Liberator Field Development
Environmental Statement
January 2019
BEIS Reference Number: D/4228/2018
Liberator Field Development
Environmental Statement
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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
Drill, evaluate and complete
second production well
Subsea infrastructure
installation and pipelay
Subsea hook up to Bleo
Holm and commissioning
First Oil
Drill, evaluate and complete
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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Environmental Statement
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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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Environmental Statement
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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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Environmental Statement
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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
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
21
proposed mitigation measures, mean the Development will not result in any significant long-
term impacts.
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
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)
Liberator Field Development
Environmental Statement
26
Figure 1-4 Revised Liberator development layout
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
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.
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
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.
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
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;
Liberator Field Development
Environmental Statement
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
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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.
Liberator Field Development
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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.
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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.
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Environmental Statement
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
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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
Liberator Field Development
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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.
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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
Drill, evaluate and complete
first production well
Drill, evaluate and abandon
appraisal well
Drill, evaluate and complete
second production well
Subsea infrastructure
installation and pipelay
Subsea hook up to Bleo Holm
and commissioning
First Oil
Drill, evaluate and complete
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.
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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.
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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
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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.
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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
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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
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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
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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)).
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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
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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.
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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
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• 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.
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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
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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
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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
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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.
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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
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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
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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.
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Figure 2-9 Schematic of the Blake flowlines crossing
Figure 2-10 Schematic of the Ross DCD flowlines crossing
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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.
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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
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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.
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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.
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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).
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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
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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).
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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
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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)
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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).
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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)
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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
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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.
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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-
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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
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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,
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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
)
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Red box denoted Liberator development area. Source: Aires et al. (2014)
c)
e)
d)
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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,
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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).
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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.
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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
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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.
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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).
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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).
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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.
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Figure 3-8 UK conservation designations in the vicinity of the Liberator field
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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
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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
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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
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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
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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
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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)
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Figure 3-13 Pelagic landings in 2012-2016 by ICES rectangle
Notes: ICES rectangle 45E8 is highlighted in black
Source: Scottish Government (2018b)
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
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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
Source: Scottish Government (2018b)
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
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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.
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Figure 3-16 Seabed obstructions identified by SFF in the Liberator development area
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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
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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.
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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
ellf
ish
Ma
rin
e M
am
ma
ls
Wa
ter
& S
eab
ird
s
Fis
her
ies
Oth
er O
ffsh
ore
Use
rs
Sh
ipp
ing
On
sho
re /
La
nd
Use
& S
easc
ap
e
Inte
rna
tio
nall
y
Imp
ort
an
t S
ites
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
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
ellf
ish
Ma
rin
e M
am
ma
ls
Wa
ter
& S
eab
ird
s
Fis
her
ies
Oth
er O
ffsh
ore
Use
rs
Sh
ipp
ing
On
sho
re /
La
nd
Use
& S
easc
ap
e
Inte
rna
tio
nall
y
Imp
ort
an
t S
ites
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
115
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
understanding and/or outreach.
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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
understanding and/or outreach.
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
understanding and/or outreach.
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.
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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.
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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
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Environmental Statement
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
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Environmental Statement
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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Environmental Statement
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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
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Environmental Statement
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.
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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,
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Environmental Statement
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
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Environmental Statement
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
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Environmental Statement
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
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Environmental Statement
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,
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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.
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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
Liberator Field Development
Environmental Statement
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.
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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.
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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.
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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.
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Environmental Statement
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.
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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.
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145
Seasonal sensitivities of potential receptors are not considered to be sufficiently variable to
mean seasonal mitigation commitments are of value.
Cumulative and in-combination impact assessment
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.
Transboundary impact assessment
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
Liberator Field Development
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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
Receptor Sensitivity Vulnerability Value Magnitude
Benthos Low Low Negligible 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.
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.
Consequence Impact significance
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
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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
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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
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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
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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.
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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
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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.
Cumulative and in-combination impact assessment
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.
Transboundary impact assessment
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
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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
Receptor Sensitivity Vulnerability Value Magnitude
Marine mammals Low Low Low Minor
Fish Low Low Negligible 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.
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.
Consequence Impact significance
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
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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
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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)
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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.
Cumulative and in-combination impact assessment
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.
Transboundary impact assessment
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.
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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
Receptor Sensitivity Vulnerability Value Magnitude
Fisheries Low Low Low Minor
Other sea users,
except fisheries
Negligible Negligible Negligible 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. 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
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(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.
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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
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• 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
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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).
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Transboundary impact assessment
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
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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.
Receptor Sensitivity Vulnerability Value Magnitude
Atmosphere Low Low Low Minor
Rationale
The information in the Environment Description (Section 4) has been used to assign the sensitivity,
vulnerability and value of the receptor as follows.
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.
Consequence Impact significance
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
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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
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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.
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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:
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• 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%.
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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
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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.
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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.
Seasonal sensitivities of potential receptors are not considered to be sufficiently variable to
mean seasonal mitigation commitments are of value.
Cumulative and in-combination impact assessment
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
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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.
Transboundary impact assessment
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.
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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.
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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
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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
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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
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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.
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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
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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
Receptor Sensitivity Vulnerability Value Magnitude
Protected sites
and socio-
economic
features
High High High Moderate
Rationale
The information in the Environment Description (Section 3) has been used to assign the sensitivity,
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.
Consequence Impact significance
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.
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No. ES section Topic Commitment
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
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No. ES section Topic Commitment
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.
Liberator Field Development
Environmental Statement
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.
Liberator Field Development
Environmental Statement
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
Liberator Field Development
Environmental Statement
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).
Liberator Field Development
Environmental Statement
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.
Liberator Field Development
Environmental Statement
193
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Liberator Field Development
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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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206
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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207
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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208
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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209
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
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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).
Liberator Field Development
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212
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.
Liberator Field Development
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213
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.
Liberator Field Development
Environmental Statement
214
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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