Solan Production Operation MAT Direction for · PDF fileProduction MAT Direction for...

Solan Production Operation MAT

Direction for Commissioning and Operation

Production MAT Direction for Commissioning and Operation

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North Sea Rev B19, November 2015 Page 2

REV ISSUE DATE

STATUS AMENDMENT DETAILS ORIGINATED

BY APPROVED

B1 31/05/2014 1st Draft Submitted for client review Genesis Premier

B2 05/06/2014 Final Client comments incorporated Genesis Premier

B3 09/07/2014 Update 1 Update in response to DECC

comments Genesis Premier

B4 19/11/2014 Update 2 Update to incorporate

commissioning and production operations

Genesis Premier

B5 27/11/2014 Update 3 Update to include assessment of

potential environmental impacts of the flotel

Genesis Premier

B6 27/01/2015 Update 4 Update to address Marine

Scotland comments Genesis Premier

B7 03/03/2015 Update 5

Update to address DECC comments and include Floatel

Victory and drill rig impact assessment

Genesis Premier

B8 10/03/2015 Update 6 Update to address DECC

comments Genesis Premier

B9 30/03/2015 Update 7 Update to include consent to

locate addition of the SAL marker buoy

Premier Premier

B10 07/04/2015 Update 8 Update to amend drill rig dates Genesis Premier

B11 15/04/2015 Update 9 Update to biocide information Genesis Premier

B12 01/05/2015 Update 10

Update to vessel information for hook-up and commissioning phase and update with new

chemical permit (CP/699) under PLA/90

Genesis Premier

B13 06/05/2015 Update 11 Update to include consent to locate addition of the Floatel

Victory Genesis Premier

B14 12/05/2015 Update 12 Update to W2W vessel

information in relation to consent to locate requirements

Premier Premier

B15 02/06/2015 Update 13 Update to amend vessel

information and include OPEP Annexes

Genesis Premier

B16 30/06/2015 Update 14 Update to include Flotel Regalia and update document for current

operations Genesis Premier

B17 29/09/2015 Update 15

Update to include consent to locate addition of the Aquaterra trash caps and to include Floatel

Superior

Genesis Premier

B18 30/09/2015 Update 16 Update to include Consent to

Location addition of Waverider Buoy

Premier Premier


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B19 10/11/2015 Update 17 Update to production profiles and

commissioning operations for start-up/first oil

Genesis Premier

This document contains proprietary information belonging to Premier and must not be wholly or partially reproduced nor disclosed without prior written permission from Premier. The master copy of this document is held electronically within Premier’s Document Management System. If you are using a paper copy or a CD issue of this document, it is your responsibility to ensure it is the latest version.


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ACRONYMS

CH4 Methane

CMID Common Marine Inspection Documents

CO2 Carbon dioxide

CP Chemical Permit

CtL Consent to locate

DECC Department of Energy and Climate Change

DepCon Deposit consent

DHSV Down Hole Safety Valve

DP Dynamic Positioning

DSV Dive Support Vessel

DTI Department of Trade and Industry

EC European Commission

EIA Environmental Impact Assessment

EPS European Protected Species

ERRV Emergency Response and Rescue Vessel

ES Environmental Statement

ESD Emergency Shut Down

ESP Electric submersible pump

EU European Union

FSV Field Support Vessel

GHG Greenhouse gas

GOR Gas Oil Ratio

H2S Hydrogen Sulphide

HP High pressure

HSE Health, Safety And Environment Inspectorate

HSES Health, Safety, Environmental and Security

Hz Hertz

IBC Intermediate Bulk Container

ICES International Council for the Exploration of the Seas

JNCC Joint Nature Conservation Committee

kg Kilograms

kHz Kilohertz

km Kilometres

KW/m Kilowatts per metre


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LAT Lowest Astronomical Tide

LP Low pressure

m Metres

m³ Cubic metres

m/s Metres per second

MAT Master Application Template

MCZ Marine Conservation Zones

mg/l Milligrams per litre

ml Millilitre

mm Millimeter

MMscfd Million standard cubic feet per day

MODU Mobile Offshore Drilling Unit

MPA Marine Protected Area

MRV Multi-Role Vessel

MW Mega watts

nm Nautical mile

NCMPA Nature Conservation Marine Protected Area

NMVOC Non Methane Volatile Organic Compounds

NPMI Not Permanently Manned Installation

NO Nitrogen monoxide

NO2 Nitrogen dioxide

NOx Nitrous oxides

OCNR Onshore Control Room

OCNS Offshore Chemical Notification Scheme

OCR Offshore Chemical Regulations

OLS Oil Offloading System

OPEP Oil Pollution Emergency Plan

OPOL Offshore Pollution Liability Association Limited

OPPC Oil Prevention Pollution and Control

OSCAR Oil Spill Contingency and Response

OSPAR Oslo and Paris Convention for the Protection of the Marine Environment in the North East Atlantic

OSRL Oil Spill Response Limited

OVI Offshore Vulnerability Index

PLA Pipeline Application

PRA Production Application

rms Root Mean Square


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ROV Remote Operated Vehicle

SAC Special Area of Conservation

SAL Single Anchor Loading

SAT Subsidiary Application Template

SCANS Small Cetacean Abundance in the North Sea

scf/bbl Standard cubic feet per barrel

SCI Site of Community Importance

SEL Sound Exposure Level

SOST Subsea Oil Storage Tank

SOPEP Ship Oil Pollution Emergency Plan

SPA Special Protection Area

SPL Sound Pressure Level

Te Tonnes

UKCS United Kingdom Continental Shelf

VOC Volatile Organic Compounds

WoS West of Shetland

WoSP West of Shetland Pipeline


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1 INTRODUCTION

1.1 Background

The Solan field is located in Block 205/26a in the West of Shetland (WoS) area at

approximately 3°58'10" W, 60°03'50" N. The field lies approximately 95 km from the

Scottish coast and 55 km from the UK/Faroes median line in water depths of

approximately 138 m lowest astronomical tide (LAT) (Figure 1-1).

Figure 1-1 Solan field development

Premier Oil UK Limited (hereafter referred to as Premier) are developing the field via two

production wells with the potential of two further producer wells in the future. Two water

injection wells will be used to maintain reservoir pressure from the start of production

whilst a third water injection well may be drilled in the future.

The facility comprises a jacket substructure, topsides facilities, a subsea oil storage tank

(SOST), and oil offloading system (OLS). The facility is designed to produce a peak flow

rate of 4,000 tonnes (Te) of oil, with a peak of up to 5,000 Te of total liquids.


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Both the production and injection wells will be tied back to the jacket and topside facilities

by flexible flowlines and rigid risers. The four leg jacket structure incorporates all

connections for the risers, caissons and J-tubes. The topsides facilities consist of primary

separation, gas treatment to fuel gas quality and power generation.

Oil will be produced via a piled SOST which will be used to store the crude, prior to export

via the OLS hose and then via a dynamically positioned (DP) shuttle tanker. The offloading

hose will be laid on the seabed with a pennant line and buoy to allow recovery to surface

when required. An overview of the field layout is shown in Figure 1-2.

Figure 1-2 Solan development project field layout

Solan will be developed by natural reservoir depletion assisted by water injection for

pressure support and artificial lift (electrical submersible pumps (ESP)) to improve

production rates. Injection water will be supplied by produced water, ballast water from the

SOST and filtered seawater. On completion, the Solan subsea wells and infrastructure will

be monitored, controlled and operated remotely from the shore via systems installed in the


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platform. For at least the first 12 months Solan will be manned to complete commissioning

and manage plant stabilisation.

Produced oil from the Solan Field will be separated and metered in the facilities on the

platform and collected in the SOST prior to being transferred to tanker for export. The

produced gas will be used as fuel gas for onboard power generation. Any surplus gas will

be flared. Produced water will be cleaned-up and re-injected where possible. During

periods of Water injection downtime and during the initial commissioning of the plant post

start-up Ballast water will be cleaned and discharged to sea via the sea water caisson.

therefore there will be zero water discharge (Chrysaor, 2009).

The overall process flow diagram is shown in Figure 1-3.

Figure 1-3 Overall Process Flow Diagram

1.2 Purpose of Current Justification Document

This Justification Document supports a number of applications:

An EIA Direction under the Offshore Petroleum Production and Pipelines

(Assessment of Environmental Effects) Regulations 1999 (as amended);


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A Chemical permit under the Offshore Chemicals Regulations 2002 (as

amended);

A Consent to Locate (CtL) under The Energy Act 2008, Part 4A.

An Oil Discharge Permit under the Offshore Petroleum Activities (Oil Pollution

Prevention and Control, OPPC) Regulations 2005 (as amended 2011).

The applications capture the commissioning works and ongoing production. Table 1-1

summarises the applications supported by this Justification Document.

The commissioning/tank first fill is described in Section 2 and production operations are

described in Section 3.

Table 1-1 Summary of Applications Supported by this Justification Document

Application Portal Reference Description

EIA Direction PRA/157 SP/215 Direction to commence production from new primary field

Chemical Permit PRA/157 CP/371 Includes chemical use and discharge during commissioning and production chemicals during operation

Consent to Locate PRA/157: CL/207 & CL/208

Floating accommodation units

Deployment of MODU Ocean Valiant within 500 m zone of Solan platform

SAL marker buoy within 500m zone (moved from CL/264)

Storage of Aquaterra trash caps (moved from PLA/90 ML/121)

Oil Discharge Permit PRA/157 OLP/198

For commissioning operations:

Discharge of ballast water For production operations:

Production of hydrocarbons

Produced water re-injection


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The project schedule is summarised in Table 1-2.

Table 1-2 Indicative Schedule of Activities

Activity 2015 2016

2017 Q4 Q1 Q2

Dec Jan Feb Mar Apr May Jun

Minimum facilities, fi rst oil P1

First fill of SOST

P1 ESP and Solar gas turbines online

Final commissioning of full facilities

P2 and W2 availability

P2 ESPs

PW Treatment Facilities


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2 HOOK-UP AND COMMISSIONING

2.1 Overview

Figure 2-1 shows the outstanding subsea commissioning operations (as of Nov 2015) for

the Solan development to be undertaken during subsea Phase 6. the current status (Feb

2015) of the Solan infrastructure. After the March 2015 subsea campaign this is expected

to change considerably once the campaign has finished.

Solan will operate on minimum facilities during initial start-up and commissioning. ESP

operation will not commence until plant stability is achieved to reduce stops and starts.

During this period the water injection system will not be available and ballast water which

is displaced by hydrocarbons will be discharged overboard.

Temporary ballast water filters have been installed on the platform and all ballast water will

be routed through these filters. The filter banks are absorption cartridge filters expected to

reduce hydrocarbons to 5mg/l. It is not expected that any hydrocarbons are present in the

fluids from the first fill of the tank. The SOST is currently filled with chemically treated

seawater. The discharge of this has been included on CP/371.

Post first fill of the tank the water injection system is planned to be commissioned. When

available all ballast water will be injected and discharge to sea will only occur if the system

is unavailable. The expected uptime post commissioning of the WI system is 95%.


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Figure 2-1 Outstanding commissioning operations (Nov 2015) for the Solan development to be undertaken during subsea Phase 6.


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2.2 Interference Test

Upon first oil start-up the water injection system will not be commissioned. The first fill of

oil can be contained if water injection is available however It is currently planned to

perform an interference test between the producer and injection wells to understand Solan

compartmentalisation and to make provision for sidetracks or new well injectors. In order

to perform this test the producers have to be flowed (natural flow without the ESP) and no

injection in order to understand the pressure decline in the injectors. This test is likely to

take between 36 and 48 hours to complete. Water injection can then be brought online

and all fluids injected into the reservoir through the injection wells.

Solan is committed to minimising discharges to the environment. P1 will be flowed

naturally at about 5,000 bpd for a period approximated of 14 days to test the

communication between the producers and the injectors prior to start-up of the well with

the ESP and start-up of water injection. The purpose of the above mentioned test is to

produce a pressure decline pulse at the injectors’ reservoir area in the order of 50 psig.

The Petroleum engineer will be closely monitoring the pressure decline. Any early sign of

effective communication between the producers and the injectors will halt the test which

means water injection can be started.

First fill volume is estimated to be approximated 300,000 bbls of treated water, any fluids

produced will displace the equal amount of fluid from the tank which will be discharged to

sea when water injection is not available.

In addition, as this is a first plant start-up, there will be plant stability issues to manage and

therefore it may be necessary to overboard full first fill volume of the tank.

Every effort will be made to minimise the discharge of water into the sea to minimise

environmental discharge and the pressure decline in the reservoir. All parties are aware of

this requirement which supports the reservoir management plan. After the first cargo off-

load there will be no discharge of production chemicals to sea. A commitment was made

in the Environmental Statement (ES) that production will be shut in when water injection is

not available.

2.3 Chemical Discharges

The fate of the chemicals left in the system after installation of the pipelines and tank will

either be:


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displaced downhole;

discharged to sea from the topsides during the first fill of the SOST;

discharged to sea with the ballast water prior to WI commissioning; or

flowed to the tanker during the first cargo off-load.

These operations have been fully risk assessed as part of the chemical permit SAT

(PRA/157 CP/371). None of the chemicals proposed to be used in these operations were

found to present a risk to the environment; therefore, the overall effects of marine

discharges on the benthic communities and the marine environment are not expected to

be significant.

2.4 Drill Rig

Ongoing drilling operations require the Ocean Valiant Mobile Offshore Drilling Unit

(MODU) to be onsite at the Solan development from the 15th May 2015 for approximately

250 days to allow drilling of P2 and W2 wells with a possible re-spud of W2. The Ocean

Valiant is semi-submersible and will be anchored in place.

2.5 Vessel Use

This section summarises the ongoing vessel requirements associated with the hook-up

and commissioning phase. These include:

A standby Emergency Response and Rescue Vessel (ERRV)

A Dive Support Vessel (DSV)

The Flotel Regalia – accommodation vessel

The Floatel Superior – accommodation vessel to replace the Flotel Regalia

A second standby ERRV will also be on location, however this has been captured

previously in the Solan drilling permit applications. In addition the supply vessel has

already been captured in the Solan drilling permit applications.

Table 2-1 provides an estimate of the anticipated number of vessel and their estimated

fuel. The number of transit days provided allows for coming into port to accommodate

crew changes and the initial mobilisation and demobilisation days.


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Table 2-1 Anticipated vessel use during Solan hook up and commissioning phase 2015

Vessel type Duration

(days) Working fuel

consumption (Te/day)1 Total fuel use

(Te)

Walk to work vessel (in transit) 4 28 112

Walk to work vessel (working on DP)

56 18 1,008

Flotel Regalia (in transit) 4 40 160

Flotel Regalia (working on DP) 111 30 3330

Floatel Superior (in transit) 4 40 160

Floatel Superior (working on DP) 103 30 3,090

Standby ERRV (in transit)2 12 3.5 42

Standby ERRV (working)2 70 0.8 56

DSV (in transit) 4 22 88

DSV (working) 16 18 288

Total Fuel Use 8,334

1The Institute of Petroleum, 2000

2Only one standby ERRV captured here as other assessed in Solan drilling application.

The Flotel Regalia will replace the Siem Spearfish as an accommodation vessel. The

Regalia is anticipated to arrive at the Solan field at the earliest on the 1st August until

around the 20th November 2015. The vessel will be used as a walk to work vessel where

the vessel will be on DP to the east of the Solan platform within the 500 m zone and only

connect to the platform in order to transfer personnel and then disconnect and move away

during working hours. The vessel will be on DP at all times and will not use mooring lines

or anchors.

The Floatel Superior will then replace the Flotel Regalia as the accommodation vessel.

The Superior is anticipated to arrive at the Solan field on the 18th November 2015 and stay

until the end of February 2016. The Regalia will overlap with the Superior for

approximately 3 days during the changeover of the accommodation vessels. The vessel

will be used as a walk to work vessel where the vessel will be on DP to the east of the

Solan platform within the 500 m zone and only connect to the platform in order to transfer

personnel and then disconnect and move away during working hours. The vessel will be

on DP at all times and will not use mooring lines or anchors.


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3 PROCESS OPERATIONS DESCRIPTION AND PRODUCTION PROFILES

The facility has been designed as a Not Permanently Manned Installation (NPMI) which

can be operated remotely from the Onshore Control Room (ONCR) with the exception of

the hook-up and commissioning phase. However, the installation will always be capable of

operating as a manned platform. It will operate as a manned platform for at least the first

twelve months of production operations or until such time as approval to operate as a

NPMI is granted by the Department of Energy and Climate Change (DECC) / HSE.

The facility comprises of a SOST, a jacket substructure, topsides facilities, and oil

offloading system. The jacket substructure consists of a four leg design and all associated

bracing and stiffening necessary for the environment where it will be installed. It shall also

incorporate all connections for the risers, caissons and J-tubes, from the base of the jacket

to the top of the deck stab-in points. The topsides facilities will consist of primary

separation, gas treatment to fuel gas quality, all necessary Utilities, and Power

Generation. Power will be generated by dual-fuel turbines and a diesel generator. Initially

the turbines will be fuelled by fuel gas taken from associated gas with any excess gas

being flared. When the field becomes fuel-gas deficient the turbines will be fuelled by

diesel.

The SOST is located on the seabed. Oil will be exported via the oil offloading system to

shuttle tankers.

3.1 Process Description

Reservoir fluids (oil, gas and water) are brought from the seabed with the aid of ESPs

installed in each oil production well.

Production wells P1 and P2 are fitted with wellhead chokes to enable back-pressuring of

the production tubing to assist in prevention of asphaltenes deposition in the production

tubing. The individual flowlines from all production wells are fitted with choke valves at the

platform topsides, which will enable start-up flows to be controlled and will permit back-

pressuring of the flowlines to aid with asphaltenes control.

Reservoir fluids (oil, gas and water) are brought from the seabed to the topsides with the

aid of ESPs installed in each oil production well. The well fluids are directed to a first stage

high pressure (HP) separator and the associated HP gas is used to fuel the power


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generation equipment. Liquids then pass to the second stage low pressure (LP) separator

where further LP gas is taken off and sent to the flare for disposal. From the first and

second stage separators, produced water is directed to the water injection pumps for

injection back into the reservoir. No sand is anticipated in the separators. If sand occurs it

will be manually removed by a recognised contracting company whilst production is offline

and will be disposed of onshore.

During normal fully commissioned operations, as oil enters the SOST, ballast water is

displaced from the bottom of the SOST and will be lifted onto the platform by caisson

pumps, and passed to the water injection system.

If the total of the produced water and ballast water rates falls short of the water injection

rate required for voidage replacement, the water injection volume is supplemented with

deoxygenated seawater taken from the seawater header. The total water injection stream

is then directed to the water injection pumps where it is raised to the required injection

pressure.

Oil will flow to and water to/from the topside facilities to the crude storage tank via rigid

risers on the jacket and rigid and flexible flowlines on the seabed. These will be connected

at the base of the jacket and be protected from dropped objects.

Oil export from the SOST will take place to a DP shuttle tanker. When not in use the

export line will be laid on the seabed, with a pennant line and buoy to allow recovery of the

line to surface.

Oil transfer uses the hydrostatic head of seawater with two displacement water lift pumps

located topsides delivering seawater to allow the oil transfer of up to 42,927 Te (300,000

bbl) a day.

3.1.1 Fuel Gas

Produced gas required for fuel gas will be removed from the process stream from the first

stage separator and will be routed to the fuel gas package, where it will be compressed for

the gas turbine power generators.

The fuel gas will not be stored. Premier will use the fuel gas as it is produced with a small

flare of surplus gas in the early life. The associated gas is a fixed amount for each barrel of


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oil produced as there is no separate gas cap in Solan reservoir. The gas oil ratio (GOR) is

approximately 19.5 to 23 m3/m3 (110-130 scf/bbl) so as the oil production profile declines,

the available associated gas declines with it. As the platform becomes deficient in gas it

will progressively change over to diesel. Initially there was the prospect of importing gas

from the West of Shetland Pipeline (WoSP), this has been discounted due to technical and

cost implications and is no longer a viable option.

3.1.2 Flaring

The flare system will be designed to enable the safe disposal of gas under normal and

emergency operating conditions. The maximum amount of gas flared will be approximately

57 Mm3/d (2 MMscfd). The flare is located on the northwest corner to minimise the wind

effect.

3.1.3 Produced Water

Premier are committed to an operating philosophy of no production without re-injection.

Produced water will be re-injected, where possible, to the reservoir as it eliminates

discharge to the environment and provides the required pressure support to the reservoir.

Premier will submit an addendum to the Solan environmental statement WI/4031/2008 to

address changes to the operating philosophy concerning the discharge to sea of ballast

and produced water.

The produced water system is designed to remove residual dispersed oil, solids and

dissolved gas from the first and second stage separator produced water streams.

Produced water from the separators is directed to the intake of the water injection pumps

while produced oil is directed to the SOST.

As the oil enters the SOST, ballast water is displaced from the bottom of the SOST (Figure

3-1). This ballast water is filtered and deoxygenated and commingled with the separated

produced water at the intake of the injection pumps.

An application for an Oil Discharge permit has been submitted and approved (OLP/198)

for the re-injection of the produced water. A variation will be submitted to OLP/198 to cover

discharge of ballast and drains fluids.


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Figure 3-1 Diagram of SOST operation

3.1.4 Seawater Treatment and Injection System

Seawater dosed with hypochlorite is lifted directly using seawater lift pumps. In addition to

supplying the required make-up injection water for reservoir pressure support, the lift pump

also distributes seawater to the cooling water and low pressure seawater supply headers

and can supply fire water if required.

Seawater is coarse filtered prior to distribution to the cooling water supply and injection

water treatment system. A separate low pressure seawater supply is also provided to

distribute seawater to the following users:

Electrochlorination package for hypochlorite generation;

Vacuum pumps for pump seal water; and

Accommodation module.

Seawater for injection is initially comingled with ballast water and is then fine filtered and

deaerated. Oxygen scavenger is also injected at the deaerator to meet the final residual


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oxygen specification. Biocide will also be injected into the system as and when required to

mitigate against microbiological growth.

Injection water from the deaerator is routed to the water injection holding drum, where it

mixes with produced water from the separators. Water is then injected into water injection

wells W1 and W2 via dedicated pumps and discharge manifolds.

3.1.5 Ballast Water

the philosophy is to inject all the ballast water into the reservoir via water injection wells

W1 and W2 due to possible hydrocarbon contamination.

During normal production, ballast water from the SOST is routed to the water injection

treatment system. Prior to mixing with produced water and injection via water injection

pumps, the ballast water is fine filtered and de-aerated. Ballast water will be used for

injection in preference to lifted seawater.

From first oil the ballast water will be discharged to sea to a maximum of the first fill of the

SOST, approx. 300,000 bbls. This is treated seawater and is not expected to contain any

hydrocarbons. To mitigate against discharge of hydrocarbons to sea, temporary ballast

water filters, F-4210A/B/C, have been installed on the Solan platform. These are

absorption cartridge filters designed to remove down to approx. 5mg/l oil in water

concentration.

Post first fill of the SOST the water injection system will be commissioned. Once

commissioned it is expected that all ballast water will be injected to support the Solan

reservoir and minimise environmental discharges. The Solan water injection system has

an expected uptime of approx. 95%. Should the water injection system become

unavailable ballast water will be discharged to sea via the sea water disposal caisson C-

4801. The seawater disposal caisson is fitted with an oil skim pump, P-4083, to allow oil

recovery which is routed back to the Open Drains tank and then back to the Closed Drains

tank.


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3.1.6 Water Injection

The water injection system has been designed to allow for injection of both seawater and

produced water as well as the ballast water which is displaced during the filling of the tank

with oil.

In early field life when oil rates are high the injection water requirements will mostly be met

by displaced ballast water with additional seawater as required. As oil production declines

and water cut rates increase the majority of water injected will be produced water.

During platform start-up operations it is envisaged that the water injection system will be

brought on line before field production commences, using only seawater. In this case

injection at a reduced rate of 204 m3/h (30,800 bpd) will be carried out until ballast and

produced water are available. Following start-up the injection rate can be increased to up

to 212 m3/h.

During normal production, once water injection is commissioned, ballast water will be

drawn from the oil storage system and used as a water injection supply in preference to

directly lifted seawater. The ballast water will be filtered in a temporary filtration system for

the first year of operation as described in section 3.1.5. There is no expectation of oil in the

ballast water but the filtration unit is in place to be used to ensure this is the case as best

practice and will be covered by operating procedures carried out by the Aker/Solan

offshore operations team. Water from the temporary filters will be routed downstream of

the fine filters. Ballast water is introduced to the water injection treatment system upstream

of fine filters, allowing ballast water to be subject to the same de-aeration process as lifted

seawater.

3.1.7 Tanker Offloading

Tanker offloading will take between 24 and 36 hours and is anticipated to occur

approximately every 7 to 10 days once full production is reached. To ensure safe

operations tanker offloading will only commence during daylight hours in the Solan field.

Due to unpredictable weather conditions and limited daylight hours, tanker-fill operations

may occur out-with daylight hours. There is a dedicated Multi-Role Vessel (MRV) which

will assist in tanker hook-up and act as a guard vessel during offloading operations. The

MRV is based at Solan 24/7 with a relief vessel with the same capabilities to perform

duties at Solan during the MRV crew change periods. The MRV also comes equipped with


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oil spill detection equipment (which uses radar to pick up any oil on the sea surface) and

dispersant. The Solan platform also has a spill detection system which uses radar. This

extends outwith the tanker offloading station.

Should any issues arise, the tanker will initiate an Emergency Shutdown (ESD) level 1,

breaking the ‘green line’ between the tanker and the Solan platform. An ESD level 1 will

close the inboard coupler valve on the tanker and disengage the hose end valve which

will spring closed which takes around 24 seconds from disconnection. A break in the

‘green line’ will cause an ESD Level 2 Export Inter-trip on the platform which will stop the

seawater displacement pumps and close the 24” export valve on the SOST, thereby

stopping any further offloading operations. As a further barrier, the MRV can also close

the 16” valve on the Solan single anchor loading (SAL) system by using the dunking

transducer on board to remotely close this valve if required.

3.2 Production Profiles

The amended production profiles provided within the Solan ES Addendum (Premier Oil,

2014a) are shown in Table 3-1 Table 3-2 and Table 3-3. The impact assessment of the

production profile using peak rates is included in the original ES. The current production

profiles, which are average rather than peak rates, are less than those stated in the ES.

Therefore, the worst case impact has already been assessed and is in line with those

stated in the field development plan.


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Peak oil production is anticipated in 2016 2019 at a rate of 3,767 2,719 Te/d.

Table 3-1: Anticipated High Case Oil Production Profiles.

Year Average high case annual oil

production rate (Te/d)

2015 2,425 0

2016 3,767 1,473

2017 3,504 2,261

2018 2,192 2,428

2019 1,580 2,719

2020 1,332 1,644

2021 1,154 1,077

2022 899 784

2023 709 644

2024 602 528

2025 537 420

2026 489 389

2027 450 332

2028 418 305

2029 389 274

2030 361 234

2031 314 230

2032 272 206

2033 246 197

2034 228 183

2035 214 161

2036 202 162

2037 190 148

2038 180 144

2039 171 137

2040 163 130

2041 156 124

2042 149 118

2043 143 113

2044 137 109


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Peak gas production is anticipated in 2016 2019 at a rate of 85.7 68.1 Mm3/d.

Table 3-2: Anticipated High Case Gas Production Profiles.

Year Average high case annual gas

production rate (Mm3/d)

2015 55.1 0

2016 85.7 36.9

2017 79.7 56.6

2018 54.3 60.8

2019 39.2 68.1

2020 33 41.2

2021 28.6 27

2022 22.3 19.7

2023 17.6 16.1

2024 14.9 13.2

2025 13.3 10.5

2026 12.1 9.7

2027 11.1 8.3

2028 10.4 7.6

2029 9.6 6.9

2030 8.9 5.9

2031 7.8 5.8

2032 6.8 5.2

2033 6.1 4.9

2034 5.7 4.6

2035 5.3 4

2036 5 4

2037 4.7 3.7

2038 4.5 3.6

2039 4.2 3.4

2040 4 3.3.3

2041 3.9 3.1

2042 3.7 3

2043 3.5 2.8

2044 3.4 2.7


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Water production is anticipated to increase throughout field life and peak in 2044 at a rate

of 4,576 4,010 Te/d.

Table 3-3: Anticipated High Case Water Production Profiles.

Year Average high case annual water

production rate (Te/d)

2015 -

2016 100 0

2017 1,089 0

2018 2,269 220

2019 2,956 974

2020 3,235 2,454

2021 3,435 3,342

2022 3,721 3,177

2023 3,934 3,475

2024 4,054 3,590

2025 4,127 3,457

2026 4,181 3,730

2027 4,225 3,629

2028 4,261 3,813

2029 4,293 3,844

2030 4,325 3,643

2031 4,378 3,889

2032 4,424 3,755

2033 4,454 3,922

2034 4,474 3,935

2035 4,490 3,716

2036 4,504 3,957

2037 4,516 3,813

2038 4,528 3,974

2039 4,538 3,981

2040 4,547 3,988

2041 4,555 3,994

2042 4,563 4,000

2043 4,570 4,005

2044 4,576 4,010

3.3 Chemical Injection System and Flow Assurance

Production chemistry issues occur as a result of chemical and physical changes to the

wellstream fluid as it is transported from the reservoir through the processing system. In


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general, chemicals are required to overcome or minimise a number of the production

chemistry problems that cannot be tackled in other ways and are typically associated with:

Fouling, such as deposition of scales, corrosion products, asphaltenes and

biofouling;

The physical properties of the fluid (foams, emulsions and viscous flow);

Corrosion; and

Environmental or commercial specifications (oily water discharge and the

presence of compounds of sulphur such as H2S).

3.3.1 Chemicals Injected into Production Wells

3.3.1.1 Asphaltene Inhibitor and Solvent Washes

There is a risk of asphaltene precipitation from the P1 and P2 wells. The uncontrolled

precipitation rates could be significant (up to 2 - 3 tonnes per 1,000 bbl of oil production

from P2), and consequently active control and remediation measures will be required.

Asphaltene inhibitor will be required from initial crude production whilst properties of the

crude are verified under operating and laboratory conditions to decide whether ongoing

injection is required.

Asphaltene deposition tends to alleviate with the onset of water production and in general

high water rates are predicted in the Solan development. Consequently asphaltene

inhibitor may only be required for the first few years of production; to be confirmed by

operational experience.

Ashpaltene solvent washes may be required for the flowlines (and for the well production

tubing if asphaltene deposition has occurred there) until the well water cuts are high

(inverted) which is anticipated after 2 to 3 years.

3.3.1.2 Demulsifier

To cater for the uncertainties in emulsion formation and behaviour, demulsifier injection

locations are provided at each wellhead and at the inlet to 1st stage and 2nd stage

separator.

3.3.1.3 Methanol

Methanol should not be required for any routine operation, subject to further detailed

investigation. However, the process design allows for methanol injection at the trees in the


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case of any unforeseen problem such as hydrates, or for use in maintenance operations,

etc.

3.3.1.4 Scale Inhibitor and Scale Squeezes

Calcium carbonate scale formation, and a limited amount of barium sulphate scale, is

likely to occur in the producing wells throughout field life once water production

commences. In order to prevent scale formation, downhole injection of inhibitor will be

required as a proportion of water production. This philosophy assumes that even if an

initial scale inhibitor placement by scale squeeze is carried out prior to production then

continuous scale inhibitor injection may still be required.

In addition to continuous scale inhibition chemical injection, it may be necessary to

conduct reservoir squeezes, particularly if scale formation occurs across the production

well sand screens.

3.3.2 Chemicals Injected into the Oil Processing System

Production chemicals for oil processing including demulsifier, antifoam and asphaltene

inhibitor are required on either a continuous or intermittent basis for injection into the

topsides oil processing facilities.

Production chemicals are exported with the oil. Residual water based chemicals will

partition into the produced water during the separation phase and will be disposed of with

the produced water stream.

3.3.2.1 Diesel Biocide

Facility is provided to inject biocide into the diesel storage feed line and thereby into the

tanks. Diesel biociding will be carried out from the platform should this be required. Biocide

will be applied via a temporary chemical pump set up on the platform. The injection point

topsides is provided as a contingency.

The diesel biocide is a separate formulation from that required for water injection. Manual

dosing immediately prior to or during filling may be adequate unless remote diesel

bunkering is adopted, in which case a dedicated tank and feed line with remotely operated

valve and quantity control would be required.

3.3.2.2 Scale Inhibitor

Scale formation between early-life formation water production carried through into the tank

and the seawater used for displacement and ballast water is not expected to occur except


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possibly for short periods before full water injection breakthrough occurs. Some calcium

carbonate scaling is also possible from displacement water that has been heated by

incoming warm oil. Residual scale inhibitor will be present in the produced water carry-

over from the 2nd stage separator and will provide protection, and any scale that may form

will be minor and would precipitate and fall to the base of the tank.

A contingency scale inhibitor injection point is provided upstream of the inlet separator

should dosing to the wells not be conducted, or to top up squeeze inhibitor returns to

provide sufficient scale control in the process train.

3.3.3 Water Injection Chemicals

Several production chemicals are utilised to optimise the performance of the seawater and

produced water treatment / injection systems. Antifoam, scale inhibitor, biocide and

oxygen scavenger are required either on a continuous or intermittent basis for injection

into the topside seawater treatment facilities.

3.3.3.1 Biocide

Sodium hypochlorite is the principal biocide required to inhibit marine growth within the

lifted seawater. Sodium hypochlorite will be generated in situ by electrochlorination. The

hypochlorite is dosed into the seawater lift pumps, which supplies seawater to the storage

tank displacement water, ballast water and seawater make-up for reinjection.

The SOST is constructed from carbon steel as is the internal pipework. There is a high risk

of corrosive bacteria forming, particularly biofilms, therefore biocidal protection is essential

to protect the integrity of the SOST and internal pipework. Organic biocide will be applied,

from start-up during the first fill of the SOST with oil and then during ongoing normal

operations, to the seawater displacement fluid during offloading of oil from the SOST. The

application of biocide will be reduced as required based on a robust monitoring and

sampling regime.

A shock dose of organic biocide for 2 - 3 hours will be applied every week to the water

injection holding drum once commissioned, to prevent sessile bacteria growth and

possible reservoir / well damage and souring. Organic biocide will also be applied to the

seawater caisson every 3 months and to the umbilical J-Tubes monthly until start up to

maintain the integrity of the pump functions on return to the platform.


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3.3.3.2 Scale Inhibitor

During initial injection of seawater there is a risk of scale formation at the injectors due to

the rise in injected water temperature and incompatibility of reservoir and injection water.

Scale inhibitor is therefore continuously dosed into the injected water stream sufficiently

upstream of the mixing point topsides of produced water and seawater/ballast water, to

ensure its full availability at the mixing point. Two alternative injection points are provided,

one upstream of the water injection booster pumps and, to allow for the risk of warm

ballast water return creating scale in the deaerator, one upstream of the deaerator.

3.3.4 Utility Chemicals

There are requirements for various detergent/cleaning materials including:

A general purpose rig wash (SOBO S GOLD 08) to clean light hydrocarbons

from the decks, which will then mix with fluid in the drainage system and be re-

injected, where possible and discharged with the ballast water should the

injection system be offline.

A turbine wash (ZOK 27 GS) used to perform offline washes to maintain turbine

integrity, which will then mix with fluid in the drainage system and be re-

injected, where possible and discharged with the ballast water should the

injection system be offline.

3.4 Corrosion Management

Process levels of H2S have been calculated as being below the sour limits, and therefore

no specific measures are required.

The primary corrosion protection method for the tank is cathodic protection, although the

bottom section of the tank is also coated as a further mitigation against under deposit

corrosion. The cathodic protection design is standard and has been proven in practice by

anode performance in tanker oil and ballast tanks which represent similar environments.

Externally, the tank is protected by cathodic protection without coating. Monitoring of

cathodic protection performance during operations should be easily achieved by ROV

surveys.

Internal pipework is constructed from 25Cr duplex and coated externally therefore no

corrosion threats are envisaged. However, connections with external piping introduce a

galvanic corrosion threat through dissimilar materials.


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Internal integrity of the pipelines and umbilicals is achieved through chemical injections

and condition monitoring regime combined with pipeline corrosion allowances. Provision

has been made in the umbilical for chemical injection capability.

Cathodic protection of the riser system will be applied in the form of sacrificial anodes. 3-

layer polypropylene (3-LPP) anti-corrosion coating will be applied to the super duplex

water injection line and oil risers. Anti-corrosion coating has been applied to the infield

pipelines.

In addition to the above as the SOST is constructed from carbon steel as is the internal

pipework an robust biocide strategy is in place. There is a high risk of corrosive bacteria

forming, particularly biofilms, therefore biocidal protection is essential to protect the

integrity of the SOST and internal pipework. Organic biocide will be injected with the

seawater displacement fluids during offload and on a batch basis with the oil from the 2nd

stage into the SOST.

There is a high risk of bacterial growth in the SOST as raw seawater will be used for

displacement, which will contain bacteria and is oxygenated. The seawater will then be

allowed to sit in stagnant conditions ideal for the proliferation of biofilm that leads to

microbial influenced corrosion. Therefore, a biopenetrant is required to prevent

establishment and aid removal of biofilm.

3.5 Drains

The main deck areas are plated. The platform cellar deck is bunded to contain pool fires.

All deck areas are drained to either the Closed drains drum or Open drains tank under the

cellar deck. All liquid from the Closed drains drum is pumped to the second stage

separator. Liquids from the Open drains tank are separated into clean water and

hydrocarbons, water is routed to the ballast water caisson and through the temporary

filters and hydrocarbons are returned to the closed drains drum and then back to 2nd stage

separator. a tank under the cellar deck. All liquid from this tank is pumped to the second

stage separator. Hence, all aqueous liquids are directed to the water injection system and

all organic liquids are directed to the oil export system (Chrysaor Ltd, 2009).

3.5.1 Closed Drains System

The closed drain system collects hydrocarbon liquids and oily water drained from the

topsides equipment. These are routed independently to the closed drain drum, where they

are degassed. The recovered liquids are routed to the second stage separator, whilst the


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flashed vapours are routed to the flare header for safe disposal. Future provision is also

provided for routing the reject oil from any produced water treatment package to the

closed drain drum.

3.5.2 Open Drains System

The open drains system is a single open hazardous area drains system only. This takes

deck open drains, diesel drains, skim from the seawater disposal caisson, and backwash

returns from the seawater fine filter (which may be contaminated with oil from ballast

water). Drainage from non-hazardous areas (i.e. rainwater from areas not credibly

exposed to oil contamination) will not be collected but will be allowed to go over the side of

the decks.

Overboard discharge of oil-contaminated water is not permitted.

Open drains water that could credibly be oil-contaminated shall be routed to the open

drains tank where oil will be skimmed utilising a parallel plate pack followed by bucket-

and-weir oil skimming system. Skimmed oil will be returned to the closed drains drum.

The cleaned, but potentially still oily, water from the open drains tank shall be directed by

pump to the ballast water caissons, where it will co-mingle with the ballast water. From

there it will pass through the temporary filtration package and once water injection is

commissioned to the de-aeration package and water injection systems and onwards for

injection into the reservoir. Prior to water injection commissioning and during first fill of the

SOST the drains water will co-mingle with the ballast water then through the temporary

filtration package and be discharged overboard via the seawater disposal caisson C-4801.

As Solan operate a ‘zero’ discharge operating philosophy, the platform will shutdown

should water injection fail. In the event of a planned prolonged water injection shutdown

(during which there will be no production), for example during the annual shutdown, drains

water may be routed from the open drains tank to the seawater disposal caisson. This

pathway, under normal operating conditions, has the flange removed preventing water

from reaching the caisson. This route may be reinstated during prolonged periods of

process shutdown to ensure safe operation of the platform drains. Should this be required,

an Oil Discharge Permit update will be submitted. Any oily residue will be pumped by the

seawater disposal caisson skim pump to the open drains tank.


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4 BASELINE ENVIRONMENT

This part of the document provides a review of the baseline environment and principal

environmental receptors within the area which could be affected by the proposed

installation activities. All infrastructure for the Solan development will be located within

Block 205/26, therefore this section is focussed on the environmental receptors in Block

205/26. These receptors include benthos, birds, fish, marine mammals and other sea

users. This information is gathered from recognised literature sources and draws upon site

specific survey information undertaken by Gardline (2008).

4.1 Metocean Conditions

4.1.1 Water Currents, Waves and Tides

Local current speeds and direction influence the transport, dispersion and ultimate fate of

marine discharges and materials. The general circulation within the North Sea is an anti-

clockwise direction with water entering the North Sea from the Atlantic Ocean north of

Scotland and travelling down the UK east coast to approximately the North Norfolk

coastline where the water current mixes with a weaker current travelling through the

English Channel. The WoS area is predominately influenced by North Atlantic water

(Figure 4-1).

Solan

Development


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Figure 4-1 Prevailing ocean currents in the North Sea

The water current patterns in the WoS area are complex, with various strong non-tidal

currents interacting with the relatively weak tidal flow. Semi-diurnal tidal currents are

relatively weak in offshore northern and central North Sea areas (DTI, 2001). The

maximum tidal current speed within the Solan development area during spring peak flow is

between 0.26 m/s and 0.5 m/s, and during neap peak flow is between 0.11 m/s and 0.25

m/s (Scottish Government NMPI, 2014). Mixing in the water column intensifies with

increased tidal current speed.

The annual mean significant wave height within the area is 2.1-2.4 m. Annual significant

wave power is 24.1-30.0 kW/m of wave crest (Scottish Government NMPI, 2014). During

storms, the re-suspension and vertical dispersion of bottom sediments due to waves and

currents affects most of the North Sea.

4.1.2 Water Temperature

Seawater temperatures vary with season, depth and proximity to land. A seasonal

thermocline can develop during the summer months in response to warmer surface water

floating on top of cooler more dense water. This thermocline breaks down in the autumn

due to seasonal cooling and increasing frequency and intensity of storms causing the

water column to mix. Annual mean surface temperatures in the Solan development area

range from 8-9 ºC, and annual mean seabed temperatures range from 9-10 ºC (Scottish

Government NMPI, 2014).

4.1.3 Winds

Offshore winds in the region may blow from any direction, however winds are

predominantly from southerly and westerly directions (DTI, 2003). A windrose for the area

is shown in PhysE (2009) (see Figure 4-2). Annual wind speed for the area is 11.1-11.5

m/s, with an average range of 10.6-11.0 m/s in spring, 8.1-8.5 m/s in summer, 11.6-12.0

m/s in autumn and 13.1-13.5 m/s in winter (Scottish Government NMPI, 2014). During the

spring (April to June), the area is characterised by a uniform wind distribution with east-

southeast, north-northwest, north and north-northeast winds being predominant. From July

to March, south-southwest, west-southwest and north winds occur with a frequency of

32% (DTI, 2003).


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Figure 4-2 Windrose for the Solan area (PhysE, 2009)

4.2 The Seabed

4.2.1 Bathymetry

The main feature of the region surrounding the Solan area is the Faroe-Shetland Channel,

which reaches depths of up to 1,700 m and is bordered to the northwest by the Faroe

Shelf and to the southeast by the West Shetland Continental Shelf. Just north of 60ºN, the

channel hits the Wyville Thomson Ridge and makes a right-angled turn to the northwest to

form the Faroe Bank Channel.

Quadrant 205 lies over the West Shetland continental slope and the West Shetland

Continental Shelf.

The water depth at the site is 138 m LAT. Depths within the area surveyed by Gardline

(2008) ranged from 125.5 m LAT in the south to 162.2 m LAT in the northwest. Across the

survey area, the seabed shoals towards the south. Across much of the centre and north of

the survey site, and parts of the south, low relief, northeast-southwest orientated striations

were observed. These correlated with areas of gravel, cobbles and boulders found on

sonar records. The maximum gradient within the survey area was 1.9° (Gardline, 2008).

Occasional larger boulders / debris items were identified by side scan sonar.


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4.2.2 Sediment and Seabed Features

Site-specific surveys determined that the sediments throughout the area are

predominantly comprised of gravelly shelly sand with northeast-southwest orientated

bands of gravel, cobbles and boulders. In the southeast of the survey are there are

localised areas of gravelly shelly sand and gravel/cobbles (Gardline, 2008). A large area of

sand waves was also identified orientated northwest to southeast across the Solan

development area (Gardline, 1991; Gardline, 2008). Sand ribbons were also observed in

the southeast, east and southwest of the site, and some trawl scarring was observed

(Gardline, 2008). Within the greater survey area, 17 boulders ranging in height from 0.5 to

1.3 m have been identified (Gardline, 2008).

Seabed image examples are provided in Figure 4-3.

Figure 4-3 Seabed image examples (Gardline, 2008)

There was no indication from the acoustic data, seabed imagery or seabed sampling

within the survey area of any Annex I habitats protected under the UK’s Offshore Marine

Conservation (Natural habitats, &c.) (Amendment) Regulations 2010, which implements

the European Commission (EC) Habitats Directive 92/43/EEC.

4.3 Marine Flora and Fauna

This section describes the main receptors of the marine environment.

4.3.1 Plankton

Plankton are drifting organisms that inhabit the pelagic zone of a body of water and

include single celled organisms such as bacteria as well as plants (phytoplankton) and

animals (zooplankton). Phytoplankton are the primary producers of organic matter in the

Fix: 74 Depth: 155 m

Location: 444605 E 6660438 N

Fix: 64 Depth: 144

Location: 444013 E 6658544 N

Fix 74: Coarse shelly sandy sediment with some gravel

Fix 64: Coarse shelly sandy sediment with some gravel and cobbles


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marine environment and form the basis of marine ecosystem food chains. They are grazed

upon by zooplankton and larger species such as fish, birds and cetaceans; therefore, the

distribution of plankton directly influences the movement and distribution of other marine

species. Meroplankton includes the eggs, larvae and spores of non-planktonic species

(fish, benthic invertebrates and algae) that are found in the plankton. This meroplankton

population may have a very different seasonal cycle depending on the life cycle strategy of

the fish species and benthic organisms which inhabit the area.

The composition and abundance of plankton communities vary throughout the year and

are influenced by several factors including depth, tidal mixing, temperature stratification,

nutrient availability and the location of oceanographic fronts. The distribution, abundance,

production and biodiversity of various plankton species and communities are thought to be

profoundly affected by physical pressures such as oceanic circulation, stratification,

nutrient availability and light levels (McQuatters-Gollop et al., 2010).

Plankton communities in the area of interest are influenced by the inflow of Atlantic Ocean

water through the Faroe-Shetland Channel (Johns and Wooton, 2003). Phytoplankton

assemblages in the area of interest are predicted to be a mixture of oceanic and neritic

(shallow water) plankton species (DTI, 2003). Dominant phytoplankton forms in this region

of the North East Atlantic include diatoms of the genus Chaetoceros and Thalassiosira in

addition to dinoflagellates of the genus Ceratium (Johns and Wooton, 2003). Zooplankton

species found in this region include the Calanoid copepods Calanus helgolandicus and C.

finmarchicus as well as a number of Decapoda and Echinodermata larvae.

4.3.2 Benthos

Bacteria, plants and animals living on or within the seabed sediments are collectively

referred to as the benthos. These include species living on top of the sea floor which are

collectively referred to as epibenthic organisms and may be sessile (e.g. seaweeds) or

freely moving (e.g. starfish). Animals living within the sediment (e.g. clams, tubeworms

and burrowing crabs) are termed infaunal organisms. Semi-infaunal animals, including sea

pens and some bivalves, lie partially buried in the seabed.

The structure and distribution of benthic communities can be explained largely by

environmental parameters including temperature, salinity, tidal / wave-induced bed stress,

stratification, depth, and sediment type. Their relative importance varies spatially and

many are intercorrelated (Rees et al., 2007).

Historical surveys have confirmed that the seabed communities of the Shetland

continental shelf are typical of the Boreal province extending south to the North Sea (DTI,


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2003). The abundance of fauna in the area of the Solan development was found to be low

across the site, with slight increases around areas of cobbles and boulders. Crustaceans

(Pagarus sp.), annelids (Lanice conchilega, Ditrupa arietina, Pomatoceros sp.), cnidarians,

molluscs, dogfish and flatfish are commonly recorded. No protected species or habitats of

conservational concern were observed (Gardline, 2008).

4.3.3 Seabirds

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

borne pollution. The aerial habits of fulmars and gulls, together with their large populations

and widespread distribution, reduce their vulnerability to oil related pollution. Auks (e.g.

guillemots, razorbills and puffins) are most vulnerable in the post-breeding season (July to

August) when they become flightless during periods of moult, thus spending large

amounts of time on the water surface. Generally, vulnerability is lowest during the pre-

breeding and breeding months, increasing as the breeding season ends and birds

disperse into offshore waters (Stone et al., 1995).

JNCC has produced an Offshore Vulnerability Index (OVI) for seabirds encountered within

each offshore licence block in the Southern, Central and Northern North Sea and the Irish

Sea. For each block, an index of vulnerability for all species is given which considers four

factors:

The amount of time spent on the water;

Total biogeographical population;

Reliance on the marine environment;

Potential rate of population recovery.

Each of these factors is weighted according to its biological importance and the OVI is

then derived (Williams et al., 1994). The OVI of seabirds within each offshore licence block

changes throughout the year. This is due to seasonal fluctuations in the species and

number of birds present in an area.

Seabirds present within the immediate vicinity of the Solan area include fulmars, gannets,

great black-backed gulls, kittiwakes, guillemots, razorbills, little auks and puffins. As can

be seen from Table 4-1, the sensitivity of birds to surface pollution in the immediate area

of the Solan field and the surrounding blocks varies throughout the year (JNCC, 1999).

Seabird vulnerability within Block 205/26a during the proposed pipeline operations

(covering a period from June to October with contingency to end of December) is high in


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July, moderate in June, October and November and low in August, September and

December. The overall vulnerability of seabirds to surface pollution is considered low, as

shown in Figure 4-4.

Table 4-1 Seabird vulnerability to surface pollution by block

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

204/25 3 4 3 2 3 2 2 4 3 3 3 4

205/21 3 4 3 2 3 3 2 4 3 3 3 4

205/22 3 4 3 2 3 3 2 4 3 3 3 4

204/30 3 4 3 2 3 2 2 4 3 3 3 4

205/26 3 4 3 2 3 3 2 4 4 3 3 4

205/27 3 4 3 2 3 3 2 4 4 3 3 4

202/5 3 3 2 2 2 2 1 4 3 2 3 4

203/1 3 3 2 2 2 2 1 4 4 2 3 4

203/2 3 3 2 2 2 2 1 4 4 2 3 4

Key 1 = Very high 2 = High 3 = Moderate 4 = Low

Figure 4-4 Overall seabird vulnerability to surface pollution

4.3.4 Fish

At present, more than 330 fish species are thought to inhabit the shelf seas of the UK

Continental Shelf (UKCS) (Pinnegar et al., 2010). Many of these species are widespread

across the North Sea, having large extended spawning and nursery grounds. Some of the


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commercial species with recognised spawning and nursery grounds in the area of Block

205/26 are listed in Table 4-2 (Coull et al., 1998; Ellis et al., 2012).

Table 4-2 Spawning and nursery activity of some commercial fish species found in the vicinity of Block 205/26 (Coull et al., 1998; Ellis et al., 2012).

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

Norway pout

Sandeel

Mackerel

Blue whiting

Herring

Whiting

Lemon sole

Haddock

Key Spawning Peak Spawning

4.3.5 Marine Mammals

Cetaceans regularly recorded in the North Sea include harbour porpoise, white-beaked

dolphin, minke whale, Atlantic white-sided dolphin, bottlenose dolphin (primarily in inshore

waters) and killer whale (Reid et al., 2003). Risso’s dolphin and large baleen whales are

also occasionally sighted. Spatially and temporally, harbour porpoise, white-beaked

dolphin and minke whale are the most commonly sighted cetacean species in the North

Sea (Reid et al., 2003).

The most common species of cetaceans in the vicinity of the Block 205/26 are harbour

porpoise, Atlantic white-sided dolphin, white-beaked dolphin and minke whale (Table 4-3).

Other published sources of data regarding cetacean distribution in the area include the

SCANS-II (Small Cetacean Abundance in the North Sea) project (SMRU, 2008).

Table 4-3 Cetacean sightings in the vicinity of Block 205/26 (Reid et al., 2003)

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

Harbour porpoise

Atlantic white-sided dolphin

White-beaked dolphin

Minke whale

Species recorded Species not recorded

Common (or harbour) seals (Phoca vitulina) and grey seals (Halichoerus grypus) are

frequently observed throughout the North Sea. Both the common and grey seal are listed

species in Annex II of the Habitats Directive (see Section 4.5).


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Seals tend to exhibit a general pattern of remaining in close proximity to haul out sites.

Given the distance of the Block 205/26 from the nearest seal haul out site, located

approximately 100 km away on the Orkney Isles (Scottish Government, 2011), seals are

not expected to occur in significant numbers in the area.

4.4 Socio-Economic Environment

4.4.1 Commercial Fishing

Block 205/26 occurs within ICES rectangle 49E6. The UK fishing effort within this area

varies throughout the year. Annually the effort (or importance of the area) can be

considered moderate with an average fishing effort of 788 days (2010 – 2014) per annum.

Approximately 0.44 % of total UK landings between 2010 and 2014 were taken from the

area (Table 4-4) (Scottish Government 2015).

Table 4-4 Fishing Effort by UK Fishing Fleet in ICES Rectangle 49E6 (Scottish Government, 2015).

Year Total Fishing Effort by UK Fishing Fleet (days)

UK total 49E6 49E6 as a % of UK

2010 205,083 1,012 0.49

2011 188,389 994 0.53

2012 185,182 641 0.35

2013 183,413 652 0.36

2014 129,850 639 0.49

Average over 2010 - 2014 788 0.44

The value of landings from ICES rectangle 49E6 over the years 2010 – 2014 are shown in

Table 4-5. In general, the most valuable fisheries in the area are demersal and shellfish

fisheries, although in 2010 the value of pelagic fisheries was much higher than shellfish

than in other years. Over the five years, the average value of demersal, pelagic and

shellfish fisheries in ICES rectangle 49E6 have ranged between 0.67 and 1.36 % of the

UK total.

Table 4-5 Value of Landings (£) by Target Species Group in ICES Rectangle 49E6 (Scottish Government, 2015).

Year Target Species Group (value of landings £) 49E6 as % of

UKCS Demersal Pelagic Shellfish

2010 7,071,130 308,317 62,612 0.98

2011 6,746,227 338 58,225 0.78

2012 5,572,326 1391 44,996 0.67


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2013 6,661,708 1,650 87,088 0.89

2014 8,962,055 572 42,969 1.36

4.4.2 Shipping

A vessel traffic survey was conducted by Anatec on behalf of Premier Oil. The Shipping

Route Positions within 10nm of the Solan central survival location are shown in Figure 4-5

(Anatec, 2015). There are an estimated 835 ships per year passing within 10nm of the

Solan Platform location, corresponding to an average of 2 to 3 vessels per day.

Figure 4-5 Shipping route positions within 10 nm of the Solan location

4.5 Protected Sites and Species

The European Union (EU) Habitats Directive (92/43/EEC) and the EU Birds Directive

(79/409/EEC) are the main driving forces for safeguarding biodiversity in Europe. Through

the establishment of a network of protected sites, these directives provide for the

protection of animal and plant species of European importance and the habitats that

support them.

The EU Habitats Directive and the EU Birds Directive have been enacted in the UK by the

following legislation:

The Conservation (Natural Habitats, &.c.) Regulations 1994 (as amended): These

regulations transpose the Habitats and Birds Directives into UK law. They apply to


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land and territorial waters out to 12 nautical miles (nm) from the coast and have

been subsequently amended several times.

The Conservation of Habitats and Species Regulations 2010: The Conservation of

Habitats and Species Regulations 2010 consolidate all the amendments made to

the Conservation (Natural Habitats, &c.) Regulations 1994 in respect of England

and Wales. In Scotland, the Habitats and Birds Directives are transposed through a

combination of the Habitats Regulations 2010 (in relation to reserved matters) and

the 1994 Regulations.

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

amended 2009 and 2010): These regulations are the principal means by which the

Birds and Habitats Directives are transposed in the UK offshore marine area (i.e.

outside the 12 nm territorial limit) and in English and Welsh territorial waters.

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

amended 2007): These regulations apply the Habitats Directive and the Birds

Directive in relation to oil and gas plans or projects wholly or partly on the United

Kingdom Continental Shelf and superjacent waters outside territorial waters (‘the

UKCS’) (i.e. outside the 12 nm territorial zone).

The Habitats Directive lists those habitats and species (Annex I and II respectively)

whose conservation requires the designation of special areas of interest. These

habitats and species are to be protected by the creation of a series of ‘Special

Areas of Conservation’ (SACs), and by various other safeguard measures (Sites of

Community Importance (SCIs)) for particular species. The Birds Directive requires

member states to nominate sites as Special Protection Areas (SPAs). Together

with adopted SACs, the SPA network forms the ‘Natura 2000’ network of protected

areas in the European Union.

Of the habitat types listed in Annex I of the Habitats Directive as requiring

protection, four occur or potentially occur in the UK offshore area (EC, 2007):

Sandbanks which are slightly covered by seawater at all times;

Reefs:

o bedrock reefs; made from continuous outcroppings of bedrock which

may be of various topographical shape (e.g. pinnacles and offshore

banks);


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o stony reefs; aggregations of boulders and cobbles which may have

some finer sediments in interstitial spaces;

o biogenic reefs; formed by cold water corals (e.g. Lophelia pertusa)

and the polychaete worm Sabellaria spinulosa;

Submarine structures made by leaking gases; and

Submerged or partially submerged sea caves.

The benthic community recorded in the vicinity of Block 205/26 is characteristic of

communities recorded in the West of Shetland region. No leaking gas features, reefs

(geological or biological) or other potential marine Annex I features were recorded

(Gardline, 2008).

The closest protected areas to Block 205/26 are the Foula SPA and the Wyville Thomson

Ridge SAC which lie approximately 100 km east and 110 km west of the site, respectively

(Figure 4-6). Due to these distances, no adverse effects on any protected areas are

expected from the proposed pipeline operations at the Solan field.

Figure 4-6 Offshore SACs, SCIs and MPAs in Closest Proximity to the Solan Development


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Four of the species listed in Annex II of the Habitats Directive occur in relatively large

numbers in UK offshore waters:

Grey seal (Halichoerus grypus);

Common seal (Phoca vitulina);

Bottlenose dolphin (Tursiops truncatus); and

Harbour porpoise (Phocoena phocoena).

The only one of these species likely to occur within the area is the harbour porpoise.

As a result of the Marine and Coastal Access Act (2009), the Marine Conservation Zones

(MCZ) and Marine Protected Areas (MPA) Project was set up. 30 Nature Conservation

MPAs were designated in July 2014, 13 of which are offshore (beyond 12 nm) (JNCC,

2014). These have been designated to contribute to an ecologically coherent, well-

managed network of MPAs by the end of 2016 to fulfil international and European

commitments.

The nature conservation MPAs (NCMPAs) nearest to the Solan development are the

Faroe-Shetland Sponge Belt, the West Shetland Shelf and Northwest Orkney, located

approximately 23 km northwest, 27 km southeast and 50 km southwest of the site,

respectively. Due to these distances the proposed installation activities are unlikely to

have an impacted on any designated NCMPAs.


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5 IMPACT ASSESSMENT

This section presents the results from the identification and assessment of environmental

impacts from the proposed commissioning and operational activities, grouped under the

following headings;

Physical presence;

Seabed Disturbance;

Underwater Noise;

Atmospheric Emissions;

Marine Discharges;

Accidental Events; and

Waste

5.1 Physical Presence

5.1.1 Installation

The vessels which will be on site during precommissioning activities are described in

Section 2.4. These vessels have the potential to impact on other sea users, notably

commercial fishing and shipping. Existing levels of shipping and fishing are described in

Section 4.4.1.

In addition the presence of the jacket and SOST may impact on fishing activities in the

area. This section assesses the impact of the physical presence of the vessels and

infrastructure on other sea users whilst the impacts on the benthic communities are

discussed in Section 5.2.

The two 500 m exclusion zones around the SOST and platform, respectively, will be

unavailable to other sea users to decrease the likelihood of vessel collision.

Consent to Locate applications will be submitted to DECC under this EIA Justification

document and the Collision Risk Management Plan will be implemented. Consent to

Locate CL/264, which covered the installation of the SAL marker buoy, expired on the 31st

of March. The installation of the marker buoy for the SAL system has been delayed and

will now not be fitted until summer of 2015. This installation has been moved to CL/208

and is now covered by this EIA Justification.


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In addition when the W1 and W2 wells were suspended in 2008, protective Aquaterra

trash caps were installed onto the wellheads. These remained on the wells until 2013

when they were removed to allow the drilling campaign to commence. At this point they

were laid down on the seabed to allow the opportunity for reinstallation, if required. The

deposit of trash caps was reported under a PON2 (0157) as no consent was sought for

this operation; however, re-installation was not required and it was originally planned to

retrieve the structures under PLA/90 ML121. Due to technical feasibility and operational

risks of recovering the trash caps, Premier now propose to withdraw the trash caps from

the Marine Licence application and add them to the Consent to Locate for the Solan

platform (CL/208) so they will now be covered by this EIA Justification.

The total area of the two protective structures is 8.6 m2 (Table 5-1) of which only a small

proportion actually contacts the seabed. No further impact on the seabed environment is

anticipated from the protective structures remaining on the seabed in their current location

until the end of field life.

Table 5-1 Anticipated foot print

Deposit Number of

objects

Area impacted

by one object (m2)

Approximate total area impacted (m2)

Aquaterra trash caps 2 4.30 8.60

Variation 9 Version 2:

A Waverider Buoy was deployed at the start of the 2015 campaign for metocean data

acquisition to assist with ongoing wellhead fatigue analysis and to assess rig motion

characteristics (approved as per CL/208/7 Version 1).

At 21:57 on 17th September the buoy stopped transmitting data. Premier was informed on

the 18th September by Fugro. The Stand-by vessel was dispatched to investigate and

took some pictures, one of which is shown below (Figure 5-1).


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Figure 5-1 Waverider Buoy with damage shown

The pictures indicated that the buoy had been in a collision with a dent visible, (brown

circle). The buoy was still afloat and at the time we had no concerns about the integrity

of the buoy. Fugro, who supply the buoy were contacted and requested to supply a

replacement buoy. The plan was to swap out old for new, using the existing clump

weight and tether line. We had planned to load the replacement buoy onto the regular

Supply Vessel who had agreed to perform the recovery and re-deployment operation.

As the rig had skidded approximately 250 m away from the buoys location, when the rig

moved from the P2z to the W2 Re-drill location, the buoy was not easily visible from the

rig in anything but a totally calm sea. The Stand-by vessel was asked to sail past the

buoys’ location and verify its condition again. At morning rig call on the 30th September

2015, the rig confirmed that the buoy was no longer on the sea surface and had sunk. A

PON10 has been submitted notifying the relevant authorities (reference TBC). The

location is shown in Figure 5-2.


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Figure 5-2 Waverider Buoy location within anchor spread


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The buoy’s location was chosen so that in the event that the buoy sunk for any reason

the buoy would not foul either of the anchor lines adjacent. The anchor lines adjacent to

the buoy’s location contain fibre inserts which cannot tolerate abrasion and must be

kept in the catenary at all times. The anchor lines adjacent to the buoy’s location are

suspending the water at a depth of approximately 150 ft above seabed. The water

depth at the buoy location is approximately 440 ft.

The buoy contains several accelerometers and sufficient computer and signalling

equipment to allow wave data to be transmitted real time to the weather collection

centre. The buoy also contains a battery pack. The buoy contains no foam buoyancy

which would allow it to stay afloat if the integrity of the buoy is breached. Either the

buoy is floating or it is on the seabed. The tether attaching the buoy to the seabed

contains chain segments and several small buoys. With the buoy on the seabed Fugro,

who supply the buoy, estimate that no part of the tether would be more than 275 ft

above seabed.

As the buoy is within the existing catenary structure of the anchor spread and no part of

the tether is capable of coming closer than 163 ft (approx.) of the surface of the sea we

do not consider that the buoy to present a hazard to shipping in its current state. We

would propose to recover the buoy when we have a suitable anchor handling vessel in

the area. This may be when the rig anchor spread is recovered after the current

campaign.

With regards to the existing DSV in the Solan field at the moment, this vessel will not be

in a position to recover the buoy before it comes off contract tomorrow. The contract

cannot be extended as the vessel is committed to another operator and the necessary

pre-job risk assessments and pre checks would prevent the recovery operations being

completed in the time available.

In summary the wave buoy in its current sunk condition represents no danger to

shipping in the area. The area around the rig is patrolled by a dedicated Stand-by

vessel which is on duty 24 hrs a day.

Additionally there is the intention to deploy another Waverider buoy (same model)

approximately 100m away from the current sunk Waverider buoy (as detailed in

CL/208/9).

The area of seabed that the Waverider buoys are contained within an area that has

already been assessed by the anchor spread of the Ocean Valiant therefore there is not


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expected to be any environmental impact. Additionally, the new Waverider buoy is not

expected to present a navigational hazard to other sea users.

5.1.2 Commissioning

Ongoing drilling operations require the Ocean Valiant Mobile Offshore Drilling Unit

(MODU) to be onsite at the Solan development from the 15th May 2015 for approximately

250 days. The Ocean Valiant is semi-submersible and will be anchored in place.

The hook-up and commissioning operations will require additional accommodation in the

form of a DP flotel, the Flotel Regalia. The flotel will be moored next to the Solan Platform

and is expected to arrive at the Solan field on the 1st August and stay for approximately

111 days. The Floatel Superior will replace the Flotel Regalia as accommodation vessel

from the 18th of November and stay for approximately 103 days. The two flotels may

coincide with one another for 3 days before the Regalia leaves.

These vessels will be within the established 500 m safety zone at the Solan platform.

Therefore, restrictions to shipping and fishing in the area will not alter during

commissioning and will not cause any additional disruption to navigation in the area. As

discussed, the area is of relatively low importance in terms of shipping traffic and fishing,

the physical presence of the accommodation vessel in the area during commissioning

activities is not considered to be significant.

5.2 Seabed Disturbance

5.2.1 Commissioning

5.2.1.1 Ocean Valiant

Seabed disturbance associated with anchor chains from the drilling rig Ocean Valiant has

been assessed. The rig will be held in position by a 12 chain and anchor mooring system,

the provisional anchor layout is illustrated in Figure 5-1. A seabed footprint of

approximately 0.12 km2 has been calculated (Table 5-2). All the anchors and chains will be

recovered and so the disturbance to the seabed will be temporary.


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Table 5-2 Seabed area temporarily impacted by the drilling rig mooring

Parameter Area (km2)

12 x anchors, 10 m x 10 m per anchor placement 0.0012

12 x anchor chains, with a worse case impact on an area of seabed assumed to be 1,000 m x 10 m per chain

0.12

Total 0.1212

Physical disturbance as a result of anchor scarring can cause mortality or displacement of

benthic species in the impacted zone, direct loss of habitat and direct mortality of sessile

seabed organisms that cannot move away from the contact area at seabed contact points.

Two factors minimise these impacts:

Biological communities are in a continual state of flux and are able to either

adjust to disturbed conditions or rapidly re-colonise areas that have been

disturbed;

The active / dynamic nature of much of the seabed environment will aid the

rapid recovery of the disturbed areas, although some seabed scars may

persist.

As discussed in Section 5.2, the majority of seabed species recorded from the European

continental shelf are known or believed to have short life spans (Rees and Dare, 1993).

Therefore, it is expected that the benthic species will be recruited from the surrounding

seabed and so the impacted areas will recover from the physical disturbance.


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Figure 5-3 Proposed anchor pattern (Diamond Offshore, 2015)


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There is limited data on the impacts of scarring from oil and gas activities. However,

Coastline Surveys Limited (1999) has undertaken a study on the impacts of marine

aggregate mining on the benthic community. Dredge pits were still visible in coarse gravel

deposits after two years. Recovery time can range from one to 15 years depending on the

currents in the area.

Seabed currents in the Solan development area are strong with a maximum spring tide of

0.5 m/s (Scottish Government NMPI, 2015). Significant erosion of anchor mounds is

considered to start when the seabed critical velocity reaches 0.35 m/s (UK Offshore

Operators Association, 1999). It is therefore likely that significant erosion of anchor

mounds will occur at times. The temporary nature of the anchor placements ensures that

once the anchors have been removed from the seabed, re-colonisation and recovery can

begin.

DTI (2003b) suggests that the recovery of affected areas of seabed from operations such

as anchoring is expected to be rapid on the WoS continental shelf and slope; recovery

may be expected within five years. Impacts to the seabed are unavoidable; however, the

area that will be affected is small in comparison with the surrounding available seabed and

the localised impacts are not likely to result in large-scale changes in the benthic

community.

5.3 Underwater Noise

5.3.1 Hook-up and Commissioning

This section discusses the noise from the vessels associated with the hook-up and

commissioning works. Previously, Premier were to use the Ceona Amazon as the walk to

work vessel, the Siem Spearfish will now be used instead of the Ceona Amazon. The

current noise impact assessment is for the Ceona Amazon, the Siem Spearfish is a

smaller vessel and has less thrusters and power output. Therefore, the current

assessment will likely overestimate the potential impact of the walk to work vessel for the

commissioning phase work during 2015. The Siem Spearfish will be used as the

accommodation vessel from the 20th June until the 1st August, after which the Flotel

Regalia will replace the Siem Spearfish. As the vessels will be both be on DP the following

noise assessment is representative of both accommodation vessels.

The Floatel Superior will replace the Flotel Regalia as the accommodation vessel, there is

a possibility that they could overlap by 3 days. The Superior will initially be to the south

side of the Solan platform until the Regalia leaves when it will move to the east side of the

platform where the Regalia previously was. The Superior will be on DP at times.


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For completion this section also considers the noise associated with the drilling rig which

will also be on location (as described in the Solan drilling permit applications). Underwater

sound associated with the hook-up and commissioning operations will primarily result from

the accommodation vessels, and other vessels also in the area, namely, a DSV and two

standby ERRVs. The drilling rig, the Ocean Valiant will also be in the area and so has

been included in this assessment. This section assesses the impact on marine mammals

of noise generated by the accommodation vessel, the drilling rig and associated vessels.

The primary sources of sound from vessels are propellers, thrusters and other machinery

(Ross, 1976; Wales and Heitmeyer, 2002). In general, vessel sound is continuous and

results from narrowband tonal sounds at specific frequencies and broadband sounds.

Acoustic broadband source levels typically increase with increasing vessel size, with

smaller vessels (< 50 m) having source levels 160-175 dB (re 1 μPa), medium size

vessels (50-100 m) 165-180 dB (re 1 μPa) and large vessels (> 100 m) 180-190 dB (re

1μPa) (summarised by Richardson et al., 1995). However, sound levels depend on the

operating status of the vessel and can vary considerably in time. Acoustic energy is

strongest at frequencies below 1 kHz. Sound levels can be increased during use of DP,

which requires the use of thrusters to control a ship’s location.

Sound associated with drilling rigs will propagate from rotating equipment such as

generators, pumps and the drill string. No specific measurements are available for sound

generated by a semi-submersible drill rig. In general, sound from drilling has been found to

be predominantly low frequency (< 1,000 Hz) with relatively low source levels. Source

levels were found to be less than 195 dB (rms) re 1 µPa-m for a drill ship (Nedwell and

Edwards, 2004). A study by Greene (1987) found that the sound generated by drilling

activities from a semi-submersible did not exceed local ambient levels beyond 1 km,

although weak tones were detectable up to 18 km away. Studies have shown that during

drilling underwater sound levels increase when compared to periods of non-drilling, which

has been related to the use of additional machinery and power demands (McCauley,

1998). Drilling sounds, although of a relatively low level, will be continuously generated for

long periods throughout drilling.

This section assesses the impact on marine mammals of noise generated by the

accommodation vessel, the drilling rig and associated vessels. The impact on marine

mammals is determined by modelling the propagation of sound from the walk to work

vessel, the drilling rig and vessels into the surrounding water and comparing the levels

with precautionary thresholds for injury and disturbance to marine mammals (Southall et


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al., 2007). Southall et al. (2007) conducted a review of noise impact studies and used the

results to propose thresholds for injury and disturbance for different:

marine mammal hearing types – low, mid and high frequency hearing;

sound types – pulse, multiple pulse and non-pulse; and

sound metrics – peak unweighted SPL and SEL weighted for different marine

mammal hearing types.

The assessment method used here is based on the JNCC guidance on the protection of

marine European Protected Species from injury and disturbance (JNCC, 2010).

As the Solan field is approximately 95 km from the nearest coastline, it is not expected that

seals will regularly occur in the area (Scottish Government, 2011). Therefore, this

assessment focuses on cetaceans.

The Regalia will sit alongside the platform and connect to the platform to transfer

personnel and then move alongside the platform. The flotel is a column stabilised semi-

submersible vessel. There are three thrusters, six thrusters in total. The thrusters are

NDM3 DP and each thruster is 2.64 MW in power (Prosafe, 2014). A DP system is used

for station keeping, using all six of the thrusters.

The Floatel Superior will replace the Regalia as accommodation vessel, the two flotel

could potentially overlap for 3 days which could increase underwater noise levels during

that time. The Superior has six azimuth thrusters each 3,200 KW. The thrusters are DP3

Knosberg K-Pos DPM-32 (Floatel International, 2015). A DP system is used for station

keeping, using all six of the thrusters.

Other vessels that will also be in the area at the same time as the accommodation vessel

have also been included in the assessment. A DSV will be used for 20 days at the end of

May and two standby ERRVs will be in the vicinity of the field at all times during the

campaign. As a conservative assumption here all vessels have been modelled as being in

the same place at the same time, whereas in reality the vessels will be spread out. As

mentioned previously the Ocean Valiant drilling rig has also been included and has been

modelled as being in the same place as the vessels.

As the two flotels could potentially overlap, additional modelling was carried out to assess

the cumulative impact of all the vessels in the field. The results found that an additional

flotel will only increase the broadband peak SPL by 1 dB. Therefore, the noise assessment

which follows will be representative.


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5.3.1.1 Unweighted peak SPL thresholds

Peak SPL is a measure of the loudest instantaneous sound likely to be generated during

an activity. To assess the impact of noise on marine mammals from the thrusters of the

walk to work vessel, the drilling rig and the vessels, the sources have been modelled using

representative spectra from published sound measurements (Figure 5-4).

The frequencies and sound levels generated by the accommodation vessel were modelled

using measurements of six offshore oil production vessels (Erbe et al., 2013). The sound

recordings were combined and the 95th percentile of the measurements were used as a

conservative assumption. The resulting sound spectrum is considered a reasonable

representation of the walk to work vessel due to the use of azimuth thrusters by both

vessel types (Siem Offshore, 2014; Prosafe, 2015; Floatel International, 2015 and Erbe et

al., 2013). As no source spectra were available for sound from a semi-submersible drilling

rig, the drilling noise was represented by a source spectrum for a drillship (Miles et al.,

1987), which is a conservative assumption. The DSV and the standby ERRVs were

represented by a source spectrum for a typical merchant vessel (Wales and Heitmeyer,

2002).

Figure 5-4 Sound sources used to represent accommodation vessel and associated vessels

120

130

140

150

160

170

180

190

1 10 100 1,000 10,000 100,000

1/3

oct

ave

ban

ds

0-p

SP

L (d

B r

e 1

µP

a-m

)

Frequency (Hz)

Walk to work vessel - FPSO [Erbe et al., 2013]

DSV and Standby vessels - Merchant vessel [Wales and Heitmeyer, 2002]

Ocean Valiant - Drillship [Miles et al., 1987]


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Figure 5-5 Modelled unweighted SPL from combined sound sources

5.3.1.2 Weighted SEL thresholds

SEL is a measure of total sound energy over a period of time.

The estimated source spectrum for the combined sound sources of the accommodation

vessel, drilling rig and associated vessels with the hook up and commissioning work was

weighted for marine mammal hearing by applying the Southall et al. (2007) M-weightings

for each marine mammal hearing type – low frequency, mid frequency and high frequency

hearing (Figure 5-5). The resulting weighted source spectra are shown in Figure 5-6.


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Figure 5-6 Resulting M-weighted SEL for combined accommodation vessel, drilling rig and vessels

In order to calculate the total SEL experienced by an animal, it is necessary to make

assumptions about the movement pattern of the animal in time. To compare with the

Southall et al. (2007) recommendations, the calculation of SEL should be based on the

animal’s behaviour over a 24-hour period. This is extremely difficult to predict. Therefore, a

scenario has been modelled whereby an animal displays avoidance behaviour by moving

away from the source.

5.3.1.3 Travelling animal

This scenario assumes that an animal exposed to the noise from the accommodation

vessel would display avoidance behaviour, swimming away from the source at a fixed

speed and relative to the source.

Figure 5-7 shows the received unweighted SEL and the cumulative received SEL as the

animal moves away from the source at 5 m/s. While a wide range of cruising speeds are

found in the literature this travelling speed has been assumed for previous assessments

carried out for piling noise (e.g. Theobald et al., 2009). A sensitivity analysis has been

conducted using various swimming speeds and the conclusions were not found to change.

One example is shown: an animal is initially 1 m from the source (Figure 5-7), for an

70

90

110

130

150

170

190

210

1 10 100 1,000 10,000 100,000

Sou

rce

M-w

eig

hte

d S

EL (

dB

re

1µ

Pa

2 s a

t 1

m)

Frequency (Hz)

Unweighted

Low-frequency cetacean

Mid-frequency cetacean

High-frequency cetacean


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unweighted broadband SEL. This starting distance is a very pessimistic assumption and

ignores the more likely scenario of the sound sources being spread out over a large area.

Figure 5-7 Cumulative SEL from the flotel and vessels as an animal travels away at 5 m/s from an initial distance of 1 m.

The results indicate that the Southall et al. (2007) SEL threshold for injury from a non-

pulse (215 dB re 1 µPa2s) will not be exceeded at any point.

5.3.1.4 Comparison with behavioural response thresholds for disturbance

The sound generated by the accommodation vessel, drilling rig and associated vessels

with the hook up and commissioning work will primarily be of non-pulse type and all

hearing classes of cetaceans have the potential to occur in the development area. A

review of the studies collated by Southall et al. (2007) that are relevant to the sound

sources suggests the following:

Low-frequency cetaceans exposed to non-pulse sound appear in general to

show little or no response to received SPL lower than 120 dB re 1 µPa rms and

increasing probability of response at 120-160 dB re 1 µPa rms. However, there

is considerable variation in response and contextual variables such as level of

habituation are at least as important as received sound level. 120 dB re 1 µPa

rms is used here as a conservative threshold.

180

185

190

195

200

205

210

215

220

0 50 100 150 200

Re

ceiv

ed

SEL

(d

B r

e 1

µP

a2 s

)

Time (seconds)

Cumulative Received SEL

SEL injury threshold for cetaceans


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Studies of mid-frequency cetaceans exposed to non-pulse sounds did not find

a consistent level of sound above which a severe response resulted. A severe

response was noted in some studies at 90-120 dB re 1 µPa rms but in other

studies no response was exhibited at 120-150 dB re 1 µPa rms. As mid-

frequency cetaceans are likely to be less sensitive to vessel sound than low-

frequency cetaceans, whose frequency range of most acute hearing overlaps

with the peak frequencies generated by vessels, the disturbance threshold for

low-frequency cetaceans (120 dB re 1 µPa rms) is used here for mid-frequency

cetaceans.

Of high-frequency cetaceans, only the harbour porpoise has been well studied.

Severe and sustained avoidance was found to result for received non-pulse

sound levels above 140 dB re 1 µPa rms. Habituation was noted in some

studies, whereby the response waned with repeated exposure.

Based on these data, the estimated zones of disturbance for each marine mammal

hearing type to multiple pulses during the hook up and commissioning work have been

calculated (Table 5-3). It should be noted that there is considerable uncertainty in these

values, related to paucity of data and variation in the reported responses of marine

mammals to sound levels. In addition, conservative values have been selected, i.e. the

lowest sound levels leading to a severe behavioural response.


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Figure 5-8 Modelled unweighted rms SPL and weighted cetacean disturbance zones

Table 5-3 Distances to disturbance thresholds for marine mammals.

Marine mammal

hearing group

Precautionary disturbance threshold

(rms SPL in dB re 1µPa)

Distance to threshold (km)

Area of potential impact (km2)

Low frequency cetacean

120 11.8 437

Mid frequency cetacean

120 2.0 12.6

High frequency cetacean

140 0.15 0.07

The estimated numbers for each species are shown in Table 5-4, using the SCANS data

as described previously.


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Table 5-4 Estimated number of animals within potential disturbance zone.

Species

Density (animals/km2)

(SCANS II 2008, Survey Block J)

Total abundance (SCANS II, 2008,

entire survey area)

Number of animals within

disturbance zone

Percentage of

population (%)

Minke whale 0.012 16,391 5 0.03

White-sided dolphin 0.052 27,228 1 0.002

White-beaked dolphin1 0.052 22,398 1 0.003

Harbour porpoise 0.067 375,358 <1 0.000001 Notes: 1Combined data for white-beaked and white-sided dolphin, which can be difficult to distinguish in the field.

5.3.1.5 Conclusions of Noise Assessment

The modelling found that the SPL injury thresholds were unlikely to be exceeded (Figure

5-5). Assuming that an animal would be likely to move away from the sound generated by

the accommodation vessel, drilling rig and associated vessels with the hook up and

commissioning work, the modelling found that the SEL thresholds are also unlikely to be

exceeded for any marine mammal hearing type Figure 5-7. Based on these results, it is

considered unlikely that any marine mammal will be injured by sound generated by the

accommodation vessel, drilling rig and associated vessels with the hook up and

commissioning campaign.

JNCC (2010) acknowledge that chronic exposure to vessel noise has the potential to

cause disturbance to marine mammals. Tentative disturbance thresholds were applied

based on studies of marine mammals exposed to non-pulse sounds reviewed by Southall

et al. (2007). The results suggest that sound generated by the accommodation vessel,

drilling rig and associated vessels with the hook up and commissioning work may be loud

enough to cause disturbance within a few kilometres to a few tens of kilometres (Figure

5-8). These values are very conservative as they are based on the lowest sound levels

reported to cause a severe behavioural response. The numbers of animals affected,

estimated by multiplying the modelled areas of disturbance by the average density of each

species in the Solan area, are low com (Table 5-4).

JNCC (2010) state that the likelihood of disturbance to marine mammals from vessel noise

depends on many factors such as the type of vessel, importance of the area for marine

mammals, the receptor’s behaviour and habituation, etc. As stated above, the reported

response of animals to received sound waned with repeated exposure in some studies.

This suggests that sound from the accommodation vessel may become less disturbing

over time and also that animals may already be habituated to vessel noise.


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The Flotel Regalia is anticipated to be on location at Solan for approximately 111 days.

This is a longer duration than the previous accommodation vessel, the Siem Spearfish.

The Floatel Superior will replace the Regalia and will stay for 103 days, the two flotels may

also potentially overlap by 3 days. From the shipping routes shown in Figure 4-5, it can be

seen that on average several vessels pass through the area on a daily basis, therefore

background noise in the area is not expected to be very low. The additional noise from the

commissioning operations at Solan is not anticipated to be above background noise levels.

Based on the above, it is concluded that the accommodation vessel, drilling rig and

associated vessels with the hook up and commissioning campaign will not have a

significant effect and the likelihood of an injury or disturbance offence to marine European

Protected Species (EPS) is negligible.

5.3.2 Operation of Platform

Noise will be generated from operation of the platform; however, this will have negligible

impact underwater where there are sensitive receptors and is therefore not taken forward

for further consideration in this assessment.

5.4 Atmospheric Emissions

Gaseous emissions contribute to global atmospheric concentrations of greenhouse gases

(GHGs), regional acid loads and in some circumstances low-level ozone and

photochemical smog formation. The main GHGs are carbon dioxide (CO2), methane

(CH4), nitrous oxide (N2O) and halogenated fluorocarbons; the latter are now strictly

controlled under the Montreal Protocol.

Table 5-5 summarises the emissions associated with the hook-up and commissioning

during 2015 for the Siem Spearfish for 56 days and four days in transit, the Flotel Regalia

for 111 days and 4 days in transit, the Floatel Superior for 103 days and 4 days in transit

and associated supporting vessels. Emissions have been calculated using emission

factors from the Environmental Emissions Monitoring System (EEMS) Atmospherics

Calculations (EEMS, 2012). Based on an estimated total fuel use of 8,334 tonnes, it can

be seen that the emissions associated with the installation vessels equate to

approximately 0.3 % of CO2 generated by UK domestic and international shipping

emissions in 2012 (DFT, 2014).


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Table 5-5 Anticipated atmospheric emissions from the support and accommodation vessels during 2015

Source Total fuel use (Te)

Emissions (Te)

CO2 NOx N2O SO2 CO CH4 VOC

Siem Spearfish 1,120 3,584 67 0.25 4.5 17.6 0.2 2

Flotel Regalia 3,490 11,168 207 0.8 14 55 0.6 7

Floatel Superior 3,250 10,400 193 0.72 13 51 0.6 6.5

Vessels supporting hook-up and commissioning whilst the accommodation vessels are on location

474 1,517 28 0.1 1.9 7.4 0.09 0.9

TOTAL 8,334 26,669 495 2 33 131 2 17

UK domestic and international shipping CO2 emissions (2012) (DFT, 2014)

8,600,000

Total vessel CO2 emissions as a percentage

0.3%

The atmospheric emissions associated with the accommodation vessels may result in

short-term deterioration of local air quality within the vicinity of the vessel. In the exposed

conditions that prevail offshore, the emissions generated are expected to rapidly disperse,

ensuring that all released gases are present in very low concentrations outside the

immediate vicinity of the vessel. It should be noted that the accommodation vessels will

not be onsite at the same time. Emissions from the vessels are therefore assessed to be

an impact of minor magnitude.

The impact will be mitigated by the optimisation of vessel efficiency and minimising fuel

use. Due to the high dispersion rates and minimal nature of the emissions in relation to

total UKCS emissions, no further mitigation measures are proposed.

5.4.1 Production Operations

Atmospheric emissions resulting from production operations have the potential to impact

on local air quality, transboundary and cumulative air quality and to contribute to regional /

global effects such as acid rain, low level ozone and global climate change. The main

sources of atmospheric emissions during production are from:

Power generation for the Solan platform;

Flaring of a small amount of surplus gas in the early life of the field;

Power generation for shuttle tankers and support vessel; and


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Venting from shuttle tankers during oil loading.

Fuel combustion processes produce nitrogen monoxide (NO) and nitrogen dioxide (NO2),

as well as various derivatives that result from the chemical reaction of NO and NO2 with

other elements and compounds in the atmosphere. The emission of NOx compounds and

their derivatives can result in a wide variety of adverse impacts to human health and the

environment. These impacts can occur on both a local scale, caused by the immediate

effect on the surrounding environment, or on a wider global scale, caused by the

transportation of NOx compounds over national boundaries by wind and current

(transboundary).

The emission of NOx can have a detrimental impact on human health. Ground level ozone,

which is a major contributor to smog, is formed in the atmosphere through the reaction of

NOx with volatile organic compounds (VOCs) in the presence of light and heat. NOx also

reacts with water, ammonia, and various other compounds in the atmosphere to produce

nitric acid vapour and other particulate matter. Both ozone and particulate matter

contribute to lung and respiratory problems in humans and prolonged exposure can cause

damage to lung tissues, acute bronchitis, emphysema, chest pains, and aggravation of

respiratory conditions such as asthma.

NOx emissions can lead to deterioration in local air quality. Consequently local receptors

should be identified in order to assess the potential impacts. There are no receptors in

close proximity to the Solan installation. The nearest receptors in the area are the

Schiehallion field (35 km to the North) and Clair (90 km North East).

The Solan platform is located approximately 55 km from the UK/Faroes median line and

95 km from the Scottish coast so there is unlikely to be a potential for trans-boundary

transport of atmospheric contaminants. The increase in emissions from the Solan platform

in relation to existing operations in the area is not a significant additive effect when

considering the total annual offshore emissions from the UKCS.

Emissions of VOCs may result from oil loading. VOCs are of environmental concern due to

the regional and global scale impacts associated with their role in the formation of low-

level ozone and emission of greenhouse gases. Low-level ozone is not emitted directly but

is formed by a complex mechanism involving VOCs and nitrogen oxides in the presence of

sunlight. The low-level ozone is known to damage vegetation and high concentrations are

toxic to humans. Due to limited time period over which these emissions will take place, the

regional scale of the ozone likely to be formed and the distances the emissions must be

transported from the Solan development before encountering any sensitive receptors


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(such as urban or agricultural areas), it is likely the environmental impact of these

emissions is of relatively low significance.

5.4.1.1 Power generation for the Solan platform

Power generation on the Solan platform will be supplied by dual-fuel turbine generators.

Initially the turbines will be fuelled by fuel gas taken from the associated gas with any

excess gas flared. When the field becomes fuel gas deficient the turbines will be fuelled by

diesel.

When both turbines are in operation, offloading to tanker is occurring and PWRI is

occurring, Premier estimate the peak operating load will be 4.3 MW, utilising an estimated

1.34 MMscf of gas per day. However, due to increased efficiency with higher load, the

worst case gas use of 1.56 MMscf of gas per day corresponds to an operating load of 3.8

MW. Using this figure, an annual contribution of approximately 27,530 tonnes of CO2

represents 0.19 % of the total CO2 emissions during 2012 from UKCS oil and gas

installations (Table 5-6).

Table 5-6 Annual Atmospheric Emissions resulting from Power Generation at Solan

Emissions (Tonnes)

CO2 NOx SO2 CO CH4 VOC

Emissions due to power generation for Solan platform

27,530 554 0.12 73 191 31

Total emissions from UKCS offshore exploration and production

14,119,482 47,743 2,559 21,369 47,678 60,470

Emissions from power generation on Solan as % of 2012 UKCS emissions

0.19 1.16 0.005 0.34 0.40 0.05

The mitigation measures employed for atmospheric emissions from the Solan platform

include;

All engines, generators and other combustion plant will be well maintained

and correctly operated to ensure that they are working as efficiently as

possible to minimise emissions;

Emissions will be monitored and reported in line with the EU ETS Permit for

the installation; and

Predicted emissions will be minimised by ensuring that vessel engines are

well maintained. Low sulphur diesel will be used at all times.


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5.4.1.2 Flaring of a small amount of surplus gas in the early life of the field

Premier will use fuel gas as it is produced with a small flare of surplus gas in the early life.

As the oil production profile declines, the available associated gas declines with it and

flaring of surplus gas will cease. The quantity of gas flared will be kept to a minimum and

the Solan platform will have a Flare and Vent Consent in place by the start of production.

Flaring results in an annual contribution of approximately 34,778 29,286 tonnes of CO2

which represents 0.28 0.24 % of the total CO2 emissions during 2012 from flaring from

UKCS oil and gas installations (Table 5-7).

Table 5-7 Annual Atmospheric Emissions Resulting from Flaring at Solan

Emissions (Tonnes)

CO2 NOx SO2 CO CH4 VOC

Flaring emissions from the Solan platform 34,778 29,286

15 13 0.16 0.13

83 70 224 188 25 21

Total flaring emissions from UKCS offshore exploration and production

12,358,635 2,220 17,959 39,608 41,364 43,477

Emissions from flaring on the Solan platform as % of 2012 UKCS emissions from offshore oil and gas activities

0.28 0.24 0.67 0.57

0.00 0.21 0.18

0.54 0.46

0.06 0.05

5.4.1.3 Power generation for shuttle tankers and support vessel

Table 5-8 summarises the anticipated emissions from the power generation of the shuttle

tankers and the support vessel during crude loading operations. As the table shows, the

emissions associated amount to approximately 1.12 % of CO2 generated by UK domestic

and international shipping emissions in 2012. This is therefore assessed to be an impact

of minor magnitude.


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Table 5-8 Estimated Emissions Associated with Shuttle Tanker and Support Vessel Operations.

Source Total

fuel use (te)

Emissions (Te)

CO2 NOx N2O SO2 CO CH4 VOC

Shuttle Tanker 24,674 78,957 1,466 5.4 99 387 4.4 49

Support Vessel (anchor handling tug)

5,475 17,520 325 1.2 22 86 1.0 11

Total shuttle tanker loading emissions

30,149 96,477 1,791 6.6 121 473 5.4 50

UK domestic and international shipping CO2 emissions (2012) (DFT, 2014)

8,600,000

Total shuttle tanker loading and support vessel CO2 emissions as a percentage

1.12%

The impact will be mitigated by the optimisation of vessel efficiency and the avoidance of

unnecessary operation of power generation/combustion equipment. MARPOL

requirements will be complied with, including the use of shuttle tankers and a support

vessel with an IAPP Certificate. The overall risk to the environment is assessed to be

medium.

5.4.1.4 Venting from shuttle tankers during oil loading

During the loading of crude oil onto the shuttle tanker, VOC emissions (principally CH4 and

Non-Methane Volatile Organic Compounds (NMVOC)) will be produced, with the potential

for associated impacts.

VOC recovery packages are not fitted as standard on UKCS shuttle tankers; however,

Premier have three tankers which will alternate tanker offload duties at Solan: Navian

Oslo, Stena Natalia and the Scott Spirit, all of which have VOC recovery packs fitted. The

VOC recovery process is based on the direct absorption of VOCs in a side stream of the

loading oil. Using this process the oil containing the absorbed VOC is re-mixed with the

main oil-loading stream.

Atmospheric dispersion modelling of the pollutant concentrations of VOCs (CH4 and

NMVOC) from the loading of crude oil to the shuttle tanker generated worst case surface

level concentrations of 8,183 µg/m3.These concentrations were predicted approximately

20 m from the shuttle tanker and were found to drop off considerably by 500 m.


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On consideration of the mitigation measures that will be employed including, if possible,

the blanketing of cargo gas with inert gas and the use of VOC recovery equipment, the

residual risk to the environment of the VOC emissions associated with the shuttle tanker is

assessed to be low.

5.5 Marine Discharges

5.5.1 Potential Impacts

Chemical discharges will present a localised impact immediately around the discharge

point resulting in potential impacts to plankton, benthos, fish and mammal species. All

chemicals used and discharged as part of the SOST installation and as part of the

commissioning and operational phase have undergone a risk assessment as discussed in

the Chemical Permit SAT and variations.

During the first fill of the SOST, there is a requirement to discharge some of the chemicals

used during the installation phase. These discharges have been risk assessed as part of

the Chemical Permit SAT and it is concluded that they are unlikely to have a significant

impact on the marine environment. There will be no routine discharge of chemicals during

the operational phase as all production chemicals will either be exported with the

hydrocarbons or will be re-injected downhole.

The exception to this are the chemicals used during grouting operations as these

chemicals are exempt from the Offshore Chemical Regulations (OCR). During grouting

operations, some chemicals will be discharged subsea. RX-9022 is a Cefas registered

Gold rated chemical with no product warnings and no hazard warnings. It is

biodegradable, non-bioaccumulating and of moderate toxicity. The product is soluble in

water and will quickly disperse in the marine environment.

NF-6 is a non-Cefas registered defoamer product. It is considered to be readily

biodegradable and have a low toxicity with TLM96 > 1100 mg/l for the rainbow

trout (Oncorhynchus mykiss) and TLM96 > 83644 ppm for the mysid shrimp

Mysidopsis bahia. The product does not contain any known endocrine

disruptors and will readily disperse in the marine environment.

DF-700 is a non-Cefas registered an anti-foam product which is dispersible in

water and is not considered to be a marine pollutant.

CEMI 52.5 N is a non-Cefas registered cement product which is not considered

to be hazardous to the environment. However, a large release of cement in

water can lead to a pH increase and thus be toxic to aquatic organisms.


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Shell Naturelle Fluid HF-E 46 is a non-Cefas registered hydraulic oil product

which is not soluble in water and contains components with the potential to

bioaccumulate. It may cause the physical fouling of aquatic organisms,

although is considered to be practically non toxic with LL/EL/IL50 > 100 mg/l for

aquatic organisms. The product is considered to be readily biodegradable and

is not classified as dangerous to the marine environment

A full chemical risk assessment for chemicals covered by OCNS is provided in a separate

document in the Risk Assessment section of the Chemical Permit SATs.

There may be some localised impact associated with the discharge of grouting chemicals

to the marine environment. However, volumes of chemicals associated with the grouting

operations are small and combined with the toxicity and biodegradability properties of the

chemicals proposed, the environmental impact associated with their use is expected to be

negligible.

Discharges of grey and black water from vessels may have immediate local impact on

water quality (deoxygenation) and resultant impacts on marine flora and fauna. Release of

food waste to sea can have potential food chain impacts through introduction of an

anthropogenic food source (although this may have a positive effect in that nutrients are

provided for fauna). Discharges of grey, black and food waste releases are not expected

to adversely affect marine flora and fauna, which are expected to rapidly recover.

5.5.2 Mitigation

Premier will review Common Marine Inspection Documents (CMID) as part of vessel

assurance. The chemical selection process will aim for the lowest environmental impact

for given technical requirements. Use and discharge of chemicals will be kept to a

minimum commensurate with the operations to be undertaken.

5.6 Accidental Events

5.6.1 Oil Spill Risk

Accidental spills of hydrocarbons and chemicals are recognised as potentially damaging to

the environment. The history of the oil and gas industry shows that the accidental events

which could cause large-scale spillage of oil are rare. Despite the recent Macondo blowout

resulting in a large oil spill in the Gulf of Mexico and the Montara blowout resulting in a

large oil spill in the east Timor Sea, the probability of a large-scale uncontrolled oil spill

event occurring remains very low.


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Although unlikely, an accidental loss of containment from the Solan facilities or a vessel

collision is possible. A number of mitigation measures are in place to lower the likelihood

of an incident. The Solan Offshore Oil Pollution Emergency Plan (OPEP) was approved by

DECC on 4th September 2014 (Premier Oil, 2014c). The worst case assessment of an oil

spill from the Solan development has been assessed in this OPEP. To update the OPEP

for additional work, Solan Offshore OPEP Annex 1 (Safe Scandinavia) (Premier Oil,

2014d) and Annex 2 (Ocean Valiant) (Premier Oil, 2015) have been submitted and

approved by DECC.

The following updates have subsequently been submitted and approved for additional

work: Annex 3 (Floatel Victory), Annex 4 (Ocean Valiant as a Flotel (retracted)), Annex 5

(Ocean Valiant as a drill rig) and Annex 6 (Flotel Regalia).

Potentially significant sources of environmental risk that could occur from accidental spills

and non-routine events during the activities at Solan include:

Loss of well control (blow-out) resulting in a release of crude oil from the

reservoir;

Spill of chemicals / hydrocarbons from Solan platform;

Diesel bunkering during production activities;

Damage to the SOST and resultant release of hydrocarbons;

Release of hydrocarbons during oil loading to the oil offload tanker;

Spill due to vessel collision.

5.6.2 Oil Spill Prevention

Following the published Macondo report, Premier has taken the recommendations put

forward in the report into consideration when developing the design features and operating

procedures at the Solan development. The prevention of hydrocarbon or chemical spills is

of the highest environmental priority during operations at the Solan development.

The Solan wells, Solan platform, the SOST, the offloading facilities and the offload tanker

are all within four 500 m safety exclusion zones. These zones maximise the protection of

subsea equipment and protect third parties such as fishermen and thereby minimises the

risk of events such as snagging and vessel collision which could lead to oil release.


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5.6.2.1 Loss of Well-Control (Blow-out)

A loss of well control (blow-out) can result in an accidental release of crude oil from the

reservoir. Although the likelihood of a hydrocarbon or chemical spill from the Solan wells is

remote, there is a potential risk for organisms in the surrounding marine environment.

Both platform and subsea trees and wellheads are designed with a maximum working

pressure of 5,000 psig (345 barg) and a maximum temperature rating of 105 oC. Wellhead

equipment and xmas trees are maintained and inspected as per industry appropriate

standards. This will be carried out using an ROV and recorded on the maintenance

system.

All wells will be operated within their defined operational envelope. The flowrates from

blowouts of a completed well will be controlled:

By daily monitoring the annulus pressure;

Through the use of an actuated master and wing valve fitted on all wells,

i.e. two independent safety barriers for controlling fluid flow;

Through the use of a Surface Controlled Downhole Safety Valve (DHSV)

fitted on all well; and

By high and low pressure trips resulting in automatic shutdown of the well.

Staff will have received standard industry well control training.

Loss of well control will be mitigated as far as practicable through controls applied during

the design of the well. The well has been engineered by Premier in accordance with

internal design policies and procedures in line with current best industry practices and then

reviewed and approved by the third party independent well examiner and the Health,

Safety and Environment (HSE) Inspectorate.

Premier has in place a call off contract with a Well Control company (Wild Well Control,

Inc.) for the provision of well control services. Wild Well Control, Inc. specialise in

controlling blow outs and provide services to aid the drilling of relief wells.

5.6.2.2 Topside Chemical and Hydrocarbon Release

There is a potential risk of unplanned discharge of production chemicals or hydrocarbon

release from the Solan platform. This could arise as a result of a misuse or technical

failure during transfer of chemicals between the supply vessel and the platform.


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Depending on the scale of the event, this could lead to a deterioration of the water quality

and toxicity to organisms in the water column.

The Solan platform has key preventative and mitigating measures in place which are

designed to prevent overboard discharge of pollutants or contaminated water to the sea to

meet the platform environmental standard of zero discharge to sea. The procedures in

place to minimise the risks of a chemical or hydrocarbon spill occurring are summarised

below.

Bunded areas and the drains system are provided in process and utility areas to control

the spread of chemical and hydrocarbon spillage across plated decks in the event of loss

of containment from pipework, vessels, tanks or relevant equipment and to provide

drainage from plant and equipment that contain hydrocarbon/ flammable fluid contents,

from washdown water or rainwater that may contain hydrocarbons and chemical storage

areas. By design, loss of containment in process areas will be routed to the open drains

system.

Sources for open drains include:

1) Bunded areas beneath equipment in hydrocarbon service. These are intended to collect

deluge water, washdown water, maintenance spillages, and possible leakage from

equipment. Bunded areas are provided where drainage flowrate is significant or where

deck plating is used for catching the spillage.

2) Drip trays beneath smaller equipment items such as pumps and filters, in water service.

These are intended to collect maintenance spillages. Some equipment items such as the

chemical injection package, generators, pumps, etc. may be provided with built-in drip

retention as part of the skid to contain any leaks or spills.

3) Bunded area at the chemical storage area on the weather deck

4) Deck drains for contaminated deck areas. These are intended to collect washdown

water, fire hose water and rain water.

5) Helideck drains. These will collect rainwater, deluge water, fire hose water and aviation

fuel spills.

Bunding is provided around vessels containing significant liquid inventories (such as the

inlet or second-stage separators).


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This document details the management of chemicals on the Solan Platform, and complies

with the Premier Oil standard for ‘Compliance with Offshore Chemical regulations 2002 (as

amended). This procedure applies to all chemicals stored and used on the Solan offshore

platform. This procedure includes the chemical management relating to:

Small containers;

Drums, up to 200 litres;

Tote tanks;

Intermediate Bulk Containers (IBCs) up to 1,000 litres; and

Intermediate Bulk Containers (IBCs) over 1,000 litres;

The procedure provides information on:

Permitting;

Control of the chemicals on board the installation;

The correct methods to adopt when using the Installations chemicals;

Decanting of chemicals from the tote tanks and IBCs;

The use of various chemicals found on the Installation;

Chemical spillages and the process of reporting; and

Monitoring of the Solan Platform’s chemicals stock.

The potential for chemical spillages has been mitigated by having the facility of a

designated bunded lay-down area on the weather deck for the chemical tote tanks, short

length purpose-built chemical hoses/connections and hard piping to fixed storage tanks.

The probability of a chemical spill occurring is low and does not add significantly to the

overall risk of a spill in the area. Therefore it is not expected that there will be any

associated cumulative effects in the marine environment.

It is necessary that all types of hose on board the Solan Platform are recorded and

inspected on a regular basis to ensure the safety of personnel, and to ensure that the

equipment is well-maintained and fluid containment is assured.

This document aims to ensure that all hoses shipped out or manufactured for the Solan

are correctly tested before fitting and are accompanied with test certification, and that

hoses are safely used and maintained.

The procedure contains a Hose Management Register which details


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The location and specifications of every tagged hose.

Fitness for service / condition assessment for every individual hose.

Schedule for the installation, inspection, and replacement of damaged

hoses and the replacement of all hoses coming to the end of their life cycle.

In the unlikely event of an oil spillage, the platform oil spill detection system will ensure

early detection and will minimize the potential impact of a spill.

The Solan Platform has a Rutter Sigma S6 Oil Spill Detection with Surveillance System

which uses two radar systems, with radar heads located at the SE and NW corners of the

platform, to detect oil spills within a 360° panorama of the surrounding area.

No operator configuration is required to acquire and track oil spill targets. The system will

automatically acquire all oil spill targets within a range of four nautical miles of the radar

installation.

Oil spills can be tracked, and information such as size and thickness of the spill will then

be used by the system to give a calculation which will estimate the spill volume. The Rutter

Sigma S6 provides a very high level of scrutiny in oil spill detection.

The MRV will also be available to check the sea surface during initial filling of the SOST

and offloading, and to report to the Control Room Operator if any oil is observed.

5.6.2.3 Diesel Spill during Bunkering

Spillages from bunkering of diesel fuel to the platform may potentially occur as a result of a

hose becoming disconnected or overfilling of the diesel bund.

Diesel is non-persistent oil that rapidly evaporates from the surface of the sea, and when it

is spilt on the sea surface it spreads rapidly and disperses to form a sheen on the sea

surface within hours of the release. This could have a potential environmental impact on

seabirds through damage to feathers.

Several measures are in place to minimise and prevent a small-scale hydrocarbon spill

during re-fuelling:

Bunkering of diesel fuel will only take place during daylight hours

Non-return connections and dead man closures will be used on bulk transfer hoses

All transfers will be controlled by written instruction with the operations

Supervisors and communication links tested prior to transfer.


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The bunkering operation will be monitored both by the supply boat and

onshore/offshore control rooms (and deck personnel during manned operation).

There will be a thorough inspection and maintenance regime on all refuelling

equipment.

All transfer operations will be suspended in rough weather

Spill kits will be available at strategic areas of the platform.

The MRV will also be available to check the sea surface during bunkering, and to report to

the Control Room Operator if any oil is observed.

Impacts from a diesel spill during bunkering are therefore expected to be low.

5.6.2.4 Oil Spill from the SOST

The SOST, and oil offloading systems, including the oil and water connections and the

loading base and loading hose, are designed to ensure no leakage of oil or ballast water to

the environment.

To assist with control of any potential spill, such as by damage caused to the SOST or

corrosion, the SOST and its associated facilities are designed to allow the ballast water

caisson level to be reduced below LAT to a sufficient level to ensure a slight internal

negative pressure relative to the sea, so that any leakage occurring will be of seawater

into the tank rather than of oil or ballast water out.

The SOST is designed to withstand multiple pressure cases including internal pressure

due to static pressure from the platform, a reduction in external pressure at the seabed

caused by the trough of the 100 year wave (a reduction of nominally 1 bar in external

pressure at the sea bed) and an external static differential pressure (excluding wave

loading) equivalent to drawing the water level in the ballast water caissons to 10m below

LAT.

The following SOST protection measures are also in place:

The SOST base is coated against under-deposit (and other) corrosion.

The SOST is affixed to the seabed with a suitable number, length and

distribution of piles to ensure its stability under all design environmental

conditions.


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The SOST and the OLS are provided with over-trawable with sloping sided

protection structure and anti-snag features to mitigate against accidental

damage.

The MRV will also be available to check the sea surface in the vicinity of the SOST and to

report to the Control Room Operator if any oil is observed.

5.6.2.5 Oil Spill during Oil Loading

There is a potential risk of a spill whilst loading hydrocarbons into the oil offload tanker.

There are several operations-specific control measures in place to mitigate against such

an incident, including:

Connection will only occur during daylight hours and in suitable weather

conditions;

Flow/pressure monitoring, alarms and observation from the shuttle tanker and

storage vessel to detect spills;

Telemetry to shut down oil export in an incident;

Self-sealing oil export hose;

Integrated dry-break valve in export line allowing emergency disconnection;

Regular checks of the integrity of the hose and cargo tanks will be carried out;

and

The MRV will be on site during oil offloading and has a spill detection system

on board which is the same as the system used on the Solan platform.

The impact of a hydrocarbon spill associated with the connection to the oil offload tanker

during oil loading would be significant and include a possible requirement for counter-

pollution resources on a national scale. However, the overall risk to the environment is low

when the mitigation measures discussed are taken into account.

5.6.2.6 Vessel Collision Risk

There is a potential for a vessel collision with the Solan platform. This could lead to a loss

of vessel inventory but accidents leading to the total loss of the vessel inventory are

extremely rare events.


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In the unlikely event of an accidental spill of diesel fuel from a vessel, a diesel slick would

form on the sea surface. Diesel is non-persistent oil that rapidly evaporates from the

surface of the sea, and when it is spilt on the sea surface it spreads rapidly and disperses

to form a sheen on the sea surface within hours of the release.

The platform complex will be surrounded by a 500 m safety exclusion zone. Shipping

routes are not permitted to travel close to the Solan platform, greatly reducing the potential

for vessel collision.

5.6.3 Oil Spill Modelling

The worst case hydrocarbon spill scenarios have been assessed as part of the Solan

Offshore OPEP (Premier Oil, 2014c). The OPEP presents the worst-case modelling

scenarios for the largest and most persistent hydrocarbon inventories.

Both stochastic and deterministic modelling has been undertaken using the SINTEF Oil

Spill Contingency and Response (OSCAR) modelling package. Solan crude is not

characterised within the OSCAR oil database, therefore for modelling illustration Maya

crude was used as an analogue to Solan crude.

Stochastic and deterministic modelling was carried out for the following scenarios: well

blowout from the production well P1, total inventory loss from the SOST, total inventory

loss from the largest shuttle tanker and diesel release. A summary of the parameters used

within the modelling and the results is presented below, with further detail provided in the

Solan Offshore OPEP (Premier Oil, 2014c). .

5.6.3.1 Well Blowout

Scenario 1a: Well Blowout: declining rate over 30 days. Initially at 4,020 m3 on day 1

declining to 893 m3 per day by day 30, towards Faroese median line (offshore). Scenario

1b: Well Blowout: declining rate over 30 days. Initially at 4,020 m3 on day 1 declining to

893 m3 per day by day 30, towards UK shoreline (onshore).


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Results from the deterministic modelling indicate that a well blow-out over 30 days, without

response interventions, under the worst case conditions of a 30 knot onshore wind, would

beach on the Shetland coastline after 2 days, the Faroes coastline after 8 days and the

Norwegian coast after 12 days (Figure 5-9).

Figure 5-9 Well blowout: a) in the direction of the Faroes (left) and b) the UK (right)

5.6.3.2 Release of SOST Inventory

Scenario 2a: Subsea Tank Release: Instantaneous loss of 50,625 m3 of Solan crude,

towards Faroese median line (offshore).

Scenario 2b: Subsea Tank Release: Instantaneous loss of 50,625 m3 of Solan crude,

towards UK shoreline (onshore).

An instantaneous loss of the SOST inventory was modelled over 30 days, without

response interventions, under the worst case conditions of a 30 knot onshore wind. The

results indicate that shoreline oiling would occur on the coast of Shetland after 4 days and

the Faroes coastline after 6 days (Figure 5-10).


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Figure 5-10 Loss of SOST inventory: a) in direction of the Faroes (left) and b) the UK (right)

5.6.3.3 Release of Offload Tanker Inventory

Scenario 3a: Offload Tanker Release: Loss of 121,700 m3 from all cargo oil tanks, 3,000

m3 of heavy fuel oil, and 600 m3

of diesel. Towards Faroese median line (offshore).

Scenario 3b: Offload Tanker Release: Loss of 121,700 m3 from all cargo oil tanks, 3,000

m3 of heavy fuel oil, and 600 m3

of diesel. Towards UK (onshore).

An instantaneous loss of the shuttle tanker inventory was modelled over 30 days, without

response interventions, under the worst case conditions of a 30 knot onshore wind. The

results indicate that shoreline oiling would occur on the coast of Shetland after 4 days, the

Faroes coastline after 7 days and the Norwegian coast after 16 days (Figure 5-11).


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Figure 5-11 Loss of shuttle tanker inventory: a) in direction of the Faroes (left) and b) the UK (right)

5.6.3.4 Diesel Release

Scenario 4a: Diesel Release: 3,550 m3 instantaneous release from Solan field location.

Towards Faroese median line (offshore).

Scenario 4b: Diesel Release: 3,550 m3 instantaneous release from Solan field location.

Towards UK (onshore).

An instantaneous loss of marine diesel was modelled over 30 days, without response

interventions, under the worst case conditions of a 30 knot onshore wind. The results

indicate that shoreline oiling would occur on the coast of Shetland after 8 days and that

oiling is not expected elsewhere on the UK coastline or on the Norwegian coastline (Figure

5-12).


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Figure 5-12 Loss of marine diesel: a) in direction of Faroes (left) and b) the UK (right)


A number of protected areas have been identified that have the potential to be impacted

as a result of an oil release to sea from Solan field operations. There are no offshore

protected areas in close proximity to the Solan development, the nearest being the Wyville

Thompson Ridge and Darwin Mounds located approximately 107 km and 110 km

respectively, west of the development and the Solan Bank Reef located approximately 158

km southwest of the development.

Stochastic modelling output for the worst case scenario of instantaneous release of

approximately 120,000 m3 of solan crude from the offload tanker suggested that, of these

offshore Sites of Community Interest (SCIs), only the Solan Bank Reef could be (<20 %

probability) impacted by a total loss of hydrocarbons from the shuttle tanker (Premier Oil,

2014a). In addition, the Pobie Bank SCI east of Shetland could also be impacted (<20 %).

There are no NCMPAs within the immediate vicinity of the Solan Development; however,

there are a number in close proximity: the Faroe Shetland Belt approximately 20 km to the

northeast, the Northeast Faroe Shetland Channel approximately 200 km north, the West

Shetland Shelf approximately 27 km south and the North West Orkney MPA approximately

50 km southeast of the Solan location (see Figure 4-6). The worst case stochastic

modelling outputs suggest that each of the MPAs listed may be impacted following a Tier 3

spill (up to 20 %).


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There are no onshore protected areas within the immediate vicinity of the Solan

Development, the nearest being Foula, an island off the west coast of Shetland located

approximately 95 km to the east of the Solan Development location which is protected due

to the birds that inhabit the island (see Figure 4-6).

The potential risk to seabirds from oil and diesel pollution is through damage to feathers

resulting in loss of mobility, buoyancy, insulation and waterproofing. Birds may also be at

risk from toxicity through ingestion of hydrocarbons and may face starvation through

depletion of food sources. The birds most affected are those such as guillemots, razorbills

and puffins that spend large periods of time on the water, particularly during the moulting

season when they become flightless (DTI, 2001).

Major oil spills can result in direct mortality to marine mammals, although generally, they

are less vulnerable than seabirds to fouling by oil. Cetaceans have smooth hairless skin

over a thick layer of insulating blubber, so oil is unlikely to adhere persistently or cause

breakdown in insulation. However, they are at risk from chemicals evaporating from the

surface of an oil slick at sea, especially within the first few days. They may inhale vapours

given off by spilt oil, their eyes may be vulnerable to major pollution, and individuals may

drown as a result of associated symptoms. Neonatal (very young) seal pups are

particularly at risk from oil coming ashore. In addition, a major release of oil or diesel may

deplete marine mammals’ food sources (SMRU, 2008).

The impact that may be caused by a spill is dependent on the location of the spill, its size,

the properties of hydrocarbon or chemical that is spilt, the prevailing weather and

metocean conditions at the time of the spill, the sensitivities of environmental receptors

that could be impacted by the spill, and the success of the contingency plans.

Hydrocarbon spills have a detrimental effect on water quality and a resultant effect on

marine organisms, benthos, plankton, fish and shellfish, seabirds, conservation sites and

commercial fishing.

5.6.5 Oil Spill Response

The response resources range from the Field Support Vessel (FSV) on site with

dispersant (Tier 1 response) to Oil Spill Response Limited’s (OSRL) response capabilities

(Tier 2/3 response) and ultimately the activation of the National Contingency Plan. Premier

has access to specialist oil spill response services provided by OSRL. In the event of an

oil or diesel spill, there are three planned levels of response, depending on the size of the

spill:


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Spill will be monitored and allowed to disperse naturally. If spill is relatively

small ‘prop washing’ may aid dissipation (Tier 1);

Air surveillance and dispersant spraying through OSRL (Tier 2); and

Clean-up equipment and specialist staff available through OSRL. (Tier 3).

These arrangements make realistic provision for immediately mitigating the effects of an

oil spill on the marine environment and in particular bird populations and fisheries

resources.

Premier has in place a call off contract with a Well Control company (Wild Well Control,

Inc.) for the provision of well control services. Wild Well Control, Inc. specialise in

controlling blow outs and provide services to aid the drilling of relief wells. As a member of

Offshore Pollution Liability Association Limited (OPOL), Premier can demonstrate financial

responsibility should there be the need to drill a relief well.

The Solan Offshore OPEP (Premier Oil, 2014c) provides full details of the response

procedures and techniques that will be used in the event of an accidental release of

hydrocarbons.

5.7 Waste


Waste will be generated during all phases of the Solan Development. Careful

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

eventual disposal such that waste is only disposed of if it cannot be prevented, reclaimed

or recovered. The impacts of wastes associated with the Solan development were

assessed in the Solan Development ES (Chrysaor Ltd., 2009).

Waste will be generated from the oil offload tankers and support vessel which will be

present on site during production operations. Waste will also be generated by the

accommodation vessels present during commissioning activities. Some special waste is

expected for example empty chemical/oil containers, batteries etc. All waste will be

transferred onshore for recycling/disposal.

5.7.2 Mitigation Measures

Premier is committed to reducing waste production and to disposing of waste to landfill

only if cannot be prevented, reclaimed or recovered. The project HSE plan (AB-SO-SA-

PL-0005) and the individual vessel garbage management plans will be used throughout

the operations. These will identify the types of waste generated and management

procedures for each waste stream.


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Legal requirements will be adhered to including use of transfer/consignment notes, use of

registered waste carriers licensed disposal sites.

Premier’s vessel assurance process will include compliance with the project Waste

Management Plan. Vessel operators will be required to maintain a Waste Record Book

and submit monthly reports of waste sent to shore.

With the application of the above control measures, the impact of waste production will be

minimised; however, given the nature of some of the wastes likely to be produced e.g. oily

wastes from the vessels, the overall impact is considered to be minor.


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6 ENVIRONMENTAL MANAGEMENT

Effective health, safety, environmental and security (HSES) performance is a key objective

for Premier, equal to all other key business objectives. An integrated HSES Management

System has been established and maintained that achieves this by:

Leadership and Commitment

Providing strong and visible leadership and commitment in HSES performance.

Policy and Strategic Objectives

Setting policy and strategic objectives that support the commitment to compliance

with all relevant statutory legislation and continuous improvement and take due

account of industry codes and practices and any other requirements to which the

company subscribes.

Organisation, Resources & Documentation

Establishing and populating a fit for purpose organisational structure for the

effective management of HSES and fully defining the HSES responsibilities of each

function.

Appointing management representatives who are responsible for and have the

resources to implement this policy.

Ensuring that all employees and contractors have adequate HSES awareness,

skills and competence.

Selecting and managing contractors to ensure their HSES performance meets

Premiers requirements.

Maintaining appropriate HSES documentation.

Risk Evaluation and Management

Identifying health, safety, environmental and security risks to people, the local

biodiversity and physical assets arising from Premier operations.

Managing risks to levels that are as low as reasonably practicable in line with legal

and other obligations and the strategy for continual improvement.


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Planning

Ensuring that HSES critical facilities and equipment are fit for purpose and meet

defined HSES and reliability targets.

Controlling activities and operations through the use of documented procedures

and practices.

Managing changes in people, plant and processes to avoid adverse HSES

consequences.

Maintaining emergency preparedness to manage the response to mitigate the

effect of and facilitate recovery from unplanned events.

Monitoring and Implementation

Monitoring HSES performance to determine compliance and keeping records in

support of the HSES Management System.

Recording areas of non-compliance and addressing these through corrective

actions.

Open reporting and investigation of all HSES related incidents.

Audit and Review

Auditing and reviewing compliance with the HSES Policy and the adequacy of the

HSES Management System.

All documented policies, procedures and practices will be consistent with the HSES Policy

and with the requirements of the HSES Management System. It is the responsibility of

every employee to comply with these and to assist Premier in their implementation.

The Premier environmental management system is certified to the international standard

ISO14001, with surveillance audits carried out by an external party on a 6 monthly basis.


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7 CONCLUSIONS

The potential environmental impacts of the commissioning and operation of the Solan

complex have also been identified and assessed and the outcome is summarised in Table

7-1.


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Table 7-1 Impact Assessment Summary (Commissioning and Operation)

Potential Impact Assessment

Seabed disturbance

The long term presence of the Solan complex will result in the permanent

loss of sedimentary habitat during the lifetime of the SOST and

installation. There will also be temporary disturbance associated with the

mooring of the accommodation vessel (seabed footprint of 0.12 km2) and

the mooring of the drill rig (seabed footprint of 0.12 km2).

Noise

Noise caused by dynamic positioning of the flotel is not likely to have a

significant effect on the receiving environment and the likelihood of an

injury or disturbance offence to marine EPS is negligible.

Noise will be generated from operation of the platform; however, this will

have negligible impact underwater where there are sensitive receptors.

Atmospheric emissions

Emissions associated with the operational activities will comprise

approximately 0.19 % of UKCS offshore exploration and production

activities emissions in 2012, therefore the impact is considered to be

minor.

Emissions associated with the accommodation vessels will comprise

approximately 0.2 % of CO2 generated by UK domestic and international

shipping emissions in 2012, therefore the impact is considered to be

minor.

Marine discharges

During the first fill of the SOST, there is a requirement to discharge some

of the chemicals used during the installation phase. These discharges

have been risk assessed as part of the Chemical Permit SAT and it is

concluded that they are unlikely to have a significant impact on the

marine environment. There will be no routine discharge of chemicals

during the operational phase as all production chemicals will either be

exported with the hydrocarbons or will be re-injected downhole.

Accidental events

Premier has the appropriate mitigation measures and responses in place

to limit the likelihood and control any spills that may occur. The possibility

of hydrocarbon spills during production operations will be covered under

the Solan field OPEP.

Waste

The impact of waste production will be minimised via the Project HSE

Plan and vessel waste management plans; special waste may be

generated but quantities will be small therefore the impact is considered

to be minor.


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The Solan area is of relatively low importance in terms of commercial fishing and shipping.

These industries are not expected to be significantly impacted by the pipeline installation

commissioning, or production operations.

Spawning and nursery grounds of several commercially important fish species also fall

within Block 205/26. Localised disturbance to the seabed will occur due to the physical

presence of the infrastructure. Due to the area impacted (5,480 m2) and the rapid recovery

time of benthic communities, the impacts on the seabed are considered to be of low

magnitude, and of an overall negligible risk to the environment.

The phytoplankton community in the area is dominated by diatoms including Chaetoceros

species and Thalassiosira species, and dinoflagellates of the genus Ceratium, while in

terms of abundance the zooplankton communities are dominated by copepods in

particular Calanus species. Due to rapid doubling times, plankton are unlikely to be

significantly impacted by the small and temporary nature of these operations. Benthic

species are typical of communities of the Boreal province extending south to the North

Sea. Crustaceans (Pagarus sp.), annelids (Lanice conchilega, Ditrupa arietina,

Pomatoceros sp.), cnidarians, molluscs, dogfish and flatfish are commonly recorded.

During commissioning and normal operations of the platform noise will have a negligible

impact. Noise caused by dynamic positioning of the flotel and vessels associated with the

hook-up and commissioning activities is not likely to have a significant effect on the

receiving environment and the likelihood of an injury or disturbance offence to marine EPS

is negligible.

The CO2 emissions from the accommodation vessel associated with commissioning

operations comprise around 0.2 % of the total UK domestic and international shipping CO2

emissions in 2012. There may be a small localised impact on local air quality in the vicinity

of the vessels but due to the high dispersive conditions in the area impacts are expected

to be negligible. The CO2 emissions associated with production operations comprise

around 0.19 % of UKCS offshore exploration and production activities emissions in 2012,

therefore the impact is considered to be minor.

Chemical use and discharge relating to the proposed operations has been assessed for

potential environmental impacts using both quantitative and qualitative approaches and it

is concluded that the proposed chemical use and discharge will not constitute a significant

risk to the environment.


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Accidental spills of hydrocarbons and chemicals are recognised as potentially damaging to

the environment. The history of the oil and gas industry shows that the accidental events

which could cause large-scale spillage of oil are rare. Although unlikely, an accidental loss

of containment from the Solan facilities or a vessel collision is possible during installation

and operation. A number of mitigation measures are in place to lower the likelihood of an

incident. An approved Oil Pollution Emergency Plan is also in place, which meets the

requirements of relevant legislation and guidance.

Transboundary impacts from emissions, discharges and accidental releases were

assessed. The Solan facilities are located approximately 55 km from the UK/Faroes

median line, therefore there is unlikely to be a potential for trans-boundary transport of

atmospheric contaminants.

The release of a worst case well blow-out release of crude oil would be likely to have a

transboundary impact. However, due to the spill prevention and response procedures in

place, the likelihood of a significant spill event occurring is considered very low. Any

transboundary incident will be managed through the Solan Field OPEP (Premier Oil,

2014c).

Premier has examined the environmental sensitivities of the Solan area in this EIA

Justification MAT submission and considered the significance of impacts during the

proposed time of operations. It is concluded that the procedures in place during proposed

activities will minimise the environmental impact of the operations. As such, the execution

of the Solan Development, incorporating the procedures identified in the EIA Justification

MAT, is not expected to have a significant impact on the environment.


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