LAT-G-BA-00150 Rev D04 - Basis of Design

Basic Engineering Basis of Design

TOTAL OR PARTIAL REPRODUCTION AND/OR UTILISATION OF THIS DOCUMENT IS FORBIDDEN WITHOUT PRIOR WRITTEN AUTHORISATION OF THE OWNER

REVISION RECORD SHEET Revision Number

Purpose

01 02 03 04

Issued for Internal Review Issued for Client Review Re-Issued for Client Review Approved For Design

List of Updated/Modified Sections, if any

Change from Methanol to MEG plus various other updates

TABLE OF HOLDS/TBC Number

Section

1 2 3 4 5 6 7 8 9 10 11

6.5.3 8.4 8.5 8.6 10.1.1 10.1.3 11.7.2 11.15.6 11.16.1 11.17 12.2.3

Document No. LAT-G-BA-00150

Description MEG product specification Subsea metering requirements Manifold design pressure and design temperature MEG design injection rate Production Flowlines – Applicability of Sour service Production Flowlines and MEG Line – Crossing information Shared facilities with BP SVT – Operating and design conditions Instrument electrical power Telecoms - UPS Civils - Compressor buildings Export Pipeline – Crossing information

Rev D04 – 11 August 2009

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TABLE OF CONTENTS Page

1.

INTRODUCTION ........................................................................................................................7

2.

DEFINITIONS AND ABBREVIATIONS.....................................................................................8

3.

UNITS .......................................................................................................................................10

4.

CO-ORDINATE SYSTEM ........................................................................................................10

5.

SAFETY, HEALTH AND ENVIRONMENTAL .........................................................................11

6.

5.1

LEGISLATIVE COMPLIANCE .....................................................................................................11

5.2

INHERENT SAFETY ....................................................................................................................12

5.3

ENVIRONMENTAL ASPIRATIONS .............................................................................................12

FIELD DATA.............................................................................................................................14 6.1

FIELD LOCATION........................................................................................................................14

6.2

RESERVOIR PROPERTIES ........................................................................................................15 6.2.1 Laggan Reservoir Description ......................................................................................15 6.2.2 Tormore Reservoir Description .....................................................................................15 6.2.3 Summary of Reservoir Properties.................................................................................15 6.2.4 Reservoir Characteristics..............................................................................................16

6.3

PRODUCTION PROFILES ..........................................................................................................16 6.3.1 Laggan Production Profile ............................................................................................17 6.3.2 Tormore Production Profile ...........................................................................................18 6.3.3 Laggan-Tormore Production Profile..............................................................................19 6.3.4 Design Gas Flowrates...................................................................................................20 6.3.5 Formation Water ...........................................................................................................20 6.3.6 Condensation Water .....................................................................................................20 6.3.7 Boundary Pressures .....................................................................................................21

6.4

WELLHEAD CONDITIONS ..........................................................................................................21

6.5

PRODUCTION FLUIDS PROPERTIES .......................................................................................22 6.5.1 Reservoir Hydrocarbons Composition ..........................................................................22 6.5.2 Formation Water ...........................................................................................................25 6.5.3 Contaminant Management ...........................................................................................25 6.5.4 Wax Management.........................................................................................................27 6.5.5 Other Risks ...................................................................................................................27

6.6

OFFSHORE ENVIRONMENTAL DATA.......................................................................................28 6.6.1 Wave and Current Data ................................................................................................28 6.6.2 Wind Data .....................................................................................................................29 6.6.3 Temperature Data.........................................................................................................30 6.6.4 Marine Growth ..............................................................................................................30 6.6.5 EoS and WoS Environmentally Sensitive Areas ..........................................................30

6.7

ONSHORE ENVIRONMENTAL DATA ........................................................................................31 6.7.1 Climate ..........................................................................................................................31 6.7.2 Hydrology ......................................................................................................................33 6.7.3 Environmentally Sensitive Areas ..................................................................................33



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6.8

SURVEY DATA ALONG FLOWLINES/PIPELINE ROUTES .......................................................34 6.8.1 Proposed Routes ..........................................................................................................34 6.8.2 Bathymetrical Data........................................................................................................38 6.8.3 Geophysical and Geotechnical Data ............................................................................40

6.9

SURVEY DATA AT SVT LOCATION...........................................................................................40

6.10 FISHING ACTIVITIES DATA .......................................................................................................40

7.

8.

9.

FIELD DEVELOPMENT...........................................................................................................41 7.1

PRODUCTION STRATEGY.........................................................................................................41

7.2

AVAILABILITY TARGETS............................................................................................................41

7.3

DESIGN CAPACITIES .................................................................................................................41

7.4

DESIGN LIFE ...............................................................................................................................41

SUBSEA PRODUCTION SYSTEMS.......................................................................................42 8.1

SUBSEA WELLS..........................................................................................................................42 8.1.1 Casing Design...............................................................................................................42 8.1.2 Completion Design........................................................................................................42 8.1.3 Upper Completion .........................................................................................................43 8.1.4 Subsea Wellhead..........................................................................................................43

8.2

CHRISTMAS TREE......................................................................................................................44

8.3

SUBSEA CONTROL SYSTEMS..................................................................................................44

8.4

SUBSEA METERING...................................................................................................................44

8.5

TEMPLATE AND MANIFOLD ......................................................................................................45

8.6

SUBSEA CHEMICAL INJECTION REQUIREMENTS.................................................................45

8.7

UMBILICAL SERVICES DISTRIBUTION.....................................................................................45

UMBILICAL ..............................................................................................................................46 9.1

LAYOUT .......................................................................................................................................46 9.1.1 Base Case ....................................................................................................................46 9.1.2 Alternative No 1 ............................................................................................................47 9.1.3 Alternative No 2 ............................................................................................................48

9.2

DESIGN REQUIREMENTS..........................................................................................................49 9.2.1 Temperature Range......................................................................................................49 9.2.2 Tubes ............................................................................................................................49 9.2.3 Power ............................................................................................................................49 9.2.4 Communication .............................................................................................................49

9.3

INSTALLATION AND PROTECTION ..........................................................................................49

10. PRODUCTION FLOWLINES ...................................................................................................50 10.1 OFFSHORE FLOWLINES............................................................................................................50 10.1.1 Design Data ..................................................................................................................50 10.1.2 Material Data.................................................................................................................51 10.1.3 Crossing Data ...............................................................................................................51 10.2 ONSHORE FLOWLINES .............................................................................................................52 10.2.1 Design Conditions.........................................................................................................52 10.2.2 Valve Installation...........................................................................................................52 10.2.3 Pigging Facilities ...........................................................................................................52 10.2.4 Construction Requirements ..........................................................................................53 10.2.5 Crossings ......................................................................................................................53



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10.2.6 10.2.7 10.2.8 10.2.9

Corrosion Coatings .......................................................................................................53 Cathodic Protection.......................................................................................................54 Testing ..........................................................................................................................54 Integrity Monitoring .......................................................................................................54

11. GAS PROCESSING PLANT....................................................................................................55 11.1 INTRODUCTION..........................................................................................................................55 11.2 OPERATING AND DESIGN CAPACITIES ..................................................................................55 11.3 PROCESSING FACILITIES .........................................................................................................55 11.4 SIMULATION BASIS....................................................................................................................56 11.5 PRODUCT SPECIFICATIONS ....................................................................................................56 11.5.1 Gas................................................................................................................................56 11.5.2 Condensate...................................................................................................................57 11.6 ENVIRONMENTAL REQUIREMENTS ........................................................................................58 11.6.1 Water Discharge Requirements....................................................................................58 11.6.2 Air Emissions Requirements.........................................................................................58 11.7 UTILITY AND SERVICE SYSTEMS SHARED WITH BP SVT ....................................................60 11.7.1 List of Utility and Service Systems................................................................................60 11.7.2 Operating and Design Conditions.................................................................................60 11.7.3 Available Ullages ..........................................................................................................60 11.8 STAND-ALONE UTILITY AND SERVICE SYSTEMS .................................................................61 11.9 FLARE AND VENT SYSTEMS ....................................................................................................61 11.10 HIGH INTEGRITY PROTECTION SYSTEM................................................................................61 11.10.1 Inlet Facilities ................................................................................................................61 11.10.2 Gas Export Pipeline ......................................................................................................61 11.11 PLANT LAYOUT AND PIPING ....................................................................................................62 11.12 MATERIALS AND CORROSION MANAGEMENT ......................................................................62 11.12.1 Material Selection .........................................................................................................62 11.12.2 Protective Coating.........................................................................................................63 11.12.3 Cathodic Protection.......................................................................................................63 11.13 MECHANICAL ..............................................................................................................................63 11.14 ELECTRICAL ...............................................................................................................................65 11.14.1 Main Power ...................................................................................................................65 11.14.2 Essential Power ............................................................................................................65 11.14.3 UPS...............................................................................................................................65 11.14.4 Lightning Protection ......................................................................................................66 11.15 INSTRUMENTATION...................................................................................................................66 11.15.1 General .........................................................................................................................66 11.15.2 Export Gas Metering System (UN3501) .......................................................................67 11.15.3 Condensate Metering System (UN4601)......................................................................67 11.15.4 Other Metering Systems ...............................................................................................67 11.15.5 Machine Monitoring System .........................................................................................67 11.15.6 Instrument Electrical Power ..........................................................................................68 11.15.7 Field Instrumentation ....................................................................................................68 11.15.8 Field Installation and Design.........................................................................................68 11.16 TELECOMS DESIGN...................................................................................................................69 11.16.1 General .........................................................................................................................69 11.16.2 System Components.....................................................................................................69 11.17 CIVILS ..........................................................................................................................................70



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12. GAS EXPORT PIPELINE.........................................................................................................71 12.1 ONSHORE PIPELINE ..................................................................................................................71 12.1.1 Design Conditions.........................................................................................................71 12.1.2 Valve Installation...........................................................................................................71 12.1.3 Pigging Facilities ...........................................................................................................72 12.1.4 Construction Requirements ..........................................................................................72 12.1.5 Crossings ......................................................................................................................72 12.1.6 Corrosion Coatings .......................................................................................................73 12.1.7 Cathodic Protection.......................................................................................................73 12.1.8 Testing ..........................................................................................................................73 12.1.9 Integrity Monitoring .......................................................................................................73 12.2 OFFSHORE PIPELINE ................................................................................................................74 12.2.1 Design Data ..................................................................................................................74 12.2.2 Material Data.................................................................................................................74 12.2.3 Crossing Data ...............................................................................................................75

13. MEG LINE.................................................................................................................................76 13.1 ONSHORE LINE ..........................................................................................................................76 13.1.1 Design Conditions.........................................................................................................76 13.1.2 Valve Installation...........................................................................................................76 13.1.3 Pigging Facilities ...........................................................................................................76 13.1.4 Construction Requirements ..........................................................................................77 13.1.5 Crossings ......................................................................................................................77 13.1.6 Corrosion Coatings .......................................................................................................77 13.1.7 Cathodic Protection.......................................................................................................77 13.1.8 Testing ..........................................................................................................................78 13.1.9 Integrity Monitoring .......................................................................................................78 13.2 OFFSHORE LINE ........................................................................................................................78 13.2.1 Design Data ..................................................................................................................78 13.2.2 Material Data.................................................................................................................79 13.2.3 Crossing Data ...............................................................................................................79

14. ONSHORE WATER OUTFALL PIPELINE .............................................................................80 15. SPECIFICATIONS, CODES AND STANDARDS ...................................................................82 15.1 TOTAL SPECIFICATIONS...........................................................................................................82 15.2 CODES AND STANDARDS.........................................................................................................82

16. REFERENCES .........................................................................................................................83



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1.

INTRODUCTION

Total E&P UK Ltd is developing the Laggan & Tormore gas fields which are located in approximately 600 metres water depth in Blocks 206/1a, (P911) and 205/5a (P1159) respectively, and are situated some 125km north west of the Shetland Islands on the UK Continental Shelf. The field development shall include a nominal 500MMscfd Gas Processing Plant within the Sullom Voe Terminal. From there the gas is transported to St. Fergus processing terminal via a new 222km long 30inch export pipeline that will tie-in to the existing FUKA line at MCP01. ODE/Doris Joint Venture has been commissioned by Total E&P UK Ltd to undertake a Basic Engineering Design for the above scope.

This Basis of Design provides the design data for the whole scope of Laggan-Tormore Basic Engineering project as far as the tie-ins at MCP01.



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This document shall be used by all work packages and disciplines of the Basic Engineering, including: • • • • • • •

Subsea Production Systems Umbilicals Production Flowlines (Offshore, Onshore) Flow Assurance Gas Processing Plant (GPP) Export Pipeline (Onshore, Offshore) MEG Line

The objective of this document is to ensure a consistent basis for all of the design work that is carried out by the various disciplines. It is also intended that this document is used to maintain an audit trail of decisions and results from technical work. This document shall therefore be updated as required. This Basis of Design shall be read in conjunction with the Project Statement of Requirements (SOR) (Ref [1]) and with the Pre-Project Basis of Design (Ref [2]), the first document taking precedence over the second one.

2.

DEFINITIONS AND ABBREVIATIONS

3PIP AGR AQLV AQS BHFP BAT BBL BOP BPD CAPEX CGR CIV CS DAF DBB DCS DECC DST EDP EoS ESS ESD F&G FTS FUKA GPP GOR

3rd Party Investment Process Aqueous Gas Ratio Air Quality Limit Value Air Quality Standards Bottom Hole Flow Pressure Best Available Technology Barrel Blow Out Preventer Barrel Per Day Capital Expenditure Condensate Gas Ratio Chemical Injection Valve Carbon Steel Dissolved Air Flotation Double Block and Bleed Distributed Control System Department of Energy and Climate Change Drill Stem Test Emergency DePressurisation East of Shetland Expandable Sand Screen Emergency Shutdown Fire and Gas Frigg Transmission System Frigg UK Area pipeline Gas Processing Plant Gas Oil Ratio



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GWC HAZID HAZOP HIPS HP HPU HMI IJ ILT LAT LP MAOP MCM MAIP MEG MeOH MMS MMSCFD MODU MSCM mss ND NPS NTS OD ODR OPF ppm PSD PTT PVT PWRI SAC SAW SCM SDU SEM SHE SIMOPS SOR SPA SPCS SPS SRK SRM SSSI STM SVT TCP TDS TEPUK TRSCSSV

Gas Water Contact Hazard Identification Study Hazard & Operability Study High Integrity Protection System High Pressure Hydraulic Power Unit Human Machine Interface Isolation Joint In Line Tee Lowest Astronomical Tide Low Pressure Maximum Allowable Operating Pressure Manifold Control Module Maximum Allowable Incidental Pressure MonoEthylene Glycol Methanol Machine Monitoring System Million Standard Cubic Feet per Day Mobile Offshore Drilling Unit Manifold Subsea Control Module Metres Subsea Nominal Diameter Ninian Pipeline System National Transmission System Outside Diameter Overall Development Review Organic Phase Fluid parts per million Process Shut Down Pressure Temperature Transmitter Pressure Volume Temperature Produced Water Re-Injection Special Areas of Conservation Submerged Arc Welded Subsea Control Module Subsea Distribution Unit Subsea Electronic Module Safety, Health and Environmental Simultaneous Operations Statement of Requirements Special Protection Area Subsea Production Control System Subsea Production System Soave Redlich Kwong Subsea Router Module Sites of Special Scientific Interest Synchronous Transfer Module Sullom Voe Terminal Tubing Conveyed Perforating Total Dissolved Solids Total Exploration & Production UK Tubing Retrievable Surface Controlled Subsurface Safety Valve



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TRSSSV TVD/MSL TVDSS TVP UET UTA WAT WEG WHP WHSIP WoS WOW XT

3.

Tubing Retrievable Sub-Surface Safety Valve True Vertical Depth/Mean Sea Level True Vertical Depth SubSea True Vapour Pressure Umbilical End Termination Umbilical Termination Assembly Wax Appearance Temperature Wireline Entry Guide Wellhead Pressure Wellhead Shut-In Pressure West of Shetland Waiting on Weather Christmas Tree

UNITS

A consistent set of engineering units is to be used in all engineering documentation as follows: • • • • • • • • • •

4.

Length Time Fluid Pressure Atmospheric Pressure Temperature Volume Volume Flow Mass Flow Energy Gas Production

: : : : : : : : : :

m or km or mm sec or h barg mbar °C m3 Sm3/h kg/h or Te/h MJ/h MScmd (106 Sm3/day) or MMScfd (106 Scf/day)

CO-ORDINATE SYSTEM

Offshore mapping is based on the Transverse Mercator Zone 30 N projection and European Datum ED50. Onshore mapping is based on the Transverse Mercator Airy Spheroid OSGB (1936) Datum, with all coordinates given as Ordnance Survey National Grid Eastings and Northings. The GPP will use the Plant coordinate system.



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5.

SAFETY, HEALTH AND ENVIRONMENTAL

Total E&P UK Ltd (TEPUK) is committed to minimising the risk to the safety and health at work for all employees and contractors. Protection of people, the environment and Company assets is a key management responsibility. The safety, health and environmental aspects of the Laggan-Tormore Development project will be controlled by the application of the TEP UK Safety, Health and Environmental (SHE) Policy and TEP UK Safety, Health and Environment Management Plan (SHEMP) (Ref [3]). For Basic Engineering, reference should be made to the Project SHE Plan (Ref [4]) and Project SHE Philosophy (Ref [5]). 5.1

LEGISLATIVE COMPLIANCE

The Laggan-Tormore development is subject to UK legislation and design codes. The following are some of the key Safety Acts and Regulations applicable to this development. A more comprehensive list will be included in the Project SHE Plan (Ref [4]). Acts: 1) 2)

Health and Safety at Work etc Act, 1974 Pipelines Act, 1962

Regulations: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11)

Offshore Installations (Safety Case) Regulations, 2005, SI 2005/3007 Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations, SI 1995/743 Offshore Installations (Design and Construction) Regulations, 1996, SI 1996/913 Offshore Installations and Pipeline Works (Management/Administration) Regulations, 1995, SI 1995/738 (MAR) Pipeline Safety Regulations, SI825/1996 Control of Major Accident Hazards (Amendment) Regulations, 2005 Management of Health and Safety at Work Regulations, 1999, SI 1999/3242 Health and Safety at Work etc Act 1974 Application Outside Great Britain Order 2001, SI 2001/2127 Pressure Systems Safety Regulations, 2000 Pipelines Safety (Amendment) Regulations, 2003 Construction (Design And Management) Regulations, 2007

Any design will also comply with relevant UK regulations, design codes, TEPUK company standards and specifications (Company Referential), and recognised good practices. The design shall also comply with the relevant Total company standards and specifications. For the SVT onshore plant, appropriate interface requirements shall be developed for the tie-ins to BP systems and services.



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5.2

INHERENT SAFETY

The most effective principle of hazard management is to eliminate or minimise hazards at source. As far as reasonably practicable (ALARP), inherent safety will be maximised in the LagganTormore development and the emphasis will be on eliminating or reducing the likelihood of events occurring rather than mitigating their associated effects. Inherent safety is achieved through the application of the following measures: • • • •

Minimisation of hydrocarbon inventory Reduction in potential number of leak paths by minimising the amount of equipment, number of fittings and flanged joint connections Reduction in potential number of ignition sources Optimisation of site layout to limit the effects of identified events

Reliable and effective life saving, fire protection, emergency shutdown and life support systems each designed for the hazards involved, will be incorporated in the Laggan-Tormore development project design. These will provide an overall system that will help reduce the loss of life, shutdown production and minimise loss of capital investment in the event of an accident occurring (Ref [5]). 5.3

ENVIRONMENTAL ASPIRATIONS

The environmental aspirations are summarised in the Table 5-01 below: Environmental Aspect

Design Specification

General

Use of Best Available Technology (BAT) in design Environmental considerations taken into account in contractor selection Flaring No continuous operational flaring All flaring associated with well clean-up to be below 96 hrs and 2000 tonnes per well Venting No continuous venting Combustion Combustion plant should be designed according to BAT with DLE (dry low emissions emissions). An assessment of BAT will be prepared covering air emissions. Energy efficiency Facilities designed to optimise energy efficiency throughout life of field. An assessment of BAT will be prepared covering energy efficiency. Emissions to Air Minimise flaring during production and well clean up/ commissioning phases Minimise combustion emissions through use of BATNEEC Minimise fugitive emissions – no routine venting to atmosphere, emergency only Minimise VOC emissions Optimise fuel efficiency An assessment of BAT will be prepared covering air emissions. Discharges to water Manage drainage/spill collection systems discharges to marine and freshwater environments Minimise produced water emissions through use of BATNEEC Zero spills of oil or chemicals to the environment An assessment of BAT will be prepared covering wastewater. Ecosystems Pipeline route selection to avoid areas of conservation importance and significant environmental sensitivity Minimise disturbance to seabed and onshore habitats Resource Use Minimise chemical use or use chemicals with lowest environmental risk Chemicals No use of chemical products containing hazardous substances or products with substitution warnings unless no alternative available



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Design systems/facilities to minimise the use of chemicals OPF Contaminated Cuttings disposal options must be systematically assessed in order of the following Cuttings priority:- Cuttings re-injection - Offshore treatment and disposal (<1% oil) - Skip and ship Waste Design facilities to minimise waste production and disposal. An assessment of BAT will be prepared covering solid wastes. Design facilities for complete removal at decommissioning Other users Pipeline route selection to avoid SAC’s (special areas of conservation) Minimise footprint of subsea facilities and pipelines Subsea facilities and pipelines to be ‘fishing friendly’ design Installation of pipelines must be systematically assessed in order of the following priority:- Surface laid (where protection is not required) - Trenched and buried - Rock dumped Zero complaints/claims from other sea/land users; manage communications Noise Noise considerations to be taken into account during development selection Table 5-01 - Environmental Requirements



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6.

FIELD DATA

6.1

FIELD LOCATION

Laggan is a lean gas condensate discovery, located West of Shetland in block 206/1, approximately 35 km northwest of Clair, 90 km North East of Schiehallion , 126 km from Sullom Voe Terminal and 400km from St Fergus. The water depth local to Laggan is approximately 600 m. Laggan was discovered by well 206/2-2 drilled by SHELL in 1986. Subsequently, an additional well, 206/1-3 was drilled by Total in 1996. This well disproved the presence of an oil rim. Two appraisal wells were drilled mid-2004 leading to reserves revision. Tormore is a richer gas condensate discovery discovered some 16km South West of Laggan, at a water depth of around 610m. Tormore was discovered by well 205/5a-1, drilled by Total in 2007.

Figure 6-01 - Laggan and Tormore Location

Licenses, Appraisal/Exploration wells Laggan

Tormore

Block

206/1

205/5a

License

P 911

P 1159

Partners

TOTAL 50% (Operator) DONG ENERGY 20% ENI 20% CHEVRON 10%

TOTAL 50% (Operator) DONG ENERGY 20% ENI 20% CHEVRON 10%

206/1-2 (1986)

205/5a-1 (2007)

Exploration Well Appraisal Well

206/1-3 (1996) 206/1a-4a (2004) 206/1a-4aZ (2004) Table 6-01 - Licenses, Appraisal/Exploration Wells



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Well locations (Top Hole Location) Laggan appraisal well 206/1a-4Z (1986) Tormore exploration well 205/5a-1 (2007)

Latitude : 060 56 43.510 N Longitude : 002 53 28.806 W (Coordinate system = ED50) Latitude : 060 52 20.630 N Longitude : 003 08 07.470 W (Coordinate system = ED50)

Table 6-02 - Well Locations

6.2

RESERVOIR PROPERTIES

6.2.1

Laggan Reservoir Description

The reservoir lies at a depth of between 3500 (crest of the field) and 3909mss (GWC). The fluid is a lean gas condensate. There are a total of 4 exploration and appraisal wells in the field area. Laggan was discovered by well 206/1-2 in 1986. The well was cored over most of the reservoir interval and 2 DSTs were performed over the reservoir interval. The second well 206/1-3 was cored and encountered the GWC (-3909mss). 206/1a-4a was drilled in 2004 to appraise the crest of the structure and then side-tracked downdip (as well 206/1a-4aZ). The reservoir interval in the 4aZ well was cored. The 4aZ well was tested at a maximum rate of 37.8 mmscfd of gas and 800 bbls/d of condensate (1 inch choke) from the B sands, in line with expectations. The well was then suspended as a potential future producer. 6.2.2

Tormore Reservoir Description

The reservoir lies at a depth of between 3505 mss (crest of the field) and the assumed most likely GWC of 3933 mss. The mid-reservoir point is 3769m TVCSS. The fluid is a gas condensate, approximately 3 times richer than Laggan. There is one exploration well in the field area, 205/5a-1, drilled in 2007. The well was tested at a maximum rate of 28.3 MMscfg/d and 1975 bbls/d of condensate (1 inch choke) from the C sands. The well was then suspended as a potential future producer. 6.2.3

Summary of Reservoir Properties

Crest of Field Mid Reservoir GWC Initial Reservoir Pressure Initial Reservoir Temperature WHSIP

mss mss mss bara °C barg

Laggan

Tormore

3500 3666 3909 431 (Note 3) 112 (Note 3) 380 (Note 1)

3505 3769 3933 418.3 (Note 3) 117.6 (Note 3) Note 2

Table 6-03 - Reservoir Properties



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Note 1: Laggan WHSIP estimated based upon initial reservoir pressure of 440 barg @ 3909mss, seabed at 600mss and the static head in the tubing assuming full of reservoir gas at a constant temperature. Note 2: WHSIP for Tormore assumed to be the same as Laggan but likely to be slightly lower, due to lower reservoir pressure. Note 3: As per Ref [7] which corrected the Pre-Project figures.

6.2.4

Reservoir Characteristics

The profile of the reservoir characteristics (reservoir pressure, bottom-hole pressure and production index) throughout the field life is summarised in the following table:

Table 6-04 - Reservoir Characteristics Profile

This profile may have to be updated pending the latest reservoir model outputs.

6.3

PRODUCTION PROFILES

As a base case, the Proven and Probable Case (2P Case) will be considered. The production profiles are given here after for Laggan, for Tormore and for the combination of Laggan and Tormore. The Laggan-Tormore plateau will be approximately 2.5 years. The gas production profiles per well are also given, for Laggan and for Tormore. Reference shall be made to Ref [6] and Ref [42].



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6.3.1

Laggan Production Profile Peak production rates - 2P Laggan 7

400

Peak Gas Rate Peak Oil Rate

350

6

300 5 Gas Rate (MMScfd) 250

Oil Rate (Mbpd) 4

200 3 150 2 100

1

50

0 déc-11

0 déc-12

déc-13

déc-14

déc-15

déc-16

déc-17

déc-18

déc-19

nov-20

nov-21

nov-22

nov-23

nov-24

nov-25

nov-26

nov-27

Time

Figure 6-02 - 2P Laggan Production Profile

Well Gas Production Rate- Laggan 2P case

110 WGPR:L1 WGPR:L2 WGPR:L3 WGPR:L4 WGPR:L5

100 90 80

MMscfd

70 60 50 40 30 20 10

28/11/2028

29/11/2027

29/11/2026

29/11/2025

29/11/2024

30/11/2023

30/11/2022

30/11/2021

30/11/2020

01/12/2019

01/12/2018

01/12/2017

01/12/2016

02/12/2015

02/12/2014

02/12/2013

02/12/2012

03/12/2011

03/12/2010

0

Figure 6-03 - 2P Laggan Gas Production Profile per Well



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6.3.2

Tormore Production Profile Peak production rates - 2P Tormore 12

Peak Gas Rate Peak Oil Rate 200

10

6 100

Oil Rate (Mbpd)

Gas Rate (MMScfd)

8 150

4

50 2

0 0 déc-11 déc-12 déc-13 déc-14 déc-15 déc-16 déc-17 déc-18 déc-19 nov-20 nov-21 nov-22 nov-23 nov-24 nov-25 nov-26 nov-27 Time

Figure 6-04 - 2P Tormore Production Profile

Well Gas Production Rate - Tormore 2P case 90 WGPR:205_5A-1 WGPR:T2 WGPR:T3

80

70

MMscfd

60

50

40

30

20

10

28/11/2028

29/11/2027

29/11/2026

29/11/2025

29/11/2024

30/11/2023

30/11/2022

30/11/2021

30/11/2020

01/12/2019

01/12/2018

01/12/2017

01/12/2016

02/12/2015

02/12/2014

02/12/2013

02/12/2012

03/12/2011

03/12/2010

0

Figure 6-05 - 2P Tormore Gas Production Profile per Well



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6.3.3

Laggan-Tormore Production Profile

Peak production rates - 2P Laggan & Tormore 18

600

Peak Gas Rate

16

Peak Oil Rate

500

14

12

10 300 8

Oil Rate (Mbpd)

Gas Rate (MMScfd)

400

6

200

4 100 2

0 0 déc-11 déc-12 déc-13 déc-14 déc-15 déc-16 déc-17 déc-18 déc-19 nov-20 nov-21 nov-22 nov-23 nov-24 nov-25 nov-26 nov-27 Time

Figure 6-06 - 2P Laggan + Tormore Production Profile

The contributions of Laggan and Tormore are illustrated on the next figure for gas production. Distribution between Laggan and Tormore for Gas Production of 2P case 80% 70%

% of Gas production

60% 50% 40% 30%

% Tormore 20%

% Laggan

10% 0% 01-avr-12

27-déc-14

22-sept-17

18-juin-20

15-mars-23

09-déc-25

04-sept-28

Year

Figure 6-07 - Gas Production Split for 2P Case



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6.3.4

Design Gas Flowrates

The gas peak rate of the Laggan-Tormore development will be 500 MMSCFD. The annual average rate during the plateau will be 455MMSCFD. Here below are the design flowrates to be considered: Laggan+Tormore Template Well 6.3.5

: : :

500 MMscfd 352 MMscfd 115 MMscfd

Formation Water

The formation water flowrate profile is illustrated on the following chart. Peak Formation Water rates - 2P Case 16

Laggan Tormore

14

Laggan + Tormore

Formation Water Rate (bpd)

12

10

8

6

4

2

0 déc-11

déc-12

déc-13

déc-14

déc-15

déc-16

déc-17

déc-18

déc-19

nov-20

nov-21

nov-22

nov-23

nov-24

nov-25

nov-26

nov-27

Time

Figure 6-08 - Formation Water Flowrate Profile for 2P Case

A maximal flowrate of 2,000 bwpd of formation water is considered as a design value for the flowlines. The maximal flowrate of formation water per well is 500 bwpd (Ref [20]). Moreover, to take future development into account, a maximal flowrate of 3,000 bpd of formation water is considered as a design value for MEG injection system (SOR Ref [1] Section 1.5). 6.3.6

Condensation Water

The condensation water peak rate to be considered is 864 bwpd in accordance with Ref [44]. A preliminary figure of 727 bwpd was given in the SOR (Ref [1]), which was considered during the Basic Engineering early stages.



Page 20 of 84


6.3.7

Boundary Pressures

The design basis is to perform subsea choking to regulate the flow rate.

Table 6-05 - Arrival Pressures (Ref [2])

The transition between the initial high arrival pressure and the lower arrival pressure required for late field life will be governed by maximizing production within the constraints of compressor capacity, and to a lesser extent pipeline operability. Estimated transition dates shall be refined during the course of the study. 6.4

WELLHEAD CONDITIONS

In the Pre-Project phase, the following wellhead temperatures and pressures were calculated. These will be confirmed by Company during Basic Engineering.

Year 0 2 3 5 7 9 11 12

Pressure bara U/S choke D/S choke 283.5 131.2 160.3 127.5 114.8 111.2 93.0 80.4 79.4 66.8 70.5 64.8 57.4 45.5 47.2 38.8

Temperature C U/S choke D/S choke 85.8 63.2 79.1 67.7 75.0 67.9 69.0 57.2 62.1 47.0 53.1 37.9 48.2 30.5 48.2 31.7

Table 6-06 - Pressure and Temperature Drop Over Laggan Choke

Year 0 2 3 5 7 9 11

Pressure bara U/S choke D/S choke 221.1 132.6 149.7 128.7 126.8 112.2 90.1 81.4 69.3 67.8 66.0 65.9 48.2 46.6

Temperature C U/S choke D/S choke 86.6 74.4 79.7 71.2 76.8 67.7 72.3 62.1 67.9 57.4 56.0 43.1 60.0 47.2

Table 6-07 - Pressure and Temperature Drop Over Tormore Choke



Page 21 of 84


6.5

PRODUCTION FLUIDS PROPERTIES

6.5.1

Reservoir Hydrocarbons Composition

Thermodynamic properties of the components of Laggan and Tormore fluids are given below. Pseudo components considered for heavy cuts are denominated C36PGL, C36POL, C36PGT and C36POT for the gas and oil phases of Laggan and Tormore fluids, respectively (Ref [7]).

N2 CO2 C1 C2 C3 IC4 NC4 IC5 NC5 C6 Benz C7 Tol C8 EBenz mpXyl oXyl C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30 C31 C32 C33 C34 C35 C36PGL C36POL C36PGT C36POT

Mw Tc Pc gmole °C bar 28.01 -146.95 44.01 31.05 16.04 -82.55 30.07 32.25 44.10 96.65 58.12 134.95 58.12 152.05 72.01 190.27 72.15 196.45 84.00 237.00 78.11 288.95 96.00 270.00 92.14 318.65 107.00 300.00 106.17 343.95 106.17 343.75 106.17 357.22 121.00 329.00 134.00 345.67 147.00 362.17 161.00 378.50 175.00 394.67 190.00 410.67 206.00 426.50 222.00 442.17 237.00 457.67 251.00 473.00 263.00 488.17 275.00 503.17 288.00 518.00 300.00 532.67 312.00 546.67 324.00 560.50 337.00 574.17 349.00 587.00 360.00 599.00 372.00 609.50 382.00 619.50 394.00 629.00 404.00 638.00 415.00 646.50 426.00 654.50 437.00 662.00 445.00 669.00 520.00 760.00 600.00 819.00 520.00 719.00 600.00 779.00

Omega 33.90 73.80 46.00 48.80 42.50 36.50 38.00 34.48 33.70 31.40 49.24 30.20 41.00 28.70 36.07 35.77 37.33 27.65 25.66 24.01 22.49 21.32 20.11 18.97 18.00 17.32 16.70 16.26 15.86 15.43 15.18 14.85 14.54 14.21 13.92 13.76 13.48 13.28 13.01 12.89 12.66 12.44 12.23 12.10 11.90 11.60 11.30 11.00

0.0400 0.2250 0.0115 0.0908 0.1454 0.1760 0.1928 0.2202 0.2273 0.2697 0.2150 0.3042 0.2596 0.3401 0.3010 0.3361 0.3023 0.3567 0.3677 0.4010 0.4356 0.4691 0.5037 0.5391 0.5729 0.6033 0.6304 0.6527 0.6700 0.6900 0.7090 0.7270 0.7440 0.7600 0.7750 0.7890 0.8020 0.8140 0.8250 0.8350 0.8440 0.8520 0.8590 0.8650 0.9650 0.9900 0.9450 0.9800

Ci 0.00 0.00 -0.10 -0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01 0.01 0.01 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.05 0.05 0.05 0.05

Vc Parachor Sg cm3/mole 89.8 41.0 0.8090 93.9 78.0 0.8230 99.2 77.0 0.3000 148.3 108.0 0.3580 203.0 150.3 0.5230 263.0 181.5 0.5970 255.0 189.9 0.6140 306.0 225.0 0.6650 304.0 231.5 0.6490 356.5 255.3 0.6830 260.0 238.1 0.8822 394.1 290.3 0.7200 316.0 279.1 0.8700 433.4 322.4 0.7420 374.0 320.0 0.8700 373.4 320.0 0.8669 369.1 320.0 0.8831 484.4 363.3 0.7650 570.0 401.3 0.7770 578.0 439.2 0.7840 634.0 480.1 0.8000 690.0 521.0 0.8070 749.0 564.8 0.8130 813.0 611.5 0.8200 879.0 658.2 0.8320 939.0 702.0 0.8370 997.0 742.9 0.8410 1046.0 778.0 0.8450 1096.0 813.0 0.8480 1161.0 851.0 0.8520 1199.0 886.0 0.8550 1248.0 921.0 0.8560 1298.0 956.1 0.8580 1353.0 994.0 0.8720 1403.0 1029.1 0.8750 1448.0 1061.2 0.8780 1499.0 1096.2 0.8800 1540.0 1125.4 0.8820 1591.0 1160.5 0.8840 1632.0 1189.7 0.8860 1678.0 1221.8 0.8880 1723.0 1253.9 0.8900 1770.0 1286.0 0.8910 1803.0 1309.4 0.8930 2160.7 1528.4 0.9200 2347.2 1762.0 0.9800 2190.0 1528.4 0.9100 2385.8 1762.0 0.9700

Table 6-08 - Thermodynamic Properties of the Components



Page 22 of 84


The binary interaction coefficients are given below.

N2 CO2 N2 CO2 -0.02 C1 0.04 0.1 C2 0.05 0.13 C3 0.08 0.13 IC4 0.1 0.13 NC4 0.09 0.13 IC5 0.1 0.12 NC5 0.1 0.12 C6 0.1 0.1 Benz 0.1 0.1 C7 0.1 0.1 Tol 0.1 0.1 C8 0.1 0.1 EBenz 0.1 0.1 mpXyl 0.1 0.1 oXyl 0.1 0.1 C9 0.1 0.1 C10 0.1 0.1 C11 0.1 0.1 C12 0.1 0.1 C13 0.1 0.1 C14 0.1 0.1 C15 0.1 0.1 C16 0.1 0.1 C17 0.1 0.1 C18 0.1 0.1 C19 0.1 0.1 C20 0.1 0.1 C21 0.1 0.1 C22 0.1 0.1 C23 0.1 0.1 C24 0.1 0.1 C25 0.1 0.1 C26 0.1 0.1 C27 0.1 0.1 C28 0.1 0.1 C29 0.1 0.1 C30 0.1 0.1 C31 0.1 0.1 C32 0.1 0.1 C33 0.1 0.1 C34 0.1 0.1 C35 0.1 0.1 C36PGL 0.1 0.1 C36POL 0.1 0.1 C36PGT 0.1 0.1 C36POT 0.1 0.1

C1

0 0 0 0 0 0 0.03 0.04 0.03 0.06 0.03 0.03 0.03 0.05 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.08 0.08 0.08 0.08 0.08 0.11 0.11 0.08 0.08

C2

0 0 0 0 0 0 0 0 0 0 0 0 0 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02

C3

0 0 0 0 0 0 0 0 0 0 0 0 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01

Table 6-09 - Binary Coefficients



Page 23 of 84


Fluid compositions (% molar) for Laggan and Tormore fluids are detailed in the next table. Tormore

Laggan N2 CO2 C1 C2 C3 IC4 NC4 IC5 NC5 C6 Benz C7 Tol C8 EBenz mpXyl oXyl C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30 C31 C32 C33 C34 C35 C36PGL C36POL C36PGT C36POT

Base case Maxi case Mini Case 0.40952 0.40926 0.41002 0.19976 0.19973 0.2 90.89238 90.84984 91.00219 3.99527 3.99527 3.99995 1.74793 1.74872 1.74976 0.29965 0.29992 0.29987 0.42949 0.42998 0.42971 0.15981 0.16009 0.1597 0.13983 0.14009 0.13967 0.2203 0.221 0.21886 0.05564 0.05591 0.05517 0.33849 0.34002 0.33192 0.08258 0.08319 0.08015 0.27867 0.28041 0.26553 0.00867 0.00875 0.00809 0.04155 0.04195 0.0384 0.01327 0.01341 0.01225 0.10129 0.10228 0.09289 0.10712 0.10834 0.09579 0.07422 0.07525 0.06481 0.06252 0.06358 0.05383 0.05764 0.05884 0.0493 0.04605 0.04724 0.03926 0.04709 0.0486 0.0401 0.03136 0.03261 0.02669 0.02632 0.02764 0.0224 0.02562 0.02723 0.0218 0.01956 0.02109 0.01665 0.01562 0.01713 0.01329 0.01309 0.01465 0.01114 0.01086 0.01249 0.00924 0.00917 0.01086 0.0078 0.00777 0.00952 0.00661 0.00596 0.00758 0.00507 0.00528 0.007 0.00449 0.00415 0.00576 0.00353 0.00385 0.00555 0.00328 0.00281 0.00422 0.00239 0.00229 0.00357 0.00195 0.00172 0.00284 0.00146 0.00135 0.0023 0.00115 0.00113 0.00198 0.00096 0.00087 0.00156 0.00074 0.00063 0.00116 0.00054 0.00143 0.00141 0.00122 0.00042 0.00017 0.00036 0 0 0 0 0 0

Table 6-10 - Laggan Fluid Composition


N2 CO2 C1 C2 C3 IC4 NC4 IC5 NC5 C6 Benz C7 Tol C8 EBenz mpXyl oXyl C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30 C31 C32 C33 C34 C35 C36PGL C36POL C36PGT C36POT

Base case Maxi case Mini case 0.5167 0.5146 0.5193 0.0383 0.0381 0.0385 86.7642 86.3833 87.1939 3.8567 3.8382 3.8752 2.3971 2.3859 2.4073 0.4772 0.4754 0.4786 0.79 0.7876 0.7917 0.2952 0.2956 0.2944 0.3619 0.3629 0.3603 0.4914 0.5014 0.4801 0.0895 0.0918 0.0869 0.679 0.7141 0.6414 0.1434 0.1531 0.1329 0.6473 0.7058 0.5855 0.0248 0.0274 0.022 0.0868 0.0964 0.0766 0.0389 0.0432 0.0343 0.3252 0.3625 0.2855 0.3563 0.4007 0.3091 0.2794 0.3159 0.2403 0.2236 0.2534 0.1916 0.2068 0.2344 0.1769 0.1685 0.1908 0.144 0.153 0.1731 0.1307 0.1092 0.1233 0.0933 0.0875 0.0986 0.0747 0.0778 0.0875 0.0665 0.0621 0.0696 0.053 0.047 0.0526 0.0401 0.0386 0.043 0.033 0.0312 0.0346 0.0267 0.026 0.0287 0.0222 0.0209 0.023 0.0179 0.0173 0.0189 0.0148 0.0135 0.0147 0.0115 0.0113 0.0122 0.0097 0.0092 0.0099 0.0079 0.0077 0.0082 0.0066 0.0062 0.0066 0.0053 0.0049 0.0051 0.0042 0.0038 0.0039 0.0032 0.0031 0.0032 0.0026 0.0025 0.0026 0.0021 0.0019 0.0019 0.0016 0 0 0 0 0 0 0.0055 0.005 0.0047 0.0016 0.0012 0.0014

Table 6-11 - Tormore Fluid Composition


Page 24 of 84


6.5.2

Formation Water

A theoretical water composition has been determined using the results of analyses performed on aquifer water sampled from Laggan well 206/1-3 in 1997 (Ref [1] and Ref [28]). The aquifer sample composition and the formation water theoretical composition are given in the following table. The aquifer sample composition is multiplied by 6.71 to convert from the aquifer salinity (5960 mg/l TDS) to the estimated formation water salinity (40,000 mg/l).

Table 6-12 - Formation Water Composition

From this composition, the formation water is assumed with no acid organic content. It should be noted that the organic acid content is necessary to evaluate the potential appearance of top of line corrosion. (ongoing work) In the absence of aquifer water sample from Tormore, the Tormore formation water composition shall be assumed to be the same as that of Laggan. 6.5.3

Contaminant Management

Hydrates Management Hydrate dissociation curves for the Laggan and Tormore fluids with pure water have been generated using the fluid modeling in PVTsim (Ref [7]), and are shown below.



Page 25 of 84


Hydrates curves 450

400

350

Pressure (bara)

300

250

200

150

100

50

0 -30

-20

-10

0

10

20

30

Temperature (°C) Laggan hydrate curve

Tormore hydrate curve

Pre-project hydrate curve

Figure 6-09 - Laggan and Tormore Hydrate Curve

For conservatism the dissociation curves shall be used to predict hydrate formation and a 3°C margin shall be applied in addition. The hydrate formation curves are issued from PVTsim v.16.2.0 software. Hydrate formation prediction curve is reliable with an accuracy of 0.5 to 1°C. This margin is required to account for this 0.5 to 1°C uncertainty of hydrate curves but also for inhibitor rate assessment correlations uncertainty or thermo hydraulic calculation uncertainties. Prevention of hydrate formation is based on continuous injection of MEG during production. Methanol was envisaged at the early stage of Basic Engineering but the decision was eventually taken by TEP UK to use MEG instead. As a conservative approach MEG 85% is considered for flowline design ([HOLD]) although the GPP will allow for MEG 90%. MEG will also be used for start-up and restart, the minimum start-up temperature being -18°C, which is well above the MEG freezing temperature. As per Ref [1] Section 1.5, the MEG design flow rate has been calculated based on: • • •

2,000 bwpd of formation water from Laggan Tormore 1,000 bwpd of 3rd Party water allowance 864 bwpd of condensation water (Ref [44])

The calculated MEG design flow rate and design pressure are: Design flowrate Design pressure

: :

70.1 m 3/h (70.8 Sm3/h) [HOLD] 622 barg @ -610m [HOLD]



Page 26 of 84


6.5.4

Wax Management

Laggan There is a low risk of wax deposition along flowlines. Indeed the Wax Appearance Temperature (WAT) is only 9°C and wax content at 0°C is 1% as indicated in Ref [2]. Tormore The WAT being 19°C and 15°C, there is a risk of wax deposition along pipes and flowlines (Ref [8] Section 2.2.2). Injection of wax inhibitor shall be allowed for. Moreover pigging of all subsea flowlines is highly recommended. Although modelling of wax deposition in polyphasic flowlines is only at research stage, deposition rates have been estimated using various hypotheses. A pigging frequency of 3 months is proposed but will have to be adapted based on a proper monitoring. It should be highlighted that wax deposition will be limited in time by the rapid depletion of the reservoir. Pigging for wax management should actually be considered in the first 3 years max. 6.5.5

Other Risks

Asphaltene No asphaltenes have been measured in the Laggan and Tormore fluids, no risks of asphaltenes deposition are expected (Ref [2] Section 3.5.5 and Ref [8]). Naphthenates No naphthenates have been measured in the Laggan and Tormore fluids, no risks of naphthenates deposition are expected (Ref [2] and Ref [8]). Scale Reference shall be made to Ref [2] Section 3.5.5. There is no risk of Calcium Carbonate scale upstream of the GPP but Calcium Carbonate or Calcium Sulphonate scaling could occur at the GPP. There is a low risk of Barium Sulphate scaling. A downhole scale inhibitor is not required while a subsea scale inhibitor injection facilities should be retained. Sand Reference shall be made to Ref [1] Section 1.1 page 18 and Ref [2] Section 3.5.5. Sand has to be managed downhole and therefore the facilities will not be designed to handle sand, though as a precaution, jetting nozzles should be included in the upstream separators to enable sand removal. Sand monitoring at subsea is required. Additionally clamp-on sand monitoring devices could be considered at the inlet of the GPP, once early field life pigging operations have ceased. Mercury Reference shall be made to Ref [2] Section 3.5.5. For Laggan, no mercury was detected during the multi-rate test. For Tormore, Mercury levels in the gas averaged 84-85 ng/m3 throughout the test. Mercury is not currently considered to be a significant issue. However provisions will be made in the GPP design for future retrofit of Mercury traps and absorber beds, should they be required.



Page 27 of 84


H2S Reference shall be made to Ref [1] Section 1.1 page 18, Ref [2] Section 3.5.5 and Ref [19] Section 6.2.2. No significant levels of H2S have been observed (3ppm max). However the GPP shall be conservatively designed to NACE requirements. In addition, provision will be made in the GPP design for future retrofit of H2S absorber bed, should it be required. 6.6

OFFSHORE ENVIRONMENTAL DATA

6.6.1

Wave and Current Data

Environmental conditions between Laggan and SVT are summarised in Table 6-13. Environmental conditions between SVT and MCP01 are summarised in Table 6-14 (full data available in Ref [9]). PhysE Location (1)

Latitude (°N)

Longit (°W)

Depth (m MSL)

1 (Laggan)

60.945

2.895

599

2

60.921

2.636

444

3

60.896

2.393

319

4

60.869

2.126

154

6

60.810

1.575

117

S3

60.730

1.256

95.4

S4

60.653

1.209

71.9

S17

60.568

1.252

42.4

S14

60.490

1.258

21.0

S15

60.479

1.265

6.8

Return Period

Hs (m)

Tp (s)

Current at 1m asb (m/s)

1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year

13.38 15.81 18.14 13.25 15.65 17.96 12.68 14.99 17.2 12.25 14.48 16.62 12.16 14.37 16.49 11.96 14.13 16.21 10.56 12.48 14.32 6.14 7.28 8.35 3.16 3.75 4.30 3.10 3.67 4.21

18.53 20.14 21.58 18.50 20.11 21.54 18.42 20.02 21.45 18.40 20.01 21.43 18.35 19.95 21.37 18.31 19.90 21.32 17.51 19.03 20.38 14.61 15.91 17.04 10.58 11.51 12.33 10.47 11.40 12.21

0.67 0.72 0.76 0.67 0.72 0.76 0.67 0.72 0.76 0.67 0.72 0.76 0.33 0.38 0.44 0.53 0.60 0.67 0.64 0.67 0.70 0.91 0.95 1.00 0.69 0.73 0.85 0.35 0.37 0.39

Table 6-13 - Environmental Conditions from Laggan to SVT



Page 28 of 84


PhysE Location (1)

Latitude (°N)

Longit (°W)

Depth (m MSL)

S31

60.453

1.162

35.0

S32

60.456

1.151

31.8

S33

60.458

1.135

33.8

S36

60.469

1.032

54.5

S37

60.481

0.966

120.0

S39

60.416

0.551

115.1

12

58.874

0.246

131

Return Period

Hs (m)

Tp (s)

Current at 1m asb (m/s)

1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year 1 year 10 year 100 year

1.05 1.25 1.43 1.58 1.88 2.15 1.64 1.94 2.23 4.94 5.85 6.71 5.65 6.70 7.68 10.10 11.97 13.73 9.28 11.00 12.62

6.11 6.65 7.12 7.49 8.15 8.73 7.62 8.30 8.88 13.22 14.39 15.41 14.14 15.40 16.49 13.89 15.12 16.19 13.40 14.59 15.62

2.01 2.17 2.34 1.84 2.00 2.16 1.34 1.40 1.45 0.79 0.81 0.82 0.36 0.40 0.44 0.33 0.38 0.42 0.37 0.47 0.57

Table 6-14 - Environmental Conditions for Export Pipeline (1)

6.6.2

PhysE Data Locations. Environmental data for other locations along pipeline route are available in physE “Wave & Current Conditions for the Laggan Export Pipelines – Volume 1” (Ref [9]).

Wind Data

Severe weather is common in the region, and storm build-up is faster and less predictable than in other deep water oil regions around the world. Wind roses show no clear directionality in summer, with winds blowing from almost any direction. The directionality is clearer in the winter when winds mostly blow from the south to west sectors.

Wind Speeds in m/sec Hourly Mean Wind Speed (10m above sea level)

1-year

10-year

50-year

100-year

34.3

38.4

41.0

42.0

Table 6-15 - Annual Omni-directional Hourly Mean Wind Speeds for the Laggan Field



Page 29 of 84


Monthly Mean (m/s)

Maximum Hourly Mean (m/s)

1998

1998

10.9 14.0 11.4 10.5 8.6 8.4 9.1 8.8 8.6 11.5 10.8 14.1

23.5 25.2 20.2 19.0 17.5 23.6 155 14.8 14.9 17.3 25.8 24.3

Jan Feb March April May June July Aug Sept Oct Nov Dec

1922-1998 Speed (m/s) and year 43.4 37.9 35.9 37.2 29.8 28.5 27.1 33.9 39.9 39.3 34.5 39.3

1961 1981 1967 1967 1982 1955 1940 1923 1978 1965 1973 1949

Highest Gust (ms/) 1922-1998 Speed (ms/s) and year

1998 40 46.5 44.1 33.5 27.6 38.8 28.2 26.5 27.6 36.5 52.9 45.9

64.3 56.2 52.2 52.8 44.1 41.3 41.3 48.1 58.9 60.9 54.2 60.9

1961,1992 1943,1957 1967 1957 1982 1955 1964 1923 1963 1980 1936,1938 1956

Table 6-16 - Shetland Wind Speed Records 1998 (adapted from SIC, 1999)

6.6.3

Temperature Data

Air and seawater temperatures for the Laggan field are given below (Ref [10]): Parameter

Maximum (°C)

Minimum (°C)

Air Temperature

16

-1

Sea Temperature (surface)

15

6.1

Sea Temperature (seabed)

7.2

-0.9

Table 6-17 - Air and Seawater Temperatures at Laggan Field

6.6.4

Marine Growth

There is no evidence of the existence of marine growth near the seabed in Fugro reports Ref [12] and [13]. Accordingly, no marine growth will be considered on the Production Flowlines and on the Export Pipeline. 6.6.5

EoS and WoS Environmentally Sensitive Areas

Reference shall be made to Ref [29] Section 1.1.5 (Tables 2-2 to 2-5) for the review of existing sources of information and for an overview of the existing understanding of the environment in the area.



Page 30 of 84


6.7

ONSHORE ENVIRONMENTAL DATA

6.7.1

Climate

The Shetland Islands have a temperate maritime climate, characterised by cool, short summers and mild, wet winters. Air temperature Air temperatures based on Ref [30], Ref [31] and Ref [33] are given below: Parameter

Maximum (°C)

Minimum (°C)

Air Temperature (°C)

26

-7

Table 6-18 - Air Temperatures

100.00%

10000

95.00% 90.00%

9000

85.00% 80.00%

8000

75.00% 70.00%

7000

Frequency

60.00% 55.00%

Cummulative % 5000

50.00% 45.00%

4000

40.00%

Cummulative %

65.00% Totals

6000

35.00% 3000

30.00% 25.00%

2000

20.00% 15.00%

1000

10.00% 5.00%

M or e

22 23

20 21

18 19

16 17

14 15

12 13

9 10 11

8

7

6

5

4

3

2

1

0

-1

-2

-3

-4

-5

-6

-7

-8

0.00%

-9

-1 0

0

Air Temperature [Deg C]

Figure 6-10 - SVT Ambient Air Temperatures (1996 to 2005 inclusive)

The design air temperature for Air Coolers will be taken to be a maximum of 19°C, in accordance with Ref [33]. Relative humidity Relative humidity will be taken to be a minimum of 50% and a maximum of 100%, average 80%, based on Ref [31] and Ref [33].



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Barometric pressure Barometric pressures based on Ref [32] are given below: Average barometric pressure Maximum design barometric pressure Minimum design barometric pressure

: : :

1010 mbar 1055 mbar 925 mbar

Wind Wind speeds at a height of 10m based on Ref [32] are given below: Mean wind speed Maximum wind speed (1 hour) Maximum wind speed (3 sec gust)

: : :

9 m/sec 39 m/sec 58 m/sec

Direction % of time blowing in each quadrant is given below: North-East

North-West

South-East

South-West

18

25

25

32

% of time

Rainfall The closest gauging station to the onshore pipeline route is at Weisdale, which has records back to 2002. The monthly average rainfall for the area has been calculated from the daily rainfall data collected at Weisdale Gauging Station (Ref [30]) and is shown in the table below:

Average Rainfall (mm) - Weisdale Jan

Feb

Mar

April

May

June

July

Aug

Sept

Oct

Nov

Dec

144

84

71

42

47

67

58

82

110

126

132

125

Table 6-19 - Average Rainfall

Snowfall Maximal snow accumulation based on Ref [32] is 279mm. Snow season is from November to March, typically.



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6.7.2

Hydrology

Peak runoff rates have been estimated for Crooksetter Burn and the Houb (SVT) using the FEHCD catchment characteristics and the rainfall runoff method for a range of return periods. Flow statistics (Ref [30]) for the catchments discussed above are provided hereafter. The Q95 is the flow exceeded 95% of the time, as observed over a 10-day period, and is a measure of low flow.

Area (km2)

Mean Daily Flow (m3/s)

Q95 (10) (m3/s)

Crooksetter Burn

2.78

0.099

The Houb (SVT)

1.00

0.035

Catchment

Estimated Peak Runoff (m3/s) for each return period (years) 2

5

10

25

50

100

0.00646

1.77

2.211

2.562

3.091

3.555

4.087

0.00138

0.87

1.110

1.306

1.606

1.872

2.182

Table 6-20 - Estimated Peak Runoffs

6.7.3

Environmentally Sensitive Areas

Reference shall be made to Ref [30] Section 1.1.5 (Tables 2-2 to 2-5) for the review of existing sources of information and for an overview of the existing understanding of the environment in the area. There are a number of designated areas near to or through which the pipeline route passes, with others lying near the edge of the study area. These number three Special Areas of Conservation (SAC), one of which is also a Special Protection Area (SPA) and RAMSAR site, and two Sites of Special Scientific Interest (SSSI). Refer to Ref [34]. These three sites are: • • •

Ronas Hill SAC/SPA/RAMSAR site Clothister Hill Quarry SSSI Ayres of Swinister SSSI



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6.8

SURVEY DATA ALONG FLOWLINES/PIPELINE ROUTES

6.8.1

Proposed Routes

Offshore Section of Production Flowlines The Production Flowlines run from Tormore to Laggan, and then South-East to follow the route corridor of the existing West of Shetland and Clair pipelines. They cross the WoS and Clair pipelines North of Shetland, and then run parallel about 100m to their West through Yell Sound, to make a landfall at Orka Voe, adjacent to SVT. The proposed Production Flowlines route starts at a depth of 610 m LAT at Tormore, goes through Laggan and ascends rapidly up the continental slope to around 100 m LAT before rising gradually into Yell Sound and landfall.

Figure 6-11 - Offshore Route for Production Flowlines

Onshore Section of Production Flowlines The offshore flowlines come onshore from Yell Sound at the landfall within Orka Voe, to the north of the existing SVT site and transports the production fluid to the GPP. The proposed landfall is approximately 100m to the west of the existing landfall for the 20” East of Shetland (EOS) Gas Pipeline, 20” West of Shetland (WOS) Gas Pipeline and the 22” Clair Oil Pipeline. The landfall itself is within SVT property, fenced off from public access; however it is outside the main SVT operational site boundary.



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As the ground from the landfall into SVT is made up of reclaimed materials, ground conditions are unknown; however the precedent of existing pipeline construction implies that conditions are suitable for the flowlines route. It is known that the middle of the reclaimed area is flooded and may contain contaminated material; however this is not certain. From the landfall the flowlines route turns east towards the existing BP pipelines, following them until the existing and new flowlines turn in a southerly direction. The flowlines continue south, running in parallel to the BP pipelines, to the west of the SVT security road. After approximately 300m the flowlines cross the main SVT operational site boundary fence, an SVT security patrol road and beneath the 22” Clair Pipeline, which turns to the west. The flowlines route continues in parallel with the 20” WOS and EOS pipelines, until the flowlines route turns east, having to cross beneath the existing BP lines into the proposed GPP location. The flowline route continues along the northern edge of the GPP, between the GPP site road and the boundary fence. The pipeline then leaves the ground to enter the pig trap installation.

The total length of each of the parallel onshore flowlines is approximately 1.5km, depending on the final route selection and the location of the route and pipeline valves within the GPP

Figure 6-12 - Onshore Route from Orka Voe to GPP (Production Flowlines)

Onshore Section of Export Pipeline The onshore export pipeline transports gas from the outlet of the GPP to the tie-in connection with the offshore export pipeline at Firths Voe to the east. The export pipeline exits the GPP southwards, maintaining a suitable distance from the GPP administration building, and runs parallel with the GPP access roadway for approximately 1km. The peat depth in this area is anticipated to be as little as 0.5m or in excess of 4.0m. The pipeline then leaves the GPP access roadway as it continues to head south, downhill towards the B9076.



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Approximately 20m before reaching the B9076, the export route crosses beneath some overhead power lines at an angle of 70degrees. The export pipeline will then cross the existing 36” Brent oil pipeline and the 36” Ninian Oil Pipeline before crossing the B9076. The two existing 36” pipelines run parallel with and to the north of the B9076. The peat depth indicates that it may only be 0.5m at this location. After the B9076, the route turns south east to follow the road for approximately 2.0km until the road starts to turn north east, where the export route separates from the road. From here the export pipeline route runs parallel with the existing BP 36” pipelines that also cross the road. The peat depth in this area is anticipated to be as little as 0.5m or in excess of 4.0m. Approximately, 100m after the separation from the B9076, the 36” Ninian pipeline turns south requiring the proposed export pipeline route to cross it. Approximately 400m after the Ninian crossing, the Export Pipeline will pass beneath a series of overhead power lines before crossing the A968. From the road crossing, the route falls steeply to the landfall area within approximately 50m, into Firths Voe. The landfall area is very wet and the peat depth here is considered to be only 0.5m. To the east of the A968 will be a landfall valve installation, which will require a site of approximately 25m x 30m to access the buried valve. This will also require a short access road from the A968 to access the installation. The total length of the onshore export pipeline is approximately 5.6km.

Figure 6-13 - Onshore Route from GPP to Firths Voe (Export Pipeline)



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Offshore Section of Export Pipeline The processed gas is exported through a Gas Export Pipeline which runs 228.5km offshore from the landfall at Firths Voe to two tie-in points on the existing FUKA Pipeline, both of which are located at MCP01. Gas is then exported to St. Fergus Terminal through the FUKA Pipeline.

Figure 6-14 - Offshore Route for Export Pipeline



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6.8.2

Bathymetrical Data

Bathymetrical survey data were gathered in 2007 by Fugro along the proposed flowlines/pipeline routes. Reference shall be made to Ref [12] and Ref [13]. From Tormore to Laggan The seabed profile along the Production Flowlines route from Tormore to Laggan is presented in the following figure:

-580

Water Depth (m)

-590 -600 -610 -620 -630 -640 -650 0

2

4

6

8

10

12

14

16

KP (km)

Figure 6-15 - Offshore Route Seabed Profile from Tormore to Laggan

From Laggan to Beach Valve The seabed profile along the proposed Production Flowlines route from Laggan to the beach valve close to GPP is provided hereafter. The proposed route starts at a depth of 600 m LAT and ascends rapidly up the continental slope to around 100 m LAT before rising gradually into Yell Sound and landfall.



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Figure 6-16 - Offshore Route Seabed Profile from Laggan to Beach Valve

From Firths Voe to MCP01 The seabed profile along the proposed Export Pipeline route from Firths Voe to tie-in location at MCP01 is provided hereafter. KP (m) 0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

220,000

0

Firths Voe from SVT Plant 20

Water depth (m)

40

60

80

MPC01 to FUKA system

100

120

140

Figure 6-17 - Offshore Route Seabed Profile from Firths Voe to MCP01



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6.8.3

Geophysical and Geotechnical Data

Geophysical and geotechnical survey data were gathered in 2007 by Fugro along the proposed flowlines/pipeline routes. Reference shall be made to Ref [12] for the offshore Production Flowlines and for the MEG Line between Laggan and SVT. Reference shall be made to Ref [13] for the offshore Export Pipeline from SVT to MCP01. Geotechnical survey data were gathered in 2006 by Fugro at Laggan well location. Reference shall be made to Ref [22], Ref [23], Ref [24], Ref [25] and Ref [26]. Geotechnical survey data were gathered in 2009 by Fugro at Tormore well location. Reference shall be made to Ref [27]. 6.9

SURVEY DATA AT SVT LOCATION

A partial soils survey of the proposed location for the new processing plant was carried out during 2007 (Ref [14]). The available data to date does not indicate the depth at which the possible hard granite layer commences. Therefore, it is assumed that compact sub soils are present at depths varying from 5m to 0.3m. 6.10

FISHING ACTIVITIES DATA

Fishing activities data have been supplied by AURORA Environmental Ltd (Ref [15]); this was sourced from the National Fishing Authorities who have vessels active in the Northern North Sea and the Scottish Executive fisheries surveillance data. AURORA have sorted and complied the data for each of the relevant ICES rectangles, International Council for the Exploration of the Sea, so that it can be read by area, gear type and intensity in terms of days fished during the time period of the study. For full detailed information and data, reference shall be made to Ref [15]. Subsea structures shall be designed to be overtrawlable, hence no snag loads are to be considered. However, trawl gear impact, trawl gear pull-over and trawl net friction shall be considered. Only otter trawls (demersal) with no clamp weight shall be considered. Pelagic trawls and beam trawls are not considered as their percentage of occurrence is small, coupled with the proposed exclusion zone.



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7.

FIELD DEVELOPMENT

7.1

PRODUCTION STRATEGY

The production strategy is pressure depletion. Well placement and planning will be key to mitigate against possible reservoir compartmentalisation. Initially the wellhead chokes will constrain the wells to the peak gas rate but once the field comes off plateau the wellhead chokes will be fully open. Arrival pressure at the processing facilities will be reduced at a certain point in field life, in order to maximise reserves recovery. Regular round-trip pigging will be required in order to remove wax deposit during early life and liquids from the flowlines in late field life. Subsea gas compression will be considered in the future to reduce system back pressure and increase ultimate recovery. Allowances shall therefore be made in the design for tie-in of possible sub-sea facilities. 7.2

AVAILABILITY TARGETS

The target system availability (global efficiency) including wells, subsea, pipelines, GPP, export route, etc, is 90%. Availability targets shall be further developed for each part of the system, through RAM modelling and optimisation. 7.3

DESIGN CAPACITIES

The Production Flowlines from the field to the processing facilities will be designed for a wet gas flow of 500 MMSCFD plus associated condensate. Design Capacities for the processing facilities at the GPP are as follows: • • •

500 MMSCFD peak gas export Condensate rate calculated based upon the gas rate given above, and composition given in Section 6.5.1, with an appropriate margin added. 2,000 BPD Formation Water, plus condensed water (845 BPD, Ref [44])

The gas export pipeline will be designed for an entry gas flowrate of 665 MMSCFD. This flowrate includes an allowance of 165 MMSCFD for additional 3rd party gas. The hydrate inhibitor pipeline shall be designed to supply sufficient hydrate inhibitor for a formation water rate of 3000 bpd, plus condensed water. 7.4

DESIGN LIFE

Design life for Laggan-Tormore project facilities is 30 years. Design life for Laggan-Tormore wells is 30 years.



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8.

SUBSEA PRODUCTION SYSTEMS

8.1

SUBSEA WELLS

The planned drilling program is as follows: •

For Laggan : 4 wells drilled from a six slot template, plus one re-entry of an off-template well tied-back to the main template (Laggan Appraisal well 206/1a-4z)

•

For Tormore : 2 wells drilled from a six slot template, plus one re-entry of an off-template well tied-back to the main template (Tormore Exploration well 205/4a-1)

8.1.1

Casing Design

The casing design has not yet been finalised by COMPANY, however it is expected to be very similar to the existing 4Z well. The well design incorporates a 36” x 30” conductor string and a 20” surface casing string being set vertically above the kick-off point. The 13 3/8” casing will be set just above the Flett formation and the 10 ¾” x 9 5/8” string set at the top of the Vaila reservoir sands. The table below gives an overview of the anticipated weights, grades and connections for the strings to be used on the wells. Casing OD (in)

Weight (ppf)

Depth (m) TVDSS

Grade

Connection

Notes

36 36 x 30 30 30 20 20 20 13 3/8 10 3/4 x 9 5/8 7 (or ESS)

533 (1 ¼” WT) 533 x 310 310 (1” WT) 310 166 (0.812” WT) 129 (0.625” WT) 129 68 53.5 32

600 - 690

X56 X56 x X52 X52 X52 X56 X56 X56 P110 L80 L80

RL-4H

2 joints Swage joint 2 x Intermediate joints Shoe joint Wellhead joint Intermediate joints Shoe joint

690 – 1,300

1,300 – 2,475 2,475 – 3,615 3,615 – 3,770

TBA

New Vam New Vam New Vam

ESS looks most likely to be used

Table 8-01 - Casing Description

8.1.2

Completion Design

A review of the optimum tubing diameter was carried out during the Laggan Pre-Project, taking into account the following parameters: well count, number of horizontal wells, tubing diameter, compartmentalisation, segment transmissibility and geo-model. It was found that the discounted reserves are optimised by the use of 5.5” OD tubing, and this decision was found to be robust to compartmentalisation, segment transmissibility, geo-model and well count. Down hole chemical injection mandrel is required for all Tormore wells.



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8.1.3

Upper Completion

Tubing Hanger The subsea tubing hanger must be able to accommodate the following penetrations: • • •

2 electrical penetrators for down hole gauges (¼”) 2 hydraulic control lines for the TRSSSV (¼”) 1 chemical injection (optional dependant of chemistry study, ¼”)

Cable and control line protectors are required at each coupling and above and below each sub assembly where applicable Down Hole Safety Valve A tubing retrievable down hole safety valve is recommended for the subsea deployment. TRSSSV will be run with dual ¼” control line and integral communication nipple. The second control line is to provide redundancy and to allow circuit flushing. Recommended Nipple profile size is 4.562”. In all the wells except for the 206/1-4az (W01) well it is planned to run 1000m of 10-3/4” casing to accommodate the TRSSSV. For the 206/1-4az (W01) well 9-5/8” casing exists to the hanger. Therefore W01 will require a slim TRSSSV. The setting depth of the TRSSSV shall be 250m below sea bed in accordance with Ref [21]. The max WHP being around 385 bar and the water depth being 600m, a standard TRSSSV will require to have around 610 bar umbilical pressure to operate the valve. Initial studies indicate a standard TRSSSV should be used if possible. However alternatives such as using nitrogen precharged chambers, subsea intensifiers, or the Halliburton Depth Star should be examined. Control Line The hydraulic control line fittings must be auto-lock ones with metal to metal seal. The hydraulic control line is to be made in Inconel 825 steel, preferably protected in a plastic flat pack, clamped on the tubing with steel protectors. Hydraulic control fluid must be selected accordingly to well temperature, the same fluid must be used in plant for acceptance tests and on the field to avoid mixture of non compatible fluids. For subsea it is recommended to use a water based fluid. Two hydraulic lines will be used so that any ingress of gas can be flushed out of the system. Permanent Down Hole Gauges Given the limited opportunities for regular well testing and logging campaigns, regular quality data shall be collected by permanent down-hole measurements. 8.1.4

Subsea Wellhead

A standard 18 ¾” subsea wellhead fully compatible with the selected template and Xmas tree (XT) shall be selected. The pressure rating of the wellhead system is minimum 690 bar.



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8.2

CHRISTMAS TREE

The main characteristics of the XT are the following: Nominal bore Pressure rating

: :

5 1/8” 690 bar

MEG will be injected between PMV and PWV as well as downstream of PWV 8.3

SUBSEA CONTROL SYSTEMS

The following main requirements shall apply to the design of the subsea control systems: • • • • • • • • • •

•

Control to be linked to ICSS system Fibre optic primary communication Single phase power transmission Electro-hydraulic umbilical with fibre optic Dual redundant electrical power and fibre optic communication systems Communication channels to have spare capacity for future intelligent instrumentation Additional fibre optic spare channels to be provided Base Case max 20 wells to allow for future expansion Open loop (vent to sea) hydraulic system with water glycol based hydraulic fluid Control Umbilical requirements: 2 x HP Hydraulic 2 x LP Hydraulic 1 x Chemical Injection (Scale Inhibitor) 5 x Chemical Injection (Wax Inhibitor) 1 x Chemical Injection (Corrosion Inhibitor) 1 x Chemical Spare 4 x Power quads (based on a Single Umbilical concept) 3 x Fibre optic signal bundles Subsea HIPS will not be considered.

A Subsea Router Module (SRM) will be used to switch and distribute the optical fibre system. The SRM will be used to convert the optical fibre system to an electrical comms system for distribution to all the Subsea Electronic Modules (SEMs). To maintain standardisation a Manifold Subsea Control Module (MSCM) will be considered to gather subsea data and operate any Chemical Injection Valves (CIVs) not operated in the XT SCM. 8.4

SUBSEA METERING

One off replaceable Wet gas Flowmeter per well shall be installed. HOLD – Metering and allocation study ongoing to confirm subsea metering requirements



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8.5

TEMPLATE AND MANIFOLD

The Laggan and Tormore templates are 6-well-slot templates. The manifold shall be a replaceable unit. Subsea systems shall be overtrawlable/fishing ‘friendly’. The manifold design pressure and design temperature are: Design pressure Design temperature

: :

622 barg [HOLD] -18 °C [HOLD] / +121 °C

The headers and branches diameters are: Production header : Production branches : MEG header MEG branches 8.6

242.9 mm ID – 10” nominal OD 130.7 mm ID – 6“ nominal OD

: :

87.3 mm ID – 4” nominal OD 33.3 mm ID – 2” nominal OD

SUBSEA CHEMICAL INJECTION REQUIREMENTS

The subsea chemical injection design requirements are tabulated here below. Reference can be made to Ref [43]. Chemical

Injection Point

Design Injection Rate (litres/hour)

Pressure @ Injection Point (barg)

Wax Inhibitor

On manifold header downstream of well inlets

99 *

300

Scale Inhibitor

Down hole and upstream of PWV

0.9 * (undiluted)

380

Corrosion Inhibitor

Upstream of PWV

18 *

300

Bulk Chemical Spare

-

-

-

Hydrate Inhibitor (MEG) via discrete 8” line

On tree, upstream and downstream of PWV On manifold header, upstream of well inlets

70,800 [HOLD]

380

* Injection rates based on Ref [43] + 50% margin

Table 8-02 - Chemical Injection Design Requirements

8.7

UMBILICAL SERVICES DISTRIBUTION

The umbilical will be installed complete with an Umbilical End Termination (UET). The UET will contain all the required connection systems for connection to a Subsea Distribution Unit (SDU). A SDU shall be considered to minimise the distribution systems on the manifold and to provide an easily retrievable system for IMR.



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9.

UMBILICAL

9.1

LAYOUT

9.1.1

Base Case

The schematic hereafter presents the umbilical layout base case:

TORMORE

17.4 km

LAGGAN

Production line MEG line Umbilical Joint

In-line connection 127.3 km Beach connection

2 km Gas Processing Plant

Figure 9-1 - Umbilical Layout Base Case

Its main features are: − − −

A 2 km onshore umbilical from GPP to the beach connection A 127.4 km umbilical from the beach connection to Laggan (The extra 100 m comes from the over-length required for the subsea joint) A 17.4 km umbilical from Laggan to Tormore

Due to the projected weight of the main umbilical from beach to Laggan, it will most likely be composed of two shorter and lighter sections linked by a subsea joint. This subsea joint will be located in relatively shallow water (ca 120 m water depth) to allow easier intervention.



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9.1.2

Alternative No 1

The schematic hereafter presents the umbilical layout alternative no 1:

TORMORE

17.4 km

LAGGAN

Production line MEG line Hydraulic/chemical Umbilical

127.3 km Beach connection

Electrical/optical Umbilical

2 km Gas Processing Plant

Laggan-Tormore Umbilical Joint Figure 9-2 - Umbilical Layout Alternative No 1

Its main features are: − − − −

A 2 km onshore umbilical from GPP to the beach connection A 127.3 km umbilical from the beach connection to Laggan including the electrical and optical components A 127.3 km umbilical from the beach connection to Laggan including the hydraulic control and chemicals injection tubes A 17.4 km umbilical from Laggan to Tormore

The projected weight of the umbilicals from beach to Laggan should enable them to be manufactured and installed as a single length.



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9.1.3

Alternative No 2

The schematic hereafter presents the umbilical layout alternative no 2:

TORMORE

17.4 km

LAGGAN

Production line MEG line + Wax Inhibitor Piggy-back

127.3 km

Umbilical Joint

2 km

Beach connection

Gas Processing Plant

Figure 9-3 - Umbilical Layout Alternative No 2

Its main features are: − − − − −

A 2 km onshore umbilical from GPP to the beach connection A 127.3 km umbilical from the beach connection to Laggan A 144.7 km umbilical from the beach connection to Tormore A 17.4 km umbilical from Laggan to Tormore An additional piggy-back line on the 8” MEG line for the wax inhibitor

The projected weight of the umbilicals from beach to Laggan and to Tormore should enable them to be manufactured and installed as a single length, provided that the wax inhibitor is injected through a discrete line outside the umbilical.



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9.2

DESIGN REQUIREMENTS

9.2.1

Temperature Range

The operating temperature range to be considered in the design is -15ºC / +40ºC in accordance with ISO 13628-5. The design temperature range is otherwise -20ºC / +50ºC. 9.2.2

Tubes

The preferred solution is steel tubes. However Contractors will be allowed to propose thermoplastic tubes if they can demonstrate that these bring benefits to the project. 9.2.3

Power

The base case is a single phase power system using 3 kV rated 16 mm² quads. 25 mm² quads may however be required depending on the SPS bidders proposals. 9.2.4

Communication

Optical fibres shall be used for communication. 9.3

INSTALLATION AND PROTECTION

The umbilical will require protection against trawling activities and dropped objects. In the vicinity of the templates, the umbilical and its appurtenances (e.g. termination heads) will be protected by the templates’ protection structures. On the umbilical route, the umbilical will be trenched and buried. Rock dumping will be used when trenching is not possible. The umbilical will be protected against rock dumping operations. The type of protection is left open. The umbilical manufacturer may or may not propose armouring. The subsea joint for the layout base case will require a dedicated protection structure and overlength will be allocated to allow retrieval of the joint to the surface if necessary.



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10.

PRODUCTION FLOWLINES

10.1

OFFSHORE FLOWLINES

10.1.1 Design Data The following data are obtained from the Project Statement of Requirements (SoR) Revision 0-iii (Ref [1]) and Pre-Project Update 2008 Final Report (Ref [18]), unless otherwise specified. Parameter Size Steel Grade Design Pressure Min/Max Design Temperature (°C) Service Length (approx.)

Design Life Corrosion Allowance

Production Flowline 18” ND (see Note 1) DNV 450 380 barg @ Laggan / Tormore -18/+96 (Tormore – KP30) -18/Ambient (KP30 – GPP) Non-sour (Severity 0) (see Note 2) 16 km (Tormore – Laggan) 125 km (Laggan – Landfall) 1 km (Onshore: Landfall - GPP) 30 years 5 mm (Tormore – Laggan & first 10 km from Laggan) 3 mm (remainder)

Table 10-1 - Production Flowline Design Data Note 1: Internal diameter constant Note 2: Project may revert to NACE MR 0175 / ISO 15156 intermediate level requirements (Sour Service Severity 2) [HOLD]

Where required, pipelines will be concrete coated to ensure adequate stability on the seabed during installation and operation. Parameter Production Spool Size Steel Grade Design Pressure Min/Max Design Temperature (°C)

Spools 10” ND DNV 22Cr Duplex 380 barg @ Laggan / Tormore -18/121

Table 10-2 - SPS to Production Flowline Spool Design Data

Tie-in

KP mark from Tormore

HTT #1 (Tormore) HTT #2 (Laggan) HTT #3 HTT #4 HTT #5 HTT #6 (Mouth of Yell Sound)

1.5 25 36 59 77 105

Table 10-3 - Location of Production Flowline Hot Tap Tees (HTT) for Third Party Tie-in



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10.1.2 Material Data All flowlines/spools will be constructed of Carbon Steel or Duplex, which main properties are summarised in Table 10-4 below. Note that the Specified Minimum Yield Stress (SMYS) and Specified Minimum Tensile Strength (SMTS) values must be de-rated as appropriate for the temperatures of the development (refer to DNV-OS-F101 Section 5 Figure 2).

Steel Grade

SMYS (MPa)

SMTS (MPa)

450 450

535 620

DNV 450 C-Mn Steel DNV 22Cr Duplex

Table 10-4 - Material Mechanical Properties

Property Young’s Modulus Poisson’s Ratio Thermal Expansion Coeff. Density

Unit

DNV 450 C-Mn

DNV 22Cr Duplex

GPa 10-5/ °C

207 0.3 1.17

190 0.3 1.42

kg/m3

7850

7833

Table 10-5 - Typical Steel Properties

The surface roughnesses to be considered in the design are presented in the table below (extracted from Ref [11]). Surface Material

Surface Roughness k (m) -5

Steel, New Uncoated Steel, Painted Steel, Highly Corroded Concrete Marine Growth

5 x 10 -6 5 x 10 -3 3 x 10 -3 3 x 10 -3 -2 5 x 10 - 5 x 10 Table 10-6 - Surface Roughness

10.1.3 Crossing Data The following crossing data are extracted from Fugro survey report Ref [12] (Drawing no 9049-YellAL21-1K, Rev1).

Type Pipeline

Pipeline

Crossing Identification PL1844 22” Oil Export Clair to Sullom Voe (BP) PL1761 20” Gas Export Foinaven to Sullom Voe (BP)

KP Mark

Crossing Size/ Angle

111.6

111.9

Crossing Co-ordinate (m) Easting

Northing

22” OD [TBC] / 46.4

595 150.7

6 734 262.7

20” OD [TBC] / 45.2

595 035.0

6 733 994.5

Comment Angle and location are preliminary Angle and location are preliminary

Table 10-7 - Crossing Information for 18” Production Flowlines and MEG Line



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10.2

ONSHORE FLOWLINES

10.2.1 Design Conditions The flowlines shall be designed in accordance with the DNV-OS-F101 standard, as an extension to the offshore pipelines. The proposed minimum depth of cover for the flowlines is to be 1.2m. The suitability of the ground to achieve this required cover can only be ascertained by a geotechnical survey, which should include ground probes and trial excavations. With the exception of any personnel at the existing SVT or proposed GPP locations, it is noted that the area is sparsely populated with no occupied dwellings close to the pipeline route. In accordance with DNV requirements, the route is considered to be a Medium to High Risk and will be designed to the same requirements as the foreshore flowlines. The linepipe materials are to be manufactured in accordance with DNV-OS-F101, which shall be of an L450 grade. The end preparation weld bevel shall be suitable for the method of pipeline welding. Presently the service is assumed to be sweet service; however to allow for the possibility of sour service, additional sour service data sheets are required for pipeline components. All connections to the pipelines shall be fully welded, including the first valve connection, the minimum size of which shall be 2”, after which connections shall be flanged. Therefore any line valves shall be fully welded and shall be buried. As the valves will require actuation, it is proposed that the valve actuation and valve maintenance connections shall be above the ground any necessary extensions and valve assemblies. Double Block and Bleed (DBB) facilities shall be required for all connections to the pipelines with any screwed instrument connections being separated from the pipeline by a DBB facility. 10.2.2 Valve Installation The flowlines require a beach valve installation. The location of this beach valve is within the GPP perimeter fence. 10.2.3 Pigging Facilities The flowlines shall be fully piggable, suitable for the passage of commercially available spheres, pig, scrapers and inspection tools. Permanent pigging facilities shall be incorporated into the design for the GPP on both flowlines, allowing pigging operations that can clean and de-wax the flowlines as required. The flowlines shall be designed with a constant internal diameter (ID) which shall be based on the ID of the offshore flowline. All in-line equipment shall therefore be suitable for pigging. Valves shall be full bore valves and tees or connections greater than 40% of the pipeline ID shall incorporate pigging bars, as necessary.



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The minimum bend radius shall be equivalent to five (5) times the pipeline diameter (5D) which shall conform to the ovality and diameter restrictions identified within DNV-OS-F101. Minor variations in elevation and direction shall be achieved by the natural flexing of the pipeline as it is laid, with angles up to approximately 5 degrees achieved by bending the pipeline, where the geometry requirements shall be maintained. Tighter bends shall be achieved by manufactured hot formed pipeline bends. 10.2.4 Construction Requirements As the flowlines are predominately within the SVT jurisdiction, the construction must conform to any permitting procedures required by the SVT Operator. Presently the only access to the landfall and flowline route is via the SVT terminal and will require designated routes through the operational site. The flowlines shall be constructed by welding together individual linepipe lengths above the ground with each girth weld being 100% radiographically inspected before being coated and buried. The reinstated ground shall be replaced to an as found condition, with the route being identified with route markers, and buried warning tape. Construction activities shall include any protection required for the working near or crossing of the existing pipelines, utilities or services. 10.2.5 Crossings It is customary for all new pipelines to cross beneath any existing pipelines, utilities and services and the crossing design will require approvals with the owner of the existing pipeline owner. This shall include the requirement to maintain the support around the existing buried pipelines and suitable reinstatement. As the road crossings are terminal roads which are predominantly used for security patrol, the method of construction shall be by open cut construction. In addition to the approximate locations of the roads and pipeline crossings identified, a number of buried cable markers were identified around the proposed route location. Definitive locations of all pipelines and services shall be identified by a full topographical survey. 10.2.6 Corrosion Coatings There is no requirement for internal corrosion coating or flow coating for the flowlines. The external coating of the linepipe shall be factory applied, which shall be the same external coating as the offshore pipeline. A lower grade coating may be possible; however it is not considered worthwhile for the amount of onshore pipeline required. Fabricated girth welds shall be coated using heat shrink sleeves that are compatible with the factory applied linepipe coating. Each completed flowline shall be 100% inspected for coating faults prior to burial.



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10.2.7 Cathodic Protection The flowlines shall also be protected by the provision of a Cathodic Protection (CP) system. The CP system shall be applied and shall be compatible with the offshore CP system. To isolate the buried pipeline CP system from the above ground pipework within the GPP, an Isolation Joint (IJ) will be required at the pipeline termination, as the pipeline leaves the ground. The presence of the applied CP system will require cross bonding with each other, the MEG pipeline and the existing pipeline systems and interaction tests undertaken, ensuring that the systems do not have a detrimental effect on each other. 10.2.8 Testing The flowlines shall be hydrostatically tested to achieve a minimum of 90% of the specified minimum yield stress in the pipe wall for a period of 24hrs. Weather windows and environmental restrictions may cause difficulty in synchronising the onshore flowlines construction work with the offshore and GPP construction activities. The onshore flowlines will therefore be constructed and hydrostatically tested separately. This will allow the Contractor to complete all the onshore flowlines sections as efficiently as possible, leaving the tie-in of the onshore sections to be completed as the offshore flowlines are available. The complete flowlines will then undergo a hydrostatic strength test, removing any requirement for golden welds at the landfall tie-in locations. The water used for the hydrostatic test will require treatment with biocides and oxygen scavengers. All fabricated assemblies shall be fully tested prior to being introduced into the pipeline, including pig traps, IJ’s and valves. 10.2.9 Integrity Monitoring The continued use of the flowlines will be dependent on the integrity monitoring of the facility during operation, including testing of the CP system and on-line inspection with the use of smart pigs to identify any metal losses, cracks or other faults that may occur during the design life of the flowlines.



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11.

GAS PROCESSING PLANT

11.1

INTRODUCTION

The Gas Processing Plant (GPP) will be located north of the existing Sullom Voe oil Terminal (SVT), which is operated by BP. The well streams will be processed at the GPP in order to produce gas of export quality suitable for transportation via the FUKA Pipeline which delivers into St. Fergus. Live condensate will also be produced but then commingled with existing BP SVT crude oil. Actually the hydrocarbon export routes are as follows: •

Gas exported via a new pipeline which ties in at MCP01 to the FUKA Pipeline for onwards transportation to St Fergus

•

Live condensate commingled with existing BP SVT crude oil, prior to stabilisation and export with SVT crude

Aqueous streams arriving at GPP contain MEG and shall be separated and treated to recover the MEG. 11.2

OPERATING AND DESIGN CAPACITIES

The GPP facilities will be designed to export 500 MMSCFD of dry gas into the Export Pipeline. The Export Pipeline will be designed for an additional 165 MMSCFD of dry gas, which is an allowance for future third party operators. Design margins for the GPP will be in accordance with Total general specification GS-EP-ECP103. 11.3

PROCESSING FACILITIES

Laggan and Tormore well fluids arrive via two 18” Production Flowlines, each of which has a dedicated pig launcher/ receiver, onshore chokes and a slugcatcher at GPP. The slug catchers allow for bulk liquids separation and shall be interconnected. Gas from the slugcatcher outlet manifold undergoes a further two-phase separation in a production separator before being compressed, dehydrated to meet the FUKA Pipeline specification for export gas and fiscally metered. The Export Pipeline is equipped with a dedicated HIPS system, to ensure that the FUKA Pipeline cannot be overpressured by Laggan-Tormore, and has connections for a temporary pig trap. Condensate and water from the slugcatcher liquid outlets are separately filtered and metered before being recombined, heated (to break emulsions) and passed via a three-phase separator and liquid coalescer. Associated LP gas is compressed and routed back to the production separator. The separated live condensate is pumped and metered before being routed to the BP SVT facility for stabilisation and commingling with the Brent-Ninian crude. The aqueous streams (water and MEG) are passed through hydrocyclones to allow for further separation of condensate. The rich MEG is then regenerated to produce lean MEG for injection while the water stream is combined with oil contaminated open drains and routed for effluent water treatment.



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Effluent water shall be treated within the GPP and disposed of via an outfall pipe. The effluent water comprises produced water and oil contaminated open drains effluent which shall be cleaned up to less than 5 mg/l oil in water concentration to meet regulatory discharge limits. The GPP will also provide subsea facilities with services such as control, power and chemical injection. 11.4

SIMULATION BASIS

The first preference shall be to use the SRK (Soave Redlich Kwong) equation of state, because the Laggan fluid model has been “tuned” on this basis. However Peng Robinson may be used in certain circumstances, where this approach is considered to provide more accurate results. 11.5

PRODUCT SPECIFICATIONS

11.5.1 Gas The Gas Export route is a new build line to a tie-in on the FUKA pipeline at MCP01, thence to St Fergus. Gas entering this Export Pipeline will be conditioned to meet the FUKA ‘pipeline specification’. The FUKA pipeline entry specification is given in table below: Frigg UK Pipeline Entry Specification Gas Cricondenbar Pressure Temperature H2O Content H2S Content Total Sulphur CO2 Content O2 Content Mercury Mercaptans Methanol

max min/max min/max max max max max max max max max

106 bara Note 1 110 to 149.9 bara Note 2 -5 oC to 55 oC 24 kg/106 SCM 2.6 ppm (v) 15 ppm (v) as H2S 3.84 mol % 7.5 ppm (v) 0.01 g/SCM 1.0 ppm(v) 20 ppm(v)

Table 11-1 - Entry Specification for FRIGG UK Area Pipeline (per Ref [1]) Note 1: As calculated by the Peng Robinson equation of state or such alternative method as may be agreed from time to time. Note 2: As required from time to time by Total Note 3: Gas shall be commercially free from objectionable odours and from materials and dust or other solid or fluid matter, waxes, gums and gum forming constituents which might cause injury to, or interference with, the proper operation of the lines, meters, regulators or other appliances or facilities though which it flows. Note 4: No chemical or other substances may be introduced by any means into the Gas, which will be carried over into the FTS without the prior agreement of Total, such agreement not to be unreasonably withheld.



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11.5.2 Condensate Live condensate is to be exported to the existing BP SVT facility where it will be stabilised. The stabilised condensate specification is outlined below (Ref [16]): Item

Value Description o

True Vapour Pressure (TVP)

• Maximum of 220psia at 100 F

Entry Temperature

• Maximum of 70 C

Entry Pressure

• Must not exceed 40barg

Sediment and Water

• Maximum of 2% by volume, provided that New Entrant Pipeline Liquids are essentially free of sediments • Sediment not to exceed 0.2% by volume • Produced Water shall be made compatible (at the cost of the new entrant) with water produced by other NPS users

pH

• pH value to remain within the following limits (7
Salt Content

• Maximum of 1,500 milligrams per litre

Viscosity

• Maximum of 15 centistokes at 4oC

Hydrogen Sulphide

• The H2S content of Crude Oils shall be such that the H2S in the fuel gas evolved from the SVT De-ethaniser shall not exceed 200ppm vol. • Maximum H2S level of incoming Pipeline Liquids shall not exceed 2.1mg/l

Carbon Dioxide

• Maximum of 0.25% by weight

Carbonyl Sulphide

• Maximum of 0.02ppm by weight

Acidity

• The total acidity number shall be no greater than 0.05mg of potassium hydroxide per gram of stabilised Pipeline Liquids

Nitrogen

• Maximum of 0.2% mol.

Mercaptans

• Maximum of 0.1ppm by weight as sulphur of volatile mercaptans

Metal Content

• Vanadium plus nickel shall not exceed 5ppm by weight

Emulsions

• When new Entrant Pipeline Liquids are mixed with those of other NPS users, they should not form emulsions which are stable at temperature at or above 40oC and pressure above one atmosphere.

Methanol

• Methanol to be reported if present, and to be no greater than 10ppm.

Mercury

• Maximum of 2pbb as volatile organic or metallic mercury

Acidity

• Total acid number shall be no greater than 0.05mg of potassium hydroxide per gram of liquids

Salt Content

• Maximum of 1,400 milligrams per litre of sodium, calcium and magnesium chlorides in solution

Oxygenates / Alcohol

• Maximum of 10ppm by weight Methanol. No other alcohols other than oxygenates shall be permitted.

General

• No chemical additives or processing material shall be present in liquids either directly or through processing without prior consultation and agreement with the Terminal Operator. Liquids to be free of undesirable substances or material (including, without limitation, radioactive materials)

o

Table 11-2 - Stabilised Condensate Specification



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11.6

ENVIRONMENTAL REQUIREMENTS

11.6.1 Water Discharge Requirements The effluent water from the GPP comprises treated produced water and treated oil contaminated open drainage. The treated effluent water will be required to meet the following discharge limits (Ref [17]): Substance

Range (mg/l) (Note 1)

Total hydrocarbon oil content (IR Method) Biochemical Oxygen Demand (BOD) Chemical Oxygen Demand (COD) Ammonical Nitrogen (as N) Phenol Sulphide Suspended Solids (dried at 105°C) Metals pH Temperature Chloride Methanol

1-3 (Note 2) (0.05-5)** 20-30 (30-160)** 50-100 (2-30)** 1-5 0.1-0.5 0.5-1 20-30 (Note 3) 6-9 Note 4 Note 4 Max 15 ppm

Table 11-3 - Water Discharge Requirements Note 1:

The levels given above are ranges achievable after treatment using a biological treatment step and are not release limits. They are given on the basis of 95% of values not exceeding the relevant level.

Note 2:

Acid soluble oils should be present at trace levels.

Note 3:

Statutory Instrument (1989) No 2286 gives limits for releases to water for cadmium and mercury. Levels should be as low as practicable and reflect the quality of the receiving waters. Typical limits at the edge of a defined mixing zone in the receiving waters are to change the receiving water by no more that 1°C and salinity by no more than 5%. The upper temperature limit for a discharge is around 40°C.

Note 4:

*BREF Limits set by SEPA

11.6.2 Air Emissions Requirements It is expected that local air quality management in the UK will be assessed and controlled under the AQS (Air Quality Standards) for the foreseeable future. For this reason it is appropriate to use the objective levels specified under the current UK AQS at this stage of the GPP design. Review and adherence to new UK legislation will be required as and when available. The limit values set out in the Air Quality Standards (Scotland) Regulations 2007 and the objectives set out in the current UK AQS, for PM10 and oxides of nitrogen, are summarised hereafter (Ref [17]). Emissions from the GPP will be expected to aim for the more stringent of the AQLVs on the basis of it being a newly constructed terminal.



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Pollutant Oxides of Nitrogen (NOx)

Averaging Period Annual

(a)

Objectives / Limit Values 30 µg.m

-3

Not to be Exceeded More Than (f) -

Target Date 19.07.03

(e)

> 18 times pcy

31.12.05 (d) (e) 01.01.10

-

31.12.05 (d) (e) 01.01.10

Maximum daily running 8-hour mean

31.12.03 01.01.05 (e)

-3

> 35 times pcy

31.12.05

-3

> 24 times pcy

31.12.04 (d) (e) 01.01.05

125 µg.m-3

> 3 times pcy

31.12.04 01.01.05 (e)

Annual (b)

20 µg.m-3

-

19.07.03 (e)

24 hour

50 µg.m-3

> 7 times pcy

31.12.10 01.01.10 (c)

24 hour

50 µg.m-3

> 35 times pcy

01.01.05 (e)

Annual

18 µg.m

-3

-

31.12.10

(d)

Annual

40 µg.m

-3

-

01.01.05

(e)

Annual

20 µg.m

-3

-

01.01.10

(c)

Annual

Target of 15% reduction in concentrations at urban background locations

Annual

12 µg.m

Lead

Annual

0.5 µg.m

Arsenic

Annual

6 ng.m

-3

-

31.12.12

Benzo(a)pyrene

Annual

1 ng.m-3

-

31.12.12 (e)(h)

Cadmium

Annual

5 ng.m-3

-

31.12.12 (e)(h)

-

31.12.12

Nitrogen Dioxide (NO2)

Carbon Monoxide (CO)

Sulphur Dioxide (SO2)

1 hour

200 µg.m-3

Annual

40 µg.m

8 hour

10,000 µg.m

15 minute

266 µg.m

1 hour

350 µg.m

24 hour

-3

-3

(d)

(d)

(d)

(d)

Particulate Matter (PM10)

Particulate Matter (PM2.5)(g)

Nickel

Annual

20 ng.m

-

-3

-

-3

-

-3

Between 2010 and 2020 (g) 2020

(g)

31.12.04 (d) (e) 01.01.05 (e)(h)

(e)(h)

Table 11-4 - Summary of Relevant Air Quality Limit Values and Objectives (a) (b) (c) (d)

(e) (f) (g) (h)

For protection of vegetation For protection of ecosystems Provisional (Stage 2) Objectives included under Directive 1999/30/EEC (Ref [35]) Air Quality (Scotland) Regulations 2000 (Ref [36]) and Air Quality (Scotland) (Amendment) Regulations 2002 (Ref [37]) Air Quality Limit Values (Scotland) Regulations 2007 (Ref [38]) pcy - per calendar year Objectives set in Scotland Air Quality Strategy and not within Regulations Relate to the total content of the relevant pollutant in the PM10 fraction averaged over one calendar year



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Ref [39] provides the following achievable emissions for new gas turbines: Achievable Releases (mg/Nm3)

Pollutant Particulate Matter (PM)

5

Sulphur Dioxide (SO2)

10

Nitrogen Oxides (NOx)

20-50

Carbon monoxide

100

Release reported dry, 273K, 101.3kPa and 15% O2

Table 11-5 - Achievable Releases for New Gas Turbines

11.7

UTILITY AND SERVICE SYSTEMS SHARED WITH BP SVT

11.7.1 List of Utility and Service Systems The following utility and service systems shall be provided by means of utilising the spare capacity in the respective BP SVT systems: • • • •

Potable Water Service Water Main Electrical Power Low-low Pressure (LLP) Gas sent to BP SVT

11.7.2 Operating and Design Conditions

Service

Operating Conditions o C Barg

Design Conditions o C Barg

Potable Water Service Water LLP Gas to Recovery LLP Gas to Flare

HOLD 7.5 0.0 0.4

HOLD HOLD 9 5

HOLD 10 37 HOLD

HOLD HOLD 90 90

Table 11-6 - Operating and Design Conditions

11.7.3 Available Ullages Service

Ullage

Potable Water Service Water Main Electrical Power LLP Gas

Adequate supply assured by BP Adequate supply assured by BP Adequate supply assured by BP At least 41 Te/h Table 11-7 - Available Ullages



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11.8

STAND-ALONE UTILITY AND SERVICE SYSTEMS

The GPP will provide the following utility and/or service systems: • • • • • • • • • • •

11.9

Fuel Gas Closed Drains Oil Contaminated Open Drains Oil Free Open Drains Instrument and Plant Air Nitrogen Heating Medium Essential Services Power Generation Firewater MEG Chemical Injection incl. Corrosion inhibitor, Scaling inhibitor, Waxing inhibitor, Foaming inhibitor and Demulsifier

FLARE AND VENT SYSTEMS

The following separate gas disposal systems will be provided: •

LP Offgas System: Offgas from the TEG regeneration package, MEG recovery package and produced water flash drum will be recovered directly to the BP SVT Low Pressure gas compression suction header. In the event that the TSP vapour recovery system is unavailable, the LP offgas is diverted to a flare within the BP facility.

•

LT Flare: A low temperature blowdown system for the high pressure compression system.

•

Atmospheric Vents: Individual atmospheric pressure vents will be provided at source for outbreathings from low pressure tanks, e.g. produced water break tank and pre-DAF storage tank.

•

LP Flare: A low pressure flare line from the Closed Drain Drum and other LP sources.

•

HP Flare: A high pressure flare system for relief and blowdown of all other systems sized for 600 MMSCFD.

11.10 HIGH INTEGRITY PROTECTION SYSTEM Two separate HIPS systems will be provided, one for the import facilities and one for the Export Pipeline. Analysis and risk assessment reports shall be produced as part of complete HIPS Dossiers. 11.10.1 Inlet Facilities A HIPS system will be provided on each incoming multiphase Production Flowline to protect the 380 barg/48 barg design pressure break upstream of the Slug Catcher. 11.10.2 Gas Export Pipeline A HIPS system will be provided on the gas Export Pipeline to protect the HP/LP interface at the Export Pipeline tie-in at MCP01.



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11.11 PLANT LAYOUT AND PIPING The layout of the GPP will be developed in accordance with the relevant Total Design and Safety specifications incl. GS-SAF-021 to produce a safe, operable and maintainable plant. Administration & all other associated buildings will be located in close proximity to the Plant main entrance and in a Non-Hazardous area. Particular attention will be given during the Plant layout to constructability and any constraints relating to the topography, equipment installation and maintenance. The layout will be developed using Piping & Instrument Flow Diagram information and all relevant Vendor & Civil data etc. Piping will be routed and supported in an efficient manner and where defined as stress critical will be analysed to validate the design. Pipe racks will be utilised to facilitate pipe routing both within and between plant areas. These racks will be as straight as possible and mainly consist of welded piping. Attention shall be paid to systematically eliminating sources of hydrocarbon leakage from piping between process equipment areas. Unless required to the contrary, pipe racks will also be used for the segregated routing of instrument and electrical cables in cable trays. Any required tie-ins to the existing BP SVT will be specified and routed to an agreed location. These tie-ins will be routed & supported in such a manner as to not impose any pipe loads on the connecting BP pipework. Plant layout shall conform to TEP UK requirements in relation with safety distances, in particular GS EP SAF 253 Impacted Areas, Restricted Areas and Fire Zones. Hazardous Area Classification shall be performed in accordance with Total Spec GS-EP-SAF-216. 11.12 MATERIALS AND CORROSION MANAGEMENT 11.12.1 Material Selection Material selection for the GPP will be based upon the philosophy of ‘carbon steel’ being the favoured choice. Initially, corrosion rate calculations will be carried out, for each stream, utilising heat and mass balance data. By adding an appropriate corrosion allowance, either 1.27mm, 3mm or 6mm, the expected life of the material in that situation can be estimated. Only where the specified design life of 30 years still cannot be achieved, a change of material to a CRA, usually an austenitic stainless steel or non metallic such as a GRP would be considered. For specialist applications, such as sea water cooling, either GRP or a cupro nickel would be considered. For higher service temperatures, such as heating medium, either a 1¼ Cr ½ Mo or 2¼ Cr 1 Mo would be selected. To enhance the capability of the plant to accommodate ‘sour supplies’ it will be designed and built to NACE MR-01-75 (ISO 15156) intermediate level requirements. With the possibility of sour ‘product’ being present in the plant, materials and welding electrodes will be limited to Ni contents of < 1% and weld hardnesses limited to Rc 22.



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Low temperature requirements, e.g. blowdown situations will be accommodated by the use of low temperature impact tested material, the impact test temperature reflecting the result of the blowdown calculations. Fabrication will be carried out in line with Project specific Total procedures for plant and piping fabrication and welding specifications. Low hydrogen consumables will be specified and the test results (mechanical and chemical) recorded, reflecting the service requirements of the base material. Other industry standard practices will be adopted as required. For example, stainless steel piping or equipment will not be located underneath galvanized components (e.g. cable trays). This is in order to avoid the risk of liquid metal embrittlement in the event of a fire. 11.12.2 Protective Coating The requirement for internal lining of carbon steel vessels or tanks, and any need for supplementary internal cathodic protection (CP), will be reviewed on an item-by-item basis. Broadly speaking, vessels where produced water may accumulate will be lined up to a level above the maximum anticipated height of the separated water phase. Potable water tanks will be lined with polymeric systems certified as being compatible with that service. Lining will be according to a project particular version of GS EP COR 352. The GPP is deemed to be a coastal/offshore installation for the purposes of providing external corrosion protection. Accordingly, atmospherically exposed carbon steel will be painted according to a project particular version of GS EP COR 350. The requirement for coating any CRA will be assessed on a case-by-case basis. The preferred coating for stainless steel is thermally sprayed aluminium. The risk of corrosion under insulation will be mitigated by applying a full anticorrosion coating system to all insulated substrates (carbon steel or corrosion resistant alloy). 11.12.3 Cathodic Protection Tank bases, and any other buried or ground-contacting, metalwork, will be protected from soil-side corrosion by impressed current CP. This will be designed and installed according to a project particular version of GS COR 111. If internal CP is also needed then it will be by means of a sacrificial anode system. This will be designed and installed in accordance with GS EP COR 101. 11.13 MECHANICAL The mechanical equipment at GPP is determined by the processing requirements for handling, treatment and export of gas to MCP01 tie-in at the FUKA Pipeline, live condensate export to the BP SVT facilities and water treatment and discharge. Major mechanical equipment items / packages for processing well fluids include: • • • • •

Slugcatchers Production Separator HP/ Export Compression Gas Dehydration Column TEG Regeneration Package



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• • • • • •

Liquid Coalescer Produced Water Break Tanks MEG Regeneration Package MEG Desalination Package MEG Injection Pumps Dissolved Air Flotation (DAF) Package

The HP/ Export Compression trains are arranged as 3 x 50% trains. Each HP Compressor shares a common drive shaft with its corresponding Export Compressor, driven by gas turbine. Each compression train has a standard arrangement comprising a suction scrubber, compressor, aftercooler, anti-surge recycle line and a flow-controlled suction valve at the inlet to each compressor suction scrubber. Care must be taken to ensure that application of Total specifications does not result in excessive margins (on flow and/or absorbed power). Emulsions could be present and hence the liquids separation equipment includes preheating, a liquid coalescer and hydrocyclones. Associated offgas is to be recompressed in preference to flaring. Produced Water Break Tanks are provided as a buffer, to ensure that the MEG Regeneration Package is not overloaded during slug catcher draindown operation. A MEG Desalination Package should also be provided to prevent build-up of salts in the MEG reboiler. Utility equipment at the GPP, in addition to main processing, is identified in Section 11.8. Further points to note are: •

The fuel gas system normally takes dehydrated gas from the GPP plant but also takes dry gas from the FUKA Pipeline for start-up purposes.

•

Water from the oil contaminated open drains is to be treated along with produced water prior to combined effluent discharge. Items include an Oily Water Treatment Package, PreDAF Storage Tank & Pumps, Dissolved Air Flotation Package and Retention Pond Pumps.

•

The instrument and plant air system includes a wet air and instrument air receiver as well as air compressor and air dryer packages.

•

The nitrogen system includes a nitrogen generation package and a nitrogen bottle rack.

•

A Waste Heat Recovery Unit (WHRU) shall be provided on each of the 3 x 50% HP/ Export Compressor gas turbines. The selected heating medium is 30wt% TEG in water and the associated equipment includes a fired heater.

•

Main power generation is taken from BP SVT but a diesel generator package is to be provided at GPP for essential services power generation.

•

The Fire Water System includes 2 x 100% Fire Water Tanks, Fire Water Jockey Pumps, 2 x 50% Diesel Fire Water Pumps and 1 x 50% Electric Fire Water Pumps. Top up of the firewater tanks is to be by seawater lift pump.

•

The chemical injection package comprises a set of chemical storage tanks and pumps for supply of Wax Inhibitor, Corrosion Inhibitor and Scale Inhibitor to the Subsea Production System and also for Demulsifier injection at GPP.

Other utililities are provided from the BP SVT (see Section 11.7). Additional equipment for Potable and Service Water at GPP comprises: • •

Potable Water Storage Tank and Pumps Service Water Supply Drum and Pumps

Relief and Blowdown Systems include an LP flare drum and pumps, an HP flare drum and pumps and a Flare Package fed by the LT, LP and HP flare headers.



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11.14 ELECTRICAL 11.14.1 Main Power The SVT electric supply system will be utilised to supply normal power supplies and this has adequate reliability and sufficient spare capacity to meet the GPP power requirements for the design life of the project. Normal power will be supplied from the existing SVT 11kV switchboard SB2B1 at 50Hz to the GPP. Two spare circuit breakers at switchboard SB2B1, one each side of a bus-tie breaker, will be refurbished and utilised to supply normal power to the GPP. A new 11kV switchboard will be installed at the GPP. This will have four bus-sections, two supplied from separate bus-sections of switchboard SB2B1, one from the 11kV essential generator and one to be supplied by a future third gas turbine generator. New 11kV cables will be installed to supply power from the refurbished circuit breakers of SB2B1 to the new switchboard. Normal power will be distributed at 11kV at the GPP to supply large loads. Four sets of dual redundant 11/0.42kV Dyn11 transformers will be installed. Each transformer will be supplied from dedicated circuit breakers located on separate bus sections of the new 11kV switchboard. Four new 400V switchboards will be installed and will receive power via the new transformers. The new 400V switchboard will be installed having three bus sections to supply both normal and essential power users. The new transformers will supply separate normal bus-sections of the respective new switchboards. The normal supply bus-sections will be inter-connected via a normally open circuit breaker. 11.14.2 Essential Power Essential power shall be supplied from the on-site Essential services diesel generator. Power will be supplied at 11kV to switchboard SV2-IJ-6-1-01. Essential power is then distributed to the Essential bus-section on each 400V switchboard via 11/0.42kV transformers. The 400 volt Essential bus-section of each switchboard is interconnected with the main switchgear bus-bars via a normally closed circuit breaker. Power will be transmitted from the respective Essential bus-sections to supply loads identified as Essential power users at the GPP. During normal operation the essential power bus-bar will receive power from the normal power busbars of the new LV switchboards. In the event of loss of both normal power supplies, the bus-tie circuit breaker between the normal and essential bus sections will open and the essential supplies circuit breaker will close to restore supplies to the essential bus-bar. 11.14.3 UPS Battery backed-up uninterruptible power supplies will be provided to supply emergency loads in the event the essential power is not available.



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Each UPS will receive two independent 400V power supplies, one from the normal bus-section and one from the essential bus-section. UPS autonomy times shall be in accordance with the requirements of GS EP ELE 001 when backed-up by an emergency generator. 11.14.4 Lightning Protection Lightning protection shall be provided in accordance with Ref [40]. Enclosures of electrical equipment, structures, plant/equipment and the lightning protection system shall be connected to the earth grid. Tall structures shall be provided with air terminations and grounding conductors to protect against the effects of lightning. Where earth electrodes are installed, these shall be located near the base of elevated structures connected to the common earth grid. The electrode(s) shall be connected to the structure to be protected and interconnected with the plant earth ring. Interconnection of the earth grid shall be via copper cables. 11.15 INSTRUMENTATION 11.15.1 General The GPP facilities are controlled and monitored from the CCR by an Integrated Control and Safety System (ICSS). The term ICSS has been selected to define the fully integrated functionality of the process monitoring and safety system selected for the project. ‘Integrated functionality’ defines that the control functions and operator interface functions shall be fully integrated, with fully consistent display formats and control interfaces for all subsea and GPP. The component parts of the ICSS are as follows: • • • • •

Process Control System (PCS) Process Safety System (PSS) Emergency Shutdown System (ESD) Fire and Gas System (F&G) High Integrity Protection System (HIPS)

Each of these sub-systems shall be independent of each other and be functionally segregated, including cabling and connections. The ICSS sub-systems shall be located in the CCR Building and LER 1 and the sub-systems redundant networks interconnected via a fibre optic ring network, run in diverse path. The PCS is used for control and monitoring of the process systems, start/stop of drives, sequential logic and batch operations. The PSS forms part of the GPP safety system. Upon command, it shall automatically carry out the safe shutdown of particular units or equipment (e.g. SD-3). The ESD system executes functional logic related to the different emergency shutdown functions caused by unexpected process conditions or operations in the plant.



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The F&G system shall continuously monitor the GPP environment and execute functional logic based on the received input signals to either initiate alarms or shutdown. The HIPS system consists of two independent logic solvers. The HIPS will protect the GPP from overpressure at the inlet flowlines of the GPP and will protect the FUKA Pipeline system from overpressure at the outlet. All 3rd party equipment packages (metering, subsea control system, compressor unit control panels etc) shall tie in to the ICSS either via hardwired signals, serial links or as extension of network segments. 11.15.2 Export Gas Metering System (UN3501) Dedicated fiscal gas metering system shall be provided for custody transfer of the Laggan-Tormore export gas and shall meet the requirements of GS EP INS 112 - Design and supply of gas custody transfer metering units. The metering systems shall be supplied complete as a pre-engineered package including the flow measurement skids, associated instrumentation, analyzers and flow computers. The need to house the metering computer and electronics shall be finalized during EPIC phase. The metering system shall be based on 3 x 50% meter runs utilising transit time, multi path ultrasonic flow meters to BS 7965: 2000. 11.15.3 Condensate Metering System (UN4601) Dedicated fiscal condensate metering system shall be provided for custody transfer of the LagganTormore condensate prior to co-mingling with other SVT condensates and shall meet the requirements of GS EP INS 111 - Design and supply of liquid custody transfer metering units. The metering systems shall be supplied complete as a pre-engineered package including the flow measurement skid, prover loop, associated instrumentation, analyzers and flow computers. The need to house the metering computer and electronics shall be finalized during EPIC phase. The metering system shall be based on 3 x 50% meter runs utilising Coriolis flow meters, each metering stream shall be provided with a separate stream flow computer. 11.15.4 Other Metering Systems Reference should be made to Ref [41], which includes for Gas import metering and metering of other systems for GPP. 11.15.5 Machine Monitoring System Machine Monitoring System (MMS) based on Bently Nevada System 1 shall be installed in the CCR rack room and LER-1 to monitor shaft vibration, axial displacement and bearing temperatures of the HP / Export Gas compressors, MEG pumps and other major rotating machines. The vibration monitors shall generally be installed within the packaged equipment and wired back to Bently Nevada 3500 series racks which form part of package Supplier’s UCPs (located in CCR and LER-1).



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The MMS shall as a minimum comprise the following main equipment: − − −

Operator HMI (Location: CCR Rack Room) Server Cabinet (Location: CCR Rack Room) Hubs (Location: CCR Rack Room and LER-1)

11.15.6 Instrument Electrical Power Instrumentation electrical power shall be supplied from UPS systems. These systems shall provide sufficient battery storage for one hour (TBC by TEPUK) of control power from total loss of installation power. UPS power shall be distributed at 230V 50 Hz and for critical duties (i.e. systems undertaking emergency or process shutdown actions) two separate UPS feeders shall be installed. Loop power (nominally 24 VDC) shall be derived from the ICSS for all field instruments and package units interfacing the PCS. 11.15.7 Field Instrumentation Field instrumentation shall comply with GS EP INS 101 - Instrumentation engineering, supply and construction general requirements. All equipment on the GPP necessary for mounting in hazardous areas shall be certified to ATEX 94/9/EU standards as being suitable for use in a Zone 1 IIA T3 environment. All equipment offered for use in these areas shall have ATEX certification and its proposed application shall fully comply with all conditions of the certificate. No instrumentation equipment shall be installed in Zone 0 areas. The use of intrinsically safe (EEx’i’) instrumentation is preferred except for solenoid valves which will be flameproof (EEx’d’). Increased safety (EEx’e’) Junction boxes shall be used. Equipment protected by purge systems (EEx p) shall be avoided wherever possible. 11.15.8 Field Installation and Design Tubing, fittings, cables, junction boxes, field terminal cabinets, etc shall conform to the following specifications: GS EP INS 101 GS EP INS 107 GS EP INS 900

General Specification Design and Installation of Instrumentation Links Instrument Hook-up Diagrams

All cables shall be flame retardant (IEC 60332 – Part 3), except for safety related systems when fail safe principle is not applied (such as fire & gas detectors, emergency / fire pushbuttons, CO2 release, etc) for which cables shall be fire resistant (IEC 60331). Cables shall comply with GS EP ELE 161 – Electrical Cables.



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11.16 TELECOMS DESIGN 11.16.1 General An integrated telecommunications system supports all voice and data communication within the GPP and between other locations. This telecommunication network provides the communication facilities needed for the safe, efficient and cost-effective operation of the GPP. Telecoms systems will be stand alone systems however there will be an interface to BPX to exchange all necessary data. Equipment duplication or redundancy is provided where necessary, ensuring that communications are not prejudiced by the failure of any one item of telecommunication equipment. There will be a hardwired interface between the F&G system and the Public Address / General Alarm (PA/GA) system. All telecoms systems will be located in a controlled entry room within the control building. An Uninterruptible Power Supply shall be provided to support the vital systems for (TBC by TEPUK). 11.16.2 System Components Systems comprise the following: •

Main bearer systems – links to TEP UK Aberdeen and St Fergus will be established via separate leased line circuits @ 45 Mbps. TEP UK Aberdeen will transfer required data to St. Fergus via existing connection. Multiplex equipment will provide the interface for all voice and data circuits between locations.

•

Telephone facilities – a Hybrid PABX will provide analogue, digital and VoIP facilities to internal safe area instruments and also to external EEX certified telephones. External telephones will be equipped with a hood, beacon and sounder when located in noisy areas.

•

Plant Trunk radio system – a 4 channel UHF trunk radio system will communicate with EEx IS Handportable radios. The system will also be connected to a telephone interface to provide call facilities when authorised from Handportable radios.

•

VHF FM marine radio (for bulk loading at jetty) – a standard SOLAS VHF marine radio will be rack mounted in the equipment room with a remote control unit located on the CCR console. A number of VHF Marine Handportable radios will also be provided.

•

Combined PA/GA system – the system provides voice and alarm facilities via loudspeakers located throughout the Plant. Beacons will be activated by the system in noisy areas on alarm or Emergency speech. The system will be configured in a n+1 amplifier configuration with auto changeover to ensure maximum availability.

•

WAN / LAN system – to provide interconnection to the Company data services.

•

Hotline – dedicated telephone connection independent of the telephone system to connect other control rooms and facilities.

•

Fibre optic system – FO ring will be installed utilising independent routing to increase availability

•

CCTV system – EEX certified PTZ cameras to monitor flare and process plant areas. Fixed safe area cameras will be installed to monitor the perimeter fence.



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•

Access control and intruder detection – an Access control system will be installed to ensure unauthorised access to sensitive areas is prevented and provide information to assemble the POB in case of emergency.

•

BPX interface system – a system will be installed to exchange necessary alarm, voice and adapt communications with BPX.

•

Radio tower – will be designed to ensure that the site radio communications systems provide the maximum coverage efficiently.

•

Emergency Response Room will be established in Admin Building and fully equipped with all necessary communication links and equipments.

•

Export Beach Valve – a UHF radio link will be established to provide essential information to this location.

•

Telecoms Supervisory System – to monitor alarm status of the various systems and give early warning of possible communication problems.

11.17 CIVILS The site is a hill side sloped at 1 in 10 with peat on average 1 to 2 metres deep overlaying Dolerite granite. Three terrace levels are proposed to accommodate the process plant with the platform areas dictated by the process plant sizes and their access requirements. Internal site roads shall be graded to maintain a 1 in 12 slope for access, with level roads parallel to the existing contours. Road widths and service corridors shall comply with TEP UK standards. The peat shall be worked so as to avoid slippages and run off problems. The intention is to store the peat on site for future restoration purposes in peat ‘reservoirs’ created at the edge of each terrace platform. A peat working methodology shall be agreed with SEPA. Cut and fill of the granite shall include for crushing to form aggregate for surfacing the platforms. The balance of fill required will be imported to site and/or ‘Filcor’ will be used to create the platform levels. Surface drainage shall be designed with berms to control storm run off from the slope and report to a SUDS retention pond, all in accordance with the SUDS Manual and Construction Site Handbook, CIRIA. Architectural Buildings shall include: − − − − − − − − − −

Control Building Administration Building Warehouse and Workshop Gate House Laboratory 3 Compressor Buildings (TBC) 4 Sub Stations Fire Water Pump House Local Equipment Room Building Umbilical Building

The buildings shall be generally steel framed and clad with as much prefabricated as possible to minimise site construction time. Containers will be used and sectionalised buildings pre-fitted will come in 3x4x14 metre sections.



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12.

GAS EXPORT PIPELINE

12.1

ONSHORE PIPELINE

12.1.1 Design Conditions The onshore Export Pipeline shall be designed in accordance with the BS-PD-8010 standard. However due to the proximity of housing at the Firths Voe Landfall the requirement for wall thicker than required for the offshore pipeline may continue into the Voe. The proposed minimum depth of cover of the Export Pipeline is to be 1.2m. The suitability of the ground to achieve this required cover can only be ascertained by a geotechnical survey, which should include ground probes and trial excavations. The route is mostly void of occupied dwellings and may be considered rural, which would extend to the route as it runs parallel to the B9076. BS-PD-8010 therefore would only require a design factor of 0.72. Where the route crosses the A968 it is close to the village of Firth, which contains numerous occupied dwellings that run along the north side of the Voe. BS-PD-8010 defines the requirements for pipeline design parameters for proximity to housing and at crossings to be restricted to a design factor of 0.3. However the code does allow the design to be modified by the application of a risk assessment of the pipeline route when probabilities and consequences of pipeline failure are analysed. For the risk assessment BS-PD-8010 references the risk analysis identified within IGEM-TD-1. The final design requirements for the Export Pipeline will therefore be dependent on the outcome of the pipeline risk assessment and the acceptance of that outcome with the planning authorities. In consideration of the short length of pipeline required, the linepipe used for the proximity requirements at Firths Voe will be continued for the complete onshore pipeline route. The linepipe materials are to be manufactured in accordance with DNV-OS-F101, which shall be of an L450 grade. The end preparation weld bevel shall be suitable for the method of pipeline welding. All connections to the pipeline shall be fully welded, including the first valve connection, the minimum size of which shall be 2”, after which connections shall be flanged. Therefore any line valves shall be fully welded and shall be buried. As the valve will require actuation, it is proposed that the valve actuation and valve maintenance connections shall be above the ground any necessary extensions and valve assemblies. Double Block and Bleed (DBB) facilities shall be required for all connections to the pipelines with any screwed instrument connections being separated from the pipeline by a DBB facility. 12.1.2 Valve Installation The Export Pipeline will require a beach valve installation. The location of the valve installation is not agreed; however this may be subject to planning authorisation and the layout is limited by the lack of useful land, due to the slopes around the A968 and the wet conditions of the landfall area, which may also be liable to flooding during high tide and high rainfall conditions.



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As the valve installation will be outside the GPP boundary fence, it shall be self contained within its own fenced site and will require electrical and instrument connections to the GPP. As the site is remote to the GPP, it will require both pedestrian and vehicle access for maintenance activities, which is assumed to be a 24hr requirement and therefore shall include site lighting. 12.1.3 Pigging Facilities The pipeline shall be fully piggable, suitable for the passage of commercially available spheres, pig, scrapers and inspection tools. Permanent pigging facilities are not required at the GPP. However suitable fittings, connections and valving shall be required that will allow the provision of temporary pigging facilities, as required. The pipeline shall be designed with a constant ID which shall be based on the ID of the offshore pipeline. All in-line equipment shall therefore be suitable for pigging. Valves shall be full bore bore valves and tees or connections greater than 40% of the pipeline ID shall incorporate pigging bars, as necessary. The minimum bend radius shall be equivalent to five 5D which shall conform to the ovality and diameter restrictions identified within BS-PD-8010. Minor variations in elevation and direction shall be achieved by the natural flexing of the pipeline as it is laid, with angles up to approximately 5 degrees achieved by bending the pipeline, where the geometry requirements shall be maintained. Tighter bends shall be achieved by manufactured hot formed pipeline bends. 12.1.4 Construction Requirements As the pipeline is predominately within public access areas, the construction must consider security and safety of construction activities, including excavation, welding, lifting, radiography and pressure testing. The pipeline shall be constructed by welding together individual linepipe lengths above the ground with each girth weld being 100% radiographically inspected before being coated and buried. The reinstated ground shall be replaced to an as found condition, with the route being identified with route markers, and buried warning tape. Construction activities shall include any protection required for the working near or crossing of the existing pipelines, utilities or services. 12.1.5 Crossings The design shall consider the need to maintain the support around the existing buried pipelines and suitable reinstatement. As the road crossings are roads that are relatively quiet, the method of construction shall be by open cut construction, using traffic controls to enable half the road to be closed at any one time.



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In addition to the approximate locations of the roads and pipeline crossings identified, there may be other electric, communications and water utilities along the route, especially within the area of Firths Voe. Definitive locations of all pipelines and services shall be identified by a full topographical survey. 12.1.6 Corrosion Coatings There is no requirement for internal corrosion of flow coating for the Export Pipeline. The external coating of the linepipe shall be factory applied, which shall be the same external coating as the offshore pipeline. A lower grade coating may be possible; however it is not considered worthwhile for the amount of onshore pipeline required. Fabricated girth welds shall be coated using heat shrink sleeves that are compatible with the factory applied linepipe coating. The completed pipeline shall be 100% inspected for coating faults prior to burial. 12.1.7 Cathodic Protection The Export Pipeline shall also be protected by the provision of a CP system. The CP system shall be isolated from the offshore CP system by an IJ. To isolate the buried pipeline CP system from the above ground pipework within the GPP, an IJ will be required at the pipeline start, before the pipeline enters the ground. The presence of the applied CP system will require cross bonding with existing pipeline systems and interaction tests undertaken, ensuring that the systems do not have a detrimental effect on each other. 12.1.8 Testing The Export Pipeline shall be hydrostatically tested to achieve a minimum of 90% of the specified minimum yield stress in the pipe wall for a period of 24hrs. Weather windows and environmental restrictions may cause difficulty in synchronising the onshore pipeline construction work with the offshore and GPP construction activities. The onshore pipeline will therefore be constructed and hydrostatically tested separately. This will allow the Contractor to complete all the onshore pipeline sections as efficiently as possible, leaving the tie-in of the onshore sections to be completed as the offshore pipeline are available. The complete pipeline will then undergo a hydrostatic strength test. The water used for the hydrostatic test will require treatment with biocides and oxygen scavengers. All fabricated assemblies shall be fully tested prior to being introduced into the pipeline, including pig traps, IJ’s and valves. 12.1.9 Integrity Monitoring The continued use of the pipeline will be dependent on the integrity monitoring of the facility during operation, including testing of the CP system and on-line inspection with the use of smart pigs to identify any metal losses, cracks or other faults that may occur during the design life of the pipeline.



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12.2

OFFSHORE PIPELINE

12.2.1 Design Data Following data are obtained from the Project Statement of Requirements (SOR) Rev 0-iii (Ref [1]) and Pre-Project Update 2008 Final Report (Ref [18]), unless otherwise specified.

Parameter

Export Pipeline

Size Steel Grade Design Pressure Max Design Temperature Service

30” ND (see Note 1) DNV 450 172.4 barg @ MSL -20 / 50 °C Non-sour 6 km onshore 228.474 km offshore 30 years 1.5 mm

Length Design Life Corrosion Allowance

Table 12-1 - Export Pipeline Design Data Note 1: Internal diameter constant

Where required, pipelines will be concrete coated to ensure adequate stability on the seabed during installation and operation. Parameter

MCP01 Tie-in Spools

Size

12” ND

Steel Grade

DNV 450

Design Pressure

172.4 barg @ MSL

Min/Max Design Temperature (°C)

-20/+50

Table 12-2 - MCP01 Tie-in Spools Design Data

Tie-in

Location

2 No. Future Tie-in for FUKA, Size 12”

MCP01

2 No. Hot Tap Tie-in Tees for Laggan-Tormore Export Pipeline, Size 12”

40km downstream of Firth Voe Landfall 100km Upstream of MCP01

Table 12-3 - Location of Export Pipeline In-line Tees for Third Party Tie-in

12.2.2 Material Data Refer to Section 10.1.2.



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12.2.3 Crossing Data The following crossing data are extracted from Fugro survey report Ref [13]. Type

Crossing Identification

KP Mark

Crossing Size/ Angle

Crossing Co-ordinate (m) Easting

Northing

Comment

Pipeline

PL10 Ninian to Grutwick Mol (BP)

28.7

36” OD/ 49.06

626 064.5

6 710 265.6

Cable

TAT 14(K)

139.7

[HOLD]/ 73.8

637 907.6

6 605 830.0

Cable

Atlantic Crossing 1

152.0

[HOLD]/ 64.4

638 431.6

6 593 559.8

Pipeline

PL2 Gas Brent A to St Fergus (FLAGS) (SHELL)

173.1

36” OD/ 142.66

639 331.9

6 572 480.7

Cable

TAT 10(B)

185.1

[HOLD]/ 60.79

639 845.5

6 560 455.2

Possibly buried

223.4

32” OD/ 122.20

658 619.19

6 527 861.63

Exposed on seabed

226.8

32” OD/ 143.69

657 560.94

6 524 688.96

Possibly buried

227.2

18” OD/ 131.03

657 376.7

6 524 350.2

Pipeline Pipeline Pipeline

PL7N Gas Frigg to St Fergus line 2 North (TOTAL) PL6N Gas Frigg to St Fergus (TOTAL) 18” Tartan Gas

Trenched and buried In service, possibly buried In service Exposed

Exposed

Table 12-4 - Crossing Information for 30” Gas Export Pipeline Note: Crossing angles are measured from proposed pipeline (anti-clockwise)



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13.

MEG LINE

13.1

ONSHORE LINE

The onshore MEG line transports MEG from the GPP to the offshore MEG line at the landfall at Orka Voe along the same route as the Production Flowlines, for a distance of approximately 1.5km, depending on the final route and the location of the route and flowline valves within the GPP. 13.1.1 Design Conditions The onshore MEG line shall be designed in accordance with the DNV-OS-F101 standard, as an extension to the offshore MEG line. The proposed minimum depth of cover for the MEG line is to be 1.1m. The suitability of the ground to achieve this required cover can only be ascertained by a geotechnical survey, which should include ground probes and trial excavations. With the exception of any manning at the existing SVT or proposed GPP locations, it is noted that the area is sparsely populated with no occupied dwellings close to the pipeline route. As the fluid contained within the pipeline is liquid and in accordance with DNV requirements, the route is considered to be a Low to Medium Risk and will be designed to the same requirements as the foreshore pipeline. The linepipe materials are to be manufactured in accordance with DNV-OS-F101, which shall be of an L450 grade. The end preparation weld bevel shall be suitable for the method of pipeline welding. All connections shall be fully welded, including the first valve connection, the minimum size of which shall be 2”, after which connections shall be flanged. Therefore any line valves shall be fully welded and shall be buried. As the valves will require actuation, it is proposed that the valve actuation and valve maintenance connections shall be above the ground any necessary extensions and valve assemblies. DBB facilities shall be required for all connections to the pipelines with any screwed instrument connections being separated from the pipeline by a DBB facility. 13.1.2 Valve Installation No beach valve installation is required. 13.1.3 Pigging Facilities The pipeline shall be fully piggable, suitable for the passage of commercially available spheres, pig, scrapers and inspection tools. Permanent pigging facilities are not required at the GPP; however suitable fittings, connections and valving shall be required that will allow the provision of temporary pigging facilities, as required. The pipeline shall be designed with a constant ID which shall be based on the ID of the offshore pipeline.



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All in-line equipment shall therefore be suitable for pigging. Valves shall be full bore valves and tees or connections greater than 40% of the pipeline ID shall incorporate pigging bars, as necessary. The minimum bend radius shall be equivalent to 5D which shall conform to the ovality and diameter restrictions identified within DNV-OS-F101. Minor variations in elevation and direction shall be achieved by the natural flexing of the pipeline as it is laid, with angles up to approximately 5 degrees achieved by bending the pipeline, where the geometry requirements shall be maintained. Tighter bends shall be achieved by manufactured hot formed pipeline bends. 13.1.4 Construction Requirements As the pipeline is predominately within the SVT jurisdiction, the construction must conform to any permitting procedures required by the SVT Operator. Presently the only access to the landfall and flowline route is via the SVT terminal and will require designated routes through the operational site. The linepipe lengths shall be welded together above the ground with each girth weld being 100% radiographically inspected before being coated and buried. The reinstated ground shall be replaced to an as found condition, with the route being identified with route markers, and buried warning tape. Construction activities shall include any protection required for the working near or crossing of the existing pipelines, utilities or services. 13.1.5 Crossings The same crossing requirements apply to the MEG pipeline route as they do for the flowlines, being laid in parallel corridors. 13.1.6 Corrosion Coatings There is no requirement for internal corrosion of flow coating. The external coating of the linepipe shall be factory applied, which shall be the same external coating as the offshore pipeline. A lower grade coating may be possible; however it is not considered worthwhile for the amount of onshore pipeline required. Fabricated girth welds shall be coated using heat shrink sleeves that are compatible with the factory applied linepipe coating. The completed pipeline shall be 100% inspected for coating faults prior to burial. 13.1.7 Cathodic Protection The pipeline shall also be protected by the provision of a CP system. The CP system shall be applied and shall be compatible with the offshore CP system.



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To isolate the buried pipeline CP system from the above ground pipework within the GPP, an Isolation Joint (IJ) will be required at the pipeline termination, as the pipeline leaves the ground. The presence of the applied CP system will require cross bonding with the flowlines and existing pipeline systems and interaction tests undertaken, ensuring that the systems do not have a detrimental effect on each other. 13.1.8 Testing The pipeline shall be hydrostatically tested to achieve a minimum of 90% of the specified minimum yield stress in the pipe wall for a period of 24hrs. Weather windows and environmental restrictions may cause difficulty in synchronising the onshore pipeline construction work with the offshore and GPP construction activities. The onshore pipeline will therefore be constructed and hydrostatically tested separately. This will allow the Contractor to complete all the onshore pipeline sections as efficiently as possible, leaving the tie-in of the onshore sections to be completed as the offshore pipeline are available. The complete pipeline will then undergo a hydrostatic strength test. The water used for the hydrostatic test will require treatment with biocides and oxygen scavengers. All fabricated assemblies shall be fully tested prior to being introduced into the pipeline, including pig traps, IJ’s and valves. 13.1.9 Integrity Monitoring The continued use of the pipeline will be dependent on the integrity monitoring of the facility during operation, including testing of the CP system and on-line inspection with the use of smart pigs to identify any metal losses, cracks or other faults that may occur during the design life of the pipeline. 13.2

OFFSHORE LINE

13.2.1 Design Data The following data are obtained from the Project Statement of Requirements (SOR) Rev 0-iii (Ref [1]) and Pre-Project Update 2008 Final Report (Ref [18]), unless otherwise specified. Parameter

MEG Line

Size Steel Grade Design Pressure Min/Max Design Temperature (°C) Length Design Life Corrosion Allowance

8” ND DNV 450 622 barg @ -610m [HOLD] -10/+75 (GPP – KP110) -10/Ambient (KP110 – Tormore) 16 km (Tormore – Laggan) 125 km (Laggan – GPP) 1 km (onshore) 30 years 1.5 mm

Table 13-1 - MEG Line Design Data



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Parameter

Spools

Spool Size

4” ND

Steel Grade

DNV 450

Design Pressure

622 barg @ -610m [HOLD]

Min/Max Design Temperature (°C)

-10/+50

Corrosion Allowance

1.5 mm Table 13-2 - MEG Line Spools Design Data

13.2.2 Material Data Refer to Section 10.1.2. 13.2.3 Crossing Data Refer to Section 10.1.3.



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14.

ONSHORE WATER OUTFALL PIPELINE

GPP treated waste water will be sent to the existing SVT water discharge pipeline. Proposed Pipeline Route The water outfall pipeline will transport treated waste water from outlet of the GPP to a tie-in location with the existing SVT water discharge pipeline, for offshore disposal to Yell Sound off Calback Ness, via the existing SVT pipeline. The GPP outfall pipeline route crosses the reinstated Orka Voe land (known as The Vadill) in an easterly direction for a distance of approximately 550m, depending on the agreed tie-in location with the SVT discharge pipeline. The route outside the GPP boundary will therefore be within SVT operational site, fenced off from public access. The existing SVT discharge pipeline is understood to run directly north beside an existing SVT road (running south to north) to the west of The Vadill, however the existing discharge pipeline route location and tie-in point have yet to be confirmed. Operating Conditions The outfall pipeline shall be designed and constructed in accordance with the SVT-S-SP-10121: Sewers and Drainage Construction. Although the water is to be treated, it is assumed to contain entrained air and traces of hydrocarbons, which would be problematic for carbon steel pipelines. The pipeline conditions are not finalised; however the operational pressure (approximately PN16 or less) would be considered suitable for plastic pipe and fittings. As the pipeline is plastic, no CP, internal coating or external coating will be necessary. There will be no requirement for this pipeline to be piggable. As the outfall pipeline would be low pressure within the SVT site, the proposed minimum depth of cover for the pipeline flowlines is only required to be 0.8m. Valve and Tie-In Installation As the pipeline contains treated water and will operate at low pressure, there will be no requirement to fence a hazardous zone around the tie-in valve arrangement. Plastic or cast iron gate valves will be adequate for this application. Depending on the pipe diameter it may be possible to house the valves in a pit or have them directly buried. Barriers will be required to protect the valve installation from vehicles and other SVT activities. The tie-in to the existing SVT discharge pipeline will require a shut-down of the existing pipeline; otherwise a hot-tap procedure would be required. In addition to availability for a shut-down, the suitability of the pipeline material for hot-tap drill of the existing pipeline will require investigation.



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Construction Requirements As the outfall pipeline is within the SVT jurisdiction, the construction must conform to any permitting procedures required by the SVT Operator and designated routes through the SVT operational site. The flowlines shall be constructed by jointing together individual linepipe lengths above the ground and then trenching along the route with the reinstated ground replaced to an as found condition. The buried pipeline shall be identified with marker posts and buried warning tape. Crossings Construction activities shall include any protection required for the working near or crossing of the existing pipelines, utilities and services, including the tie-in connection to the existing SVT discharge line. It is customary for all new pipelines to cross beneath any existing pipelines, utilities and services and the crossing design will require approvals with the owner of the existing pipeline owner. This shall include the requirement to maintain the support around the existing buried pipelines and suitable reinstatement. As the road crossings are terminal roads which are predominantly used for security patrol, the method of construction shall be by open cut construction; however access shall remain available by the use or road plates. In addition to the approximate locations of the roads and pipeline crossings identified, a number of buried cable markers have been identified around the proposed route location. Definitive locations of all pipelines and services shall be identified by a full topographical survey. Testing The flowlines shall be hydrostatically tested to prove the pipelines integrity, at a pressure which is 1.5 times the operational pressure for a period of 2 hours.



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15.

SPECIFICATIONS, CODES AND STANDARDS

The proposed design, construction, operation and abandonment must be in line with all required national and international codes and standards in addition to the Total Referential. 15.1

TOTAL SPECIFICATIONS

The 2009 Referential of Total General Specifications will be used for the design. 15.2

CODES AND STANDARDS

The Laggan-Tormore development must comply with: • •

SI 825 : Pipeline Safety Regulation, 1996 SI 913 : Offshore Installations and Wells (Design and Construction, etc) Regulations, 1996

The primary design code for the offshore pipeline will be: •

DNV OS-F101 : Submarine Pipeline Systems, 2007

The primary design code for the onshore pipeline will be: • •

BS PD 8010 : Steel pipelines on land, 2004 DNV OS-F101 : Submarine Pipeline Systems, 2007

Other relevant documents include: • • • • • • • • • • • •

ASME B31.3 : Process Piping, 2002 ASME B31.8 : Gas Transmission and Distribution Piping Systems, 2003 BS ISO 3183-3 : Petroleum and Natural Gas Industries - Steel Pipe for Pipelines - Technical Delivery, 1999 BS ISO 13628-5 : Petroleum and Natural Gas Industries - Design and Operation of Subsea Production Systems - Part 5: Subsea Umbilicals, 2002 API Specification 5L : Specification for Line Pipe, Forty-Third Edition, January 2000 API Specification 6A : Specification for Wellhead and Christmas Tree Equipment, Nineteenth Edition, ISO 10423 Adoption API RP 2A WSD : Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms, Working Stress Design, Twentieth Edition, July 1993 DNV 1992 : Foundations, Classification Notes No.30.4, February 1992 DNV-RP-E303 : Recommended Practice – Geotechnical Design and Installation of Suction Anchors in Clay, October 2005 DNV 1977 : Rules for the Design Construction and Inspection of Offshore Structures NACE MR 0175 / ISO 15156 : Corrosion Resistant Alloys for Sulphide Service, 2003 NORSOK U-001 : Subsea Production Systems, Rev. 3, October 2002

In all cases, the latest edition of the relevant regulations, codes, standards and guidance notes will be used, unless noted otherwise.



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16.

REFERENCES

1.

LAT-DEV-WOS-LATPPU-0005 : Laggan Tormore Project Statement of Requirements (SOR) Rev 0-Iii (February 2009)

2.

LAT-DEV-WOS-LATPPU-0001 : Laggan Tormore Pre-Project Update & Conceptual Studies Basis of Design

3.

LAG-F-RP-70011 : Safety, Health and Environment Management Plan (SHEMP)

4.

LAT-F-RP-70500 : Project Safety, Health and Environment (SHE) Plan

5.

LAT-F-PY-70502 : Project Safety, Health and Environment (SHE) Philosophy

6.

E-mail dated 01/04/2009 from J. Cutler providing production profiles

7.

Memo dated 02/03/2009 from F. Montel : Extended EOS Model Laggan/Tormore UK

8.

DGEP-TDO-EXP-PRD No 08-162 : Development Tormore, Production Chemistry Report

9.

PhysE Report Jan. 2008 : Wave & Current Conditions for the Laggan Pipelines - Volume 1

10. PhysE Report No C101-05-R0190-2F October 2005 : Metocean Criteria for the Laggan Field 11. DNV-RP-C205 : Environmental Conditions And Environmental Loads (April 2007) 12. Fugro Route Survey Report No 9049 V2.1 (659049) Volume 2 of 7 : Geophysical Results Report - Yell Sound Option 13. Fugro Route Survey Report No 9049 V4.1 (659049) Volume 4 of 7 : Geophysical Results Report - Export Route Fugro Route Survey Report No 9049 V6.1 (659049) Volume 6 of 7 : Geotechnical Report Fugro Route Survey Report No 9049 V7.1 (659049) Volume 7 of 7 : Soil Parameters Report 14. SVT Soil Survey for Laggan, Peter Bardell Consulting Engineers Ltd, December 2006 15. LAT-F-SY-70004 Laggan Fishing Intensity Study, RevA02 16. Email D. Thomson to D. Neeve dated 22/06/2009 : Technical Query TQ-LAT-0065 – Export Specification – GPP Unstabilised Crude 17. LAT-F-PY-70525 R03 : Project Environmental Philosophy 18. LAT-DEV-WOS-LATPPU-0002 : Laggan Tormore Pre-project Update 2008 Final Report 19. Technical Note BD/DSP-09-23 from TEP UK, Section 6.2.2 : Concentration of H2S in the Laggan and Tormore Fluids and its Management (05 March 2009) 20. Email M. Carr dated 25/06/2009 : Design Flowrate per Well – Formation Water 21. Memo No BUS-081202-38069 from Total Well Construction and Maintenance Group, dated 28 November 2008 : Laggan Tormore Safety Valve Selection 22. Fugro Report No 61516-1 Rev1 : Laggan Site Investigation Geotechnical Report – Field Data (2006) 23. Fugro Report No 61516-2 Rev2 : Laggan Site Investigation Geotechnical Report – Laboratory & In-Situ Data (2007) 24. Fugro Report No 61516-3 Rev2 : Laggan Site Investigation Geotechnical Report – Soil Parameters Report (2007) 25. Fugro Report No 61516-4 Rev2 : Laggan Site Investigation Geotechnical Report – Engineering Report (2007) 26. Fugro Report No 61516-5 Rev2 : Laggan Site Investigation Geotechnical Report – Additional Engineering Report (2007)



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27. Fugro Report No 20081534-2 Rev1 : Tormore Site Investigation Geotechnical Report – Laboratory & In-Situ Data & Soil Parameters (2009) Fugro Report No 20081534-3 Rev1 : Tormore Site Investigation Geotechnical Report – Conductor Integrity Analysis 28. Maxoil Technical Note ref. MAX-TOT-002-TN-001 Rev1 dated March 2009 : Laggan Tormore Chemical Review Update 29. LAT-F-RP-70000 : Laggan-Tormore Offshore Scoping Report 30. LAT-F-RP-70001 : Laggan-Tormore Onshore Scoping Report 31. Scatsa Weather Station Records 1999-2008 32. Genesis Doc No J70438-H-A-TN-003-R0 : Environmental Conditions for Process Equipment Design (September 2006) 33. Technical Query TQ-LAT-ODE-0067 : Climatic Conditions at GPP (June 2009) 34. Company Supplied Environmental Hydrology and Hydrogeology Reports (October 2007) 35. Council Directive 1999/30/EC of 22 April 1999 relating to limit values for sulphur dioxide, nitrogen dioxide and oxides of nitrogen, particulate matter and lead in ambient air 36. Air Quality (Scotland) Regulations 2000, Statutory Instrument 2000 No. 97 37. Air Quality (Scotland) Amendment Regulations 2002, Statutory Instrument 2002 No. 297 38. Air Quality Limit Values (Scotland) Regulations 2007 39. EA Sector Guidance Note for Combustion Activities, PPC Sector Guidance Note Combustion Activities, Environment Agency, version 2.03, 27th July 2005 40. SVT-E-SP-60538 : Specification for Earthing, Bonding & Lightning Protection Studies 41. SVT-J-PY-50509 : Metering Philosophy (Basic Engineering Deliverable) 42. Email M. Carr dated 24/06/2009 : Well Profiles for Basic Engineering 43. LAT-W-RP-83203 R03 : Chemical Study Report - Production Chemical Treatment Rates & Delivery Pressure (Maxoil Report) 44. LAT-L-SP-90101 : Flow Assurance Basis of Study



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LAT-G-BA-00150 Rev D04 - Basis of Design

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