 2010) indicates

benthic sediments in the CNS to consist largely of sand or muddy sand, with smaller isolated

areas of coarse sediment or mud and sandy mud.

The seabed sediments of the Moray Firth Basin are mainly Holocene in origin, and their

distribution reflects both the glacial history of the area and the present hydrographic regime.

The Liberator field lies in an area of seabed which is characterised as muddy sand and sand

(Andrews et al., 1990).

Site surveys conducted by Gardline at the Liberator field in 2013 have contributed to the current

understanding of the environmental baseline (Gardline, 2013a; Gardline, 2013b; Gardline,

2013c). A shallow geophysical survey was carried out covering an area of 4.5 km x 3.9 km

over a total distance of 206.1 km, as well as a 2D High Resolution Seismic survey which

covered an area measuring 2.25 km x 2.00 km and a total distance of 121.088 km (Gardline,

2013a). Single beam and multi-beam echo sounders, side scan sonar, magnetometer, pinger,

sparker, environmental camera/grab and high resolution seismic equipment were used

(Gardline, 2013a).

Survey data to the east of the Liberator drill centre is covered by the 2006 and 2017 Blake area

surveys (Gardline, 2006, Marine Space 2017) and the southern end of the pipeline route and

Ross tie-in points are covered by an older 1997 survey (Gardline 1997). Again geophysical,

environmental and habitats assessments were carried out.

The water depth across the Gardline (2013a) survey area ranges from 100.1 m lowest

astronomical tide (LAT) in the east to 135.0 m LAT in the southwest, the seabed gradient is

1.7°. (Figure 3-). The seabed is irregular across the survey area, with some prominent NNW-

SSE orientated linear shoals and a large NNW-SSE orientated deep in the west, which

coincides with the presence of Forth Formation sediments in the shallow subsurface. The



82

Liberator drill centre is approximately 1 km south of the 2013 environmental survey station

ENV2 (water depth 126 m), within the deeper area in the west. The Liberator pipeline and

umbilical route corridor passes ca. 200 m to the south east of 2013 survey station ENV6 (118m

water depth). Occasional depressions 10 m to 130 m across and up to 3 m deep have been

found across the survey area, the origin of these features is unknown. Increased gradients are

often observed within the survey area on the edges of the seabed irregularities, with a maximum

gradient of 7° on the side of the linear shoal to the west and northwest of the proposed Liberator

location. No obstructions or hazards to drilling have been observed within the survey area or

the Liberator field (Gardline, 2013a).

Figure 3-2 Bathymetry of the Liberator field from the 2013 survey (Note: the well locations shown in this figures

are obsolete and the new drill centre location is 1 km south of station ENV2)



83

Grab sampling observations in the 2013 survey were consistent with seabed imagery,

describing samples as silty sand at each station. Particle size analysis allowed classifying

particles at all stations as muddy sand under the Modified Folk Classification. Sediments were

described as poorly sorted very fine sand under the Wentworth classification of mean sediment

grain size, apart from station ENV5 described as poorly sorted fine sand, and stations ENV1

and ENV2 described as very poorly sorted coarse silt (Figure 3-3). It was found that fine

material (<63 µm) silt and clay comprised 21.1 to 41.0% of the sediment at each station, with

the two highest proportions of fines recorded at stations ENV1 and ENV2, within the deepest

western section of the survey area. Gravel sized material (>2 mm) accounted for a negligible

<0.1% at all stations. Sediment characteristics were correlated to water depth across the survey

area and overall considered representative of the expected variation in this area of the northern

North Sea. Total organic matter (TOM) following removal of carbonates ranged from 0.9 to

2.2% with total organic carbon (TOC) ranging from 0.22 to 0.48% across the survey area

(Gardline, 2013b).

Figure 3-3 Seabed photograph from 2013 survey sites ENV2 and ENV6

Over the 2013 survey area the silty sand surface layer was present over the whole area at <0.5m

thick. Underlying the surface sediments in the west of the survey area (the current Liberator

development area) was very soft to stiff clay and sand of the Forth Formation to a depth of 5-

27 m below seabed.

The 1997 survey of the Ross field area showed a water depth of 105 m at the Ross DCA

manifold location and 96 m at the Ross DM location (Fugro, 1997). The seabed along the

southern end of the pipeline and umbilical route corridors is primarily composed of fine silty

sand with some small areas of clay with occasional boulders <0.1 m in height where the sand

cover is very thin or absent. These seabed conditions are very similar to those found in the

Blake surveys (2002 and 2017) to the east of the Liberator field suggesting that they are

indicative of the wider area. This is corroborated by the European Environment Agency’s

habitat type data, which shows that the proposed locations for all three wells are positioned in

areas classified as deep circalittoral sand (EEA, 2017).



84

Figure 3-4 a) Pockmark location in relationship to wellhead and Ross DCA Manifold, distances in m; b) Ross DCA

manifold location showing pockmark and two cross lines to determine the longitudinal profile

Source: Talisman (2010)

As part of a Ross pipeline replacement project in 2010, a pre-lay survey examined a proposed

Ross pipeline replacement route and the areas around the DCA and DCD locations. The survey

results revealed the presence of a small, shallow pockmark at the extremity of the survey area

a)

b)



85

centred on the Ross DCA manifold Area (Talisman, 2010). Figure 3-4a provides a plan view

of the Ross DCA location showing the pockmark in relationship to the existing wellhead

(distance 17.4 m) and the DCA manifold (distance 47 m). The contour interval is 0.2 m. The

DCA manifold lies to the north of the existing wellhead. Figure 3-4b indicates that the

identified pockmark has an elliptical circumference with major and minor diameters of 19 m

and 14 m respectively. Mean seabed depth around the pockmark itself is 103.5 m LAT, and the

pockmark depth is approximately 1.2 m below the mean seabed (Ross Pockmark Survey

Report, 2010). The Liberator pipeline route and tie-in to the Ross DCA manifold will not

interact with the pockmark, passing >47 m to the north east.

Contamination of sediments

Shipping activity and oil exploration and production activities are the main anthropogenic

sources of hydrocarbon contamination of water and sediments in the area (Ahmed et al. 2005,

Russell et al. 2005). Studies on the Fladen Ground (to the east of the Liberator area) have

shown that although concentrations of hydrocarbons can be higher in the vicinity of oil

installations, they are only detectable at very low levels in far field areas (Sheahan et al. 2001;

Ahmed et al. 2005).

Hydrocarbon analyses of the 2013 survey samples revealed concentrations largely

representative of the very fine sandy sediments of the Central North Sea (CNS) with Total

Hydrocarbon (THC) concentrations varying from 1.1 µg.g-1 to 4.7 µg.g-1. Mean THC

concentration was comparable to values at the 2017 survey stations (2.4 – 4.9 µg.g-1;

MarineSpace, 2017) and additional surveys in the east of the Blake field (Gardline, 2009;

2012). All concentrations were lower than the mean background threshold for the CNS (9.5

µg.g-1; UKOOA, 2001).

The total polycyclic aromatic hydrocarbon (PAH) concentrations in the 2013 survey (35-149

ng/ g) were higher and more variable than those sampled in the 2017 survey (18-50 ng/ g) and

previous Gardline 2009 and 2012 surveys in the wider area. They were however still below

the Oslo-Paris (OSPAR) Commission (2005) background concentration and effects range low

(ERL – 4,022 ng/ g) (Long et al., 1995) suggesting that adverse biological effects in marine

species are unlikely in the area. The PAH levels were also within the concentration range (20

to 74,700 ng/ g) previously reported for sediments surrounding oil and gas installations

(Sheahan et al., 2001). THC, total n-alkanes and total PAH were significantly correlated with

sediment characteristics across the survey area, indicating natural variations of these

compounds associated with sediment type. Hydrocarbon concentrations were found to be

typical of North Sea background concentrations and representative of the wider area by

comparison with other surveys.

Metals were extracted from the 2013 survey sediment samples for analysis, which showed

levels broadly comparable with nearby surveys (Gardline, 2009; Gardline, 2012; MarineSpace

2017). Barium (Ba) concentrations ranged between 363 µg.g-1 and 406 µg.g-1 and were above

the UKOOA (2001) mean concentration for the North Sea but within the UKOOA (2001) 95th

percentile threshold. The concentrations of Ba were comparatively lower in the deeper western



86

part of the survey area, including the Liberator drill centre location and pipeline route, where

slightly finer sediments were recorded.

All metals were within their apparent effect threshold at all 10 stations in the 2013 survey. All

metals were below their background concentrations (BCs) (OSPAR, 2005) with the exception

of cadmium (Cd) at stations ENV1 and ENV2. These results indicated that concentrations of

As, Cd, Cr, Cu, Hg, Ni, Pb and Zn were typical of a “pristine” environment for these metals

described by OSPAR (2005) as sites with concentrations typical of a remote, undisturbed

environment.

There was no evidence of gas hazard and no significant faults were observed within the 2013

survey area. Occasional boulder/debris and linear debris items were observed within the survey

area. Occasional minor magnetometer anomalies were found but none lie in the vicinity of any

of the debris observed on side scan sonar data. Consequently, no seabed obstructions or

hazards to drilling were observed at the proposed Liberator location (Gardline, 2013b).

The 1997 pre-development survey of the Ross area showed that even before the Ross

development there was a significant number of anchor pile and trawl scars in the area (Fugro,

1997). Subsequently a number of wells have been drilled and infrastructure installed and

therefore it can be expected that there will be some disturbance and contamination of sediments

along the southern end of the pipeline route. Most of the Ross wells were drilled prior to the

ban on overboard discharge of OBM drill cuttings. As a result, it is likely that there will be

some OBM contaminated cuttings piles within the Ross area. This will be fully investigated

during the 2019 survey. However, it should be noted that all of the DCA wells are sited close

in to the manifold and the Liberator pipeline trench will finish at the edge of the 500m exclusion

zone well away from the vicinity of the wells. The pipeline route will also not enter the DCC

500m exclusion zone and the area of the cluster of DCC wells.

3.3 Biological Environment

Benthos

The biota living near, on or in the seabed is collectively termed benthos. The diversity and

biomass of the benthos is dependent on a number of factors including substrata (e.g. sediment,

rock), water depth, salinity, the local hydrodynamics and degree of organic enrichment. The

species composition and diversity of the benthos or macrofauna found within sediments is

commonly used as a biological indicator of sediment disturbance or contamination.

In order to identify macrofaunal communities during the Gardline (2013a) survey, three 0.1 m2

faunal samples were taken at each station, two of these were analysed and one kept in storage

as a spare. A total of 9,477 individuals representing 282 taxa were identified in the 20 samples

analysed from the 10 stations, and 1,462 (15%) of these individuals from 38 taxa were

juveniles. Juvenile brittlestars (Ophiuroidea), molluscs (Abra spp.) and polychaetes

(Ampharetidae) were within the top ten most abundant records across the survey area and

accounted for 63% of the juveniles dataset and 10% of the total number of individuals. Further

analysis showed that the presence of a high number of juveniles did not significantly affect the

measures of diversity as the full dataset (including juveniles) and the adult dataset (excluding

juvenile records) were over 95% similar.



87

Analysis of the samples revealed a fairly rich, generally evenly distributed community

(Gardline, 2013c). Polychaetes were the most abundant taxa at all stations in both adult and

full datasets, 73% and 66% respectively. The polychaetes Prionospio dubia, Paramphinome

jeffreysii and Galathowenia oculata dominated the adult communities, and were found to be

ubiquitous across the survey area, accounting for 29% of all adults identified. Dominance of

polychaetes is typical from North Sea sediments where they are expected to represent at least

50% of macrofaunal species in a sample; therefore, the total contribution in these samples was

slightly higher than expected for the fine sandy sediment present (Gardline, 2013b).

The polychaete Paramphinome jeffreysii was the most abundant species in the survey area and

is considered to be tolerant to hydrocarbon contamination (Gardline, 2013c). Its abundance

was considered as natural and representative of the wider area and not attributed to hydrocarbon

concentrations. Galathowenia oculata was the second most abundant species found in the

samples. It is commonly found in sublittoral sandy muds and is thought to be intolerant to

hydrocarbon contamination. Therefore, the abundant presence of this organism backs up the

impression of the absence of significant contamination in the sediments sampled at the

Liberator location. In addition, the presence of the polychaetes Diplocirrus glaucus and

Prionospio cirrifera also indicate a low level of contaminants as these taxa are sensitive to

some metals (Gardline, 2013c).

Other typical species of the North Sea were abundant, such as the polychaete Owenia fusiformis

and the juvenile ophiuroid brittlestars. There was no localised super-abundance of any taxa.

In the full dataset, molluscs were the second most represented group followed by crustaceans

and echinoderms, at all stations except stations 7 and 8 where echinoderms were present in

higher numbers than crustaceans. The least abundant groups comprised sixteen taxa of which

four were the phyla Sipuncula (peanut worm), three from Cnidaria (sea anemones and sea

pens), two from Chordata (Ascidiacea: sea squirt) and one each from Foraminifera,

Platyhelminthes (flatworms), Nemertea (ribbon worm), Priapulida (priapulid worm), Annelida,

Phoronida (horseshoe worm) and Hemichordata (Enteropneusta: acorn worm) (Gardline,

2013c).

A total of 61 juveniles of ocean quahog Arctica islandica (a species of clam) was found across

fifteen of the twenty samples and nine of the ten stations. This is on the OSPAR (2008) list of

threatened and/or declining species in the North Sea and also listed as a Feature of Conservation

Importance (FOCI) and Priority Marine Feature (PMF) under Marine Conservation Zone

(MCZ) guidance (Natural England and Joint Nature Conservation Committee, 2010; Marine

Coastal Access Act 2009; Marine Scotland Act 2010). This species was also found in the

Gardline 2009 and 2012 surveys with 23 juveniles identified, and one adult and fourteen

juveniles, respectively. However, no adult or juvenile Arctica islandica were recorded during

laboratory analyses or drop-down video sampling in the 2017 survey and no large aggregations

in any of the surveys. The differences between surveys are attributed to natural spatial and

temporal variations. Spawning events for this species should be completed by early October,

with settlement occurring for up to several months (Gardline, 2013c).

Benthic surveys (Gardline, 2006; Gardline, 2013a) showed the presence of seapens (Virgularia

sp. and P. phosphorea) and indicated the seabed was burrowed by infauna (Figure 3-5 and 3-



88

6). The area therefore has the potential to qualify as the PMF and MPA search feature

“Burrowed mud” and the OSPAR (2008) threatened or declining habitat “Seapen and

burrowing megafauna communities”. Gardline (2013c) indicated that the low density of

seapens and the sparse occurrence of visible megafauna was unlikely to qualify the area as

OSPAR (2008) habitat, the definition of which includes “conspicuous populations of seapens”,

although it could still qualify as a PMF. Although the sea pen Pennatula phosphorea was

recorded at several stations in the 2017 survey, only a few burrows were noted and mobile

epifauna were sparse. There is, therefore, little further evidence of the potential sea pen and

burrowing megafauna communities, which is a threatened and / or declining habitat under

OSPAR (2008), as being present. The Liberator field does not fall within any of the extensive

current areas of search for Burrowed mud (SNH and JNCC, 2012), and as such is unlikely to

be designated as an MPA. The exclusion of the Liberator field from the MPA areas of search

suggests that the Liberator field does not support any outstanding examples of this feature.

Additional survey work scheduled for 2019 will however provide further information on the

possible presence of this feature.

Figure 3-5 Further photographs of the typical seabed type and fauna from the wider Project area (stations DDV,

transect 02, still 3) (MarineSpace, 2017))

Figure 3-6 Photographs of the typical seabed type and fauna from the Project area (station ENV 4) (Gardline,

2013a)

Within the Gardline (2006) survey area, bioturbation was evident in the form of occasional

circular and elliptical burrows, casts and tracks. Visible fauna included paguridae (hermit



89

crabs), echinoidea (urchins), ophiuroidae (brittlestars), pisces (fish), cnidaria (sea pens) and

mollusca (gastropods such as conch).

Seabed imagery, acoustic data and seabed samples from all surveys in the area provide no

evidence of the presence of any Annex I habitats. The predominant habitat in the area is

deemed to correspond to the features “Continental shelf muds” and “Continental shelf sands”

defined in the Marine Scotland Feature Activity Sensitivity Tool (FEAST).

The environmental baseline information on the Ross area is not available but it is expected that

given the similarities in the bathymetry, seabed features and habitats identified in the

Gardline (2013a), Gardline (2006), MarineSpace (2017), Fugro (1997), Gardline (2012) and

Gardline (2009) surveys, the benthos will be similar across the Ross and pipeline route areas.

Therefore, the previous surveys can be reasonably used as a proxy of conditions in the rest of

the development area. Similarities in seabed sediments and epifauna at two of the survey sites

are demonstrated by seabed photography from the Gardline (2013a) survey presented in Figure

3-6 and seabed photography from the MarineSpace (2017) survey presented in Figure 3-5. A

detailed report on the 2019 survey, including a comparison of bathymetry, seabed and habitat

result with results from the previous surveys, will be submitted as soon as the results are

available.

Fish and shellfish

A number of commercially important fish species are present in the vicinity of the Liberator

field. Fish and shellfish populations are vulnerable to impacts from offshore installations such

as hydrocarbon pollution and exposure to aqueous effluents, especially during the egg and

juvenile stages of their lifecycles (Bakke et al., 2013). The North Sea is historically important

for its fish stocks with fishing occurring throughout the year.

The Liberator field (ICES rectangle 45E8) is located within spawning grounds for plaice

Pleuronectes platessa. Certain species use the area for both spawning activities and as a

nursery ground including: cod Gadus morhua, herring Clupea haregenus, lemon sole

Microstomus kitt, Norway lobster Nephrops norvegicus, Norway pout Trisopterus esmarkii,

sandeel Ammodytes marinus, sprat Sprattus sprattus and whiting Merlangus merlangus. The

Liberator field also lies within nursery grounds for anglerfish Lophius piscatorius, blue whiting

Micromesistius poutassou, European hake Merluccius merluccius, haddock Melanogrammus

aeglefinus, ling Molva molva, mackerel Scomber scombrus, spotted ray Raja montagui and

spurdog Squalus acanthias (Coull et al., 1998; Ellis et al, 2012). The following species are

also listed as Scottish PMFs: anglerfish, blue whiting, cod, ling, Norway pout, herring, whiting,

mackerel, spurdog and sandeels (SNH, 2014a). Cod, haddock and spurdog are all listed as

‘vulnerable’ on the IUCN Red List (IUCN, 2018).

Fisheries sensitivity maps produced by Aires et al. (2014) for Marine Scotland Science detail

the likelihood of aggregations of fish species in the first year of their life (i.e. group 0 or juvenile

fish) occurring around the UKCS. The sensitivity maps indicate that the probability of

aggregations of juvenile cod, herring, mackerel, horse mackerel Trachurus trachurus, sprat,



90

blue whiting, plaice and sole (all true soles2) in the area of the proposed operations as being

low. For Norway pout, haddock, whiting, hake and anglerfish (Figure 3-7a-e) the probability

of juvenile aggregations ranges from low to moderate.

Figure 3-7 Probability of aggregations of juvenile fish (aged 0) of a) haddock, b) Norway pout, c) whiting, d)hake

and e) anglerfish

2 True soles includes all members of the family Solelidae.

a)

b

)



91

Red box denoted Liberator development area. Source: Aires et al. (2014)

c)

e)

d)



92

Spawning grounds are typically regarded as being of higher sensitivity to oil and gas activity

than nursery grounds (Cefas, 2001). Marine Scotland has issued a period of concern for Block

13/23 for seismic surveys from February to June, with potential for impact on fish spawning

(BEIS 2018). It is presumed that seismic surveys cannot be undertaken during these months

in the area, however it may be possible to agree with Marine Scotland appropriate mitigation

methods to minimise potential adverse effects. Drilling operations (including VSPs) for the

first production well and the appraisal well are scheduled for Q3-Q4 2019 out with the Marine

Scotland period of concern but coinciding with spawning periods for herring, lemon sole,

Norway lobster, sandeel and sprat (Table 3-1).

Table 3-1 Fish spawning and nursery times in Liberator field (ICES rectangle 45E8) (Coull et al., 1998; Ellis et al., 2012)

Species Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Anglerfish N N N N N N N N N N N N

Blue whiting N N N N N N N N N N N N

Cod S/N S/N S/N S/N N N N N N N N N

European hake N N N N N N N N N N N N

Haddock N N N N N N N N N N N N

Herring N N N N N N N S/N S/N N N N

Lemon sole N N N S/N S/N S/N S/N S/N S/N N N N

Ling N N N N N N N N N N N N

Mackerel N N N N N N N N N N N N

Norway lobster S/N S/N S/N S/N S/N S/N S/N S/N S/N S/N S/N S/N

Norway pout S/N S/N S/N S/N N N N N N N N N

Plaice S S S S

Sandeel S/N S/N N N N N N N N N S/N S/N

Spotted ray N N N N N N N N N N N N

Sprat N N N N S/N S/N S/N S/N N N N N

Spurdog N N N N N N N N N N N N

Whiting N S/N S/N S/N S/N S/N N N N N N N

S = Spawning, Peak Spawning, N = Nursery, N = High intensity nursery area, SN = Spawning and nursery, Blank = No

data,

Drilling of the second production well and subsea infrastructure installation is scheduled for

Q2 2020 and drilling of the third production well is scheduled for Q2 2021, coinciding with

peak spawning of Norway lobster and sprat and spawning of cod, lemon sole, Norway pout

and whiting (Table 3-1). Spawning areas for most species are not rigidly fixed and fish may

spawn earlier or later from year to year (Coull et al., 1998); therefore, mapped areas are

indicative at a fairly high level. Many species, whether pelagic or demersal by nature,



93

including sprat, whiting, cod, lemon sole, Norway pout, and plaice spawn into the water column

over large areas and so their eggs and juveniles are unlikely to be significantly impacted by the

proposed limited drilling operations in the Liberator field.

Herring are indicated as spawning in the Liberator field in the months of August and

September. The characteristic that distinguishes this species from others is that it requires a

specific benthic habitat on which to lay its eggs, and such habitat is very limited and only

occurs in relatively small areas. A herring (Clupea harengus) spawning ground assessment

was undertaken by Gardline (2013) at each of the stations in Figure 3-3-1. This revealed that

the survey area was not suitable for herring spawning as the area is too deep, with strong

currents and no accumulation of coarse material nor evidence of well-sorted gravels forming

raised banks, which are the preferred herring spawning substrate and seabed type (Gardline,

2013c). A similar study at the 2017 survey locations (MarineSpace, 2017) also reached the

same conclusion.

There are, however, two species in the Liberator field, namely Norway lobster and sandeel,

which use the seabed directly for spawning. Norway lobster is widely distributed on muddy

substrata throughout the north-east Atlantic (Sabatini and Hill, 2008), and is indicated in Table

3-1 as spawning all year round.

Sandeels are indicated as spawning in the Liberator field in the months of November to

February. Sandeels prefer spawning substrate with a low clay silt fraction (<10%) (Lancaster

et al., 2014), whilst the substrate at Liberator has a clay and silt (<63 µm) fraction ranging from

21 to 41% (Gardline, 2013b). This suggests that it is unlikely that sandeel spawning will occur

in the Liberator field area.

Recent research has suggested that there has been significant change in fish populations of the

north-east Atlantic over several decades (DECC, 2016). The natural variation in population

sizes through recruitment are also influenced by climatic factors and human exploitation. An

analysis of 50 fish species around the UK demonstrated that 70% changed distribution and

abundance in response to sea temperature warming between 1980 and 2008, with three-quarters

of these species increasing in abundance (Simpson et al., 2011). Other studies have suggested

that temperature variation has strongly influenced landings, and that distributions of two-thirds

of fish species in the North Sea have significantly shifted in latitude over the past 25 years

(Perry et al., 2005).

Many fish species are subject to considerable fishing pressure which acts to reduce population

biomass. Data indicate that the biomass of fish from high trophic levels declined by two thirds

in the North Atlantic in the second half of the 20th Century (Christensen et al. 2003). The

latest Charting Progress report (DEFRA, 2010) states that the majority of UK stocks are still

fished well above the levels expected to provide the highest long-term yield, although of 20

indicator stocks, the proportion being harvested sustainably rose from 10% in the early 1990s

to about 40% in 2007. Overfishing is generally considered to make populations less resilient

to the potential effects of climate change (DECC, 2016).



94

Seabirds

Much of the North Sea and its surrounding coastline and offshore waters are internationally

important breeding and feeding habitats for seabirds. Seabirds are not normally adversely

affected by routine offshore oil and gas operations on the UKCS; however, in the unlikely event

of an oil spill, birds are vulnerable to oiling from surface pollution. This can cause direct

toxicity through ingestion, and/or hypothermia as a result of feather damage (JNCC, 1999).

In general, seabirds feeding or resting on the sea surface are those most vulnerable to water-

borne pollution. The aerial habits of fulmar and gulls, together with their large populations and

widespread distribution, reduce their vulnerability to oil related pollution. The offshore

distribution and abundance of seabirds varies over the year, being lower during the breeding

season when many species return to shore to nest. The offshore distribution outside the

breeding season is mostly driven by the availability of food (DECC, 2009). The distance birds

will travel from their colonies for food varies greatly between species and this influences

offshore distribution. Non-breeding birds may be found foraging further offshore than

breeding birds.

Breeding seabird numbers of some species have shown a long-term decline, most probably as

a result of a shortage of key prey species such as sandeels associated with changes in

oceanographic conditions (Baxter et al., 2011). The Joint Nature Conservation Committee

(JNCC) has released the latest analysed trends in abundance, productivity, demographic

parameters and diet of breeding seabirds, from the Seabird Monitoring Programme (JNCC,

2016a). The new data provides at-a-glance UK population trends as a % of change in breeding

numbers from complete censuses. From the years 1998-2015, the following population trends

for species known to use the Liberator field have been recorded: northern fulmars Fulmarus

glacialis (-31%), black legged kittiwakes Rissa tridactyla (-44%) and common guillemots Uria

aalge (+5%).

Seabird abundance decreases in offshore waters following the winter period (December to

February) when large numbers of seabirds start to return to their coastal colonies for the

breeding season (April to June). During this breeding period, high numbers of breeding

seabirds are linked to their colonies and adjacent coastal waters for feeding. Generally,

vulnerability is lowest during the pre-breeding and breeding months, increasing as the breeding

season ends and birds disperse into offshore waters. After the breeding season ends in June,

large numbers of moulting auks (common guillemot, razorbill Alca torda and Atlantic puffin

Fratercula arctica) disperse from their coastal colonies and into the offshore waters from July

onwards resulting in peak numbers of seabirds during the summer. In addition to auks, black

legged kittiwake, northern gannet Morus bassanus, and northern fulmar, are also present in

sizable numbers during the post breeding season. At this time, birds are particularly vulnerable

to oil pollution as the adults are rendered flightless due to moulting and the juveniles are not

able to fly, therefore they spend a lot of time on the water’s surface, significantly increasing

their vulnerability to oil pollution on the water surface, i.e. chemical or oil spills. Northern

fulmars, black-legged kittiwakes and northern gannet are highly pelagic and capable of

travelling long distances to forage. These species are also adaptable, opportunistic feeders, and

are sometimes found scavenging around fishing vessels.



95

Table 3-2 Seabird Oil Sensitivity Index in Blocks 13/23, 13/28 and adjacent blocks

Block Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

13/17 * *

13/18 * * *

13/19 * * *

13/22 * *

13/23 * *

13/24 * *

13/27 *

13/28 * *

13/29 * *

19/2 *

19/3 *

19/4 * *

Key to

sensitivity = extremely high, = very high, = high, = medium, = low

* = Blocks populated using the highest index from adjacent months within the same block, according to JNCC

recommendations (JNCC, 2016b)

Oil & Gas UK commissioned a series of seabird surveys to assess the distribution and

abundance of both onshore and offshore seabird populations. From these surveys the ‘Seabird

Oil Sensitivity Index’ (SOSI) has been compiled to assess the possible threat of surface

pollution to seabirds (JNCC, 2016b). This index is based on the following information:

• The amount of time spent in the water;

• The extent to which species are reliant on the marine environment; and

• The rate at which the population is able to recover with low numbers.

The most abundant seabird species found in the Liberator field are northern fulmar, black-

legged kittiwake and common guillemot. Herring gulls Larus argentatus, glaucous gull Larus

hyperboreus and great black-backed gulls Larus marinus are known to use the area in winter

(DECC, 2009).

The sensitivity of seabirds to surface oil pollution (seasonal oil sensitivity index: SOSI) in the

region of the Liberator is presented in Table 3-2 for Blocks 13/23, 13/28, 13/29 and the

surrounding blocks. Blocks and months containing no data have been populated using the

methods provided by JNCC (JNCC, 2016b). The data shows that sensitivity is greatest in

Blocks 13/23 and 13/28 in February (extremely high) and in Block 13/29 in February, October



96

and November (very high), with additional peaks in surrounding blocks in April to June (low

to extremely high) and October to December (high to extremely high).

JNCC has issued a period of concern for drilling activities in Block 13/23 for May to September

(BEIS, 2018). As discussed in Section 1.7.4, this period of concern is based on the Offshore

Vulnerability Index (OVI; JNCC, 1999), which was superseded by the SOSI data in 2016.

BEIS recommend that operators check any periods of concern with the SOSI data to identify

whether there are any sequential months of very high seabird sensitivity. As can be seen in

Table 3-2, there are no 2 sequential months of very high seabird sensitivity in Block 13/23 and

therefore the period of May to September is not deemed of concern based on the current criteria.

The planned operations at the Liberator field are approximately 64 km from the nearest

coastline and is therefore remote from sensitive seabird breeding areas on the coast.

Marine mammals

3.3.4.1 Cetaceans

A total of 19 species of cetacean have been recorded in UK waters (Reid et al., 2003). Sightings

of cetacean have been recorded in the vicinity of the Liberator field (Hammond et al., 2004;

Reid et al., 2003). Table 3-3 describes the behaviour of the species that are most likely to occur

in the project area. Rarer species that are occasionally observed in the North Sea include fin

whale Balaenoptera physalus, long-finned pilot whale Globicephala melas, Risso’s dolphin

Grampus griseus and the short beaked common dolphin Delphinus delphis (NMPI, 2017; Reid

et al., 2003).

Table 3-3 Occurrence of cetaceans likely to be most regularly observed in the vicinity of the Liberator field

(Hammond et al., 2004; Reid et al., 2003)

Species Description of occurrence

Harbour porpoise

Phocoena phocoena

Harbour porpoises are frequently seen across the North Sea all year long

and are confined to shelf waters. They typically occur in small groups

of 2 to 3 individuals but they may aggregate when feeding resources are

good. They do not appear to migrate.

White-beaked dolphin

Lagenorhynchus

albirostris

White-beaked dolphins are frequently seen in the central and northern

North Sea, they are present all year round in the UK near-shore waters

at depths of 50 - 100 m, but are observed more frequently between June

and October. They are usually found in small groups of 10 or less, but

have also been observed in large groups of 50 and more.

Bottlenose dolphin

Tursiops truncatus

Bottlenose dolphins are usually seen in groups of 2 to 25, and

occasionally much larger groups in deeper waters. They are common

near-shore the North-East Scotland, and in the UK the greatest numbers

have been observed between July and October, but are present near-

shore all year long.

Minke whale

Balaenoptera

acutorostrata

Minke whales are distributed in the northern and central North Sea, at

water depths of 200 m or less, and are often sighted single or in pairs,

and sometimes aggregate into larger groups of up to 15 individuals when

feeding. Additionally, they appear to return to the same seasonal feeding

grounds.



97

Species Description of occurrence

Atlantic white-sided

dolphin

Lagenorhynchus acutus

The Atlantic white-sided dolphins are mostly confined to the North

Atlantic but have been observed in the North Sea in a number of surveys,

particularly in the western part of the North Sea. Their presence is

seasonal and peaks between May and September. They are usually

observed in groups of tens to hundreds, sometimes up to 1,000 offshore,

forming subgroups of 2-15 individuals.

Killer whale

Orcinus orca

Killer whales are widely distributed across the North Sea all year round.

They are seen in both inshore waters (April to October) and the deeper

continental shelf (November to March) and appear to move inshore to

target seals seasonally.

The harbour porpoise and the white-beaked dolphin are the most frequently recorded cetaceans

in the vicinity of the Liberator field with sightings in eight months of the year, which is

reflective of those being the most abundant and widely distributed cetaceans in the North Sea

(Reid et al., 2003). In the UK there are two known resident populations of bottlenose dolphins,

one of which is in the Moray Firth (Thompson et al., 2011). This local population is typically

restricted to the inner Moray Firth, and along the north-east coast of Scotland. The inner Moray

Firth has been designated as a Special Area of Conservation (SAC) due to the presence of this

species. Sightings of bottlenose dolphin in and around the Liberator field have only been

recorded in low numbers (JNCC, 2016a) and are rarely seen outside coastal waters though it is

thought that they may move offshore during winter (Hammond et al., 2004).

The following species are also listed as Scottish PMFs: Atlantic white-sided dolphin, bottlenose

dolphin, harbour porpoise, killer whale, white-beaked dolphin, long-finned pilot whale and

minke whale (SNH, 2014a).

The harbour porpoise is protected under Annex II of the EU Habitats Directive (92/43/EEC as

amended by 97/62/EC). Based on the available information, Blocks 13/23, 13/28 and 13/29

have low cetacean density and are not considered to be significant for feeding, breeding,

nursery or migrating cetaceans.

Ecosystem changes as a result of climatic change are likely to affect marine mammals,

however, responses of marine mammal populations to such influences is at present poorly

understood, any with and predictions largely speculative and unsubstantiated by unequivocal

evidence (DECC, 2016). Range shifts in marine mammals have been reported in the north-

east Atlantic, which have been linked to increasing sea temperatures, however, the mechanisms

causing those changes remain uncertain and for some species, it is difficult to differentiate

between short-term responses to regional resource variability and longer-term ones driven by

factors such as climate change. As data on cetacean abundance are typically few and often

characterised by considerable uncertainty and both seasonal and spatial gaps, the identification

of long term trends is very difficult. It is generally recognised that the frequency of surveys

needs to increase if changes are to be detected with a reasonable degree of confidence (DECC,

2016).



98

3.3.4.2 Pinnipeds

Five species of pinnipeds have been identified in the North Sea: grey seal Halichoerus grypus,

harbour seal Phoca vitulina, harp seal Phoca groenlandica, hooded seal Cystophora cristata

and ringed seal Pusa hispida (Jones et al., 2015). However, only two of these species live and

breed in the UK, namely the grey and harbour seal, both of which are protected under Annex

II of the EU Habitats Directive and are listed as Scottish PMFs (SNH, 2014a). The bearded,

ringed, harp and hooded seals are Arctic species, and have generally only been sighted on an

occasional basis in Scottish waters.

The Sea Mammal Research Unit (SMRU) regularly monitors Scottish seal populations using

aerial survey techniques around the Scottish coastline, but these surveys do extend to offshore

regions where, in particular, grey seals have been equipped with satellite relay data loggers in

order to study their movements and foraging areas (e.g. SCOS, 2014; SMRU, 2011). The

JNCC Seabirds at Sea Team (SAST) has also been recording seals during surveys in the

Atlantic Margin (Pollock et al., 2000).

Approximately 38% of the world’s grey seals breed in the UK with 88% of these breeding at

colonies in Scotland with the main concentrations in the Outer Hebrides and in Orkney. Birth

rates have grown since the 1960s, although population growth is levelling off (SCOS, 2014).

In the case of harbour seals, approximately 30% of the world’s population are found in the UK.

Following significant population declines due to disease in 1988 and 2002, harbour seal

numbers on the English east coast have been rising since 2009 (SCOS, 2014).

Grey and harbour seals will feed both in inshore and offshore waters depending on the

distribution of their prey, which changes both seasonally and annually. Both species tend to

be concentrated close to shore, particularly during the pupping and moulting season. Harbour

seals haul out every few days on tidally exposed areas of rock, sandbanks or mud. Pupping

and moulting seasons occur from May to August, during which time seals will be ashore more

often than at other times of the year (Hammond et al., 2004). Seal tracking studies from the

Moray Firth have indicated that the foraging movements of harbour seals are relatively local

compared to grey seals and are generally restricted to within a 40–50 km range of their haul-

out sites (SCOS, 2014). The movements of grey seals can involve larger distances than those

of the harbour seal, and trips of several hundred kilometres from one haul-out to another have

been recorded (SMRU, 2011).

The Liberator drill centre is approximately 64 km from the nearest landfall, so it is unlikely

that significant numbers of seals will be found in the vicinity of the proposed operations. This

is confirmed by a study carried out by SMRU and Marine Scotland, which analysed telemetry

data of both grey and harbour seals in the UK spanning 1991 to 2016. The density maps

generated from this work predict (on an annual basis) that seal density in the vicinity of the

Liberator field is zero to one harbour seal and one to five grey seals per 25 km2 (Jones et al.,

2015; SMRU and Marine Scotland 2017).



99

3.4 Conservation

Offshore conservation

The closest site of conservation interest to the Liberator field is the proposed Southern Trench

NCMPA located on the south Moray Firth coast 37 km to the south-west of the Liberator field

(Figure 3-8). It has been proposed for MPA designation for the presence of minke whales in

high relative density compared to wider Scottish territorial waters, as well as for its frontal

zones that create hotspots of pelagic biodiversity, its shelf deeps representing potential nursery

areas for certain fish species, and finally for its burrowed muds which is home to the Norway

lobster and giant seapens. There are no other sites of conservation interest within 70 km of the

Liberator field (Figures 3-8 and 3-9).

Both the Braemar Pockmarks SAC (189 km North East from the Liberator field; Figure 3-9)

and the Scanner Pockmarks SAC (142 km east from the Liberator field; Figure 3-9) are

designated due to the presence of submarine structures made by leaking gases (JNCC, 2016c).

However, given the distance, it is considered unlikely that this site will be affected by the

proposed operations. The same applies to the Central Fladen NCMPA, which is 104km to the

north east of Liberator and designated for burrowed muds and sub-glacial tunnel valley. Whilst

Turbot Bank NCMPA is designated for sandeels, it is over 85 km from the site and therefore

is unlikely to be impacted by Liberator operations.

A. islandica (ocean quahog) is on the OSPAR (2008) list of threatened and/or declining species

in the North Sea and also listed as a Feature of Conservation Importance (FOCI) and Priority

Marine Feature (PMF) under Marine Conservation Zone (MCZ) guidance (Natural England

and Joint Nature Conservation Committee, 2010; Marine Coastal Access Act 2009; Marine

Scotland Act 2010). Ocean quahog is commonly found within this area of the North Sea

(Gardline, 2013c). Aggregations are typically found buried in sediment from the shoreline to

depths of approximately 400 m and can be found on both sides of the North Atlantic and the

Baltic region, including within the Liberator region. Ocean quahog is a long-lived bivalve

species, with a very slow growth rate, irregular recruitment and high juvenile mortality rates,

factors contributing to the overall sensitivities of the population from human activities i.e.

seabed disturbance. The inclusion of the ocean quahog on the OSPAR list is attributed to an

observed decline in the population, sensitivities and direct threat from seabed disturbance.

Management options proposed by OSPAR include limiting seabed disturbance attributed to

human activity in the vicinity of ocean quahog aggregations (OSPAR, 2009). Spawning events

for this species should be completed by early October, with settlement occurring for up to

several months (Gardline, 2013c). Whilst a total of 61 juvenile ocean quahog were identified

in the 2013 survey (Gardline, 2013c), no aggregations were identified and the current core

distribution of this species in the central North Sea is the Fladen Ground (OSPAR, 2009). No

A.islandica were seen in the 2017 camera, video or grab samples further suggesting that the

Liberator area does not contain significant aggregations of the species.



100

Figure 3-8 UK conservation designations in the vicinity of the Liberator field



101

Figure 3-9 EU conservation designations in the vicinity of the Liberator field

As discussed in Section 3.3.1, the area has the potential to qualify as the PMF and MPA search

feature “Burrowed mud”. The 2013 and 2017 surveys reported that only a few burrows were



102

noted and mobile epifauna were sparse, suggesting that the area is not of particular importance

to burrowed mud communities. The Liberator field does not also fall within any of the current

areas of search for Burrowed mud (SNH and JNCC, 2012), and as such is unlikely to be

designated as an MPA.

As discussed in Section 3.2.2, the environmental baseline survey conducted in the vicinity of

the Liberator drill centre in 2013 did not provide any evidence of environmentally sensitive

habitats or features protected under Annex I of the EU Habitats Directive. It also determined

that there is no potential for herring spawning grounds across the survey area as it is too deep,

has strong currents and there is no accumulation of coarse material or evidence of well-sorted

gravels forming raised banks which is preferred herring spawning habitat (Gardline, 2013b).

Coastal conservation

The closest coastal designated site of conservation interest is the Troup, Pennan and Lions

Head SPA (72 km to the south west) designated for guillemots Uria aalge and seabird

assemblages during breeding season (Figure 3-8, 3-9). The Buchan Ness to Collieston SPA

and SAC (81 km to the south of Liberator) are designated for seabird assemblages during

breeding vegetated sea cliffs. Noss Head NCMPA, located 95 km west of the Liberator field

(Figure 3-9), has been designated to protect horse mussel beds that provides shelter for young

fish and crabs, and solid foundation for soft corals, sea firs and tube worms (SNH, 2014b).

The East Caithness Cliffs Nature Conservation (NC) MPA and is located at 96 km from the

Liberator field in the west (Figure 3-9). It is designated to protect black guillemots Cepphus

grille (SNH, 2014c).

The Moray Firth SAC is located 120 km SW from the Liberator field (Figure 3-9) and is

designated for the presence of sandbanks which are slightly covered by sea water at all time

under the Annex I Habitats list, and the presence of bottlenose dolphins Tursiops truncatus

under the Annex II species list (JNCC, 2016c). However, given the distance and records of

sightings of bottlenose dolphin in and around the Liberator field being low (Reid et al., 2003)

it is considered unlikely that this site will be affected by the proposed operations.

Figure 3-10 shows the proximity of the development to the location of protected shellfish

waters and sites of aquaculture development. It shows that the nearest saltwater sites are over

100km to the northwest on the coast of Orkney and 150km to the south west in Dornoch Firth.

Species

Grey seals, harbour seals, harbour porpoise and bottlenose dolphin are currently protected

under Annex II of the EU Habitats Directive. The inner Moray Firth area has been designated

as an SAC due to the presence of bottlenose dolphins; however, bottlenose dolphins are

unlikely to be recorded in vicinity of the Liberator wells for most of the year as discussed in

Section 3.3.4.1. Bottlenose dolphins are anticipated to move away from areas of disturbance.

Harbour and grey seals may be present at the Liberator drill centre location, but their presence

is likely to be in low numbers as discussed in Section 3.3.4.2. The only Annex II species

regularly recorded in the Liberator well area is the harbour porpoise, however due to their

mobile nature they are likely to move away and not be adversely affected by the proposed

drilling operations. Bottlenose dolphins are also listed as Scottish PMFs, along with Atlantic



103

white-sided dolphin, bottlenose dolphin, harbour porpoise, killer whale, white-beaked dolphin

and minke whale (SNH, 2014a). The occurrence of these species in the Liberator field is

detailed in Section 3.2.4.1.

Some commercially important fish species occupying the Liberator field are listed as Scottish

PMFs: Anglerfish, blue whiting, cod, ling, Norway pout, herring, whiting, mackerel and

sandeels (SNH, 2014a). Section 3.2.2 describes whether these species occupy the area as

spawning or nursery grounds.

Figure 3-10 Location of shellfish and aquaculture developments in relation to the Liberator development



104

Figure 3-11 Existing infrastructure around the Liberator field

Non-commercially important fish species of conservation value that are found in UK waters

include the European sturgeon Acipenser sturio, which is relatively rare and the common

whitefish Coregonus lavaretus both of which qualify for protection under Annex II of the

Habitats Directive. Other important species of conservation value include the basking shark



105

Cetorhinus maximus, tope Galeorhinus galeus and porbeagle Lamna nasus. None of these

species are recorded in significant densities in the CNS and occur only in small numbers

throughout the North Sea during periods of peak zooplankton abundance. Therefore, it is

considered unlikely that any of these species will be significantly affected by operations at the

Liberator field.

The presence of A. islandica, listed by OSPAR as an endangered and/or declining species and

under the MCZ guidance as a FOCI and PMF, is discussed in Sections 3.3.1 and 3.4.1.

3.5 Socio-Economic Environment

Oil and gas activity

Oil and gas development in the outer Moray Firth is sparse compared with other oil and gas

areas of the UKCS, although the Liberator development is within 10 km of the Captain FPSO

and subsea facilities, 5 km of the Blake subsea facilities and 10 km from the Bleo Holm FPSO

and Ross subsea infrastructure. The Liberator field is also not far from extensively developed

areas of the CNS. Figure 3-11 shows oil and gas infrastructure in the wider area.

Eight wells have previously been drilled within Block 13/23, 15 within Block 13/28 and 16

within Block 13/29 (Figure 3-1). In addition, 12 wells have been drilled in the Blake

development and 9 in the Ross development. The Liberator pipeline route passes within 500

m of the Ross DCC manifold and a cluster of 3 wells.

Offshore wind farms

There are four offshore wind farms (OWF) in the outer Moray Firth, namely Telford, MacColl,

Stevenson and Beatrice forming the Moray Offshore Renewables Ltd. Area (MORL, 2016)

located approximately 68 km to the west of the Liberator field.

Commercial fisheries

The Liberator field is located in ICES rectangle 45E8 in ICES area IVa. Based on statistical

data from 2017, landings by vessels into Scotland for ICES rectangle 45E8 ( (Scottish

Government, 2018).

Table 3-4) were dominated by pelagic fish which accounted for 53% of the value and 70% of

the landed weight. Demersal species accounted for 30% of the value and 24% of landed weight,

whilst shellfish accounted for 17% of value and 6% of live weight landed (Scottish

Government, 2018). The weight of pelagic fish landed from 45E8 in 2017is classified as

moderate (2,000-10,000 tonnes) and demersal classified as high (1,000-2,000 tonnes)

compared to the rest of Scottish waters (Scottish Government 2018). Although data from 2016

shows a similar trend, landings in ICES rectangle 45E8 in previous years (2013-2015) show a

dominance of demersal species, with pelagic landings making up <0.1% of value. The switch

in dominance from demersal to pelagic does not however suggest a change in fishing methods

in the area, more it reflects a major increase in pelagic fishing post 2015 (from 0 to > 5,000,000

tonnes between 2015 and 2016) with demersal weight and value remaining reasonably

consistent. The total caught weight from rectangle 45E8 therefore increased 236% between

2015 and 2016. In the wider Liberator area landing figures and values are very high in ICES

rectangle 46E8 which borders 45E8 to the north, north of the Captain area (Figures 3-12 and



106

3-13). This rectangle also shows the marked increase in pelagic effort and landed weight post

2015. This trend in increase in pelagic fishing post 2015 is however broadly confined to the

wider Liberator area, with no associated trend in the rest of Scottish waters.

In terms of landed weight, mackerel was the most landed species comprising 68% of landings,

it was also the most valuable species landed accounting for 55% of the landings value for 2017.

Nephrops and haddock were also important species in terms of landing value accounting for

13% and 8% of the landing value respectively for 2017 (Scottish Government, 2018).

Table 3-4 Live weight and value of fish and shellfish from ICES rectangle 45E8 (Scottish Government, 2018)

Species

type

2017 2016 2015 2014 2013

Value (£)

Live

weight

(tonnes)

Value (£)

Live

weight

(tonnes)

Value (£)

Live

weight

(tonnes)

Value (£)

Live

weight

(tonnes)

Value (£)

Live

weight

(tonnes)

Demersal 1,956,583 1,265 2,385,436 1,638 2,767,639 1,974 2,225,651 1,777 1,092,452 1,038

Pelagic 3,381,124 3,611 5,266,401 5,288 62 0 942 1 187 0

Shellfish 1,083,785 304 1,135,769 310 593,108 179 806,176 250 253,276 86

Total 6,421,492*

5,180 8,787,606 7,236 3,360,809 2,153 3,032,769 2,028 1,345,915 1,124

Notes: * annual value data for ICES rectangle 45E8 for 2017 is recorded as £6,871,492 in Scottish Government (2018) but

when the 2017 values for demersal, pelagic and shellfish are added together a total value of £6,421,492 is reached.. This is

the value used in this assessment.

Figure 3-12 Demersal landings in 2012-2016 by ICES rectangle

Notes: ICES rectangle 45E8 is highlighted in black

Source: Scottish Government (2018b)



107

Figure 3-13 Pelagic landings in 2012-2016 by ICES rectangle

Notes: ICES rectangle 45E8 is highlighted in black


In 2017, 709 days were spent fishing in ICES rectangle 45E8 as detailed in Table 3-5. Fishing

occurred throughout the year with peaks in effort occurring in June. Trawls were the dominant

gear type in 2017 comprising 90% of effort, with seine nets being used only 9% of the time.

Despite the increase in fish landings from 45E8 since 2016, the number of days fished has not

increased significantly. This may be due to the increase in pelagic fishing, which can catch

large numbers of fish in a short time period, hence landing significantly greater quantities of

fish with seemingly few extra days of fishing effort. Fishing intensity is still considered low

for pelagic (<500 days) and moderate (500-1,000 days) for demersal fisheries in comparison

with other areas of the North Sea (Scottish Government, 2018b). Furthermore, total effort

recorded for 45E8 is considered moderate in comparison to the UK total, representing 0.56%

of the UK total recorded in 2017 (Scottish Government, 2018).

Table 3-5 Number of days fished per month (all gears) in ICES rectangle 45E8 (Scottish Government, 2018)

Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total

2017 88 26 43 67 34 162 82 30 24 51 51 49 709

2016 61 74 20 101 94 207 60 133 65 46 55 47 963

2015 80 67 73 67 27 27 27 85 113 136 46 82 830

2014 64 52 60 68 49 114 100 18 10 43 122 28 728

2013 19 36 57 25 6 34 26 26 20 24 22 54 349

Note: Monthly fishing effort by UK vessels landing into Scotland: green = 0 – 100 days fished, yellow = 101 – 200, orange

=201-300, red = ≥301.

VMS data for 2007-2015 for all gears shows fishing intensity associated with oil and gas

pipelines (Scottish Government, 2018b). Figure 3-14 shows that north of the Liberator area



108

fishing intensity is moderate to high around the Captain field and associated pipelines,

especially along the Captain gas export line. The area south of the Liberator field along the

pipeline corridor to Ross is however an area of very low usage by fishing vessels. SFF has

advised that an area of deeper water to the west of the Liberator pipeline is targeted by fishing

vessels, with the central to northern end of the pipeline route used for turning and transiting

fishing vessels accessing the fishing grounds. Historically, the area is most heavily fished in

June and early July, with the potential for a substantial number of fishing vessels passing

through the development area. This pattern of increased fishing activity in summer months is

reflected by the effort data given in Table 3-5.

Figure 3-14 Fishing intensity associated with oil and gas pipelines (2007-2015) with Liberator drill centre and

pipeline route in black


Telecommunication cables

There are no telecommunication cables in the vicinity of the Liberator field (KIS-ORCA,

2017). The Caithness to Moray transmission reinforcement works includes the laying of a

subsea cable through the Moray Firth between Wick in Caithness and Buckie in Moray. The

route of the cable is >70km to the east of the Liberator area and is currently being installed. As

a result, there will no overlap in either time or space between installation activities for the two

projects.

Military activity

Blocks 13/23, 13/28 and 13/29 are not designated as Ministry of Defence (MoD) training

grounds (OGA, 2016).

Shipping

The Liberator field is located in an area defined as having low to moderate shipping density

(DECC, 2009). The area is mainly used by cargos and oil tankers (DTI, 2001b). AIS data for



109

2012-2015 (NMPI, 2018) shows that the Aberdeen to Lerwick passenger ferry and cargo route

(Figure 3-15) passes 5 km to the west of the Liberator drill centre. The supply vessels to the

Bleo Holm approach the FPSO from the south and there is limited vessel traffic in the Liberator

and Blake area, although there is the potential for supply vessels for other offshore installations

to transit through the area. This pattern is typical for all vessel types, with the exception of

fishing vessels discussed in Section 3.5.3.

Figure 3-15 Average weekly density of cargo vessels (2012-2015) in the Liberator area

Notes: Location of Liberator drill centre is marked by black circle. Figure also shows the existing pipelines and subsea

infrastructure with the Bleo Holm anchor pattern seen to the south of Liberator.

Archaeology and other infrastructure

Few artefacts of archaeological interest have been recovered from the offshore area within

which the Liberator field sits, and it is not considered to be an archaeologically rich area. A

number of obstructions and possible wrecks have been identified in the wider area (Canmore

2018) and Liberator pipeline route area (Figure 3-16); one 210 m to the west of the pipeline

route. Whilst it is not currently known whether any of the obstructions identified by SFF in

Figure 3-16 are wrecks, anything close to the pipeline route corridor will be investigated during

the Q1 2019 survey and appropriate action taken if they are thought to be at risk from the

pipeline installation operations. It should be noted that the Liberator, Blake and Ross surveys

to date (e.g. Gardline, 2006; Gardline, 2013; MG3 2017) have not recorded any wrecks or

obstructions in the Liberator drill centre area and pipeline route corridor.



110

Figure 3-16 Seabed obstructions identified by SFF in the Liberator development area



111

3.6 Summary of Environmental Sensitivities and Seasonality

Table 3-6 Blocks 13/23, 13/28 and 13/29 Key Seasonal Environmental Sensitivities

Component Block/Activity J F M A M J J A S O N D

Operations

Window 2019

2020

2021

Key: Survey Drilling Subsea Installation First Oil

Periods of

concern Seismic Surveys

Drilling

Commercial

fish species Anglerfish

N N N N N N N N N N N N

Blue whiting N N N N N N N N N N N N

Cod N N N N N N N N N N N N

European Hake N N N N N N N N N N N N

Haddock N N N N N N N N N N N N

Herring N N N N N N N N N N N N

Lemon sole N N N N N N N N N N N N

Ling N N N N N N N N N N N N

Mackerel N N N N N N N N N N N N

Norway lobster N N N N N N N N N N N N

Norway pout N N N N N N N N N N N N

Plaice

Sandeel N N N N N N N N N N N N

Spotted ray N N N N N N N N N N N N

Sprat N N N N N N N N N N N N

Spurdog N N N N N N N N N N N N

Whiting N N N N N N N N N N N N

Key: Peak Spawning Spawning Nursery

Seabird

Vulnerability

Index

Block 13/23 1 1

Block 13/28 1 1

Block 13/29 1 1

Key:

Extremely High Very High High Medium Low

1: These Blocks have no data coverage, however, data from adjoining months for the same Block have been used to fill

the data gap (Step 1 method – JNCC, 2016b).

Harbour porpoise

White-beaked dolphin

N



112

Component Block/Activity J F M A M J J A S O N D

Operations

Window 2019

2020

2021

Key: Survey Drilling Subsea Installation First Oil

Bottlenose dolphin

Minke whale

Atlantic white-sided dolphin

Killer whale

Benthos Sensitivity low throughout the year

Pinnipeds Grey seals and harbour seals may occur within the vicinity of the Liberator field but in limited numbers and

for short periods of time

Commercial

Fishing

Commercial fishing

(ICES rectangle 45E8)

Key: High (>250 days / mnth) Medium (100-250 days / mnth) Low (<100 days / mnth)

Other users

There is currently no surface infrastructure in Blocks 13/23, 13/28 and 13/29 other than the Bleo Holm

FPSO, however there is extensive infrastructure in the wider area. Eight wells have been drilled in Block

13/23, 15 wells have been drilled in Block 13/28 and 16 wells have been drilled in Block 13/29. There are

4 offshore wind farms in the outer Moray Firth; Telford, MacColl, Stevenson and Beatrice, which are

located 68 km west of the Liberator field. Shipping density within the area of the Liberator development is

defined as low to moderate. There are no Ministry of Defence exercise areas in the vicinity, and there are

no telecommunications cables within Blocks 13/23, 13/28 and 13/29. There are no designated protected

wrecks in the area and any obstacles will be investigated during the 2019 survey.

Protected sites

Marine Protected Areas

The Southern Trench NCMPA lies 37 km to the southwest of

the Liberator field, and is designated for presence of minke

whale, frontal zones and burrowed mud. The Turbot Banks

NCMPA, Central Fladen NCMPA, Scanner Pockmarks SAC

and Braemar Pockmarks SAC lie 89 km southeast, 10 4km

northeast, 142 km east and 189 km northeast to the Liberator

field respectively, so are unlikely to be affected by the Liberator

operations.

Coastal protected sites

The Troup, Pennan and Lions Head SPA lies 72 km to the

southwest of the Liberator field and is designated for guillemots

and seabird assemblages during the breeding season. The

Buchan Ness to Collieston SPA/SAC, Noss Head NCMPA, East

Caithness Cliffs NCMPA and Moray Firth SAC lie 81km south,

95 km west, 96 km west and 120 km southwest to the Liberator

field.



113

4 EIA Methodology

4.1 EIA Overview

Offshore activities can involve a number of environmental interactions and impacts due, for

example, to operational emissions and discharges and general disturbance. The objective of

the EIA process is to incorporate environmental considerations into the Project planning, to

ensure that best environmental practice is followed and, ultimately, to achieve a high standard

of environmental performance and protection. The process also allows for any potential

concerns identified by stakeholders to be addressed appropriately. As detailed in Section 1.4

an ENVID was completed prior to the original ES submission and again after the project

changes in 2018. Both the outcomes of those and issues raised during stakeholder consultation

meetings (Table 1-1) have been incorporated into the EIA process.

4.2 Sources of potential environmental effects

An EIA is to be focused on the key issues related to the specific activities proposed; the impact

assessment write-up should be proportionate to the scale of the development and to the

environmental sensitivities of the development area. i3 undertook an impact identification

exercise to identify key environmental sensitivities, discussed sources of potential impact and

identified those sources which required further assessment. The decision as to which issues

required further assessment was based on the specific proposed activities and environmental

sensitivities, a review of industry experience of EIA outcomes and on an assessment of wider

stakeholder interest. Potential impacts were further refined following feedback received during

the informal scoping process. The results of this process are presented in Table 4-1.

Table 4-1 Potential interactions and significance of impacts to receptors from the Liberator development

Activity / Source of Potential

Effect

Environmental Receptors

Cli

ma

te /

air

qu

ali

ty

Wa

ter

qu

ali

ty

Sea

bed

Ben

thic

Fa

un

a

Pla

nk

ton

Fis

h &

Sh

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Schedule

Drilling

Physical presence of drilling unit

& support vessels

Potential for introduction of alien

species in ballast water

Discharge of domestic, drainage &

bilage water from drilling unit &

vessels

Drilling – discharge of mud,

cuttings, cement & chemicals

Discharge of residual

hydrocarbons

Well completion & clean up

discharges



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Activity / Source of Potential

Effect

Environmental Receptors

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Well clean up and test flows

Power generation on drilling unit

& support vessels

Underwater noise from drilling,

vessels & VSP

Subsea Infrastructure

Physical disturbance of seabed

during installation, trenching, rock

placement etc

Underwater noise during

construction activities & operation

Pipeline pre-commissioning

Physical presence of installation

vessels

Solid and liquid wastes to shore

Power generation – installation

vessels

Vessel machinery space, sewage

and other discharges

Surface noise and light

Physical presence of pipeline &

subsea facilities

Bleo Holm FPSO

Hydraulic fluid discharges

Incremental power generation on

FPSO

Incremental produced water on

FPSO

Incremental flaring and venting on

FPSO

Incremental process and utility

chemical use & discharge

Incremental vessel usage

Unplanned Events

Accidental spills

Dropped objects

Collisions

Key

Potentially significant impact Scoped out of EIA No interaction

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For interactions in Table 4-1 where at least one of the resulting impacts is potentially

significant, these interactions have been taken forward for assessment, using the significance

evaluation methodology described in Section 4.3 below.

4.3 Environmental Significance

Overview

The decision process related to defining whether or not a project is likely to significantly impact

on the environment is the core principle of the EIA process; the methods used for identifying

and assessing potential impacts should be transparent and verifiable.

The method presented here has been developed by reference to the Institute of Ecology and

Environmental Management (IEEM) guidelines for marine impact assessment (IEEM, 2010),

the Marine Life Information Network (MarLIN) species and ecosystem sensitivities guidelines

(Tyler-Walters et al., 2001), guidance provided by Scottish Natural Heritage (SNH) in their

handbook on EIA (SNH, 2013) and by The Institute of Environmental Management and

Assessment (IEMA) in their guidelines for EIA (IEMA, 2016).

The EIA provides an assessment of the environmental effects that may result from a project’s

impact on the receiving environment. The terms impact and effect have different definitions

in EIA and one drives the other. Impacts are defined as the changes resulting from an action,

and effects are defined as the consequences of those impacts.

In general, impacts are specific, measurable changes in the receiving environment (volume,

time and/or area); for example, were a number of marine mammals to be disturbed following

exposure to vessel noise emissions. Effects (the consequences of those impacts) consider the

response of a receptor to an impact; for example, the effect of the marine mammal/noise impact

example given above might be exclusion from an area caused by disturbance, leading to a

population decline. The relationship between impacts and effects is not always so

straightforward; for example, a secondary effect may result in both a direct and indirect impact

on a single receptor. There may also be circumstances where a receptor is not sensitive to a

particular impact and thus there will be no significant effects/consequences.

For each impact, the assessment identifies a receptor’s sensitivity and vulnerability to that

effect and implements a systematic approach to understand the level of impact. The process

considers the following:

• Identification of receptor and impact (including duration, timing and nature of impact);

• Definition of sensitivity, vulnerability and value of receptor;

• Definition of magnitude and likelihood of impact; and

• Assessment of consequence of the impact on the receptor, considering the probability

that it will occur, the spatial and temporal extent and the importance of the impact. If

the assessment of consequence of impact is determined as moderate or major, it is

considered a significant impact.

Once the consequence of a potential impact has been assessed it is possible to identify measures

that can be taken to mitigate impacts through engineering decisions or execution of the project.



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This process also identifies aspects of the project that may require monitoring, such as a post-

decommissioning survey at the completion of the works to inform inspection reports.

For some impacts significance criteria are standard or numerically based. For others, for which

no applicable limits, standards or guideline values exist, a more qualitative approach is

required. This involves assessing significance using professional judgement.

Despite the assessment of impact significance being a subjective process, a defined

methodology has been used to make the assessment as objective as possible and consistent

across different topics. The assessment process is summarised below. The terms and criteria

associated with the impact assessment process are described and defined; details on how these

are combined to assess consequence and impact significance are then provided.

Baseline characterisation and receptor identification

In order to make an assessment of potential impacts on the environment it was necessary to

firstly characterise the different aspects of the environment that could potentially be affected

(the baseline environment). The baseline environment has been described in Section 1 and is

based on desk studies combined with additional site-specific surveys where required.

Information obtained through consultation with key stakeholders was also used to help

characterise specific aspects of the environment in more detail.

Where data gaps and uncertainties remained (e.g. where there are no suitable options for filling

data gaps), as part of the EIA process these have been documented and taken into consideration

as appropriate as part of the assessment of impact significance.

The EIA process requires identification of the potential receptors that could be affected by the

Project (e.g. marine mammals, seabed species and habitats). High level receptors are identified

within the impact assessments.

Impact definition

4.3.3.1 Impact magnitude

Determination of impact magnitude requires consideration of a range of key impact criteria

including:

• Nature of impact, whether it be beneficial or adverse;

• Type of impact, be it direct or indirect etc.;

• Size and scale of impact, i.e. the geographical area;

• Duration over which the impact is likely to occur i.e. days, weeks;

• Seasonality of impact, i.e. is the impact expected to occur all year or during specific

times of the year e.g. summer; and

• Frequency of impact, i.e. how often the impact is expected to occur.

Each of these variables are expanded upon in Table 4-2 to Table 4-6 to provide consistent

definitions across all EIA topics. In each impact assessment, these terms are used in the

assessment summary table to summarise the impact and are enlarged upon as necessary in any



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supporting text. With respect to the nature of the impact (Table 4-), it should be noted that all

impacts discussed in this ES are adverse unless explicitly stated.

Table 4-2 Nature of impact

Nature of impact Definition

Beneficial Advantageous or positive effect to a receptor (i.e. an improvement).

Adverse Detrimental or negative effect to a receptor.

Table 4-3 Type of impact

Type of

impact

Definition

Direct Impacts that result from a direct interaction between the Project and the receptor.

Impacts that are actually caused by the introduction of Project activities into the

receiving environment.

E.g. The direct loss of benthic habitat.

Indirect Reasonably foreseeable impacts that are caused by the interactions of the Project,

but which occur later in time than the original, or at a further distance from the

proposed Project location. Indirect impacts include impacts that may be referred

to as ‘secondary’, ‘related’ or ‘induced’.

E.g. The direct loss of benthic habitat could have an indirect or secondary impact

on by-catch of non-target species due to displacement of these species caused by

loss of habitat.

Cumulative Impacts that act together with other impacts (including those from any concurrent

or planned future third-party activities) to affect the same receptors as the proposed

Project. Definition encompasses “in-combination” impacts.

Table 4-4 Duration of impact

Duration Definition

Short term Impacts that are predicted to last for a short duration (e.g. less than one year).

Temporary Impacts that are predicted to last a limited period (e.g. a few years). For example,

impacts that occur during the decommissioning activities and which do not extend

beyond the main activity period for the works or which, due to the timescale for

mitigation, reinstatement or natural recovery, continue for only a limited time beyond

completion of the anticipated activity

Prolonged Impacts that may, although not necessarily, commence during the main phase of the

decommissioning activity and which continue through the monitoring and

maintenance, but which will eventually cease.

Permanent Impacts that are predicted to cause a permanent, irreversible change.



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Table 4-5 Frequency of impact

Frequency Description

Continuous Impacts that occur continuously or frequently.

Intermittent Impacts that are occasional or occur only under a specific set of circumstances

that occurs several times during the course of the Project. This definition also

covers such impacts that occur on a planned or unplanned basis and those that

may be described as ‘periodic’ impacts.

Table 4-6 Geographical extent of impact

Geographical

extent Description

Local Impacts that are limited to the area surrounding the proposed Project

footprint and associated working areas. Alternatively, where appropriate,

impacts that are restricted to a single habitat or biotope or community.

Regional Impacts that are experienced beyond the local area to the wider region, as

determined by habitat/ecosystem extent.

National Impacts that affect nationally important receptors or protected areas, or

which have consequences at a national level. This extent may refer to

either Scotland or the UK depending on the context.

Transboundary Impacts that could be experienced by neighbouring national administrative

areas.

International Impacts that affect areas protected by international conventions, European

and internationally designated areas or internationally important

populations of key receptors (e.g. birds, marine mammals).

4.3.3.2 Impact Magnitude Criteria

Overall impact magnitude requires consideration of all impact parameters described above.

Based on these parameters, magnitude can be assigned following the criteria outlined in Table

4-7. The resulting effect on the receptor is considered under vulnerability and is an evaluation

based on scientific judgement.

Table 4-7 Impact magnitude criteria

Magnitude Criteria

Major Extent of change: Impact occurs over a large scale or spatial geographical extent

and /or is long term or permanent in nature.

Frequency/intensity of impact: high frequency (occurring repeatedly or

continuously for a long period of time) and/or at high intensity.



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Magnitude Criteria

Moderate Extent of change: Impact occurs over a local to medium scale/spatial extent

and/or has a prolonged duration.

Frequency intensity of impact: medium to high frequency (occurring repeatedly

or continuously for a moderate length of time) and/or at moderate intensity or

occurring occasionally/intermittently for short periods of time but at a moderate

to high intensity.

Minor Extent of change: Impact occurs on-site or is localised in scale/spatial extent and

is of a temporary or short-term duration.

Frequency/intensity of impact: low frequency (occurring

occasionally/intermittently for short periods of time) and/or at low intensity.

Negligible Extent of change: Impact is highly localised and very short term in nature (e.g.

days/ few weeks only).

Positive An enhancement of some ecosystem or population parameter.

Notes: Magnitude of an impact is based on a variety of parameters. Definitions provided above are

for guidance only and may not be appropriate for all impacts. For example, an impact may occur in

a very localised area (minor to moderate) but at very high frequency/intensity for a long period of

time (major). In such cases informed judgement is used to determine the most appropriate magnitude

ranking and this is explained through the narrative of the assessment.

4.3.3.3 Impact likelihood for unplanned and accidental events

The likelihood of an impact occurring for unplanned/accidental events is another factor that is

considered in this impact assessment (Table 4-8). This captures the probability that the

impact will occur and also the probability that the receptor will be present and is generally

based on knowledge of the receptor and experienced professional judgement. Consideration

of likelihood is described in the impact characterisation text and used to provide context to

the specific impact being assessed in topic specific chapters as required.



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Table 4-8 Probability of accidental events occurring

Likelihood category Accidental event probability

5

Likely

More than once per year

Event likely to occur more than once on the facility

4

Possible

One in 10 years

Could occur within the life time of the Project

3

Unlikely

One in 100 years

Event could occur within life time of 10 similar facilities. Has occurred at

similar facilities.

2

Remote

One in 1,000 years

Similar event has occurred somewhere in industry or similar industry but

not likely to occur with current practices and procedures.

1

Extremely remote

One in 10,000 years

Has never occurred within industry or similar industry but theoretically

possible.

Receptor definition

4.3.4.1 Overview

As part of the assessment of impact significance it is necessary to differentiate between receptor

sensitivity, vulnerability and value. The sensitivity of a receptor is defined as ‘the degree to

which a receptor is affected by an impact’ and is a generic assessment based on factual

information whereas an assessment of vulnerability, which is defined as ‘the degree to which

a receptor can or cannot cope with an adverse impact’ is based on professional judgement

taking into account an number of factors, including the previously assigned receptor sensitivity

and impact magnitude, as well as other factors such as known population status or condition,

distribution and abundance.

4.3.4.2 Receptor sensitivity

Example definitions for assessing the sensitivity of a receptor are provided in Table 4-9.



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Table 4-9 Sensitivity of receptor

Receptor

sensitivity Definition

Very high Receptor with no capacity to accommodate a particular effect and no ability

to recover or adapt.

High Receptor with very low capacity to accommodate a particular effect with low

ability to recover or adapt.

Medium Receptor with low capacity to accommodate a particular effect with low

ability to recover or adapt.

Low Receptor has some tolerance to accommodate a particular effect or will be able

to recover or adapt.

Negligible Receptor is generally tolerant and can accommodate a particular effect without

the need to recover or adapt.

4.3.4.3 Receptor vulnerability

Information on both receptor sensitivity and impact magnitude is required to be able to

determine receptor vulnerability as per Table 4-10.

Table 4-10 Vulnerability of receptor

Receptor

vulnerability Definition

Very high The impact will have a permanent effect on the behaviour or condition on a

receptor such that the character, composition or attributes of the baseline, receptor

population or functioning of a system will be permanently changed.

High The impact will have a prolonged or extensive temporary effect on the behaviour

or condition on a receptor resulting in long term or prolonged alteration in the

character, composition or attributes of the baseline, receptor population or

functioning of a system.

Medium The impact will have a short-term effect on the behaviour or condition on a

receptor such that the character, composition, or attributes of the baseline,

receptor population or functioning of a system will either be partially changed

post development or experience extensive temporary change.

Low Impact is not likely to affect long term function of system or status of population.

There will be no noticeable long-term effects above the level of natural variation

experience in the area.

Negligible Changes to baseline conditions, receptor population of functioning of a system

will be imperceptible.

It is important to note that the above approach to assessing sensitivity/vulnerability is not

appropriate in all circumstances and in some instances professional judgement has been used



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in determining sensitivity. In some instances, it has also been necessary to take a precautionary

approach where stakeholder concern exists with regard to a particular receptor. Where this is

the case, this is detailed in the relevant impact assessment in Section 5.

4.3.4.4 Receptor value

The value or importance of a receptor is based on a pre-defined judgement based on legislative

requirements, guidance or policy. Where these may be absent, it is necessary to make an

informed judgement on receptor value based on perceived views of key stakeholders and

specialists. Examples of receptor value definitions are provided in Table 4-11.

Table 4-11 Receptor value

Value of

receptor

Definition

Very high Receptor of international importance (e.g. United Nations Educational,

Scientific and Cultural Organisation (UNESCO) World Heritage Site (WHS)).

Receptor of very high importance or rarity, such as those designated under

international legislation (e.g. EU Habitats Directive) or those that are

internationally recognised as globally threatened (e.g. IUCN red list).

Receptor has little flexibility or capability to utilise alternative area.

Best known or only example and/or significant potential to contribute to

knowledge and understanding and/or outreach.

High Receptor of national importance (e.g. NCMPA, MCZ).

Receptor of high importance or rarity, such as those which are designated under

national legislation, and/or ecological receptors such as United Kingdom

Biodiversity Action Plan (UKBAP) priority species with nationally important

populations in the study area, and species that are near-threatened or vulnerable

on the IUCN red list.

Receptor provides the majority of income from the Project area.

Above average example and/or high potential to contribute to knowledge and

understanding and/or outreach.

Medium Receptor of regional importance.

Receptor of moderate value or regional importance, and/or ecological receptors

listed as of least concern on the IUCN red list, but which form qualifying

interests on internationally designated sites, or which are present in

internationally important numbers.

Any receptor which is active in the Project area and utilises it for up to half of

its annual income/activities.

Average example and/or moderate potential to contribute to knowledge and




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Value of

receptor

Definition

Low Receptor of local importance.

Receptor of low local importance and/or ecological receptors such as species

which contribute to a national site, are present in regionally.

Any receptor which is active in the Project area and reliant upon it for some

income/activities.

Below average example and/or low potential to contribute to knowledge and


Negligible Receptor of very low importance, no specific value or concern.

Receptor of very low importance, such as those which are generally abundant

around the UK with no specific value or conservation concern.

Receptor of very low importance and activity generally abundant in other areas/

not typically present in the Project area.

Poor example and/or little or no potential to contribute to knowledge and


Consequence and significance of potential impact

4.3.5.1 Overview

Having determined impact magnitude and the sensitivity, vulnerability and value of the

receptor, it is then necessary to evaluate impact significance. This involves:

• Determination of impact consequence based on a consideration of sensitivity,

vulnerability and value of the receptor and impact magnitude;

• Assessment of impact significance based on assessment consequence;

• Mitigation; and

• Residual impacts.

4.3.5.2 Assessment of consequence and impact significance

The sensitivity, vulnerability and value of receptor are combined with magnitude (and

likelihood, where appropriate) of impact using informed judgement to arrive at a consequence

for each impact, as shown in Table 4-12. The significance of impact is derived directly from

the assigned consequence ranking.

Table 4-12 Assessment of consequence

Assessment

consequence

Description (consideration of receptor sensitivity and value

and impact magnitude)

Impact

significance

Major Impacts are likely to be highly noticeable and have long term

effects, or permanently alter the character of the baseline and are

likely to disrupt the function and status/value of the receptor

population. They may have broader systemic consequences (e.g.

Significant



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Assessment

consequence

Description (consideration of receptor sensitivity and value

and impact magnitude)

Impact

significance

to the wider ecosystem or industry). These impacts are a priority

for mitigation in order to avoid or reduce the anticipated effects of

the impact.

Moderate Impacts are likely to be noticeable and result in prolonged changes

to the character of the baseline and may cause hardship to, or

degradation of, the receptor population, although the overall

function and value of the baseline/ receptor population is not

disrupted. Such impacts are a priority for mitigation in order to

avoid or reduce the anticipated effects of the impact.

Significant

Low Impacts are expected to comprise noticeable changes to baseline

conditions, beyond natural variation, but are not expected to cause

long term degradation, hardship, or impair the function and value

of the receptor. However, such impacts may be of interest to

stakeholders and/or represent a contentious issue during the

decision-making process, and should therefore be avoided or

mitigated as far as reasonably practicable

Not significant

Negligible Impacts are expected to be either indistinguishable from the

baseline or within the natural level of variation. These impacts do

not require mitigation and are not anticipated to be a stakeholder

concern and/or a potentially contentious issue in the decision-

making process.

Not significant

Positive Impacts are expected to have a positive benefit or enhancement.

These impacts do not require mitigation and are not anticipated to

be a stakeholder concern and/or a potentially contentious issue in

the decision-making process.

Not significant

4.3.5.3 Mitigation

Where potentially significant impacts (i.e. those ranked as being of moderate impact level or

higher in Table 4-12) are identified, mitigation measures must be considered. The intention is

that such measures should remove, reduce or manage the impacts to a point where the resulting

residual significance is at an acceptable or insignificant level. For impacts that are deemed not

significant (i.e. low, negligible or positive in Table 4-12), there is no requirement to adopt

specific mitigation. However, mitigation can be adopted in such cases to ensure impacts that

are predicted to be not significant remain so. Section 6 provides detail on how any mitigation

measures identified during the impact assessment will be managed.

Residual impacts

Residual impacts are those that remain once all options for removing, reducing or managing

potentially significant impacts (i.e. all mitigation) have been taken into account.



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4.4 Cumulative and In-Combination Impact Assessment

The European Commission has defined cumulative impact as being those resulting “from

incremental changes caused by other past, present or reasonably foreseeable actions together

with the project” (European Commission, 1999). As outlined in studies by the European

Commission (1999) and US CEQ (1997), identifying the cumulative impacts of a project

involves:

• Considering the activities associated with the project;

• Identifying potentially sensitive receptors/resources;

• Identifying the geographic and time boundaries of the cumulative impact assessment;

• Identifying past, present and future actions which may also impact the sensitive

receptors/resources;

• Identifying impacts arising from the proposed activities; and

• Identifying which impacts on these resources are important from a cumulative impacts

perspective.

To assist the assessment of cumulative and in-combination impacts, a review of existing

developments (including oil and gas, cables and renewables) that could have the potential to

interact with the Project was undertaken; the output of this review is reported in the

Environment Description (Section 3). The impact assessment has considered these projects

when defining the potential for cumulative and in-combination impact (Section 5). This

includes, where appropriate, reference to existing fields producing through the Bleo Holm

FPSO.

4.5 Transboundary Impact Assessment

The impact assessment presented in Section 5 contains sections which identify the potential

for, and where appropriate, assessment of transboundary impacts. For the Liberator Field

Development, this is less of an issue than for some North Sea developments, considering that

it lies 170 km from the UK/Norway median line.

4.6 Habitats Regulation Appraisal (HRA)

Under Article 6.3 of the Habitats Directive, it is the responsibility of the Competent Authority

to make an Appropriate Assessment of the implications of a plan, programme or in this case

project, alone or in combination, on a Natura site (SAC or SPA) in view of the site’s

conservation objectives and the overall integrity of the site.

As part of the assessment of impacts on key receptors, for those receptors that are a qualifying

feature of a Natura site, relevant information on SACs or SPAs has also been provided as part

of the impact assessment process. This information will then be used by the Competent

Authority to determine the need for, and subsequently carry out (if required), an appropriate

assessment of the Project.

For offshore areas (12 – 200 nm) the requirements of the Habitats Directive are transposed

through the Offshore Marine Conservation Natural Habitats Regulations (2001) as amended.



126

In accordance with these Regulations, the impacts of a project on the integrity of a European

site are assessed and evaluated as part of the HRA process. In an analogous process, the Marine

(Scotland) Act and the Marine and Coastal Access Act require the potential for significant risk

to the conservation objectives of NCMPAs and MCZs (respectively) being achieved to be

assessed.

4.7 Data Gaps and Uncertainties

Baseline data

The North Sea has been extensively studied, meaning that this EIA has been able to draw on a

significant volume of published data. This bank of published data has been supplemented by

a site survey studies that have previously been undertaken within the Project area.

Additionally, i3 Energy has commissioned specific site-survey work to confirm the existing

understanding of the environmental baseline. This survey campaign, which will cover the

environmental baseline and habitat assessment, is due in Q1 2019, with the result and a

discussion on whether it aligns with previous results reported in the ES submitted in report

format to BEIS and other statutory consultees as soon as practicable. i3 recognise that this is

a current gap in the EIA, but it is not considered to compromise the robustness of the EIA itself.

i3 will make use of the information that has been collected in any permits applications that are

prepared following the survey results being reported.



127

5 Impact Assessment

5.1 Introduction

The key issues identified for assessment during the EIA process are detailed in Table 5-1. The

impact assessment for each of these topics is presented in the following sections. It is important

to note that many of the potential operational impacts associated with the Liberator Field

Development will be managed through the existing permits that the Bleo Holm FPSO currently

holds.

Table 5-1 Potential impacts to be assessed during the EIA process

Potential impact Description Section

Discharges to sea • Drill muds and cuttings, cementing, well completion

and clean-up and completion operations

• Discharge of chemicals during pipeline pre-

commissioning operations

• Subsea hydraulic control fluids

• Process chemical use and discharge

• Produced water disposal

• Potential introduction of alien species

5.2

Physical disturbance • Drilling rig anchors

• Disturbance of seabed during installation of pipelines,

trenching, rock placement etc

5.3

Underwater noise • Underwater noise from drilling, pipelay/installation and

operations 5.4

Physical presence • Installation vessels

• Drilling rig and mooring system

• Pipelines and subsea facilities

5.5

Atmospheric

emissions

• Additional combustion emissions from FPSO and

mobile units power generation,

• Well clean-up/test flaring and vessel operations

• Gas flaring and venting

5.6

Accidental events • Reservoir hydrocarbon spills

• Diesel spills 5.7

5.2 Discharges to Sea

Overview

Discharges to sea during the drilling phase of the Project will include mud, cuttings, cement

and wellbore completion and well test chemicals. Discharges due to installation of subsea

infrastructure will include chemicals used in pipeline flooding and cleaning, and installation

and commissioning of spools and the umbilical. Incremental discharges from the Bleo Holm



128

during production, resulting from the Liberator field will include produced water and process

chemicals.

The above discharges may lead to potential impacts on the seabed or water column through the

following mechanisms:

• Increased suspended solids in the water column;

• Settlement of cuttings and muds on the seabed; and

• Potential toxic impacts from hydrocarbons and chemical additives discharged.

Drilling discharges direct to seabed

As discussed in Section 2.5, it is likely that the three proposed production wells will be drilled

with WBM, using a closed mud system with all drilling muds and cuttings returned to rig and

discharged to sea from the rig with no discharge direct to seafloor. However as there is a

possibility that the two top hole sections will be drilled riserless with cuttings discharged direct

to the seabed around the well then this has been assessed below as worst case. There is a

possibility that LTOBM will be used for the 12¼ꞌꞌ section, but in this instance returned cuttings

would be skipped and shipped to shore and there would be no discharge of LTOBM cuttings

to sea. For the 8½ʺ reservoir section WBM will be used, returned to the rig, separated and the

cuttings discharged to sea, compliant with sampling and reporting requirements detailed in an

OPPC permit.

The appraisal well will be drilled wholly using WBM, again with the top two sections drilled

riserless with mud and cuttings discharged direct to seabed. As with the reservoir section of

the production wells, mud and cuttings from the 8½ʺ section will be returned to the rig,

separated and the cuttings discharged to sea under an OPPC permit.

The 30ʺ and 17½ʺ sections of the 3 production wells and the A3 appraisal well, drilled riserless,

will result in an estimated 550 tonnes of cuttings and 825 tonnes of mud for each well

discharged directly to the seabed. This will produce low mounds of cuttings surrounding the

conductor approximately 9-10 m in radius and 5m in height. The cumulative discharge direct

to seabed from all 4 wells will be 2,200 tonnes of cuttings and 3,300 tonnes of mud.

A small proportion of the cement used to secure the conductor and casings in place within the

wellbore will be discharged to the seabed during the proposed drilling operations. Most cement

will remain in the annulus between the casing and the rock formation, but some will be

discharged as excess cement is pumped which must reach the seabed and provides visual

confirmation that the cement job is complete. The cement discharged to the seabed will,

however, be confined to a small area within the immediate vicinity of the well and will not

extend beyond the area where the drill cuttings and muds are predicted to be deposited

Drilling muds and cement discharged directly to the seabed are expected to result in limited

water column sediment loading within a few metres of the top of the well bore.

The environmental effects of surface hole cuttings are similar to those of physical disturbance

of the seabed, discussed in Section 5.3, since the deposited material is similar to background

seabed sediments. The chemical formulation of WBM avoids or minimises the inclusion of



129

toxic components, and the materials used in greatest quantities (barite and bentonite) are of

negligible toxicity and biochemical oxygen demand (barium sulphate is of low bioavailability

and toxicity to benthic organisms). Toxic effects, when they occur, are likely to be caused by

sulphide and ammonia by-products of organic enrichment (DECC, 2016). Therefore, the

predicted effects predominantly relate to the smothering of benthic habitats and fauna and the

potential that changes in sediment particle size characteristics can affect the suitability of the

seabed for re-colonisation by species normally present.

Each cuttings pile will have an estimated footprint area of 314 m2 (based on a radius on 10 m),

so 1,256 m2 in total for the three production wells and appraisal well. The seabed sediments

in the Liberator area are classified as silty sand, with very sparse visible fauna consisting

mainly of Annelida and Cnidaria. The fauna and sediments are seen in the surveys as

consistent over the wider Liberator area. Given that each cuttings pile will have a limited

spatial footprint, fauna is sparse in the area, significant smothering impacts are not expected.

As sediments are not anticipated to be significantly contaminated, it is anticipated that the

benthic communities will begin to recover once the proposed drilling operations have ceased.

Recolonisation of the impacted area can take place in a number of ways, including mobile

species moving in from the edges of the area (immigration), juvenile recruitment from the

plankton or from burrowing species digging back to the surface. As the fauna seen in the

Liberator area is typical of the wider area, it is likely that inward movement of larvae and

juveniles from the same or similar species groups to replace any individuals lost during drilling

activities would be expected at a faster rate than if the project was disturbing habitat that was

unique to the footprint of the project.

Additionally, it has been predicted that any surface-hole cuttings piles in the central North Sea

area will be dispersed typically over a timescale of one to ten years, mainly through re-

suspension and bedload transport due to tidal and wave-induced currents (DTI, 2004).

A 1987 survey of 3 well sites in the central North Sea, drilled 5 years previously using WBM,

indicated that with the exception of a slightly elevated barium concentration, levels of sediment

metals and hydrocarbons were similar to background conditions. The analysis of the benthic

fauna indicated that, even at sites closest to the wellheads, full recovery of the impacted

sediments had taken place. In 2005, these well sites were revisited by Oil and Gas UK (formerly

UKOOA) and the results indicated that the area was completely consistent with background

conditions (Hartley Anderson Ltd, 2005).

The predicted effects are therefore localised and of short duration, involving smothering of

benthic habitats and fauna with relatively rapid recovery through faunal re-colonisation. The

dominant species in the Liberator area, are likely to be relatively resilient to the effects of

sediment mobilisation and to rapidly recolonise disturbed or displaced sediments. Beyond the

zone of physical smothering immediately around the wellhead, ecological effects of surface

hole cuttings discharge are predicted to be negligible.



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Drilling discharges from rig

Cuttings from drilling the 12¼ʺ and 8½ʺ sections for the production wells and just the 8½ʺ

section on the A3 appraisal well (drilled using WBM) will be discharged to sea from the rig.

This will total 450 tonnes for each production well (1,250 tonnes in total for the 3 wells) and

80 tonnes for the appraisal well. This material will consist of formation cuttings, a mixture of

clay and sand and siltstone rock fragments. There is potential that the 8½ʺ cuttings will have

some contamination from reservoir hydrocarbons and as per the requirement of the OPPC

regulations 2005 (as amended), a monitoring and sampling regime will be put in place to

quantify the amount of hydrocarbons discharged from rig alongside the cuttings.

As discussed above, four main types of environmental effect are possible following the

discharge of WBM and cuttings drilled with WBM:

• Plume formation and turbidity, mainly associated with clay and silt sized particles

which settle slowly through the water column;

• Settlement on the seabed, potentially causing physical smothering and changes to

substrate characteristics;

• Organic enrichment and subsequent oxygen depletion associated with enhanced aerobic

microbial activity in the surface sediments;

• Direct toxicity effects in the water column and affected seabed.

In general, none of the above have proved to be significant following extensive use and

discharge of WBM in the North Sea and elsewhere (e.g. Daan & Mulder 1993, 1996). A review

of 200 publications and reports by Neff (2005), suggested that the effects of WBM on benthic

communities are mainly caused by burial and low sediment oxygen concentrations resulting

from organic enrichment, rather than toxic effects.

Discharges from the rig topsides are likely to form a plume in the water column as discharged

material disperses out with the prevailing current, which is likely to change direction with the

tide several times over the discharge period. This is likely to result in a moderately large

volume of water experiencing an increased sediment load. Increased water sediment load may

cause interference with feeding, respiration and orientation of marine fauna. It may also cause

physical irritation by abrading protective mucous coatings and increase susceptibility to

parasites and infections.

Mobile fauna are likely to exhibit avoidance behaviour and avoid the sediment plume.

Plankton, which cannot effectively control its geographical location (although many species

undertake vertical migration) may be impacted by increased sediment loads, which may cause

behavioural change (lack of feeding) or even mortality in some individuals. This impact

however is not considered significant as the impact will be short-lived and on a small scale

when set against the large plankton population and available habitat in the wider area, and

naturally high mortality rates.

A number of fish species use the Liberator area for spawning and nursery grounds and are

therefore potentially sensitive to increased suspended sediment in the water column through

displacement and reduced visibility affecting foraging ability. However, the WBM discharged



131

from the rig will settle relatively rapidly and therefore any effect on suspended sediment

concentrations will be of very limited duration and mobile species would be expected to return

shortly after cessation of the discharge. Additionally, the species using the area for spawning

or nursery have a widespread distribution and are not restricted to the Liberator area for these

activities.

Dispersion of mud and cuttings is influenced by various factors, including particle size

distribution and density, vertical and horizontal turbulence, current flows, and water depth. The

WBM cuttings discharged at sea surface will separate into larger particles and flocculated

solids, representing about 90% of the mass of the solids (Neff, 2005), which will settle to the

seabed over a considerable distance dependent on hydrographic conditions and cuttings particle

characteristics; once deposited on the seabed they may be further re-suspended by wave or tidal

action, and mixed into surficial sediment through bioturbation (the activities of burrowing

fauna). Remaining fine-grained unflocculated clay-sized particles and a portion of the soluble

components of the mud will remain in suspension in the water column and disperse rapidly in

the receiving waters.

Effects of WBM and cuttings discharges on the bottom environment are related to the total

mass of drilling solids discharged and the relative energy of the water column and benthic

boundary layer at the discharge site. In low hydrodynamic energy environments such as the

central North Sea, significant amounts of mud and cuttings solids may accumulate on the sea

floor within a few hundred metres to several kilometres of the discharge. Where several wells

are drilled from one location (e.g. Liberator drill centre) the deposition of cuttings will be

cumulative.

Cuttings deposition modelling undertaken for the Blake Field Development (BG, 1999), ca.5

km to the east of the Liberator drill centre, showed that 5,960 tonnes of discharged cuttings

were deposited in an elliptical area, orientated roughly north-northwest to south-southeast

(Figure 5-1), consistent with the pattern of currents with the area. The bulk of the cuttings

were deposited in the immediate vicinity of the well location (100 - 500 m) with finer material

being carried to a greater distance (to 1,000 – 2,000 m). This general pattern of distribution

was confirmed by monitoring studies conducted by BG of the seabed sediment and fauna

around exploration well 13/24b-3. The thickness of the settled particles was >1 mm in depth

within 500 m of the discharge point, reducing to <0.1 mm within 1,000 m. The 1 mm threshold

is important as studies have shown the impacts on seabed fauna from smothering can occur

where the depth of cuttings is 1 mm or more (Bakke et al., 1986).

It is expected that 1,250 tonnes of WBM cuttings will be discharged from the Liberator drill

centre and 80 tonnes from the appraisal well location, under half that modelled for the Blake

development. It can therefore be expected that the impact from the Liberator wells will be

significantly smaller than that modelled for the Blake development. Basic modelling of cuttings

deposition from Liberator on the seabed, using a simple analytical model based on Stokes Law

equations for particle settling velocities, was done for cumulative discharges at the main drill

centre. This corroborated the above conclusion, suggesting that the majority of cuttings settled

within 300-500 m of the discharge point.



132

These predictions and the monitoring results are consistent with the results of previous studies

on the fate of drill cuttings in similar current regimes (e.g. Corralian, 2018).

Figure 5-1 Predicted deposition of cuttings from the Blake development on the seabed (BG, 1999)

Daan and Mulder (1993) looked at the possible environmental effects of discharges of WBM

cuttings from a single well site. The authors indicated that in the short term no adverse effects

on the benthic community were observed from the presence of the cuttings. A follow up study

was carried out a year later which also revealed no adverse effects on the benthic community,

and further indicated that there was no change to the sediment characteristics after one metre

from the discharge point. The lack of significant changes due to drilling cuttings deposition has

also been reported from other studies (e.g. Hartley, 1996; Kingston, 1992), which indicate that

where measurable benthic impacts have occurred from WBM discharges, they are typically

restricted to within a radius of 50 – 100 m of the well site.

A survey of the Blake drill centre area in 2017 (MG3, 2017) showed that the area is dominated

by the sand fraction (70-78%), whilst the < 63µm fraction (silt and clays) only makes up 22-

30%. This is a similar composition to that found during the Blake pre-development survey in

1999 (BG, 1999) and Liberator 2013 survey (Gardline, 2013), which overlapped the area,



133

suggesting that any drilling muds deposited during the Blake development have largely been

dispersed in the intervening time period.

The 2013 and 2017 Liberator and Blake surveys both show that the sediments of the area

generally have hydrocarbon concentrations consistent with uncontaminated sediments. The

reduced potential for contaminants to remain in the Liberator area sediments is likely a function

of the dominance of sand in the area. Contaminants are more likely to be retained and adsorbed

into fines (<63 µm) and in the Liberator area fine sediments are preferentially transported by

the local hydrodynamic regime. This suggests that any contaminants deposited in drilling muds

from the Liberator development will be dispersed and will not persist for long periods within

the sediments.

Faunal burrows and sparse megafauna were identified in the 2013 and 2017 Liberator surveys.

Although Nephrops burrows were identified, the species is considered to be tolerant of

smothering by up to 5 cm of sediment due to the complexity and length of its tunnels (Sabatini

& Hill, 2008). It is however more sensitive to heavy metal and potentially hydrocarbon

contamination, although any such contamination from the Liberator drilling muds is likely to

be very small and not settle in high concentrations in the surrounding sediments.

Chemical discharges

Chemicals will be required to clean up and complete the well once drilling is complete. These

clean up fluids will be returned to the drilling rig and will potentially be contaminated with

reservoir fluids and drilling mud. Material returned from the well during wellbore clean-up and

completion will be processed on the drilling rig to ensure that only liquids that contain less

than 30 mg/l oil in water are being discharged overboard.

The majority of chemicals selected for well completion and clean-up operations will be either

ranked as Gold or E, indicating that discharge of these chemicals would not lead to significant

environmental effects in the marine environment. A number of chemicals may also be

PLONOR listed. A variety of contingency and emergency chemical additives will be available

on the rig to deal with unplanned circumstances, such as excessive fluid loss from the hole,

stuck pipe etc. The discharge of these chemicals is not intended but may be necessary; in which

case significant effects are not predicted in view of the limited quantities, generally low Hazard

Quotients and high dispersion.

Following installation of the pipelines, they and their subsea equipment will be cleaned,

strength and leak tested using treated seawater. The seawater will be inhibited with oxygen

scavenger, corrosion inhibitor and biocides to prevent corrosion or fouling growth in the

pipelines and a dye to enable leaks to be detected. It is expected that the gas lift pipeline will

be dried using an 80/20% MEG/water mix, with discharge to sea, followed by nitrogen

displacement of the MEG/water mix into the production system. Exact quantities will be

detailed in the chemical permit for the subsea operations, but it will be in the order of 110 m3.

The production pipeline may be dewatered during the commissioning phase using produced

oil and possibly Mono-ethylene glycol (MEG) slugs, with discharge either through the FPSO



134

produced water system or subsea at the wells end. Again, exact quantities have yet to be

defined but would be in order of 420 m3.

All chemicals selected and used will have been registered with the Offshore Chemical

Notification Scheme (OCNS system) and chemicals of low toxicity and bioaccumulation

potential, and without substitution or other warnings, will be preferentially selected. Dosing

concentrations are designed to be in slight excess, resulting in minimal potential effect of

residual chemicals (e.g. the majority of oxygen scavenger will react with oxygen in the treated

seawater so that de-oxygenation of receiving waters following discharge will be negligible).

All chemicals will be further assessed during detailed design and a term permit application for

the use and discharge of chemicals is required by The Offshore Chemicals Regulations 2002

(as amended) and will be submitted to BEIS in advance of the commencement of drilling and

subsea activities.

Routine chemical use and discharge during field operation will involve small amounts of

hydraulic fluid, Pelagic 100 which is an E rated chemical under OCNS, for valve operation.

These discharges are expected to be on an extremely small scale (0.2 kg per valve opening)

and dilution, dispersion and biodegradation of the released hydraulic fluid will be rapid. Hydraulic

fluid consumption will be regularly monitored in order to identify potential leaks and instigate

remedial measures and therefore is not expected to have a significant impact.

A review of expected chemical use for the Liberator field during operations has highlighted

that the main requirements will include demulsifiers, antifoam, scale inhibitor, wax inhibitor

and wellhead corrosion inhibitor. All these products are already in use on the Bleo Holm (with

the exception of the wax inhibitor) and have been environmentally risk assessed and are rated

either gold or E (PLONOR), the lowest Hazard quotient under OCNS (Table 2-12). Although

four of the chemicals have substitution warnings, work is ongoing at the chemical suppliers to

find viable alternatives and substitutions will be made as soon as practicable. Incremental

increases in chemical use and discharge, taking into consideration the shut in of Ross

production and start-up of Liberator production, will be detailed and managed via the existing

RSRUK Bleo Holm production chemical permit (CP/170).

The potential for toxic impacts on water column receptors from drilling, installation and

operational discharge depends on many factors including the sensitivity of the receptor

organism (which can vary widely between species), the toxicity of the chemicals used, the

concentration of the chemicals and hydrocarbons in the discharge stream and the duration of

the discharge. The biota in the Liberator field is not expected to be particularly sensitive to

chemical or hydrocarbon discharges. Chemicals identified for use at the Liberator field will

be selected for their low toxicity wherever possible. Fluids and associated chemicals returned

from the wellbores and flushed from the pipelines will be treated on the rig and FPSO topsides

to ensure the oil in water concentration is <30 mg/l prior to discharge, and this treatment will

tend to remove oil-based chemicals. The chemicals that are eventually discharged will be

rapidly diluted in the water column. Bakke et al. (2013) suggests that the majority of effects

observed from the release of drilling muds is physical stress, although chemical toxicity cannot

be ruled out. Effects are expected to be restricted to a radius of 1 – 2 km from the discharge



135

point (Bakke et al., 2013). Chemical use and discharge will be permitted under the Offshore

Chemical Regulations, and the permitting process will require an individual risk assessment

for each chemical prior to discharge.

Produced water discharge

Operational discharges of produced water occur as part of the current Bleo Holm process, under

the facility’s OPPC permit. Liberator production will contribute additional produced water to

the onboard process facilities, which will be comingled with Blake produced water in the Bleo

Holm slops tanks prior to overboard discharge.

Treated produced water may contain residues of reservoir hydrocarbons, dissolved organic and

inorganic compounds and chemicals added during the production process. The types of

chemicals are discussed in Section 5.2.4 above. Whilst the produced water treatment system

is designed to remove most of these residues, some will persist within the produced water

discharged overboard. Currently produced water discharged to sea from the Bleo Holm has a

typical monthly average oil-in-water (OIW) concentration of around 30 mg/l (Table 2-13).

Table 5-2 Estimated Liberator Field Development oil quantity discharged via produced water stream

Year

Overboard discharge of produced water

(m3/year)

Estimated oil discharge (tonnes/year)

assuming 30 mg/l oil in water

concentration

High Oil and Gas

Production Case

Low Oil and Gas

Production Case

High Oil and Gas

Production Case

Low Oil and Gas

Production Case

2020 1,453 24,166 0.04 0.72

2021 99,651 205,729 2.99 6.17

2022 187,588 237,066 5.63 7.11

2023 225,408 241,625 6.76 7.25

2024 233,099 236,418 6.99 7.09

2025 237,056 237,065 7.11 7.11

2026 237,066 237,066 7.11 7.11

2027 237,066 237,066 7.11 7.11

2028 240,965 240,965 7.23 7.23

2029 109,415 240,965 3.28 7.23

Figure 2-13 in Section 2.8.1 show the projected incremental increase in produced water

discharge to sea from the Bleo Holm once the Liberator Field is on stream and Table 5-2 shows

the high and low case Liberator water profiles and associated oil discharge. The low case

production forecast has the greatest produced water values and therefore is assessed here as

worst case. Compared to 2017 (the baseline data year) this represents an annual increase of 2

- 23% for 2020-2024 based on the low case. This equates to an additional discharge of between

0.72 and 7.09 tonnes/yr of oil, based on a 30 mg/l oil in water concentration. It should be noted

that the 2017 produced water figures and those for 2020-2024 shown in Figure 2-13 include

both Ross and Blake combined, whereas Ross production will cease in 2020 and therefore the

total produced water volume, and increase due to Liberator, will also decrease. Post 2024 the



136

predicted volumes of produced water discharge remain reasonably constant, with between 7.11

and 7.23 tonnes of oil discharged per year.

This small increase in produced water volumes are not expected to affect the performance of

the Bleo Holm produced water treatment facilities or their ability to meet best BAT or BEP, as

detailed in the Bleo Holm OPPC permit.

This is a very small increase compared to the 143 million m3 of produced water discharged to

sea in 2017 from UKCS oil and gas installations (Oil & Gas UK, 2018). The additional oil

discharged to sea with Liberator produced water would account for 0.03 – 0.3% of the 2,140

tonnes of oil discharged to sea from all UKCS installations in 2017.

The potential for toxic impacts on water column receptors from operational discharge

(including produced water discharges) depends on many factors including the sensitivity of the

receptor organism (which can vary widely between species), the toxicity of the chemicals used,

the concentration of the chemicals and hydrocarbons in the discharge stream and the duration

of the discharge. Most studies of produced water toxicity and dispersion, have concluded that

the necessary dilution to achieve a No Effect Concentration (NEC) would be reached at <10 to

100 m, and usually less than 500 m from the discharge point (IOGP, 1994; OLF, 1998; Riddle

et al., 2001; Berry & Wells, 2004).

Plankton abundance is influenced strongly by the physical environment and variables such as

water temperature, current velocity, stratification in the water column, and nutrient

concentration. As a result, they are particularly vulnerable to discharges and spills of chemicals

and hydrocarbons. Plankton may be exposed to these contaminants through passive diffusion,

active uptake, or through eating contaminated prey. As plankton spend most of their lives in

the water column, they will be exposed to those contaminants that remain in solution (Sheahan

et al., 2001). Produced water can affect recruitment in calanoid copepods (Hay et al., 1988),

with lowered fecundity and increased offspring mortality reported for some plankton, as

outcomes of hydrocarbon contamination (van Beusekom & Diel-Christiansen, 1993).

Strømgren et al. (1995) found that acute toxicity in the diatom Skeletonema spp. was only likely

in individuals in the immediate vicinity of the source of produced water, where concentrations

of contaminants are highest.

The OSPAR (2010) Quality Status Report (QSR) noted that water column monitoring to

determine possible effects from polycyclic aromatic hydrocarbons (PAHs) and other chemicals

such as alkyl phenols discharged with produced water has been carried out to a limited extent

in the OSPAR area. Monitoring with caged mussels in the Netherlands and Norwegian sectors

of the North Sea has shown that mussels exposed to produced water discharges may accumulate

PAH and show biological responses up to 1,000 m from the discharge. Concentrations of PAHs

and alkyl phenols and measured biological responses in wild fish such as cod and haddock

caught in the vicinity of offshore installations from Norwegian waters in 2002 and 2005

showed a mixed pattern mostly with no increased concentrations, but some elevated biological

responses suggesting past exposure. Exposure of cod sperm cells to environmentally relevant

concentrations (100, 200, 500 ppm) of produced water from the Hibernia platform,



137

Newfoundland, did not result in a strong toxicity to the cells (only subtle changes were

observed) or a significant change in fertilisation rate (Hamoutene et al., 2010).

Bakke et al. (2013) reviewed recent research on the biological effects of offshore produced

water (and drill cuttings) discharges, with focus on Norwegian waters. Produced water

discharges are a continuous source of contaminants to continental shelf ecosystems, and

alkylphenols and PAH were found to accumulate in cod and mussels caged near the discharge

points, but these compounds are rapidly metabolized in cod. Such compounds may affect

reproductive functions, and various chemical, biochemical and genetic biomarkers, but Bakke

et al. (2013) concluded that the risk of widespread impact from such operational discharges is

low.

The minor increase in produced water discharge from the Bleo Holm resulting from the

Liberator development is not predicted to result in a significant spatial area of effect. As a result

any impact on biota will be very localised, probably within the 500 m safety zone area. It can

therefore be concluded that they will have no significant impact. As required by The Offshore

Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 (as amended),

a variation to the Bleo Holm OPPC permit will be applied for in advance of operations.

Alien species

Ballast water is likely to represent the main route by which non-native species could potentially

be introduced to the Liberator area. The majority of vessels to be used are already operating in

NW Europe and though they could serve to spread species, are unlikely to be a source of exotic

species introductions. Adherence to ballast water guidance will mitigate the likelihood of

species introductions.

Mitigation

A number of management and mitigation measures will be adopted by i3 to reduce, where

possible, the potential impacts of Project discharges to sea:

• Maximise efficient use and recovery of drilling mud;

• No discharge of LTOBM or LTOBM contaminated cuttings to sea;

• A rig audit will be conducted to ensure rig is in compliance with all relevant guidelines

and legislation;

• Environmental risk assessment as part of Offshore Chemical Regulations approval

process, and identification of measures to reduce risk including chemical selection

procedures, will be carried out to obtain approval for chemical use prior to operations

commencing;

• Oil in water discharge will be within the existing permitted limits for the Bleo Holm

FPSO.

Seasonal sensitivities of potential receptors are not considered to be sufficiently variable to

mean seasonal mitigation commitments are of value.



138

Cumulative and in-combination impact assessment

Discharges to sea during the Project will occur intermittently and will be short-term. Drilling

discharges will occur in Q3/Q4 2019, Q2 2020, and Q2 2021, and subsea infrastructure

installation and commissioning discharges will occur in Q2 2020. The limited quantities of

material discharged, the intermittent nature of the discharge and the proposed mitigation

measures are likely to limit the potential impacts.

Although there is no confirmation at the time of writing, there may be other well drilling

programmes or field development activities planned for the same period as the Liberator Field

Development. Given the limited impact expected from the Liberator Field Development, the

development will not contribute significantly to cumulative impacts associated with discharges

to sea from other projects.

There are a number of other producing oil and gas fields within and close to the North Sea area

in which Liberator sits, and some of these will be discharging chemicals and hydrocarbons to

sea via produced water discharge; this includes fields producing through the Bleo Holm FPSO.

The extremely limited additional chemical and hydrocarbon discharge expected as a result of

production from the Liberator field coming online means that cumulative impacts with other

existing developments is not expected.

Transboundary impact assessment

The Liberator field is located 174 km away from the closest (UK/Norway) transboundary line.

Given the limited impacts expected, it is extremely unlikely that there will be any

transboundary impact from the proposed operations.

Decommissioning

There will be limited potential for decommissioning activities to negatively impact the marine

environment through discharges to sea. It is possible that there may be some re-suspension of

deposited cuttings during the removal of wellhead infrastructure, but recovery and re-

colonisation would be expected to occur rapidly. The mitigation measures described in this

chapter with respect to selection and optimisation of chemical use will also apply to the

decommissioning process and chemical risk assessments will be conducted in line with the

applicable regulations at the time.

Considering the above, the potential impacts from decommissioning are thus likely to be no

greater in magnitude to those experienced during drilling and installation and thus not

significant.

Protected sites

The conclusions on the impacts presented in this chapter have taken account of protected sites

as relevant. It is important to note, however, that discharges associated with the Liberator Field

Development will not occur within any SAC, SPA, NCMPA or MCZ. It is considered unlikely,

given the small scale of the proposed development, that the discharges will spread far enough

to interact with any protected or proposed protected areas, the closest of which is the proposed

Southern Trench MPA located 37 km away. As such, there is considered to be no Likely



139

Significant Effect on SACs, SPAs, NCMPAs and MCZs and hence no impact on any

conservation objectives or site integrity.

Residual impact

Receptor Sensitivity Vulnerability Value Magnitude

Biological

features of the

water column,

seabed and

benthos

Low Low Low Minor

Rationale

The information in the Environment Description (Section 3) has been used to assign the sensitivity,

vulnerability and value of the receptor as follows.

Inhabitants of the water column around the discharge locations will have some tolerance to

accommodate the effects of increased sediment load and sensitivity is considered low, with no

particularly sensitive species known to use the area. As potential impacts are not likely to affect the

long-term function of a system or a population, there will be no noticeable long term effects above

the level of natural variation experienced in the area and vulnerability is low.

The fish populations in the Project area are characterised by species typical of the central North Sea,

with some spawning and nursery regions for commercially important fish and shellfish species

occurring in the vicinity of the Project area. There appear to be low densities of marine reptiles,

cetaceans and seals within the Project area. There are no designated or proposed sites of conservation

interest in the Project area. None of the survey work undertaken in the Project area has identified

any habitats or species that are of specific conservation significance. Value is therefore defined as

low.

The impact magnitude is minor because any chemicals that may be discharged will be negligible in

volume and have a low marine toxicity ranking. The total volume of hydrocarbons that may be

discharged alongside produced water is very low and is not expected to have an impact outside the

500m zone.

Consequence Impact significance

Low Not significant.

5.3 Physical Disturbance

Drill rig anchors

The drilling of the three production wells and one appraisal well will be conducted using a

semi-submersible drill rig. Whilst the final rig has yet to be chosen, it will be a standard 3rd

generation semi-submersible, moored using 8 anchors. The anchor spread radius is likely to

be 1,500 m. Each anchor weighs approximately 12 tonnes, is 5 m x 9 m in size and will produce

a linear scar of as it settles on the seabed. The depth of penetration will be dependent on the

shear strength and load bearing capacity of the seabed soils.



140

There will be 3 discrete periods of drilling activity and 1 inter-field rig move, meaning that the

drill rig will be positioned and anchored 4 times over the duration of Liberator drilling

programme. Three of those times will be at the Liberator drill centre and one will be at the

appraisal well location.

The anchors will be connected to the drilling rig by metal / polypropylene anchor chains, of

which approximately 750 m of each chain is expected to lie on the seabed during drilling

operations. In addition to the footprint of the chain lying on the seabed, some surface scrape

will be produced resulting from catenary contact of the anchor chains and movement of the

chains on the seabed due to current and prevailing wind conditions. The extent of the catenary

scrape is contingent on water depth, anchor spread and tension of the chain or cable and cannot

be predicted accurately. As a result, this assessment assumes a 10 m lateral impact area. The

total seabed area impacted by a single mooring of the drill rig therefore totals 0.06 km2.

Table 5.3 Seabed area impacted by anchoring of drill rig

Placement on seabed Impact area

8 x rig anchors (5m x 9m) 360 m2

8 x anchor chains: 750m on

seabed and 10m impact corridor

60,000 m2

Total per anchoring location 60,360 m2 or 0.06 km2

Total for 4 anchoring locations 241,440 m2 or 0.24 km2

Three of the anchoring locations will be at the same drill centre and effort will be made to reuse

the same anchoring sites each time to minimise seabed disturbance. However, as a worst case

assessment, if different anchor sites were used each time then the seabed impact of anchoring

would total 0.24 km2.

The placement of the anchors will cause localised direct damage to the habitats and species at

the point of placement, whilst the movement of the anchor chains as they sweep back and forth

across the seabed will affect the benthos for as long as the anchor chains remain in position.

The anchors will be in place at a single location for between 28 and 74 days, the duration of

each of the drilling programmes.

Wellheads and SUTU

After drilling activities are complete on each production well, a subsea tree will be installed

within a protection structure. Each structure will have a seabed footprint of 7.87 m x 7.87 m,

with a total affected area of 158.8 m2 for the 3 production wells. The appraisal well will be

plugged and abandoned after testing and so will not require a tree or protection structure.

Whilst the SUTUs at the wells end will each sit on a single mattress placed on the seabed, the

mattress’ will be located under the tree protection structures and therefore have no additional

seabed footprint to that detailed above.



141

Pipelaying, trenching and backfilling

The pipelines will be laid from a dynamically positioned (DP) reel-lay vessel and will not

require the use of anchors.

Trenching and backfilling to a trench depth of 1.8 m and a top width of 6.5 m will be undertaken

for both the shared production and gas lift trench and separate umbilical trench. Table 5.4

outlines the expected area of sediment disturbance during installation of the pipelines,

assuming a 20 m corridor of effect created by spoil heaps either side of the trench.

Table 5.4 Expected size of footprint and sediment disturbance from pipeline and umbilical trenching and backfilling

Length (km) Initial

displacement of

sediment (m3)1

Total affected

footprint (m2)2

Production / gas

lift pipelines

9.85 57,623 197,000

Umbilical 10.85 63,473 217,000

Total 121,096 414,000

Notes: 1 - The amount of sediment excavated from the trench over the whole pipeline length. 2 - Calculated using a 20m

corridor of effect

Trenching operations will be carefully controlled in order to avoid large variations in trench

depth, with the material excavated from the trench backfilled on top of the pipeline to provide

downward force and thermal insulation for the pipeline.

Mattress and rock placement footprint

The production / gas lift pipelines will cross two existing pipelines and the umbilical one. As

a result, mattress and rock will be required to stabilise and protect both the underlying pipelines

and the overlaying Liberator ones. In addition, mattresses will be required for protection at tie-

in locations at the wells location and Ross DCA / DM locations. Depending on the results of

the post-installation survey, additional spot rock placement may be required at places along the

production / gas lift pipeline route to prevent upheaval buckling and provide adequate thermal

insulation of the production pipeline. Although the exact volume of this contingent rock

placement is unknown, experience from existing fields in the area suggest that it is likely to be

low. This is because upheaval buckling is not expected to be a major issue for the Liberator

production pipeline as the operating temperature of the hydrocarbon in the pipeline is expected

to be low and mechanical backfill is expected to provide adequate insulation and cover. In

addition, the relatively quiescent bottom current speeds in the area will mean limited pipeline

movement resulting from external stresses. As a result, a worst-case quantity of 5,000 tonnes

of spot rock placement has been assessed but the final volume is expected to be far smaller.

Tables 2-11 and 2-12 and Figure 2-11 show the location and footprint of mattress and rock

placement associated with the development. The footprint of the mattresses totals 6,272 m2

and rock placement will impact 18,100 m2 of seabed.



142

Effects of seabed disturbance

Between the drill rig anchors, wellhead protection structures, trenching and backfilling and

mattress and rock placement it is expected that 679,970.8 m2 or 0.68 km2 of seabed will be

impacted. These items can cause mortality or displacement of benthic species in the direct

footprint of the disturbance, through physical trauma, smothering by displaced and re-

suspended sediments, and habitat modification due to changed physio-chemical characteristics.

The significance of direct habitat loss or mortality of sessile seabed organisms3 depends on the

footprint of the area of disturbance, the level of tolerance of the affected habitat and species to

direct disturbance, the conservation value of the affected habitat or species and the uniqueness

of the affected habitats or species assemblages to the area.

At the source of disturbance, fauna may be crushed and injured or killed by the placement of

structures, rock or mattresses, or by the discharge of consolidated material (like cement) from

the wellbore. Mobile epifauna may move away from the impacted area; sessile epifauna and

infauna are therefore more likely to be impacted. More mobile species of infauna may be able

to work their way back through layers of deposited to the surface. If sedimentary habitat is

covered by impenetrable material for the long term (for example by rock placement or a

structure such as a manifold), that area of habitat is lost for use by the indigenous marine fauna,

although it may provide additional habitat for epifauna that require a hard attachment point,

leading to a slight change in the species distribution in the area.

In addition to habitat loss and direct mortality and injury caused by crushing or burial, further

impacts such as smothering of benthic species and habitats may be caused by re-suspension

and re-settlement of seabed sediment. Rock placed on the seabed, installation of subsea

facilities, especially the trenching of the pipeline and umbilical/gas lift line, and installation

and retrieval of anchors associated with the drill rig is likely to result in some sediment

suspension and re-settlement. Exposure to higher than normal loads of suspended sediment

has the potential to negatively affect habitats and species in adjacent areas that are not directly

damaged by crushing and burial. The re-settlement of sediments can result in the smothering

of epifaunal benthic species (Gubbay, 2003), with the degree of impact related to their ability

to clear particles from their feeding and respiratory surfaces. Obligate filter feeding organisms

(for example hydroids and bryozoans) that rely on suspended particles for food may be more

vulnerable to potential smothering impacts than deposit-feeding organisms. Filter feeding

structures may become clogged with increased suspended solids in the water column just above

the seabed and therefore feeding could be temporarily limited. The sea pens present in the area

(P. phosphorea and Virgularia sp.; Gardline, 2013b) may be vulnerable to this type of impact,

although both P. phosphorea and V. mirabilis are capable of withdrawing into the sediment

when disturbed, which may reduce intolerance and improve recoverability (Hill and Wilson,

2000; Jones, 2008). Defra (2010) states that impacts arising from sediment re-suspension are

short-term (generally over a period of a few days to a few weeks). Due to the short-term and

3 Sessile refers to an organism that is anchored to a substrate, and which cannot move about

freely.



143

one-off nature of drilling and pipelay activities, any increase in suspended solids near the

seabed is not expected to persist for more than a day following cessation of operations.

In areas that have received a thin covering of additional material, either from re-suspension of

seabed sediments or from deposition of material from the wellbore, it is expected that deposited

material will be worked in to the existing seabed sediments by sediment reworkers, thereby

gradually returning the seabed to a condition similar to its unimpacted state.

Recolonisation of impacted areas is expected to occur from populations in the surrounding

area. Hard-surfaced items such as manifolds or areas of rock are likely to become colonised

through larval attachment from the water column and will eventually support a fauna distinct

from that found in the surrounding sediments.

Although some individual A. islandica were identified in the 2013 Liberator area survey, no

aggregations were seen, and no individuals or aggregations were identified during the 2017

survey. This suggests that the Liberator area is not an important habitat for aggregations of the

species. Similarly, the species identified during the site surveys suggests that the Liberator

field is not of particular importance to burrowed mud communities.

The well locations will not interact with any existing cuttings piles and the pipeline route

corridor will pass ca. 1 km to the east of the previous Liberator appraisal well (13/23d-8) and

so any re-suspension of drill cuttings is not expected. Although it is likely that some of the

cuttings piles from the Ross wells contain OBM, the trenched pipeline route corridor will

remain out with the Ross DCA and DCC exclusion zones within which the wells are bunched

close in to the manifolds in the centre. The pipeline trench will terminate outside the Ross

DCC exclusion zone and hard spools will complete the tie-in. All the Ross DCC wells are to

the south / south-west of the manifold and the Liberator pipeline will tie-in from the north

(Figure 2-8). In addition, the Ross and Blake wells were drilled pre-2001 and discussion in

Section 5.2 on cuttings dispersion suggests that these will have likely been resuspended and

dispersed, especially in the areas away from the immediate well location where deposition was

minimal. Therefore, no disturbance of any existing cuttings piles is expected. The 2019

Liberator survey will however fully investigate the location of existing cuttings piles and

further details will be provided in a post survey report.

The survey of the Ross DCC area in 2010 identified a pockmark 47 m to the southwest of the

DCC manifold. Again, as the Liberator pipelines will tie in from the north (>47 m away), no

impact or interaction with the pockmark is expected.

As with the impacts from seabed and rig cuttings discharge, the sensitivity of seabed habitats

and communities to physical disturbance from well associated activities is considered to be low

to moderate in view of the following factors:

• The seabed habitat types and associated communities are widespread over the Liberator

area, with little evidence for significant effects from previous drilling or construction

activities there.

• Below surficial silty sand sediments, the sequence of shallow soils likely consists of

very soft to stiff clays and sands.



144

• There is evidence of bioturbation in the area, with worm casts and burrows seen

The majority of seabed species identified in the wider Liberator surveys are known or believed

to have short life spans and relatively high reproduction rates, indicating the potential for rapid

population recovery, typically between 1 to 5 years. In general, macrofaunal population levels

are controlled by post-settlement factors rather than larval availability. It is therefore

considered that both the physical habitat consequences and benthic community effects of

anchor disturbance will fully recover within a five to ten-year period.

In conclusion, there will be direct impacts to the benthic community, however most of the

affected area will only be impacted temporarily, with recolonisation from the surrounding area

and from the water column driving a swift recovery. There will be a very small area that will

experience a long-term change in the distribution of species present, but this area is negligible

when compared to the available similar habitat in the surrounding area. There were no

protected habitats identified in the Project area during seabed surveys, and the sediment type

within the Project area is widespread in the surrounding area, suggesting that the sensitivity of

the benthos in the area is low and the potential for recovery following disturbance is high.

Information provided by SFF, Figure 3-16, suggests a number of potential obstructions or

wrecks in the pipeline route corridor area with one in very close proximity to the planned route.

There is currently no further information on the nature of the obstructions or confirmation that

they are wrecks. These, and any other objects identified during the 2019 survey, in close

proximity to the pipeline route will be fully investigated and route adjustments may be made

if necessary. The pipelay vessel will be a DP vessel and so will have no contact with the seabed

other than the area impacted by the trench and pipeline itself and any wrecks or obstructions

will not be impacted by the activities.

Mitigation

A number of management and mitigation measures will be adopted by i3 to reduce, where

possible, the potential impacts of the Project on benthic habitats and species:

• A detailed anchor pattern for the drilling rig will be developed prior to mobilisation;

this will take account of any environmental sensitivities identified close to the drilling

locations;

• On the return of the drill rig to the main drill centre for subsequent drilling campaigns

the same anchor pattern will be used where possible to minimise the area of seabed

disturbed;

• The volumes and locations of rock and mattress protection will be refined during

Detailed Design to reduce the footprint on the seabed to the extent practicable;

• During rock placement activities a fall pipe system held a few metres above the seabed

will be used to ensure accurate placement and minimise the area of seabed disturbed;

• Any drill cuttings accumulations will be identified near the pipeline route during the

2019 survey; installation work will be routed to avoid any accumulations and prevent

re-suspension of cuttings material.



145




DECC (2009) identifies that the sources of cumulative physical disturbance to the seabed

associated with oil and gas activities include drill rigs, wellhead placement and recovery,

subsea template and manifold installation, umbilical and pipeline installation and trenching and

decommissioning of infrastructure. Of these, pipelay is considered to account for the largest

spatial extent.

The Liberator Field Development is predicted to cause direct disturbance of 0.68 km2. The

majority of this area is likely to be affected only in the short term, and the area affected is

extremely small compared to available similar habitat in the vicinity of the Project. As

illustrated in Section 3.5.1, there are a number of established oil and gas fields in proximity to

the Liberator field (including the Blake and Ross fields), but the ongoing seabed impacts

caused by these projects is likely to be very small (i.e. installation has been completed and

ongoing operational impacts on the seabed are minimal). The most damaging activity taking

place in the area is almost certainly use of bottom-fishing gear by fishing vessels. This is

highlighted by the OSPAR background documents for A. islandica (OSPAR, 2009) and seapen

and burrowing megafauna communities (OSPAR, 2010), both of which identify beam trawling

/ bottom trawling as the main threat to the species / habitat assessed. In contrast, OSPAR

(2010) identifies habitat loss through infrastructure development, including offshore oil and

gas, as a low scale threat. Fishing vessels spent 638 days trawling in ICES rectangle 45E8 in

2017 (90% of the total 709 days fished), and demersal species accounted for 24% weight of

landings in 2017 (Scottish Government, 2018). In comparison with the seabed disturbance

caused by this activity, impacts from the Liberator Field Development will be negligible, and

make an insignificant contribution to any cumulative impact.


The Offshore Energy SEA for UKCS waters (DECC, 2009) states that seabed impacts are

unlikely to result in transboundary effects and even if they were to occur, the scale and

consequences of the environmental effects in the adjacent state territories would be less than

those in UK waters and would be considered unlikely to be significant. Liberator is located

approximately 174 km from UK/Norway median line; direct and indirect seabed impacts will

not extend this far from the Project and transboundary impacts will not occur.

Decommissioning

Any potential impacts that decommissioning operations (e.g. removal of Liberator

infrastructure) may have through seabed disturbance will occur in an area that already

experienced seabed disturbance during the installation operations. The potential impacts from

decommissioning operations are likely to be similar in magnitude to those experienced during

installation and thus not significant.

Protected sites

Marine Scotland’s FEAST tool indicates that the habitat features expected in the area may

show a low to moderate sensitivity to increased levels of siltation, a moderate to high sensitivity



146

to change in seabed type and a moderate sensitivity to surface and sub-surface abrasion and

penetration. Habitat assessment conducted in the Project area identified low densities of the

seapens P. phosphorea and Virgularia sp., as well as numerous faunal burrows. The density

of both features was too low to qualify as the protected habitat “seapen and burrowing

megafauna community” identified in OSPAR (2008). Whilst the seabed may be consistent

with the PMF and MPA search feature “Burrowed mud”, extensive search areas for this feature

have already been designated in the North Sea, and none of them correspond with the Liberator

Field Development. It is therefore unlikely that the Liberator Field Development will have a

significant impact on the PMF. As such it is considered unlikely that the sensitivities indicated

by the FEAST tool would translate to a significant impact on any protected sites or features.

An assessment of the site’s potential as a herring spawning ground found there was no potential

for herring spawning in the Project area (Gardline, 2013).

Residual impact


Benthos Low Low Negligible Minor

Rationale



The sensitivity of seabed habitats and species to disturbance is expected to be low, with an absence

of protected species / habitats and wide availability of similar habitat in the surrounding area.

Disturbance is expected to be extremely localised, with very limited impacts on a faunal community

that is expected to show low sensitivity to disturbance and rapid recovery. Most impacts are expected

to be short term, with prolonged impacts occurring over a very limited area.

The Project activities are expected to be negligible in terms of cumulative and in-combination

impacts.

Mitigation measures will be used to further reduce the level of impact.


Low Not significant

5.4 Underwater Noise

Introduction

Underwater sound is generated by natural sources such as rain, breaking waves and marine life,

including whales, dolphins and fish (termed ambient sound). Industrial use of the marine

environment adds additional sound from numerous sources including shipping, oil and gas

exploration and production, aircraft and military activity.

Many species found in the marine environment use sound to understand their surroundings,

track prey and communicate with members of their own species. Some species, mostly toothed

whales, dolphins and porpoise, also use sound to build up an image of their environment and



147

to detect prey and predators through echolocation. Exposure to natural sounds in the marine

environment may elicit responses in marine species; for example, harbour seals have been

shown to respond to the calls of killer whales with anti-predator behaviour (Deecke et al.,

2002).

In addition to responding to natural sounds, marine species such as fish and marine mammals

may also respond to man-made sound. The potential impacts of industrial noise on species

may include impacts to hearing, displacement of the animals themselves and potential indirect

impacts which may include displacement of prey species. Whilst there is a lack of species

specific information collected under controlled or well-documented conditions, enough

evidence exists for fish and marine mammals to suggest that sound may have a potential

biological impact and that noise from man-made sources may affect animals to varying degrees

depending on the sound source, its characteristics and the susceptibility of the species present

(e.g. Nowacek et al., 2007, report this specifically for cetaceans).

As well as potential behavioural impacts of noise, marine mammals and fish exposed to an

adequately high sound source may experience a temporary shift in hearing ability (termed a

temporary threshold shift; TTS) (e.g. Finneran et al., 2005). In some cases, the source level

may be sufficiently high such that the animal exposed to the sound level might experience

physical damage to the hearing apparatus and the shift may not be reversed; in this case there

may be a permanent threshold shift (PTS) (Southall et al., 2007), and the animal could be

considered as being injured.

Noise sources that have been identified as likely to occur during the Liberator Field

Development and which, depending on the specific nature of the sources, could cause injury

or disturbance to marine mammals and fish are limited to drill rig, vessel use and potential VSP

activity. The drill rig will use anchors to maintain station and there is thus no requirement for

ongoing use of dynamic positioning.

The sources, measurement, propagation, ecological effects and potential mitigation of

underwater noise have been extensively reviewed and assessed (Richardson et al., 1995;

McCauley et al., 2000; DTI, 2004; MMS, 2004; Weilgert, 2007). Nowacek et al. (2007)

provide a systematic update of quantitative studies of cetacean responses to anthropogenic

noise, published since Richardson et al. (1995).

In general, assessments of acoustic disturbance have involved:

• quantification of source noise levels (as Source Level, SL)

• estimation of threshold noise levels for various categories of effect (ranging from acute

trauma to behavioural responses)

• estimation of likely horizontal range of noise propagation to specified threshold level

• assessment of population density and sensitivity of marine mammals and other

receptors within affected areas

Using this approach, concentric “zones of effect” may be identified, corresponding to

increasing sound pressures and severity of effect



148

Noise sources

Available measurements indicate that drilling activities produce mainly low-frequency

continuous (non-pulsed) noise from several separate sources on the drilling unit (Richardson

et al., 1995; Lawson et al., 2001). The primary sources of noise are various types of rotating

machinery, with noise transmitted from a semi-submersible ring to the water column through

submerged parts of the drilling unit and risers, and (to a much smaller extent) across the air-

water interface. Farfield sound pressure of around 154 dB re 1μPa, in the frequency range 10-

500 Hz (GOAG, 2011) is typical of drilling from a semi-submersible rig. Noise emissions

from standby and supply vessels and potential VSPs are outlined in Table 5-5.

Table 5-5 Source characteristics for activities associated with the Liberator development

Noise

Category

Acoustic Source Sound Pressure

Level (dB re

1µPa@1m)

Low

Frequency

(Hz)

High

Frequency

(Hz)

Source

Non-Pulsed Semi-sub rig (drilling) 154 10 500 GOAG

(2011)

Non-Pulsed Semi-sub rig (standby) 113 @ 125 m 10 10,000 GOAG

(2011)

Non-Pulsed Supply / standby vessel

(2,000 t)

187 1 10,000 Wyatt

(2008)

Non-Pulsed Supply / standby vessel

(1,200 t)

135 10 20,000 Wyatt

(2008)

Pulsed VSP 238 70 140 DECC

(2011b)

Thresholds for injury and disturbance

The main concerns associated with acoustic emissions from the development are the potential

impacts on marine mammals, fish, and consequently fisheries. Of the marine mammal species

thought to be present within Blocks 13/23, 13/28 and 13/29 at any point in the year; minke

whale belong to the low frequency hearing group (hearing sound with a frequency comprised

between 7 Hz and 235 kHz); white-beaked dolphin, bottlenose dolphin, Atlantic white-sided

dolphin and killer whale belong to the mid-frequency hearing group (150 Hz to 160 kHz), and;

harbour porpoise belong to the high frequency hearing group (275 Hz to 160 kHz) (NOAA,

2018). It can be seen that the hearing ability of many species overlap with noise generated

from proposed operations detailed in Table 5-6. Pinnipeds are not routinely expected to be

found in the vicinity of the Liberator area owing to the distance offshore (64 km), however

they have a hearing range of 50-86 Hz when in water (Southall et al., 2007).

Received sound pressure levels (SPLs) associated with TTS and PTS for different categories

of cetaceans, pinniped and fish are shown in Table 5-6 (NOAA, 2018; Southall et al., 2007;

Popper et al., 2014). It can be seen that out of the noise generating activities associated with



149

the Liberator development only VSPs have a SPL greater than the TTS and PTS thresholds for

cetaceans, pinnipeds and fish.

Table 5-6 Predicted impact range for injury (PTS) and behavioural response (TTS) for marine mammals, pinniped and

fish from a VSP survey

Hearing Group PTS Threshold

(dB re 1µPa)

Impact

Distance (m)

TTS Threshold

(dB re 1µPa)

Impact

Distance (m)

LF Cetaceans 219 9 213 18

MF Cetaceans 230 3 224 5

HF Cetaceans 202 64 196 126

Pinnipeds 218 10 212 20

Fish – Type 1 213 18 -

Fish – Type 2/3 207 36 207 36

Notes: Type 1 fish have no swim bladder, Type 2 fish have a swim bladder, but it is not involved in hearing, Type 2 fish have

a swim bladder which is involved in hearing

Sources: NOAA (2018), Southall et al. (2007), Popper et al. (2014)

Figure 5-2 Sound Propagation in Water and Injury Thresholds for Cetaceans and Pinnipeds

A simplified assessment can be made by assuming that in deep water, sound pressure will

propagate spherically, with received Sound Pressure Level, SPL = SL – 20log(R), where SL =

source level (dB), R = source-receiver range (m). This is a high-level screening tool, as in

practice noise propagation is much more complex that this, with variability associated with for



150

example the angle from the source and interactions with water surface and seabed. Figure 5-2

show propagation of sound from VSPs only and Table 5-6 shows the distance from the VSP

source that PTS and TTS thresholds are met.

Marine mammal impacts

The Liberator development area lies within the SCANS-III survey block T (Hammond et al.,

2017). Density estimates for this block for the most abundant cetacean species range from

harbour porpoise (0.402 /km2), to an order of magnitude less for white-beaked dolphin (0.037

/km2), minke whale (0.032 /km2) and white-sided dolphin (0.021 /km2). Figure 5-2 and Table

5-6 both show that the probability of injury to both low frequency and medium frequency

cetaceans and pinnipeds will be found within a very limited range, <20 m assuming spherical

propagation. The probability of exposure of any individual animals within this area is low

especially given the low density of sensitive species within the area. This is further reduced

by the limited duration of the VSPs (estimated at 36 hrs per well) and operational mitigation

discussed below.

There is a larger spatial range of definite audibility, and possible behavioural effect – up to 126

m for harbour porpoise, the most abundant marine mammal in the area. The ecological

significance of these potential effects is unknown, although given recorded population densities

in the area, there is at most a possibility of SPL sufficient to result in behavioural modification

of a few individual harbour porpoise. This level and duration of disturbance is very unlikely to

have significant effects at a population scale, or over an individual lifespan

Pinniped impacts

The east coast of Scotland, Orkney and Shetland support important breeding colonies and haul-

out sites for both grey and harbour seals, several of which receive international conservation

designations. Harbour seals in Scotland generally forage within 40-60 km of haul-out sites,

with dense foraging activity occurring in waters off eastern Scotland and coastal waters

surrounding Orkney and Shetland (Thompson et al., 1996; Hammond et al., 2004). However,

harbour seals are also recorded far from shore across much of the central and northern North

Sea, including foraging trips to areas more than 200 km from haul-out sites. Grey seals

generally forage within approximately 40 km of haul-out sites (McConnell et al., 1999). This

species also occasionally embarks on long journeys between different haul-out sites, spending

long periods of time at sea and foraging in offshore areas (McConnell et al., 1999;

Matthiopoulos et al., 2004). Offshore foraging destinations are typically localised areas of

gravel/sand substrates in relatively shallow water – the preferred habitat of sandeels.

Although the Liberator area is approximately 64 km from the nearest landfall, both harbour

and grey seals are likely to be present in very limited numbers and for fairly short duration.

Telemetry data corroborates this, with zero to one harbour seal and one to five grey seals per

25 km2 (Jones et al., 2015; SMRU and Marine Scotland, 2017) predicted in the area. Therefore,

as the TTS and PTS thresholds for seals were within 20 m of the VSP source, significant

acoustic disturbance is not expected to result from the proposed development.



151

Fish impacts

Marine Scotland have a period of concern for seismic surveys (including VSPs) in February to

June in relation to impact on fish spawning. A number of species of fish spawn in the wider

Liberator area during this period including cod, Norway lobster, Norway pout, plaice and sprat.

There is a potential that VSPs will take place during this period of concern and Popper and

Hawkins (2014) outline the possibility of fish being affected by various noise emitting

industries, of which oil and gas is one. In the same way as marine mammals can be affected,

it is possible that fish could be injured or disturbed if noise emissions are sufficiently high (e.g.

De Robertis and Handegard, 2012). However, installation and support vessels will be slow

moving and fish will not experience any sudden bursts of sounds, such that they may choose

to move away, thus avoiding injury.

In terms of the potential impacts on fish, a review of published potential impact zones from

continuous and pulsed sound suggest they are likely to be limited to tens or hundreds of metres

from the noise source, if any responses do occur (e.g. De Robertis and Handegard, 2012;

Chevron, 2013; Mueller-Blenkle et al., 2010; Schulze and Ring Pettersen, 2007). For VSPs,

the predicted SPLs are below the published TTS and PTS thresholds for fish and the noise will

be for a very short duration. Even if some fish were to be injured by the VSPs, many millions

of individuals make up most species populations (e.g. Mood and Brooke, 2010) and limited

injury is not likely to result in significant impacts at the population level. Similarly, should the

noise emissions disturb fish, the short-term movement away from the short-term activities

would not constitute a large-scale movement by individuals of a species and would be highly

unlikely to result in population level impacts.

Mitigation

The primary measure of reducing potential impact will be to limit the duration of the noise

emitting activities; for example, vessels will only be deployed where necessary and limited as

far as is practicable during installation activities.

i3 will adhere to JNCC guidelines for reducing the potential for injury and disturbance to

marine mammals from VSP activity (JNCC, 2017), which include:

• A suitably trained marine mammal observer (MMO) will conduct a pre-shooting search

over a 30-minute period prior to the commencement of VSP. This will involve a visual

assessment to determine if any marine mammals are within a 500 m monitoring zone

(measured from the location of the VSP). Should operations cease for ten minutes or

more, a search will be undertaken before the re-commencement of activities;

• Should any marine mammals be detected within 500 m of the VSP operations, these

operations will be delayed until marine mammals have moved outside the mitigation

zone. In this case, there will be a 20-minute delay from the time of the last marine

mammal sighting to the commencement of activities;

• The VSP will be powered up slowly over 20 minutes in order to give marine mammals

time to leave the area. Build-up of power will occur in uniform stages to provide a

constant ‘ramp-up’ in amplitude. These soft start procedures will also be undertaken if



152

the operations are stopped for at least 10 minutes, to allow for checking of the visual

observation zone to determine if any marine mammals have entered the area whilst the

VSP activities were suspended. If marine mammals have re-entered the observation

zone, restart of the operations will be delayed until 20 minutes after the last sighting of

the marine mammal; and

• If VSP is required to commence in sub-optimal conditions for visual monitoring,

consideration will be given to using passive acoustic monitoring (PAM) in addition to

MMOs. Use of PAM in conditions that are sub-optimal for visual monitoring enhances

the probability of detecting marine mammals (when vocalising), reducing the

likelihood of potential negative impacts.

Seasonality of marine mammals is not considered significant in this assessment as they are

present in the area throughout the year and the drilling programme is split into 3 separate

phases, with VSPs planned at different times of the year all of which potentially coincide with

marine mammal and pinniped activity in the area.


It is possible that the various noise sources associated with the Liberator Field Development

activities (i.e. multiple vessels operating at the same time, or VSP occurring at the same time

as vessels being used) could result in an impact to marine mammals and fish. However, noise

levels will be sufficiently low that injury is not expected for marine mammals. Potential

disturbance zones are likely to be small and, for the most part, highly limited in temporal extent.

For fish, the potential for injury or disturbance to result in any detectable changes at the

population level is very low. Cumulative impact from sources within the Liberator Field

Development are therefore not expected. In the context of the number of vessels that use the

North Sea for fishing, shipping, passenger transport, oil and gas activity, recreation and others,

which will all emit noise, the scale of the additional in-field time required for vessels associated

with the Liberator Field Development is clearly limited.

In theory, any project that regularly emits underwater noise has the potential to act

cumulatively with the Liberator Field Development – this includes the ongoing operation of

the Bleo Holm FPSO. Cetacean and fish populations are free-ranging and long-distance

movement is likely to be frequent, and in some cases predictable through seasonal migration

(e.g. mackerel; ICES, Undated). Any animal experiencing a noise from the Liberator Field

Development is likely to belong to a much wider ranging population and there is the potential

for that same animal to subsequently come into contact with noise from activates related to

other unrelated projects. However, potential injury and disturbance impacts resulting from any

individual element of the Liberator Field Development are not expected to be significant (e.g.

animals will not be excluded from the area), and significant cumulative impact from an animal

encountering noise emissions from multiple activities within a short period of time is therefore

considered highly unlikely.


The Liberator field is approximately 174 km from the UK/Norway median line. Given the

expected noise sources involved in the project, direct transboundary impact from noise



153

emissions will not occur. However, marine mammals and fish are free-ranging animals and

any impact that occurs in UK waters is likely to occur on animals that belong to a much wider

ranging population and thus likely to cross median lines. Such a potential impact could qualify

as a transboundary impact. However, since injury and disturbance from the limited operations

associated with the Liberator Field Development are not expected to result in significant impact

to any population, potential transboundary impacts are also therefore considered not

significant.

Protected sites

As described in Section 3.4, 1only one species listed on Annex II of the Habitats Directive is

likely to occur in the Liberator field; this is the harbour porpoise (bottlenose dolphin are

generally found only within the 20 m depth contour). For harbour porpoise, animals making

use of the Southern North Sea candidate SAC may also make use of the Liberator field; harbour

porpoise within the North Sea are known to form one biogeographical population that spans

the North Sea as a whole (JNCC, 2015). However, there is expected to be no injury to harbour

porpoise from the Project activities, and no effect of disturbance at the population level. As

such, there will be no Likely Significant Effect on this protected site. It is possible that vessel

transits nearshore could overlap with bottlenose dolphin and grey and harbour seal use of an

area (i.e. the other Annex II marine mammal species found in the UKCS), but the presence by

vessels in such areas would be highly limited in temporal extent and there would be no

significant effect on any nearby protected sites. This assessment also considers there to be no

potential for underwater noise emissions to interact with protected features of an NCMPA or

MCZ (primarily as there are no sites designated for features that may be affected by noise

emissions close to the Liberator field) and there is therefore no significant risk to the

conservation objectives of any NCMPA or MCZ. The FEAST tool indicates that the seabed

habitats expected in the area are not sensitive to noise disturbance.

Residual impact


Marine mammals Low Low Low Minor

Fish Low Low Negligible Minor

Rationale



Both receptor groups have some tolerance to accommodate the limited effects that vessel use and

very restricted VSP activity could give rise to (i.e. no injury but some minor disturbance within a few

hundreds of metres of the source) and are ranked as ‘low’ in terms of sensitivity. As there is expected

to be no change at the population level for either receptor group, the impact is not likely to affect

long term function or status of any population and the vulnerability can also be considered ‘low’. In

terms of value, marine mammals found at the site are considered for protection under European

legislation but as they do not belong to protected sites around the Project area they can be classed as

‘low’ value. For fish, species found at the site are generally abundant around the UKCS and are not

afforded any specific conservation protection. As such, they can be classed as ‘negligible’ value.



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For magnitude, any possible impact on either receptor group is expected to be highly localised in

scale and of a temporary nature. On this basis, a magnitude of minor is assigned.


Low Not Significant

5.5 Physical presence

Impact on commercial shipping and oil and gas support vessels

The physical presence of the drill rig, installation vessels, pipelines and subsea facilities have

been identified as a potential cause of effect, primarily for fisheries and navigation.

It is proposed that the drilling operations will be undertaken between August and October 2019,

April and June 2020 and April and June 2021. A drill rig and EERV will be in the Liberator

field area for the full duration of the drilling programmes (224 days over a 20-month period)

and supply vessels and anchor handling vessels will be in the area for 8.5 and 75 days

respectively over the same time period.

Subsea infrastructure installation will take place between April and June 2020, with associated

vessels in the Liberator field area at the same time as the drill rig for the second drilling

campaign.

A temporary 500 m exclusion zone will be applied for centred on the drill rig, which has the

potential to displace any vessels from regular routes and lead to extended passage times and

increased fuel use. AIS data from 2012-2015 shows that the Liberator drill centre area is not

widely used by commercial and passenger vessels and is therefore unlikely to be significantly

impacted by the presence of the drill rig, pipelay and associated vessels. The Aberdeen to

Lerwick passenger ferry and cargo route passes 5 km to the west of the Liberator drill centre

and 3 km from the appraisal well drilling location and will therefore not be affected by

exclusion from the area during drilling activities. There is adequate sea room to allow minor

route alterations to be made without significant impact. Similarly, the supply vessels travelling

to and from the Bleo Holm access the FPSO from the south, away from the Liberator

development and will therefore not be impacted.

A number of vessels will be in-field for relatively short periods of time during installation and

construction phases of the development. Given that not all of the vessels will be present at the

same time, will be spread over the wells, pipeline and Ross tie-in areas and will be present for

very short durations it is unlikely that the presence of these vessels will cause significant

interference to other vessels.

Impact on commercial fishing

Whilst the drill rig is at the drill centre and appraisal well locations, a 500 m safety exclusion

zone will be in place covering an area of 0.8 km2. Commercial fishing vessels will be excluded

from this area for the duration of the proposed drilling operations, anticipated to be for 224

days over a 20-month period, in 3 distinct blocks of 97 days, 50 days and 74 days. In addition,

the drill rig moorings will extend beyond the 500 m exclusion zone and will potentially be

composed of fibre rope, which is not detectable by sonar on vishing vessels. This could result



155

in a snagging risk, and fishing in this area is unlikely to be undertaken for safety reasons. The

Liberator area is of low to moderate importance to fishing vessels, with high use areas just to

the north and west of the drill centre and very low usage areas along the southern end of the

pipeline route. Fishing vessels accessing the deep fishing grounds to the west use the drill

centre area and northern end of the pipeline route corridor for turning and transiting meaning

that vessel traffic may be moderate to high especially during June and July. Although the 2nd

and 3rd drilling campaigns are likely to extend into June the area of exclusion is however small

and for short durations with ample sea room for vessels to use the area out with the temporary

exclusion zone. In addition, the fish stocks present in the vicinity are not exclusive to the area,

suggesting that short term displacement of any fishing vessels to nearby fishing grounds would

not likely result in significant impact. Once the drill rig had moved off location, vessels would

be able to operate as before.

Once operations have been completed, the appraisal well will be plugged and abandoned with

no obstructions remaining on the seabed. At the drill centre, wellhead protection structures

will be installed at the 3 well locations and whilst no exclusion zone will be in place all the

hard spools and jumpers will be protected by concrete mattresses placed on the seabed. Tie-in

of hard spools and infrastructure at the Ross DCC and DM will take place within the current

long term 500 m exclusion zones. As a result, once drilling and installation is complete, fishing

vessels will not be excluded from any areas additional to those currently under exclusion zones.

The pipelay, rock placement and associated support vessels will exclude other sea users around

their immediate vicinity but only for a very short period of time (up to 20 days). Given that

fishing intensity in the majority of the pipeline route corridor and Ross area has been estimated

to be low (Scottish Government, 2018), a negligible impact on the fishing sector is expected.

Bottom trawling close to subsea facilities carries the risk of fishing gear snagging with

consequent loss of fishing gear, or in the worst case, the vessel. Interrogation of data from The

Marine Accident Investigation Branch shows there have been 15 sinkings resulting from

snagged fishing gear between 1989 and 2014, resulting in 26 fatalities. There is potential for

fishing gear to snag on the well trees, pipelines, rock placement and protection mattresses. To

minimise snagging risk, all well trees will be protected by fishing friendly protection structures,

and the pipeline, umbilical and gas lift lines will be buried in trenches and, where necessary,

covered by rock placement. Mattresses will protect the areas where the pipeline, umbilical and

gas lift line exit the trenches. Mattresses will have tapered edges to reduce the snagging risk

and both crossings will be of fishing friendly design using graded materials, designed to remain

stable under the action of environmental loading

In recent years there has been a significant increase in pelagic fishing in the Liberator area.

Snagging of fishing gear can occur on seabed equipment or where freespans have developed

between the seabed and the pipeline, creating potential snags for trawl otter boards (of wood

and/or steel and up to 1.5 tonnes each) used to hold open a demersal trawl net. These otter

boards typically penetrate the seabed down to 15cm and for this reason the pipelines and

umbilical will all be trenched into the seabed and backfilled, significantly reducing the potential

for interaction. As this area of the North Sea is not subject to vigorous currents and has low



156

sediment mobility, freespans along the pipeline routes are not expected to develop. Snagging

on the pipelines is considered unlikely unless substantial scour occurs along the pipeline or

there are obstacles along the pipeline route, which would be detected during the planned regular

inspections of the pipeline route. Inspection surveys at Blake and Ross have not identified any

major issues with upheaval buckling or development of freespans, suggesting that this is also

unlikely to be an issue at Liberator.

Despite the significant increase in landings of pelagic fish from the Liberator area, there has

not been a parallel increase in number of days of fishing effort in the area. This suggests that

a number of large pelagic vessels are fishing in the area for a short number of days, rather than

there has been a significant increase in fishing vessel activity.

There is the potential for the formation of mounds on the seabed due to the deployment and

recovery of the drill rig anchors. Trenching in clay soils may also give rise to clay berms at

the edges of trenches, which may pose a hazard to fishing vessels. Over-trawling such anchor

mounds and berms with fishing gear could result in sediment being retained in fishing nets,

with potential damage of nets and equipment and affecting catches, as well as posing a threat

to the safety of the vessel. There is at least one recorded incident of a fishing vessel being sunk

in the North Sea following snagging of gear on a clay trenching berm (Marine Accident

Investigation Branch, 2006). These mounds are most likely to form in areas where sediments

at or near the surface contain heavy clay. The seabed sediments across the majority of the

Liberator field comprise silty sand, but this forms only a thin veneer in places with very soft to

stiff clays underlying. The survey of the pipeline route planned for 2019 will include CPTs to

determine exact soil characteristics of the route and a post lay survey will identify any berms

or significant anchor mounds which may have formed. i3 will ensure that any post pipelay or

subsea equipment installation survey will consider issues that impact fishing activity and will

take appropriate action in consultation with SFF.

Mitigation

A number of mitigation measures will be employed to reduce the impact on other sea users:

• During installation the number of vessels and length of time they are required on site

will be reduced as far as practicable through careful planning of the installation

activities;

• A safety zone of 500 m in radius will be established around the drill rig during drilling;

• Once the drill rig is contracted, a rig anchor pattern study will be carried out to confirm

the lay pattern and steel anchor chains will be used where possible. Liaison with the

fishing industry will provide awareness of any areas of fibre rope outside the 500 m

exclusion zone;

• A standby and support vessels will operate during the period that the drill rig is in place.

These vessels will ensure that other sea users are aware of the presence of the anchor

spread outside of the drill rig safety zone;

• Information on the location of subsea infrastructure and vessel operations will be

communicated to other sea users (via the United Kingdom Hydrographic Office)



157

through the standard communication channels including Kingfisher, Notice to Mariners

and Radio Navigation Warnings;

• Infrastructure will be marked as hazards on admiralty charts and entered into the

Fishsafe system so that it may be avoided by fishing vessels;

• Consultation will be undertaken with relevant authorities and organisations with the

aim of reducing potential interference impacts resulting from Project activities as far as

practicable.

• A fishery liaison strategy will be developed and implemented;

• Regular maintenance and pipeline, umbilical and gas lift route inspection surveys will

be undertaken;

• Subsea tree protection structures will be designed to be fishing friendly;

• The majority of the pipeline, umbilical and gas lift line will be buried, eliminating snag

risk (the lines will exit trenches close to each end of the route);

• A post-installation pipeline survey will identify any potential hazards to fishing vessels

and take appropriate action;

• Should wells be abandoned, wellheads will be cut off below the seabed leaving the

seabed free of infrastructure that could pose a snagging risk to fishing gear; and

• Trenching will be conducted using plough and mechanical backfill, where there will be

minimum backfill of 1 m. This method will achieve a similar seabed profile to that

before pipelay and will reduce the potential damage to fishing gear from snagging.


Due to the low to moderate levels of shipping activity in the Project area, the wide expanse of

water available to navigate in, the limited number of vessels to be deployed for the installation

activities and since there will be no additional surface infrastructure installed (i.e. the Liberator

field will tie-back to the existing Bleo Holm FPSO), it is not anticipated that there will be any

significant cumulative impacts with respect to vessel collision risk.

DECC (2009) report that exclusion from an area and snagging risk from oil and gas activities

are cumulative to those resulting from natural obstructions, shipwrecks and other debris.

However, the area of seabed exclusion during the life of the Liberator Field Development will

be small in comparison with the total fishing area available and will be temporary and thus the

impact is likely to be low. Consequently, there is not expected to be a significant cumulative

impact.


The area in which the Project is located is regularly fished by vessels of other nations and any

effect on their landings could constitute a transboundary impact. However, the potential impact

on fisheries is considered not significant and it is therefore unlikely that the Project will result

in any transboundary impacts.



158

Decommissioning

Any potential impacts on other sea users regarding collision risk and temporary exclusion from

the Project area that decommissioning operations may have will occur at a similar level to

impacts during installation operations. Removal or appropriate decommissioning in situ of

Project infrastructure during decommissioning will act to remove any potential snag risk.

Residual Impact


Fisheries Low Low Low Minor

Other sea users,

except fisheries

Negligible Negligible Negligible Minor

Rationale


vulnerability and value of the receptor as follows. Fisheries are expected to be tolerant to short-term

interference (low sensitivity) and given the low intensity of fishing in the area, it is unlikely that

drilling activities will have an impact on the fishing sector (low vulnerability). Since fishing intensity

is estimated to be low, the value of residual impact is defined as low. Given that the area excluded

to fishing is small compared with the total available fishing area and that the area around the Liberator

field is already exploited for its oil and gas reserves meaning that fishermen are used to avoiding it,

the magnitude of residual impact is estimated to be minor. Sea users other than fisheries relates to

shipping, which is of low intensity in the Project area. It is therefore capable of accommodating any

short-term interference (negligible sensitivity) without changing behaviour (negligible vulnerability),

this makes limited use of the Liberator field (negligible value) and only very localised effects are

expected (minor magnitude). On this basis, the consequence is low and the impact not significant.

Consequence Impact Significance

Low Not significant

5.6 Atmospheric Emissions

Description and quantification of impact

The emission of gases to the atmosphere from the Liberator Field Development could

potentially result in impacts at a local, regional, transboundary and global scale. Local,

regional and transboundary issues include the potential generation of acid rain from nitrogen

and sulphur oxides (NOx and SOx) released from combustion, and the human health impacts

of ground level nitrogen dioxide (NO2), sulphur dioxide (SO2), both of which will be released

from combustion) and ozone (O3), generated via the action of sunlight on NOx and volatile

organic compounds (VOCs). On a global scale, concern with regard to atmospheric emissions

is increasingly focused on global climate change. The Intergovernmental Panel on Climate

Change (IPCC) in its fourth assessment report states that ‘Most of the observed increase in

global average temperatures since the mid-20th century is very likely due to the observed

increase in anthropogenic greenhouse gas (GHG) concentrations.’ GHGs include water

vapour, carbon dioxide (CO2), methane (CH4), nitrous oxides (N2O), O3 and

chlorofluorocarbons. The most abundant GHG is water vapour, followed by CO2. IPCC



159

(2007) reports a 35% increase in CO2 concentrations compared to pre-industrial concentrations

and states that the combustion of fossil fuels is the primary contributor.

Table 5-7 Atmospheric emissions from the Liberator Field Development drilling, subsea installation and operations

Activity Source Emissions (tonnes)

CO2 CO NOx N2O SO2 CH4 VOC CO2e

Drilling and

Completion

Drill rig 7,168 35.17 133 0.49 8.96 0.4 4.5 7,399

Vessels 13,273 65.1 246.4 0.91 16.6 0.75 8.3 13,701

Helicopters 192.6 0.31 0.75 0.01 0.24 0.005 0.05 196

Well Tests x 4 11,148 55.5 11.3 0.29 0.05 105.6 73.6 13,567

Total 31,781 156.1 391.5 1.7 25.9 106.8 86.4 34,863

Subsea

Installation

Vessels 4,022 19.7 74.7 0.28 5.03 0.23 2.5 4,153

Total 4,022 19.7 74.7 0.28 5.03 0.23 2.5 4,153

Operations

Vessels per year 1,499 7.4 27.8 0.1 1.9 0.1 0.9 1,547

Flaring per year 2,920 7.0 1.3 0.08 0.01 18.8 2.1 3,355

Venting per year 0 0 0 0 0 0 0 0

Power generation

Turbines Fuel Gas 6,655 7.0 14.2 0.5 0.03 2.1 0.08 6,873

Power generation

SW Injec. Fuel Gas 1,619 4.3 32.6 0.1 0.01 11.2 1.8 1,901

Power generation

Other Diesel 1,469 0.3 1.3 0.1 1.8 0.0 0.01 1,501

Power generation

Turbines Diesel 869 0.3 3.8 0.06 1.1 0.01 0.08 916

Power generation

SW Injec. Diesel 0 0 0 0 0 0 0 0

Total per year 15,058 26 81 1 5 32 5 16,093

Total – Field Life 150,581 262 809 9.9 48.8 322.2 50 160,929

Notes: SW Inj. = seawater injection; Power generation figures are per year unless stated; Other includes all

other engines and heaters

Atmospheric emissions from the Liberator Field Development during the drilling and

installation phases will be related largely to fuel consumption by the drill rig, installation

vessels and helicopters (Section 2.9) and flaring activities if well testing is carried out (Section

2.5.7). Emissions associated with operation of the field can be split into incremental increases

in flaring and venting on the Bleo Holm (Section 2.8.5), increased vessel use (supply vessels,

survey vessels and offtake tanker: Section 2.9) and incremental requirements of fuel gas and

diesel for power generation (Section 2.8.4). Emissions from all aspects of the development are

shown in Table 5-7. Operational emissions are shown for Liberator only for field life (10

years), with any discussion on incremental increase at the Bleo Holm for the period 2020-2024

only, using 2017 as a baseline year.



160

For the atmospheric emissions calculations, emission factors from the EEMS-Atmospheric

Emissions Calculations (Issue 1.9) (2008) have been used. An associated Global Warming

Potential, or CO2 equivalent (CO2e) has also been calculated based on the radiative forcing

effect of each GHG species relative to CO2 and the atmospheric residence time of each gas.

The CO2e therefore changes depending on the time horizon considered (IPCC, 2001, 2007).

For this assessment, a 100-year time-horizon has been used and it should be noted that a ±35%

uncertainty has been considered to apply to the conversion factors. CO2e calculations are

shown for NOx and VOCs but are not included in CO2e totals, due to the greater uncertainty

surrounding factors for these (IPCC, 2007).

Table 5-7 shows that the drilling programme will generate 34,863 tonnes of CO2e spread over

a 3-year period, whilst the subsea installation operations will generate 4,153 tonnes of CO2e in

2019.

The emissions calculations suggest 16,093 tonnes of CO2e will be generated each year during

operations, although it should be noted that for the years 2024-2029 the calculations use data

which still includes Blake and Ross, providing a very conservative estimate. No emissions are

calculated for venting per year as the 2017 baseline data (used to calculate increases) already

vented the maximum permitted volume under the Bleo Holm vent consent so no further venting

could be attributed to Liberator without exceeding these levels. Further work will be

undertaken during FEED to understand the implications of no further additional venting.

However, if a nominal 10% increase in venting is assumed above the permitted venting limit

then an additional 1,407 tonnes of CO2e would be added to the annual operations total.

Mitigation

i3 will take appropriate steps to ensure the following:

• All vessels will comply with the Merchant Shipping (Prevention of Air Pollution from

Ships) (Amendment) Regulations 2014;

• All combustion equipment will be subject to regular monitoring and inspections to

ensure an effective maintenance regime is in place, ensuring all combustion equipment

runs as efficiently as possible;

• Operations will be carefully planned to reduce vessel numbers and journeys and the

duration of operations;

• All vessels will have the appropriate UK Air Pollution Prevention or International Air

Pollution Prevention certificates in place as required;

• Various processes (i.e. maintenance procedures, ongoing monitoring, competent

personnel, internal/external auditing) are available to optimise energy efficiency and

thereby minimise emissions;

• The duration of well testing will be limited as far as is practicable to reduce the

requirement to flare; and



161

• Operational fuel use, flaring and venting will be managed by the existing permits in

place at the Bleo Holm FPSO and in line with existing monitoring and maintenance

procedures in place on the facility.

Local Air Quality

Throughout the drilling, installation, commissioning and operation of the Liberator Field

Development there will be atmospheric emissions, which may or may not have local or regional

(including transboundary) effects. Any releases from drilling, installation and commissioning

vessels will be transitory, whilst emissions from operational activities will be intermittent

throughout the life of the field.

The Liberator field is too remote from other industrial activities (including other offshore oil

and gas activity) for there to be any likely cumulative effects in terms of local air quality or

health impacts. Whilst there will be an increase in fuel use at the existing Bleo Holm FPSO,

the additional potential emissions are sufficiently low that no cumulative impact on local air

quality is expected. The drilling activities associated with the Liberator Field Development are

sufficiently far from the Scottish coast (64 km) and UK/Norway median line (174 km) that

there will be no significant coastal or transboundary impacts.

Global Climate Change

To understand the potential impact from the atmospheric emissions associated with the

Liberator Field Development, it is useful to set the emissions in the context of wider UK

emissions (and not only in context of emissions in the local area). The total annual CO2e

emissions from upstream UKCS oil and gas exploration and production was 15.7 million

tonnes in 2017 (Oil & Gas UK, 2018). Liberator production would contribute a 0.1% increase

to this annual total and a similar percentage increase to the UKCS annual CO2 emissions (14.2

million tonnes in 2017; Oil & Gas UK 2018).

The latest total annual CO2 emissions estimate for UK shipping is approximately 11,000,000

tonnes (for 2013, DECC, 2015, cited in Committee on Climate Change, 2015). The Liberator

drilling and subsea installation operations will contribute 0.3% to this total, although the

drilling operations will be split over 3 years so in reality the contribution would be far smaller.

Table 5-8 UK Carbon Budget

Budget Annual carbon budget % reduction below base

year (1990)

1st carbon budget (2008 to 2012) 3,018 million tonnes (Mt) CO2e 23%

2nd carbon budget (2013 to 2017) 2,782 MtCO2e 29%

3rd carbon budget (2018 to 2022) 2,544 MtCO2e 35% by 2020

4th carbon budget (2023 to 2027) 1,950 MtCO2e 50% by 2025

5th carbon budget (2028 to 2032) 1,765 MtCO2e 57% by 2030



162

In total emissions from the drilling, completion, installation and operation of the Liberator

Field Development are estimated to be approximately 186,384 tonnes of CO2. Whilst this is a

very small percentage of current UK offshore emissions, the UK Government has set a target

of reducing the UK’s overall GHG emissions by 80% by 2050 as part of the Climate Change

Act 2008 and a series of phased budgets have been implemented (Table 5-8), with the 5th

carbon budget setting a 57% reduction by 2030. As such, it is likely that the total annual

emissions from the UK will decline over the life of the Liberator Field Development and it is

important therefore to examine how the Liberator Field Development will sit within the context

of declining UK emissions.

Table 5-9 presents Liberator Field Development CO2e emissions against UK carbon budgets.

Table 5-9 Liberator Field Development CO2e emissions against UK carbon budget

Emission item Carbon accounting period

2018 to 2022 2023 to 2027 2028 to 2032

UK carbon budget for period (tonnes

CO2e) 2,544,000,000 1,950,000,000 1,725,000,000

Liberator Field Development emissions

for period (tonnes CO2e) 71,202 64,372 32,186

Liberator Field Development CO2e

emissions as % of UK budget 0.003 0.003 0.002

The emissions from the Liberator Field Development are spread across 3 UK carbon budget

periods, with the most in the 3rd UK carbon budget period from 2018 – 2022. For this carbon

budget period, the UK’s total carbon budget is 2,544 MT CO2e. The total estimated Liberator

Field Development CO2e emissions for this five-year period is equal to approximately 0.003%

of the whole UK budget, a very small component of the overall emissions in the UK. It should

also be noted that, to an extent, the additional CO2 emissions from the Liberator Field

Development will be offset by reducing emissions associated with currently declining

production in other UK oil and gas fields.

Offshore oil and gas flaring contributed 3.7 million tonnes of CO2e in 2017, against which

Liberator would provide an increase of 0.09% per year. This is a very minor increase and would

also keep the facilities within the permitted flaring volumes detailed in the Bleo Holm flare

consent. As discussed above no increase in venting is expected, but if there was an increase of

10% then Liberator would add 76 tonnes to the 62,000 tonnes vented by the oil and gas offshore

industry in 2017 (Oil & Gas UK, 2018), again a very small increase.

Overall, this assessment shows that the potential emissions from the Liberator Field

Development will likely have a limited cumulative effect in the context of the release of GHGs

into the environment and their contribution to global climate change (i.e. the Development will

not lead to a significant cumulative or transboundary impact).



163


The Liberator field is located approximately 174 km from the UK/Norway median line. Due

to this distance there are expected to be no significant transboundary impacts as a result of

changes in air quality in the Liberator field.

The impact assessment presented above for cumulative impact demonstrates that the Liberator

Field Development activities will make no significant contribution to UK emissions to the

global atmosphere. As such, there will be no significant transboundary impacts.

Decommissioning

At the end of field life, the Liberator Field Development will be decommissioned. The

decommissioning process will generate atmospheric emissions both directly from cessation

operations and associated vessel traffic, and indirectly through the reuse and recycling of

materials (e.g. steel). It is not possible at this stage to fully quantify the likely atmospheric

emissions, and exact emissions will depend on the removal technologies available at that time,

as well as the regulatory requirements. It is anticipated that atmospheric emissions are likely

to be limited compared to those seen during installation and commissioning activities since the

main source of emissions during the commissioning stage is from the drilling rig (Section

5.6.1).

Protected sites

Atmospheric emissions associated with the Liberator Field Development will not occur within

any SAC, SPA, NCMPA or MPA. The atmospheric emissions are expected to represent a very

small percentage of UK emissions and there is considered to be no cumulative impact from the

Project with regards to the potential impact on protected sites. As such there is considered to

be no Likely Significant Effect on SACs and SPAs and hence no impact on conservation

objectives or site integrity. This assessment also considers there to be no potential for

atmospheric emissions to interact with protected features of an NCMPA or MPA and there is

therefore no significant risk to the conservation objectives of any NCMPA or MPA. No impact

is expected on the seabed habitat features identified in FEAST.

Residual impact

Given the temporally restricted nature of the majority of the atmospheric emissions from the

Project and taking into account the distance that the Liberator field is from any potentially

sensitive receptors, it is not expected that atmospheric emissions will negatively impact local

air quality. In terms of global climate change (i.e. cumulative and transboundary impacts), the

Liberator Field Development will add a relatively small increment to the overall offshore

emissions of the UK and the release of GHG into the environment and their contribution to

global warming will be negligible or minor in relation to those from the wider offshore industry

and outputs at a national or international level. Any cumulative impact is therefore considered

not to have a direct impact on climate change.

Considering all of the above, including that there will be no impact on protected sites or on

species from protected sites, the residual consequence of atmospheric emissions is ranked as

negligible. As the majority of emissions will occur during the drilling and installation phases

and the only operational emissions will be the limited flaring and maintenance activities, the



164

frequency is defined as infrequent. As a result, the residual risk of atmospheric emissions from

the Liberator Field Development will be negligible and is therefore not significant.


Atmosphere Low Low Low Minor

Rationale



On the basis that the atmosphere has the capacity to accept the emissions without change, the receptor

sensitivity is ranked as Low. As the sensitivity is ranked as low and the magnitude is ranked as

minor, vulnerability is considered to be low. A ranking of low has been assigned to the value of the

receptor as there are no air quality issues identified in the vicinity and the impact will only impact on

a small area of the atmosphere in the immediate vicinity of the Liberator field. In a global climate

context, the anticipated emissions from the Project activities are limited. Considering this, including

that effects unlikely to be discernible or measurable, the magnitude of impact is ranked as minor. On

this basis, the consequence is negligible and the impact not significant.


Negligible Not significant

5.7 Accidental Events

Introduction

The potential impact of any accidental hydrocarbon and chemical release will be determined

by the characteristics of the release of hydrocarbons or chemicals, its weathering properties,

the direction of travel and whether environmental sensitivities lie in its path. These

environmental sensitivities will have spatial and temporal variations. Therefore, the likelihood

of any accidental release having a potential impact on the environment must consider the

likelihood of the release occurring against the probability of that hydrocarbon or chemical

reaching a sensitive area and the environmental sensitivities present in that area at the time of

hydrocarbon or chemical release.

Sources and likelihood of occurrence

5.7.2.1 Blowout and well releases

Primary well control is the process which maintains a hydrostatic pressure in the wellbore

greater than the pressure of the hydrocarbons in the formation being drilled via a drilling

fluid/mud. If the formation pressure is greater than the hydrostatic pressure of the drilling fluid

in the wellbore the well will flow and the hydrocarbons will enter into the wellbore. If the

primary well control fails this flow may be stopped by closing the BOP, which is the initial

stage of secondary well control. Secondary well control is completed by circulating out the

hydrocarbons and displacing the wellbore to the new kill weight drilling fluid / mud. If primary

and secondary well control fail, a blowout may occur.

A surface blowout is defined as an uncontrolled flow of formation hydrocarbons from the

reservoir to the surface which occurs as a result of loss of primary (hydrostatic pressure) and



165

secondary (BOP) well control, and may lead to the potential for release of hydrocarbons to the

environment. An underground blowout is when downhole pressure exceeds the fracture

pressure of a formation and hydrocarbons flow into the weaker formation.

A well release is defined as formation hydrocarbons flowing from the well when flow was not

intended, but only when flow was subsequently stopped by use of the barrier system that was

available on the well at the time that the incident started as such, the quantities of hydrocarbons

released during a well release are usually much smaller than during a blowout.

The Liberator reservoir contains an undersaturated oil (30.3⁰ API, 10.7% wax content). The

proposed Liberator wells will be drilled from a semi-submersible drill rig. Whilst historical

data for frequency of blowouts from drill rigs on the UKCS between 1990 and 2007 (Table B

1, Appendix B) do not provide information on the severity of the event or whether the blowout

or well leak led to an oil accidental release, they do provide an indication of overall frequency

of blowouts in the UKCS. Between 1990 and 2007, blowout frequency was 0.014 incidents

per year.

Blowouts are extremely rare events in modern drilling (Oil & Gas UK, OGUK, 2009; Table B

2, Appendix B); whilst over 6,000 development wells drilled on the UKCS between 1980 and

2010 (UKOOA, 2010), International Association of Oil & Gas Producers (IOGP, 2010) report

that only 34 development drilling blowouts were recorded over the same period (and those

blowouts also included a number in the Norwegian sector of the North Sea). Based on IOGP

(2010) analysis (detailed in Table B 3 in Appendix B) and on the probability definitions in

Table 4.8 in Section 4, the likelihood of a blowout is considered remote, and a well release is

considered unlikely. Nevertheless, as the consequence of a hydrocarbon release of any nature

is potentially significant, i3 will implement rigorous measures to reduce the potential for a

failure of well control and ensure effective response should an incident occur (these are detailed

in Section 5.7.5).

5.7.2.2 Drill rig accidental releases

The proposed wells will be drilled from a semi-submersible drill rig. Potential accidental

releases from drill rigs may be caused by mechanical failure, operational failure or human error,

and release sources include drilling muds, oil and chemicals and hydraulic fluids.

During the period 2001 to 2007, 172 years of operational activity were logged by drill rigs on

the UKCS with no accidental releases greater than 100 tonnes recorded. The majority of

accidental releases recorded were less than 1 tonne (Table B4, Appendix B). The most

common types of accidental release from drill rigs were found to be associated with drilling

(42%); 94% of which were less than 1 tonne. The second most common type of release was

from maintenance/operational activities (27%), with 97% of these less than 1 tonne. In addition

to accidental releases generally being small volumes, the number and frequency of accidental

releases has declined in recent years (Table B 5, Appendix B).

Other than blowouts, the types of credible accidental loss scenarios associated with the drill rig

which could result in the greatest environmental impact could be collision, explosion or vessel

grounding (although the latter is unlikely to be associated with the Liberator Field



166

Development), which could result in a total loss of hydrocarbon inventory. The largest fuel

inventories will be associated with the drill rig, although it is unlikely that the maximum storage

capacity of marine diesel would be maintained for any extended period. In terms of collision

with drill rigs, available data indicate a reduction in the frequency of such incidents between

1990 and 2007 (Table B6, Appendix B).

5.7.2.3 Subsea tie-backs

Of all accidental releases reported from subsea tie-back facilities between 1975 and 2007, the

majority (over 70%) were less than 1 tonne (TINA Consultants Ltd, 2013) (detailed in

Appendix B).

5.7.2.4 Pipelay and other support vessel accidental releases

Potential sources of accidental releases from pipelay and support vessel operations include:

• Upsets in bilge treatment systems;

• Storage tank failure of lube oils, fuel oil (diesel), oil-based mud, base oil and chemicals;

• Accidental release during maintenance activities including equipment removal and

lubrication;

• Refuelling and cargo loading operations in port; and

• Damage sustained during a collision, grounding or fire.

The most frequently reported accidental releases from vessels are associated with upsets in

bilge treatment systems and are usually small (<1 tonne). The most recent Advisory

Committee on Protection of the Sea (ACOPS) report on discharges to sea states that in 2014,

approximately 73% of accidental chemical releases involved PLONOR chemicals, which are

considered to ‘pose little or no risk’ to the environment (ACOPS, 2015). No chemicals that

are included in the OSPAR list of chemicals for priority action (i.e. those which are considered

to pose the greatest potential impact) were released and none of the releases were recorded as

having resulted in a significant environmental impact.

Behaviour of hydrocarbons at sea

The potential environmental impact of an accidental hydrocarbon release depends on a wide

variety of factors, which include:

• Release volume;

• Type of hydrocarbon released;

• Direction of travel of the release;

• Weathering properties of the hydrocarbon;

• Any environmental sensitivities present in the path of the release (these may change

with time); and

• Sensitivity of the impacted locations.



167

The Oil Spill Contingency and Response (OSCAR) model has been developed by Sintef to

model the fate of accidentally released hydrocarbons at sea. It has a built-in oil database,

containing over 110 oils, along with various gridded wind and current files, originally produced

by the Norwegian Met Office. OSCAR is a three-dimensional model, designed to predict the

fate of oil particles at the surface, sub-surface and once dissolved. OSCAR calculates and

records the distribution in three physical dimensions, plus time, of a contaminant on the water

surface, along shorelines, in the water column, and in the sediments.

The model is capable of undertaking both stochastic and deterministic modelling:

• The stochastic mode is used to estimate the likelihood of particular trajectories

occurring, based on historical wind speed and direction data. Stochastic models, often

called probability models, show the probability of where an oil spill may migrate from

the spill source under different environmental conditions. The model computes a series

of trajectories under various wind and current conditions from the historic wind records

and current records. These results are combined a probability density map of the spatial

likelihood of oil occurrence; and

• The deterministic mode is used to predict the route of a hydrocarbon slick over time,

and to estimate the oil weathering profile, under specific meteorological conditions.

Modelling outputs include the trajectory of the slick and mass balance estimates over

time (i.e. the slick volume and how much oil is estimated to have dispersed, emulsified

or evaporated). In essence, deterministic modelling investigates whether or not, and

how quickly, oil might beach under a constant (typically worst-case) wind speed and

direction.

Seasonal (winter – December to February, spring – March to May, summer – June to August

and autumn – September to November) stochastic modelling using OSCAR was undertaken in

line with the latest Oil Pollution Emergency Plans (OPEP) guidance (BEIS 2017). A minimum

of 100 runs were performed for each season, with the historical meteorological data used to

inform the model spanning a period of 7 years from 2008 – 2014.

The accidental release scenarios modelled for the Project are detailed in Table 5-10. In line

with current regulatory and industry commentary and experience with worst-case scenario

identification, the following assumptions have been made whilst undertaking the modelling for

the Liberator Field Development:

• Interactions: all scenarios are run with the assumption that there is no response from

any party, operator, local or national government. This approach is taken in order to

view the worst-case predictions of a spill and should be used as guidance only to build

and define oil spill contingency and response plans; and

• Timeframes: all modelled runs were given 10 days following cessation of release.

In order to set limits for when the spilled hydrocarbon can be considered insignificant in the

environment, the following thresholds have been used:



168

• A minimum surface oil thickness threshold of 0.3 μm has been used for all modelled

scenarios in line with BEIS guidance; and

• No such threshold was applied for shoreline oiling.

Modelling of a diesel release from the FPSO or drill rig has not been conducted for this ES.

The estimated combined total diesel inventory of the drill rig (1,178 m3) and of the Bleo Holm

FPSO (3,121 m3) comprises a much smaller volume of hydrocarbons than that associated with

well blowout (30,341 m3). Diesel is much more volatile than the crude oil expected from

Liberator, and in the event of a diesel inventory spill, the majority of the diesel would be

expected to evaporate within a few days, before reaching any sensitive coastlines. Diesel has

a lower specific gravity than crude oil and would be expected to float on the sea surface,

meaning there would be no interactions expected with seabed habitats, and the hydrocarbons

would be constantly exposed to weathering and evaporation. The only potential impact of a

diesel release in the Liberator field is likely to be on seabirds located relatively close to the

Project location, and any impacts that did occur would be much reduced compared to those

associated with crude oil from a well blowout on the same receptors. The well blowout

scenario is therefore considered to be the worst case, and it is not envisaged that any potential

impacts will be overlooked through omission of diesel release modelling.

Table 5-10 Summary of accidental release scenarios modelled for the Project

Scenario

No. Scenario description

Hydrocarbon

type Release volume

Modelled

depth of

release

Model

type

1 Well blowout at

Liberator L2 well using

the highest

unconstrained well flow

rate for 84 days

Crude oil 30,341 m3 oil

over 84 days

(variable

flowrate)

Surface,

followed

by subsea

Stochastic

5.7.3.1 Scenario 1: Well blowout at L2

Well blowout modelling was undertaken for the L2 well in the original Liberator development

layout. Although the L2 well is 3km to the east of the current Liberator drill centre, the

flowrates, characteristics of the oil and receiving environment are all the same as for the current

Liberator wells. As the site is >60 km from the nearest coastline it is not expected that a 3km

difference in well release location will affect the outcome of the oil spill modelling.

The surface probability of contamination is presented in Figure 5-3. Surface minimum arrival

time of released hydrocarbon is illustrated in Figure 5-4. The minimum crossing times to all

relevant median lines are shown in Table 5-11. Modelling indicated that there was a probability

of 90 - 100% of oil crossing the UK/Norway transboundary line within five days of release (or

three days in winter). The probability of oil crossing any other transboundary lines was less

than 30%.



169

Table 5-11 Shortest time to reach and probability (≥1%) of surface oil (≥0.3 μm) crossing median line

Shortest time to reach and probability (≥1%) of surface oil (≥0.3 μm) crossing median line

Median line Dec – Feb Mar – May Jun – Aug Sep – Nov

Norway 3 days 5 days 5 days 5 days

90 -100 90 -100 90 -100 90 - 100

Denmark 13 days >20 days >20 days >20 days

20 - 30 20 - 30 20 - 30 5 - 10

Sweden >20 days >20 days >20 days >20 days

10 - 20 10 - 20 10 - 20 1 - 5

Germany >20 days >20 days >20 days >20 days

5 - 10 1 - 5 5 - 10 1 - 5

Netherlands >20 days - >20 days -

1 - 5 - 5 - 10 -

Faroes - >20 days - -

- 1 - 5 - -



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Probability of Surface Oiling Meeting or Exceeding 0.3 μm

Figure 5-3 Scenario 1 – well blowout: surface probability of contamination (above 0.3 μm thick)

Dec - Feb

Dec - Feb

Mar - May

Mar - May

Jun - Aug Sep - Nov

Sep - Nov



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Arrival Time of Surface Oil

Figure 5-4 Scenario 1 – well blowout: surface arrival time (above 0.3 μm thick)

The shortest arrival time for oil beaching on North Sea coastlines in each season is presented

in Table 5-12. The probability of shoreline oiling is generally less than 30% for most areas;

the areas at most risk are expected to be Grampian (up to 70% probability within 2 days) and

Orkney (up to 40% probability within 2.5 days).

Dec - Feb

Dec - Feb

Dec - Feb

Dec - Feb

Mar - May

Mar - May

Mar - May

Mar - May

Jun - Aug

Jun - Aug

Jun - Aug

Jun - Aug

Sep - Nov

Sep - Nov

Sep - Nov

Sep - Nov



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Table 5-12 Shortest time and probability (≥1%) for shoreline oiling after 94 days

Shortest time and probability (≥1%) for shoreline oiling after 94 days

Shoreline Dec – Feb Mar – May Jun – Aug Sep – Nov

United Kingdom

Scotland

Shetland 8 days >20 days >20 days 7 days

20 - 30 10 - 20 5 - 10 10 - 20

Orkney 57 hours 3 days 3 days 3 days

30 - 40 30 - 40 20 - 30 20 - 30

Highlands 5 days 4 days 7 days 5 days

20 - 30 20 - 30 10 - 20 10 - 20

Grampian 3 days 2 days 3 days 3 days

40 - 50 60 - 70 30 - 40 40 - 50

Tayside and Fife 10 days 14 days 15 days 10 days

10 - 20 20 - 30 5 - 10 10 - 20

Lothian and Borders 17 days 19 days >20 days >20 days

10 - 20 10 - 20 1 - 5 1 - 5

England

North East >20 days >20 days >20 days >20 days

10 - 20 10 - 20 5 - 10 5 - 10

Yorkshire and The Humber >20 days - >20 days >20 days

1 - 5 - 1 - 5 1 - 5

Other North Sea States

Norway >20 days >20 days >20 days 12 days

30 - 40 10 - 20 30 - 40 30 - 40

Denmark >20 days >20 days >20 days >20 days

20 - 30 5 - 10 10 - 20 20 - 30

Sweden >20 days >20 days >20 days >20 days

5 – 10 1 - 5 1 - 5 5 - 10

Germany >20 days - - -

1 - 5 - - -

Netherlands - - - -

- - - -

Maximum mass accumulated onshore across all beaching locations4

After 94 days 4,505 m3 6,708 m3 3,836 m3 3,002 m3

4 This is the maximum mass accumulated onshore across all beaching locations from the single

worst case simulation in each season.



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Environmental vulnerability to spills

Environmental vulnerability to spills is a function of both the likelihood of impact from a spill

(as considered in previous sections) and the sensitivity of the environment. Offshore and

coastal vulnerabilities need to be considered separately as different parameters will apply.

There can be impacts on plankton in the immediate area of the release for the duration of the

release due to the dissolution of aromatic fractions into the water column. Such effects will be

greater during a period of plankton bloom and during fish spawning periods. Contamination

of marine prey including plankton and small fish species may then lead to aromatic

hydrocarbons accumulating in the food chain. These could have long-term chronic effects such

as reduced fecundity and breeding failure, on fish, bird and cetacean populations. This may

affect fish stocks of commercially fished species. A major release could also have a localised

effect on the fishing industry, should certain areas be temporarily closed to fishing.

Juvenile fish and eggs are potentially the most sensitive life-stage to hydrocarbon discharges.

As outlined in Section 3.5.3, a number of commercially important pelagic and demersal fish

species are found in the vicinity of the Project. Patin (2004) suggests that impacts on plankton

and fish in the open sea are unlikely to be detectable against natural background variation.

The JNCC has stated in a memorandum to the UK Parliament that the greatest risks to nature

conservation of oil on the offshore sea surface are to seabirds (JNCC, 2011). The magnitude

of any impact will depend on the number of birds present, the percentage of the population

present, their vulnerability to spilled hydrocarbons and their recovery rates from oil pollution.

The physical impact of a spill is one of plumage damage leading to loss of insulation and

waterproofing as well as toxicity of ingested oil. The seasonal sensitivity of seabirds to surface

pollutants in the immediate vicinity of the Project, derived from JNCC block-specific data

(JNCC, 2016b), suggest that seabirds in the Project area have an overall low sensitivity to

surface pollution, although some of the blocks exhibit high or very high sensitivity at certain

times of the year (see Section 3.3.33.3.3). There is a period of concern for drilling activities

in Block 13/23 for May to September, within the planned drilling campaigns. However, this

period of concern is based on the Offshore Vulnerability Index (OVI; JNCC 1999), which was

superseded by the SOSI data in 2016. BEIS recommend that operators check any periods of

concern with the SOSI data to identify whether there are any sequential months of very high

seabird sensitivity. The SOSI data shows there are no two sequential months of very high

seabird sensitivity in Block 13/23 and therefore the period of May to September is not deemed

of concern based on the current criteria.

Cetaceans are also present in the vicinity of the Project area (see Section 3.3.40). In the event

of a spill, the degree of impact will depend on the species and their feeding habits; the overall

health of individuals before exposure; and the characteristics of the hydrocarbons. Baleen

whales are particularly vulnerable whilst feeding, as oil may stick to the baleen plates if the

whales "filter feed" near surface slicks. Cetaceans are pelagic (move freely in the oceans) and

migrate. Their strong attraction to specific areas for breeding or feeding may override any

tendency cetaceans have to avoid hydrocarbon contaminated areas. It is thought unlikely that



174

a population of cetaceans in the open sea would be affected by a spill in the long-term (St.

Aubin, 1990).

The likelihood of a hydrocarbon spill impacting the coastal environment is a function of the

likelihood of a hydrocarbon spill occurring and the probability of the spilled hydrocarbons

beaching. The level of impact is also directly related to the volume of hydrocarbon beaching,

the composition of the beached hydrocarbons, and the type of beach. The hydrocarbon

associated with the Project that may beach in the event of a spill is crude oil with a relatively

high API gravity5 of 30.3 which is likely to float on the water surface. Modelling indicates that

3,002 – 6,708 m3 of crude oil may beach in the event of an uncontrolled well blowout, and that

the most likely shorelines to be impacted are those of Grampian and Orkney (Table 5-12).

Coastal environmental sensitivities to spills include nearshore breeding seabird populations,

shore birds, over wintering diver and duck species, marine mammals, mariculture operations

and sub-littoral and coastal habitats including SACs and SPAs.

Shoreline arrival probability is predicted to be highest for the Grampian coast (2 days). The

map showing shellfisheries and areas of aquaculture (Figure 3-10) shows that there are no

relevant sites on the Grampian coast and therefore the likelihood of significant impact on

shellfish and aquaculture sites is very low. Whilst there are a small number of protected

shellfish waters on Orkney, where probability of shoreline beaching was next highest (3 days),

arrival of hydrocarbons would be expected primarily on the eastern coast, away from the key

relevant sensitivities. Given the limited number of sensitive locations within the potential area

of impact from a hydrocarbon release, the low likelihood of release occurring, and the

mitigation measures outlined below, impact is not expected to be significant.

Intertidal areas of the coast show varying degrees of sensitivity to spills, this variability is a

function of both actual effects on specific organisms and the physical fate of the released

substances within the habitat concerned. For example, high energy rock, boulder or cliff

coastlines tend to have lower sensitivity to hydrocarbon pollution because oil is rapidly broken

up and dispersed by wave action, and beached oil remains on the surface of rocks and is

exposed to weathering. In contrast, sheltered, low energy shorelines tend to have moderate to

high sensitivity because oil is not broken up by wave action and it can be mixed into the

sediment where it is not exposed to weathering and therefore persists for longer. In general

terms the shorelines most likely to be exposed to beached hydrocarbons from Liberator are of

low to moderate vulnerability to hydrocarbon pollution (Gundlach and Hayes, 1978).

Mitigation

5.7.5.1 Company Approach

Well blow out is identified as a key risk to environment (and safety) during drilling operations

and i3 has insurance in place for possible pollution events resulting from such an event. This

5 American Petroleum Institute (API) index is a measure of how heavy or light a petroleum

liquid is compared to water: if its API gravity is greater than 10, it is lighter and floats on water;

if less than 10, it is heavier and sinks.



175

includes membership of The Offshore Pollution Liability Association and suitable Financial

Responsibility cover for the Liberator wells. During well operation, i3 will contract Petrofac

Emergency Management to provide resources for emergency response provision, utilising

Petrofac’s Aberdeen Emergency Response Centre. i3 will retain internal emergency response

knowledge and personnel familiar with the undertaking of Secretary of State’s Representative

(‘SOSREP’) exercises and will provide on-call personnel for Company representation

throughout any active Emergency Response. i3 has internal capability via a trained and

experienced Oil Spill Response Manager at Level 4.

5.7.5.2 Specific Control Measures

The following provides an overview of proposed measures that either reduce the probability of

an accidental release, or reduce the consequences in the event of a release:

• The Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations

2015 implement the EC Offshore Directive. As part of this, a verification scheme exists

for safety and environment critical elements (SECEs). i3 will identify SECEs in future

design stages;

• Wells and associated subsea infrastructure will be designed as per OGUK best practice;

• The drill rig will have a minimum 10,000 pound per square inch BOP stack (standard

for drill rigs);

• Installation and supply vessel personnel will be given full training in chemical release

prevention and actions to be taken in the event of an accidental chemical release;

• An appropriate OPEP will be in place, including access to the oil spill modelling tool

OSCAR and appropriate response planning;

• Shipboard Oil Pollution Emergency Plans (SOPEPs) will be in place where appropriate;

• Development of and conformance to appropriate equipment containment maintenance

procedures;

• Simultaneous operations (SIMOPs) that could result in a spill to sea will be actively

identified and managed;

• The drill rig will be subject to an environmental containment audit which will cover oil

spill response, procedural controls, bunkering and chemical storage arrangements;

• Visual inspection of hose certificates and connections will be conducted prior to use;

• Tool box talks will highlight the importance of minimising the risk of spills occurring.




Existing hydrocarbon spill risks in the North Sea are associated primarily with oil and gas

industry activities as well as other marine industries such as merchant shipping and fishing. As

indicated by historical data, the likelihood of a well blowout occurring is remote, meaning the



176

likelihood of cumulative impacts occurring from simultaneous or consecutive spills at the

Liberator Field Development and other installations (including the existing Bleo Holm FPSO)

is extremely unlikely.


Worst-case scenario spill modelling indicated that a well blowout at Liberator would likely

result in oil crossing the UK/Norway transboundary line, but oil was unlikely to reach the

transboundary lines shared with other North Sea states.

The risk of a spill having a transboundary impact, particularly from North Sea operations, is

recognised by the UK Government and the governments of other states bordering the North

Sea. International agreements are in place for dealing with transboundary spill incidents. In

the event of a major spill which is predicted to drift into Norwegian waters, the Norway-United

Kingdom Joint Contingency (NORBRIT) plan will be activated. This plan operates within the

framework of the National Contingency Plans and is oriented towards major spills. It becomes

operational when agreement to the request for its implementation is reached. Responsibility

for implementing joint action rests with the Action Co-ordinating Authority (ACA) of the

country on whose side of the median line a spill originated. The UK’s ACA is the Counter

Pollution Branch of the Maritime and Coastguard Agency.

The Espoo Convention requires notification and consultation for projects likely to have a

significant adverse environmental impact across boundaries. Since the probability of a well

blowout occurring is remote, the probability of a transboundary impact is also considered

remote, and therefore consultation under the Espoo Convention, is not expected to be required

for the Liberator Field Development.

Socio-economic vulnerability to spills

In the event of a major release from a well blowout, there would probably be an exclusion of

commercial fishing from the area until it could be determined that hydrocarbon levels had

diminished, and the absence of taint had been confirmed. Exclusion would probably be in the

order of weeks following the end of such an incident given the nature of the hydrocarbons

involved. There also exists the possibility that a release could impact on coastal fisheries,

including sites of aquaculture interest. However, an accidental hydrocarbon release large

enough to cause impact upon the UK coastline and coastal waters is remote.

Accidental hydrocarbon releases may also have a direct impact on the amenity value of the

coastline due to the physical and visual impact of oiling. The effect is generally short-lived as

a large proportion of beached oil is broken down by natural means or mechanical removal.

Perception of damage may be longer lived, particularly by potential tourists. The tourism

industry of coastal populations represents a significant proportion of the local economy value

with walking, ornithology, sailing, fishing, archaeology and diving being the most important.

Mirroring the issues associated with public perceptions of fisheries produce, experience

following the Braer incident in Shetland showed that marketing efforts were necessary to

reassure tourists.



177

However, an accidental hydrocarbon release large enough to cause impact upon the UK

coastline and coastal waters is remote and it is therefore concluded that the Liberator Field

Development is very unlikely to have a significant impact upon UK coastal industries.

Decommissioning

Cessation of production will remove one of the main sources of potential accidental

hydrocarbon release since there will no longer be a hydrocarbon flow from the wells or through

the pipeline system. Additional vessels will be required to execute decommissioning activities,

with potential impacts related to accidental hydrocarbon and chemical release from those

vessels likely to occur at a similar magnitude to those associated with installation activities.

Protected sites

5.7.10.1 Direct interaction with coastal sites

The assessment of potential impacts presented in this chapter has, where appropriate, taken

account of protected sites. This section considers the potential for accidental events related to

the Liberator Field Development to impact upon the conservation objectives (and ultimately

site integrity) of important protected sites, specifically SPAs, SACs, NCMPAs and MCZs. The

output of the accidental hydrocarbon release modelling described in Section 5.7.3.1 has been

compared against the location of coastal SPAs, SACs, NCMPAs and MCZs to determine where

there is considered to be the potential for interaction. Marine Scotland’s FEAST tool has been

used to identify any habitats within protected sites that may be particularly sensitive to

hydrocarbon contamination. Coastal sites for which possible interaction has been identified

are (Figure 5-5):

• The proposed Southern Trench NCMPA;

• The Noss Head NCMPA;

• The East Caithness Cliffs NCMPA/SPA; and

• The Moray Firth SAC.

The proposed Southern Trench NCMPA boundary is located 37 km southwest of the

release site. The proposed Southern Trench MPA site has been designated for its relatively

high population of minke whales, its pelagic frontal zones, shelf deeps and burrowed muds

(a habitat feature identified in the FEAST tool). Any accidental release of oil entering the

site is expected to primarily remain on the water surface, and as such, the pelagic and

seabed features of interest are not expected to be significantly affected. The minke whale

population may be affected if individuals encounter oil when surfacing, which may cause

skin irritation and irritation of mucous membranes in oil is inhaled. Minke whales may

also ingest contaminated prey items. These impacts are considered unlikely to cause long-

term physical injury or death. The minke whale population may exhibit avoidance of

spilled oil, although attraction to the area may override avoidance of surface oil. In

summary, whilst there may be some impacts on the local minke whale population,

significant impacts upon the features of the site will not occur, and there will thus be no

effect on the integrity of the site or on the ability to meet the conservation objectives of the

site.



178

Figure 5-5 Coastal protected sites which may be affected by a Liberator well blowout event

The Noss Head NCMPA is located 95 km west of the Liberator field and was designated to

protect Scotland’s largest horse mussel bed. Horse mussel beds are listed as sensitive to

hydrocarbon contamination in FEAST. However, the site is located in water depths of 35 m –

45 m. As such, it is not expected that an oil spill would significantly impact the site, as the

majority of the oil would remain at the sea surface. Consequently, significant impacts upon

the features of the site will not occur, and there will thus be no effect on the integrity of the site

or on the ability to meet the conservation objectives of the site.

The East Caithness Cliffs NCMPA/SPA is located approximately 96 km west of the Liberator

field. The NCMPA covers nearshore waters out to 2 km from the shore between Wick and

Helmsdale, a distance of 50 – 60 km. The MPA was designated to protect the black guillemot



179

population that inhabits the cliffs on the shoreline. The SPA designation is related to breeding

aggregations of common guillemot, herring gull, black-legged kittiwake and razorbill, as well

as supporting an internationally important number of breeding individuals from a range of

species. Black guillemots typically feed in inshore waters close to their breeding sites, which

they inhabit all year. As such the MPA covers water that is used all year round by the local

population. Black guillemots spend considerable time on the water surface, and their feeding

strategy is to dive up to 50 m below the water foraging for fish and crabs. They are therefore

vulnerable to surface slicks and oil dispersed in the water column, and they tend to remain in

one area as a distinct population, meaning that an oil spill interacting with this site could impact

upon this species. This conclusion is supported by the FEAST assessment of black guillemot

as sensitive to hydrocarbon pollution.

For many seabirds, once breeding is complete, individuals are no longer restricted to foraging

within certain distances (i.e. foraging ranges) from their breeding colony as there is no longer

any requirement to return to eggs or chicks. For a number of key species, there is strong

evidence that once birds leave the breeding colony they become widely dispersed over large

distances, often intermingling with birds from other breeding colonies (typically of the same

species) and in some cases birds that have migrated from overseas breeding colonies (Furness,

2014). Consequently, given that individuals from an SPA population become so widely

dispersed, the potential for an impact to any of these birds becomes significantly diluted.

Potential impacts on birds during the non-breeding season (i.e. when they are offshore) are

expected to be negligible.

The remote probability of a large accidental release, in conjunction with the proposed

mitigation measures means significant impacts upon the features of the site is unlikely, and

there will thus be limited effects on the integrity of the site or on the ability to meet the

conservation objectives of the site.

The Moray Firth SAC boundary is located 120 km south west of the Liberator field. The site

is designated for the presence of sandbanks that are covered by seawater all the time (Annex I

habitat) and the presence of a resident population of bottlenose dolphins (Annex II species).

The probability of surface oil reaching the SAC is less than 20% (Figure 5-3). The sandbanks

are considered unlikely to be significantly affected, as the majority of any spilled oil is expected

to remain at the sea surface. The resident population of bottlenose dolphins may be affected

through skin irritation, inhalation of oil or consumption of contaminated prey, however any

interaction with a surface slick would likely be limited, and impacts are expected to be slight.

Given the remote probability of a release occurring, significant impacts upon the features of

the site will not occur, and there will thus be no effect on the integrity of the site or on the

ability to meet the conservation objectives of the site.

5.7.10.2 Direct interaction with receptors from coastal sites found offshore

In addition to direct interaction with a site (i.e. hydrocarbon crossing the boundary of a site), it

is necessary to consider the potential that some qualifying features of some sites are mobile

(e.g. seabirds, marine mammals) and that some individuals may forage or move through the

area within which an accidental release has occurred. In terms of marine mammals for which



180

sites are designated, as outlined in Sections 3.3.4 and 3.4.2, bottlenose dolphins associated with

the Moray Firth SAC are generally restricted to the 20 m depth contour and are thus unlikely

to be found in the vicinity of any potential hydrocarbon release. Harbour seals usually forage

within 40 – 50 km of their haul-out sites (SCOS, 2014), and they may therefore be exposed to

released oil. Grey seals may forage up to 200 km from haul-outs (e.g. McConnell et al., 1999)

and mainly on the seabed at depths of up to 100 m (SCOS, 2014). However, after breeding,

most grey seals at an SAC disperse away from the site, making it very difficult to assign an

individual to a particular SAC outside of the breeding season. Grey seal usage of SACs is

therefore very time and space-specific. On this basis and reviewing available data on grey seal

movements (e.g. Cronin et al., 2011; SMRU, 2011; Russell and McConnell, 2014), it is

considered that a 20 km radius around SACs may be used as a guide to the potential for

interactions with projects. Harbour seals and grey seals may be affected by surface oil in a

similar way to cetaceans, however seals are expected to exhibit avoidance behaviour and

therefore minimise exposure. In combination with the very low probability of a release event

occurring, significant impact on harbour seals and grey seals from SACs on the east Scottish

coast are not expected to occur. As such, significant impacts upon the features of any sites

with which the animals are associated will not occur, and there will thus be no effect on the

integrity of the site or on the ability to meet the conservation objectives of any such sites.

In terms of seabirds that may move offshore from SPAs into the area of potential hydrocarbon

surface oiling, it is very difficult to apportion these birds to specific SPAs, as discussed by

Furness (2014) in their study on defining biologically appropriate, species-specific, geographic

non-breeding season population estimates for seabirds. Furness (2014) used existing data and

literature in order to determine biologically defined minimum population scales for key seabird

species. For many seabirds, once breeding is complete, individuals are no longer restricted to

foraging within certain distances (i.e. foraging ranges) from their breeding colony as there is

no longer any requirement to return to eggs or chicks. For a number of key species, there is

strong evidence that once birds leave the breeding colony they become widely dispersed over

large areas, often intermingling with birds from other breeding colonies (typically of the same

species) and in some cases birds that have migrated from overseas breeding colonies (Furness,

2014). Consequently, given that individuals from each SPA population become so widely

dispersed and mixed, the potential for an accidental release to significantly impact an individual

SPA population becomes significantly reduced, as a release event is unlikely to cover a wide

enough area to reach a significant proportion of the individuals from a given SPA. Potential

impacts on birds during the non-breeding season (i.e. when they are offshore) are therefore

expected to be not significant.

5.7.10.3 Direct interaction with offshore sites

For direct interaction with offshore sites without a land component, surface occurrence of

released hydrocarbon within the site is taken as an indication that the site has the potential to

be impacted. A hydrocarbon release encountering an offshore site has been considered for

inclusion in this assessment where the probability of the encounter occurring (in the event of a

very low probability accidental hydrocarbon release such as a well blowout) is equal to or



181

greater than 5%. On this basis, interaction may occur with the following offshore sites and the

potential for Likely Significant Effect has been investigated:

• Scanner Pockmark SCI;

• East of Gannet and Montrose Fields NCMPA;

• Norwegian Boundary Sediment Plain NCMPA;

• Central Fladen NCMPA;

• Turbot Bank NCMPA;

• Firth of Forth Banks Complex NCMPA;

• Fulmar MCZ; and

• Swallow Sand MCZ.

For these sites, all of which are designated for seabed features, the likelihood of an effect from

an accidental hydrocarbon release will be determined by the direction of travel of the release,

the amount of oil released, prevailing weather and sea conditions and water depth.

The Liberator field will produce an oil which has a gravity of approximately 30.3 °API and

therefore floats on water6. Once the lighter fractions of the hydrocarbon have evaporated, the

remaining fraction is expected to form a stable water-in-oil emulsion. At deeper than 10 m

water depth, oil is unlikely to exceed background concentrations (Patin, 2004) Given that the

protected sites are in water depths ranging from a minimum of 25 m to a maximum of

approximately 200 m, it is unlikely that oil would be distributed to these depths in sufficient

quantity to affect the protected seabed features. For these reasons, there is predicted to be no

Likely Significant Effect on sites designated for seabed features and these sites are screened

out of further assessment (and here this term is used to apply to potential impacts on SACs,

SPAs, NCMPAs and MCZs). For the same reason, impacts on seabed habitat features

identified in the FEAST tool are not expected.

5.7.10.4 Cumulative and in-combination impacts on protected sites

It is important to consider the potential for cumulative impacts to arise from the Liberator Field

Development acting upon protected sites along with other developments. In terms of the

potential for accidental releases from multiple projects to act together, the small releases

outlined earlier in this assessment chapter are of limited concern due to the their spatially and

temporally restricted nature. However, larger releases that could potentially occur from a well

blowout or loss of pipeline inventory, may act cumulatively with releases from other oil and

gas projects or industries to affect the integrity of protected sites. Although, as described in

Section 5.7.2, such releases are extremely uncommon, consideration is given both to releases

occurring simultaneously and to releases occurring a number of years apart. In the first instance

of simultaneous releases, the key to limiting the potential for impact would be restricting

interaction between released fluids and the protected sites (as it is for a single release) and a

6 If API gravity is greater than 10, the hydrocarbon is lighter than water and floats; if less than 10, it is heavier and thus sinks.



182

co-ordinated response strategy between involved parties would likely be developed, focussing

on the sites most at risk. Where releases occur some time apart, the potential impact would be

related to the extent to which sites had recovered from interaction with a previous release. The

recovery period of impacted sites could be extended should it be impacted by subsequent spills.

5.7.10.5 Major Accident Hazards and Major Environmental Incidents

The Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015

were introduced to address major accident hazards and reduce the associated risks to the health

and safety of the workforce employed on offshore installations or in connected activities. It

also aims to protect the marine environment and coastal communities against pollution. As

such, it requires major accident hazards to be identified in relevant submissions, and to identify

major environmental incidents that could occur as a result of the major accident hazard

occurring. In the case of the Liberator Field Development, a well blow out is considered to be

the worst-case potential release of hydrocarbons. This scenario has been modelled and an

assessment for the purposes of this EIA presented. The modelling and assessment will also

inform the OPEP and any submissions associated with the Offshore Installations (Offshore

Safety Directive) (Safety Case etc.) Regulations 2015. The well blow out scenario would

qualify as the worst-case scenario for consideration under Offshore Installations (Offshore

Safety Directive) (Safety Case etc.) Regulations 2015, but it is unlikely to qualify as a major

environmental incident since such an incident means one “results, or is likely to result, in

significant adverse effects on the environment in accordance with Directive 2004/35/EC of the

European Parliament and of the Council on environmental liability with regard to the

prevention and remedying of environmental damage”. As noted in the assessment presented

herein for the EIA, there is expected to be no significant impact on the environment as a result

of any unlikely well blowout.

The Water Framework Directive (WFD) requires nation states to manage the water

environment on the basis of units that make sense in environmental terms (River Basin

Districts). These include all interdependent rivers, lochs, estuaries, coastal waters and

associated underground waters. For accidental events a loss of hydrocarbons from the

Liberator field could interact with coastal waters. However, the likelihood of any such release

is remote. Additionally, coastal waters in eastern Scotland and the northern isles are almost

exclusively rated good or high condition (the two top categories) and should exhibit a good

capacity for recovery following any release. As such no significant impact is expected from

the proposed activities.

The Marine Strategy Framework Directive (MSFD) aims to develop mechanisms to achieve

‘Good Environmental Status’ for EU waters. As part of this, nation states are required to

develop a set of targets / indicators for good environmental status and to monitor the status of

its water bodies. Specifically for the UK, this means the Greater North Sea and Celtic Sea

areas. The MSFD has a broader remit than the WFD, with components such as noise,

commercial fisheries and biodiversity being of interest. The potential for the Liberator project

to compromise good environmental status of UKCS waters is low with no significant impact

expected.



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5.7.10.6 Conclusions

In the event of a major oil release there is a possibility of significant impacts on the East

Caithness Cliffs NCMPA due to potential population level impacts on the resident black

guillemot population. However, with the mitigation measures identified in Section 5.7.5, and

the remote probability of a major oil release occurring, the residual impact is not expected to

be significant.

Regarding the other sites assessed, the absence of direct interaction with coastal sites, the lack

of impacts on mobile receptors from coastal sites (e.g. marine mammals, seabirds) and the

expected lack of interaction with the seabed of offshore sites, there will be no Likely Significant

Effect on SACs and SPAs and hence no impact on conservation objectives or site integrity.

This assessment also considers there to be no potential to interact with protected features of an

NCMPA or MCZ and there is therefore no significant risk to the conservation objectives of

any NCMPA or MCZ being achieved.

Residual impact

5.7.11.1 Accidental hydrocarbon release

Although the probability of catastrophic releases from the Liberator Field Development is

remote, and comprehensive prevention and mitigation measures will be in place, the residual

risk of an accidental release, and thus impact on the marine environment, remains. This is

recognised to be true for the offshore oil and gas industry in general and the formulation of

detailed and fully tested contingency response plans is thus integral to such projects. As such,

i3 will have in place a range of response/mitigation measures to address these risks (detailed

in Section 5.7.5). All applicable offshore activities associated with the Project will be covered

by approved OPEPs and SOPEPs which will set out the responses required and the available

resources for dealing with spills of all sizes. The planning, design and support of all activities

for the Project will aim to eliminate or minimise potential environmental risks. i3’s

management processes will ensure that these mitigation commitments are implemented and

monitored.

5.7.11.2 Chemical spills

In addition to the hydrocarbon spill risk, there is also the risk of a chemical spill. Chemical

spills may occur during chemical transfer, chemical/mud handling, or through mechanical

failure. The fate of any chemical entering the water column is dependent upon how

physicochemical properties influence its partitioning between seawater and its susceptibility to

degradation (DTI, 2001). Given the high energy marine environment of the wider area,

chemical spills are expected to disperse in the offshore marine environment with a possible

negligible to minor localised and transient impact on plankton or fish eggs/larvae, depending

on the season.

Spill prevention measures in place will encompass chemicals as well as hydrocarbon spills.

Pre-mobilisation audits and bridging documentation will ensure that these prevention

procedures are in place on the drilling rig, support and supply vessels. Personnel will also be

given full training in environmental awareness and spill prevention methods. Procedures will

be in place to further reduce the risk of spillage, in particular written procedures, regular



184

inspection of equipment and provision of spill kits. Chemical spill risks at the Bleo Holm

FPSO will be covered under facility specific procedures and other spill prevention measures.

To reduce the potential risk of chemical spills offshore, i3 will work with its third-party service

providers including chemical suppliers to ensure that chemical use is minimised without

compromising technical performance. Furthermore, i3 recognises that substitution is an

important part of the OSPAR Harmonised Mandatory Control Scheme (HMCS) and is

committed to use of non-substitution chemicals and to the investigation of alternatives where

this is not possible. Information on specific chemical use and associated environmental impact

assessment will be provided in the relevant permit (e.g. Master Application

Template/Subsidiary Application Template) prior to the commencement of activity. i3 will

endeavour to use chemicals with a good environmental profile (PLONOR, Cefas OCNS group

E or Gold banded chemicals) where possible to reduce potential impacts from these chemicals

on the marine environment.

Conclusion


Protected sites

and socio-

economic

features

High High High Moderate

Rationale


vulnerability and value of the receptor as follows. Given the possibility of interaction between a

range of potential receptors following a release of hydrocarbons from a well blow out, sensitivity has

been assigned as High. Similarly, it is anticipated that some features could exhibit High vulnerability

and value (e.g. sites of conservation importance) and rankings have been assigned as such. Should

a hydrocarbon release make landfall, it is expected that there could be responses from local habitats

and species and thus magnitude is ranked as ‘Moderate’.

It is recognised that a hydrocarbon release from a well blowout could result in demonstrable change

in some receptors. However, for this type of accidental event, it is especially important to assess the

likelihood of the impact occurring. Research and a review of UKCS historical data relating to well

blow out events confirm that the likelihood of a blowout is remote.

Based solely on the magnitude of the expected impact should a well blowout occur, the magnitude

would be considered moderate. However, given the mitigation measures detailed above (aligned

with improved industry standards for well design) and the likelihood of a well blowout occurring,

the consequence is assessed as low, and therefore the impact is considered not significant.


Low Not significant



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6 Environmental Management

The commitments of i3 Energy regarding environmental management are described in the

company Environmental Policy, which is shown in Section 1.3. i3 Energy has an Integrated

Management System (IMS) which underpins the company Environmental Policy and includes

arrangements for environmental management with the following intent:

“To consistently identify hazards and aspects and assess, mitigate and report, Environmental

and Business risks through all lifecycle stages.”

Element 2.0 of the IMS (‘Risk Management’) is where processes for recognising, assessing

and managing environmental aspects and impacts can be found.

The management of environmental risks associated with i3 Energy’s activities is integral with

the business decision making process; as a new operator in the North Sea, the company is keen

to demonstrate awareness of the environmental requirements and to have an environmental

management system that supports the development and commitments associated with the

submission of a formal Environmental Statement.

Consideration of the potential for impact on the environment does not end at ES submission

but continues throughout the lifecycle of the Liberator Field Development. As such, an

important element of i3 Energy’s ongoing environmental commitments will be ensuring that

the mitigation measures developed as part of the EIA are suitably managed as part of the

ongoing development of Liberator. The commitments made within this ES, in Table 6-1, will

be incorporated into an Environmental Management Plan for the Liberator Field Development

and will evolve and be updated at each stage of the Project, continuing through the execution

and operational phases.

Commitments, objectives and targets set for the Liberator Field Development will be

communicated to our key contractors and service providers pre-contract award and for the

lifecycle of the contract. Environmental performance measures will feature within the agreed

Contract KPIs. During the operational phase, an i3 Energy representative will be onboard the

drilling rig and associated construction and installation support vessels to ensure that

environmental commitments made herein are communicated and met.

Monitoring of environmental performance (including alignment with the commitments made

in this ES) will be ongoing through the life of the Project. Specific monitoring strategies will

be developed as part of the preparation of the Environmental Management Plan for a number

of activities, but are likely to be required for key purposes such as:

• Monitoring data for compliance with environmental consents and regulatory

requirements;

• Environmental data required for submission to the Environmental and Emissions

Monitoring System (EEMS); and

• To track performance against corporate objectives and targets, including improvement

programmes.



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Table 6-1 Summary of commitments and actions to be taken forward

No. ES section Topic Commitment

1 5.2 Discharges to sea i3 Energy will ensure efficient use and recovery of drilling mud.

2 5.2 Discharges to sea If used, i3 Energy will not discharge LTOBM contaminated cuttings to sea. Cuttings will be skipped and shipped ashore

for cleaning and disposal.

3 5.2 Consultation A pre-spud environmental containment audit will be conducted to ensure rig is in compliance with all relevant guidelines

and legislation, findings should be shared with BEIS to support any potential Inspectorate led Pre-Spud inspection.

4 5.3 Seabed disturbance i3 Energy will develop a detailed anchor pattern map for the drilling rig prior to mobilisation; this will take account of

any environmental sensitivities identified close to the drilling locations.

5 5.3 Seabed disturbance On the return of the drill rig to the main drill centre for subsequent drilling campaigns the same anchor pattern will be

used where possible to minimise the area of seabed disturbed.

6 5.3 Seabed disturbance The volumes and locations of rock and mattress protection will be refined during Detailed Design to reduce the footprint

on the seabed to the extent practicable.

7 5.3 Seabed disturbance Any drill cuttings accumulations along the pipeline route will be identified during the 2019 site survey and in advance of

installation operations; installation work will be routed to avoid any accumulations and prevent re-suspension of cuttings

material.

8 5.4 Underwater noise i3 Energy will adopt the latest JNCC mitigation measures with respect to VSP activities.

9 5.5 Other sea users A safety zone of 500 m in radius will be established around the drill rig during drilling.

10 5.5 Other sea users An ERRV will be on station during the period that the drill rig is in place. These vessels will ensure that other sea users

are aware of the presence of the anchor spread outside of the drill rig safety zone.

11 5.5 Other sea users Information on the location of subsea infrastructure and vessel operations will be communicated to other sea users (via

the United Kingdom Hydrographic Office) through the standard communication channels including Kingfisher, Notice to

Mariners and Radio Navigation Warnings.



187


12 5.5 Other sea users Infrastructure will be marked as hazards on admiralty charts and entered into the FishSafe system so that it may be

avoided by fishing vessels.

13 5.5 Other sea users Consultation as part of the i3 stakeholder management process will be undertaken with relevant authorities and

organisations with the aim of reducing potential interference impacts resulting from Project activities.

14 5.5 Other sea users A fishery liaison strategy will be developed and implemented by i3 Energy as part of the i3 stakeholder management

process.

15 5.5 Other sea users Regular maintenance and pipeline, umbilical and gas lift route inspection surveys will be undertaken as part of agreed

IRM strategy.

16 5.5 Other sea users Subsea tree protection structures will be designed and installed to be fishing friendly.

17 5.5 Other sea users Should wells be abandoned, wellheads will be cut off below the seabed leaving the seabed free of infrastructure that

could pose a snagging risk to fishing gear.

18 5.5 Other sea users Trenching will be conducted by mechanical means, the 2019 pipeline survey to further investigate the best method of

additional protection for the pipelines and crossings including ways to minimise rock usage and snag risk

19 5.5 Other sea users i3 will ensure that any post pipelay or subsea equipment installation survey will consider issues that impact fishing activity

so that we can take appropriate action at that time, this includes consideration to carrying out overtrawlability trials if

deemed necessary

20 5.6 Atmospheric

emissions

All combustion equipment will be subject to regular monitoring and inspections to ensure an effective maintenance

regime is in place, ensuring all combustion equipment runs as efficiently as possible.

21 5.6 Atmospheric

emissions

Installation activities associated with the Liberator Phase 1 Field Development will be carefully planned to reduce vessel

numbers, journeys and the duration of operations.

22 5.6 Atmospheric

emissions

The need for well testing will be fully considered and will be limited as far as is practicable to reduce the requirement to

flare.

23 5.7 Accidental events i3 will ensure that the drilling OPEP will conform to the latest oil spill modelling guidelines (October 2017)

24 5.7 Accidental events During Rig Intake audit the drill rig BOP stack will be subject to inspection and verification of status prior to use



188


25 5.7 Accidental events Installation and supply vessel personnel will be given full training in chemical release prevention and actions to be taken

in the event of an accidental chemical release, this will be facilitated via the Environmental Workpack developed to

support environmental compliance

26 5.7 Accidental events Development of and conformance to appropriate equipment containment maintenance procedures.

27 5.7 Accidental events Simultaneous operations (SIMOPs) that could result in a spill to sea will be actively identified and managed via the WO

planning and operational procedures, these arrangements will be verified by i3

28 5.7 Accidental events The drill rig will be subject to an environmental containment audit which will cover oil spill response, procedural

controls, bunkering and chemical storage arrangements.

29 5.7 Accidental events Visual inspection of hose certificates and connections will be conducted prior to use.

30 5.7 Accidental events Tool box talks will highlight the importance of minimising the risk of spills occurring.

31 6 Environmental

Management

Monitoring of environmental performance will be ongoing through the life of the Project to track performance against i3

and key stakeholder stated objectives, targets and improvement programmes.



189

7 Conclusion

The EIA presented in this ES has been undertaken in support of the Liberator Field

Development. The EIA has assessed the proposed installation, commissioning, operation and

eventual decommissioning of infrastructure at the Liberator field in the context of the

environmental sensitivities of the Project area and has described the control measures that will

be in place during Project execution.

7.1 Scottish National Marine Plan

The Liberator Field Development EIA has considered the objectives and marine planning

policies of the Scottish National Marine Plan across the range of policy topics including natural

heritage, air quality, cumulative and in-combination impacts and oil and gas. i3 Energy

considers that the Liberator Field Development is in broad alignment with such objectives and

policies; the extent to which the Project is aligned with the oil and gas objectives and policies

is summarised in Table 7-1.

Table 7-1 Alignment between the Liberator Field Development and the Scottish National Marine Plan (oil and gas

objectives and policies)

Objective/policy Liberator Phase 1 Field Development

details

Maximise the recovery of reserves through a focus

on industry-led innovation, enhancing the skills

base and supply chain growth.

New oil and gas source making use of up to date

and innovative technology, providing jobs and

training.

An industry which delivers high-level risk

management across all its operations and that it is

especially vigilant in more testing current and

future environments.

Extensive mitigation measures and response

strategies developed for identified risks.

Continued technical development of enhanced oil

recovery and exploration, and the associated

seismic activity carried out according to the

principles of Best Available Technique (BAT) and

Best Environmental Practice (BEP).

Use of up to date and innovative technology in

the development of a North Sea gas reserve,

aligned with the principles of BAT and BEP.

Where possible, to work with emerging sectors to

transfer the experience, skills and knowledge built

up in the oil and gas industry to allow other sectors

to benefit and reduce their environmental impact.

The Project will draw on experienced

engineers, environmental specialists and other

groups that are not necessarily limited to oil and

gas experience throughout the Project life time.

The Scottish Government will work with BEIS, the

Oil and Gas Authority and the industry to

maximise and prolong oil and gas exploration and

production whilst ensuring that the level of

environmental risks associated with these

activities are regulated. Activity should be carried

out using the principles of BAT and BEP.

Consideration will be given to key environmental

risks including the impacts of noise, oil and

chemical contamination and habitat change.

The potentially significant environmental

impacts from noise, accidental release and

habitat change have been considered within the

Liberator Field Development EIA.



190

Objective/policy Liberator Phase 1 Field Development

details

Where re-use of oil and gas infrastructure is not

practicable, either as part of oil and gas activity or

by other sectors such as carbon capture and

storage, decommissioning must take place in line

with standard practice, and as allowed by

international obligations. Re-use or removal of

decommissioned assets from the seabed will be

fully supported where practicable and adhering to

relevant regulatory process.

i3 Energy will review decommissioning best

practice closer to the point at which the Project

will be decommissioned. Full consideration

will be given to available decommissioning

options, including reuse and removal.

Supporting marine and coastal infrastructure for

oil and gas developments, including for storage,

should utilise the minimum space needed for

activity and should take into account

environmental and socio-economic constraints.

The Liberator Field Development will make use

of existing infrastructure, including the Bleo

Holm FPSO, reducing the requirement for

further offshore infrastructure.

Consenting and licensing authorities should have

regard to the potential risks, both now and under

future climates, to oil and gas operations in

Scottish waters, and be satisfied that installations

are appropriately sited and designed to take

account of current and future conditions.

The Liberator Field Development has been

developed in a way that there will not be a

significant impact on the physical, biological

and socio-economic environment. This

demonstrates an appropriate siting within the

North Sea. The selection of the proposed

concept for the Liberator Field Development

gave due consideration to how best to develop

the field in the context of existing and future

developments in the region.

Consenting and licensing authorities should be

satisfied that adequate risk reduction measures are

in place, and that operators should have sufficient

emergency response and contingency strategies in

place that are compatible with the National

Contingency Plan (NCP) and the Offshore Safety

Directive.

Potential environmental impacts have been

reviewed as part of this EIA and relevant

mitigation measures developed. The i3 Energy

response strategy to accidental hydrocarbon

release has been developed with due reference

to the NCP and Offshore Safety Directive.

7.2 Protected Sites

The majority of species protected under Annex I of the Birds Directive that are present within

the North Sea will generally be found much closer to shore and may only encounter the Project

with any regularity during the limited period of the drilling and installation activity.

There is not expected to be significant impact on any Annex I habitat.

The presence within the Liberator field of species protected under Annex II of the Habitats

Directive is limited to marine mammals. Marine mammal species that may be present in the

Liberator field occur in relatively low densities, or occur only occasionally, or as casual

visitors. i3 Energy has assessed whether the noise emitting operations (e.g. vessel use and

limited VSP) associated with the Liberator Field Development have the potential to result in

injury or disturbance to any species. This assessment concluded that there is a low likelihood

of injury (such as temporary or permanent hearing loss), or disturbance as a result of the



191

activities associated with the Project and that noise impacts associated with the Project are not

expected to be significant.

There are a number of offshore and coastal conservation areas on the Scottish mainland that

have been designated under the Habitats Directive as SACs, under the EU Birds Directive as

SPAs and under the Marine Scotland Act 2010 and Marine and Coastal Access Act 2009 as

NCMPAs and MCZs. The potential for significant impacts on any such site has been

considered within each impact assessment, with particular focus given to the potential for an

accidental hydrocarbon release to interact with such sites. Given the location of the Liberator

field, the short-term duration of installation activities along the proposed pipeline route and the

mitigation and management measures in place (including for well blowout), the Liberator Field

Development is considered unlikely to affect the conservation objectives or site integrity of

any SAC and SPA and neither is there a significant risk to the conservation objectives of the

NCMPAs or MCZs.

Considering all of the above, no significant impacts are expected upon protected species and

habitats.

7.3 Cumulative/In-combination and Transboundary Impacts

Each of the potentially significant environmental impacts associated with the Liberator Field

Development, along with the proposed mitigation measures, has been assessed against the other

human activities in the region, including the existing production from the Bleo Holm FPSO.

The assessments indicate that no significant cumulative and in-combination impacts are

expected.

Potential transboundary environmental impacts originate in one country but have an effect on

the environment in another country. A review of each of the potentially significant

environmental impacts associated with the Liberator Field Development and the mitigation

measures proposed indicates that no significant transboundary impacts are expected.

Hydrocarbon release modelling undertaken for the Liberator Field Development indicates a

high probability that, in the unlikely event of a worst-case hydrocarbon release, a transboundary

impact could occur in Norwegian waters. The assessment of release likelihood demonstrates

that the likelihood of a release large enough to lead to such a transboundary impact is low and

that potential transboundary impacts are much reduced when likely intervention strategies are

considered.

7.4 Overall Conclusion

Through a systematic evaluation of the proposed Liberator development activities and their

interactions with the environment, a variety of potential sources of effect were identified. The

majority of these were of limited extent and duration and considered minor. Those activities

which were identified as being of potentially greater concern were assessed further in Section

5. A number of environmental management actions were highlighted to take forward into Front

End Engineering and Design and detailed design, and final development planning and

execution (Section 6).



192

Taking into account the limited geographical and temporal scale of the Development, combined

with the proposed mitigation measures, the Liberator Field Development EIA has concluded

that the Project will not result in any significant environmental impact. Predicted environmental

effects of the development are comparable with those from other subsea and FPSO tie-back

development activities on the UKCS. During the assessment process, no potential issues of

concern were identified which could not be mitigated to reduce them to meet regulatory

requirements and company policy. The risks of spills have been assessed in detail and

preventative measures and procedures put in place to minimise the likelihood of their

occurrence and possible environmental damage.



193

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discharges and releases attributed to vessels and offshore oil and gas installations operating in

the United Kingdom’s exclusive economic zone (UK EEZ) 2014. Published March 2015.

Available online at: http://www.acops.org.uk/wp-content/uploads/2017/02/annual-marine-

pollution-survey-2014.pdf [Accessed 11/07 2017].

Aires, C., González-Irusta, J.M. and Watret, R. (2014). Scottish Marine and Freshwater

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205

Appendix A Abbreviations

3LPP 3-layer polypropylene

ACA Action Co-ordinating Authority

ACOPS Advisory Committee on protection of the Sea

API American Petroleum Institute

BAT Best Available Technique

BC Background concentration

BEIS Department of Business, Energy and Industrial Strategy

BEP Best Environmental Practice

BODC British Oceanographic Data Centre

BOP Blowout preventer

CEFAS Centre for Environment, Fisheries and Aquaculture Science

CNS Central North Sea

CPT Cone penetration test

DCA Drill Centre A

DCC Drill Centre C

DCD Drill Centre D

DECC Department of Energy and Climate Change

DM Distribution Manifold

DP Dynamic positioning

DSV Dive support vessel

DTI Department of Trade and Industry

EEA European Environment Agency

EEMS Environmental and Emissions Monitoring System

EIA Environmental Impact Assessment



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ENVID Environmental Issues Identification

EPU Electric power unit

ERL Effects range low

ERRV Emergency Response and Rescue Vessel

ES Environmental Statement

EU European Union

FDP Field Development Plan

FEAST Feature Activity Sensitivity Tool

FEED Front End Engineering and Design

FOCI Feature of Conservation Importance

FPSO Floating Production Storage and Offloading vessel

GHG Greenhouse gas

HMCS Harmonised Mandatory Control Scheme

HP High Pressure

HPU Hydraulic power unit

HRA Habitat Regulations Appraisal

HS&E Health, Safety and Environmental

ICES International Council for the Exploration of the Sea

IEEM Institute of Ecology and Environmental Management

IEMA Institute of Environmental Management and Assessment

IMS Integrated Management System

IOGP International Association of Oil and Gas Producers

IPCC Intergovernmental Panel on Climate Change

IROPI Imperative Reason of Overriding Public Interest

IUCN



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JNCC Joint Nature Conservation Council

KIS-ORCA Kingfisher Information Service - Offshore Renewable Cable

Awareness

KPI Key Performance Indicator

LAT Lowest astronomical tide

LP Low pressure

LTOBM Low toxicity oil-based mud

MarLIN Marine Life Information Network

MAT Master Application Template

MCZ Marine Conservation Zone

MEG Mono-ethylene glycol

MMO Marine mammal observer

MMstb Million standard barrels

MoD Ministry of Defence

MORL Moray Offshore Renewables Ltd

MPA Marine Protected Area

MPF Multi-phase flowmeter

MS Marine Scotland

MSFD Marine Strategy Framework Directive

NC Nature Conservation

NCMPA Nature Conservation Marine Protected Area

NEC No Effect Concentration

NMPI National Marine Plan Interactive

NNS Northern North Sea

NORBRIT Norway-United Kingdom Joint Contingency plan



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OBIS SEAMAP Ocean Biogeographic Information System Spatial Ecological

Analysis of Megavertebrate Populations

OBM Oil-based mud

OCNS Offshore Chemical Notification System

OGA Oil and Gas Authority

OGUK Oil and Gas UK

OIW Oil in water

OPEP Oil Pollution Emergency Plan

OPPC The Offshore Petroleum Activities (Oil Pollution Prevention

and Control) Regulations, 2005

OPRED Offshore Petroleum Regulator for Environment and

Decommissioning

OSCAR Oil Spill Contingency and Response

OSPAR Oslo & Paris Conventions

OVI Offshore Vulnerability Index

OWF Offshore wind farm

PAH Polycyclic aromatic hydrocarbon

PAM Passive acoustic monitoring

PLONOR Pose Little or No Risk to the Environment

PMF Priority Marine Feature

Pr Reservoir pressure

PTS Permanent threshold shift

PW Produced water

PWRI Produced water reinjection

QSR Quality Status Report

ROV Remotely operated vehicle



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RSRUK Repsol Sinopec Resources UK Ltd

SAC Special Area of Conservation

SAST Seabirds at Sea Team

SAT Subsidiary Application Template

SCM Subsea control modules

SCOS Special Committee on Seals

SDU Subsea distribution unit

SECE Safety and environment critical element

SFF Scottish Fishermen’s Federation

SIMOP Simultaneous operations

SL Source Level

SMRU Sea Mammal Research Unit

SNH Scottish Natural Heritage

SNS Southern North Sea

SOPEP Shipboard Oil Pollution Emergency Plans

SOSI Seabird Oil Sensitivity Index

SOSREP Secretary of State’s Representative

SPA Special Protection Area

SPL Sound pressure levels

SUTU Subsea Umbilical Termination Unit

THC Total Hydrocarbon

TOC Total organic carbon

TOM Total organic matter

tr Reservoir temperature

TTS Temporary threshold shift



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TUTU Topside umbilical termination

UKBAP United Kingdom Biodiversity Action Plan

UKCS United Kingdom Continental Shelf

UKOOA United Kingdom Offshore Operator’s Association

UNESCO United Nations Educational, Scientific and Cultural

Organisation

US CEQ United States Council on Environmental Quality

VMS Vessel Monitoring System

VOC Volatile organic compounds

VSP Vertical seismic profiling

WBM Water based mud

WFD Water Framework Directive

WHS World Heritage Site

WO Well Operator



211

Appendix B Supporting Data for Accidental Events Assessment

Table B 1 Blowout frequency for drill rigs per unit per year on UKCS (OGUK, 2009)

Type of

facility

Number of blowout events for a given period

1990 – 1999 2000 – 2007 1990 – 2007

Number Frequency

per year Number

Frequency

per year Number

Frequency

per year

Drill rig 13 0.020 3 0.0066 16 0.014

Table B 2 Well blowouts during different operational phases 1980 – 2008 (IOGP, 20107)

Descriptor

Drilling

Completion Workover Wireline

Production

Total Development

drilling Exploration Other External(1) Internal(1)

Number of

well

blowouts

34 17 2 9 20 4

7 1 94

Percentage 36.17% 18.08% 2.16% 9.57% 21.27% 4.25% 7.44% 1.06% 100%

(1) External causes include storm, military activity and ship collision whilst internal causes refer to upsets within the production process

itself.

7 Blowout and well release frequencies reported by IOGP are for offshore operations of North Sea standard (i.e. the same type

of operations as occur in the North Sea but not necessarily located in the North Sea).



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Table B 3 Projected frequency of blowout and well release incidents for the Project

Project activity

Blowout Well release

Historical

event

frequency

(IOGP,

2010)8

Values for the Project

Historical

event

frequency

(IOGP,

2010)

Values for the Project

Probability

of event

occurrence

during

Project

activity

period9

Probable

number

of Project

activity

years per

event

(return

period)10

Probability

of event

occurrence

during

Project

activity

period

Probable

number

of

Project

activity

years

per

event

(return

period)

Development

drilling 4.8 x 10-5

(per well)

1.92 x 10-4 3,177 3.90 x 10-4

(per well) 1.56 x 10-3 391

Production 3.90 x 10-5

(per well

year)

1.17 x 10-3 8,547

2.90 x 10-6

(per well

year)

4.06 x 10-5 114,943

The project specific calculations assumes 4 wells are drilled (3 x production and 1 x appraisal), the

development schedule is in line with that stated in the Standard Information Sheet at the front of

this document, and the field life is ten years from 2020 to 2030.

8 Historical frequency is presented as number of events per unit as given for each type of

activity. For example, the frequency of blowouts for development drilling is calculated as the

total number of blowouts that have occurred during development drilling, divided by the

number of development wells drilled. For production, it is the number of blowout events that

have occurred during production operations divided by the combined number of years that all

assessed wells have been in production.

9 This is the historical frequency multiplied by the number of activity units required by the

project. For development drilling this means the historical frequency multiplied by the number

of wells (four). For Production, it is the historical frequency per well year multiplied by the

number of well years associated with the project (three wells over a field life of ten years gives

thirty well years)

10 The return period is the reciprocal of the calculated annual event probability, assuming that

the Project activity in question continues indefinitely. For example, the drilling of the four

wells is expected to be complete in 224 days or 0.61 years and based on historical data the

probability of a well blowout occurring during the drilling of these wells is 1.92 x 10-4. If

drilling were to continue for one year at the same level of risk, the probability of an event

occurring within that year would be 1.92 x 10-4 / 0.61 = 3.15 x 10-4. The reciprocal of this value

(1 / 3.15 x 10-4) is 3,177 meaning that if drilling of the four Liberator wells were to continue

indefinitely a well blowout could be expected once every 3,177 years.



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Table B 4 Number of accidental releases of oil from drill rigs, based on UKCS historical data by release size and

source during the period 2001 to 2007 (DECC, 2014)11

Accidental release

cause

<1

kg

1 to <10

kg

10 to

<100

kg

0.1 to

<1 tonnes

1 to

<10 tonnes

10 to

<100

tonnes

All

accidental

releases(1)

Maintenance/operational

activities

10 14 4 5 1 0 35

Bunkering 2 9 2 9 0 0 22

Subsea releases 1 3 3 1 2 1 12

Drilling 12 6 15 15 2 1 54

ROV associated 1 3 1 0 0 0 5

Other production 0 0 0 1 0 0 1

All accidental releases(1) 35 42 40 42 8 2 179

(1) Includes accidental releases of unknown size and of unknown cause.

DECC (2014). PON1 data. Online at

https://itportal.beis.gov.uk/eng/fox/pon1/PON1_PUBLICATION_EXTERNAL/viewCurrent

Table B 5 Number and frequency of accidental releases of fluids or gas per unit year from drill rigs in the UKCS,

1990 – 2007 (OGUK, 2009)

Type of facility

Number of accidental events for a given period

1990 – 1999 2000 – 2007 Total for 1990 – 2007

Number Frequency

per year Number

Frequency

per year Number

Frequency

per year

Drill rig 160 0.246 78 0.172 238 0.215

11 Based on SINTEF international data for wells in water >200 m (OGP, 2010). Based on approach from Scandpower (2006),

which uses the historical frequency to estimate the event return period, or average recurrence interval of an event.



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Table B 6 Number and frequency of explosions, collisions and vessel contacts per unit year from drill rigs in the

UKCS, 1990 – 2007 (OGUK, 2009)

Type of facility

Number of events for a given period

1990 – 1999 2000 – 2007 Total for 1990 – 2007

Number

Frequency

per unit

year

Number

Frequency

per unit

year

Number

Frequency

per unit

year

Vessel contact – drill

rig

108 0.166 25 0.55 133 0.120

Collision – drill rig 14 0.021 1 0.0022 10 0.014

Explosion – drill rig 10 0.015 - - 10 0.009

Table B 7 Number of accidental releases from subsea tiebacks to oil producing facilities (1975 to 2007) (TINA

Consultants Ltd pers. comm., 2013)

Accidental release cause

≥10 g

to

<100 g

≥0.1

kg to

<1 kg

≥1 kg

to

<10 kg

≥10 kg

to

<100

kg

≥0.1

tonnes

to <1 t

≥1

tonnes

to <10

All

accidental

releases(1)

Fixed 1 1 3 7 5 6 23

Floating 0 2 0 0 0 1 3

All accidental releases (1) 1 3 3 7 5 7 27

(1) Includes accidental releases of unknown size and of unknown cause.

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