11771v 009 jsd 3500 001 rev e_3427 150 s st tpf 00004 rev p03 flexible pipe design premise

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3427-150-S-ST-TPF-00004 BOURI FIELD - EAST AREA DEVELOPMENT

PROJECT JOB NUMBER

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11771V-009-JSD-3500-001 Rev E

AGIP OIL

COMPANY LIBYAN BRANCH

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SUPPLIER DOCUMENT NUMBER

FLEXIBLE PIPE DESIGN PREMISE

P03 07/09/05 Issued for Approval – IFA 2 F.MARCEL P-A THOMAS H.CORRIGNAN Y. LE CARRER

P02 13/07/05 Issued for Approval – IFA 1 F.MARCEL H.CORRIGNAN Y. LE CARRER P01 22/02/05 Issued for Review – IFR 2 F.MARCEL H.CORRIGNAN Y. LE CARRER P00 15/10/04 Issued for Review – IFR 1 F.MARCEL H.CORRIGNAN Y. LE CARRER

Rev. Date Description Prepared Verified Approved

TECHNIP France CSO SURF

Confidentiality category: C.2. CONFIDENTIAL TECHNIP FRANCE, DO NOT DISCLOSE WITHOUT ITS AUTORIZATION This document contains confidential information. Property of Technip France S.A.- Copyright Technip France - All rights reserved.

EXTERNAL DISTRIBUTION INTERNAL DISTRIBUTION AOC: : A. ARIFI Project Manager Y. LE CARRER A. HWIDI Supervision H.CORRIGNAN Project Engineer F. MARCEL PA. THOMAS

AGIP OIL COMPANY LIMITED - LIBYAN BRANCH

BOURI FIELD – EAST AREA DEVELOPMENT PROJECT

WP#2-FLOWLINE AND RISER SYSTEM AND UMBILICAL INSTALLATION

FLEXIBLE PIPE DESIGN PREMISE

TECHNIP FRANCE Job No. 11771V

Rev. Date Issue Purpose Designed by Checked by Approved by

A 1 Sept. 04 IDC F. MARCEL H. CORRIGNAN Y. LE CARRER

B 15 Oct. 04 IFR F. MARCEL H. CORRIGNAN Y. LE CARRER

C 22 Fev. 05 IFR F. MARCEL H. CORRIGNAN Y. LE CARRER

D 13 July. 05 IFA F. MARCEL H. CORRIGNAN Y. LE CARRER

E 07 Oct. 05 IFA F. MARCEL P-A.THOMAS H. CORRIGNAN Y. LE CARRER

TPFR Report No.: 11771V-009-JSD-3500-001-Rev. E

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DOCUMENT TITLE: FLEXIBLE PIPE DESIGN PREMISE

REV NO. REVISED SECTION PARA NO. DESCRIPTION OF CHANGES

P03 2 1 References added

P03 2 2 Abbreviation added

P03 4 1 Table updated and reference added

P03 4 2.1 South 8’’ Flowline section lengths updated

P03 4 2.1 Gasket name updated

P03 4 2.3 Connection elevation at XT

P03 4 4 Vertebrae update

P03 4 5 Gasket modified and reference added

P03 4 6 Chemicals update

P03 6 1 Sentences added

P03 6 7 Section on selected anode added

P03 9 3 Installation section updated update

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CONTENTS

1 INTRODUCTION 7

1.1 PROJECT DESCRIPTION 7 1.2 PURPOSE OF DESIGN PREMISE 7

2 REFERENCES, STANDARDS AND SOFTWARE 8

2.1 REFERENCE 8 2.2 DEFINITIONS AND ABBREVIATIONS 11

2.2.1 DEFINITIONS 11 2.2.2 ABBREVIATIONS 11

2.3 DESIGN CODES AND STANDARDS 12 2.4 SOFTWARE 13

3 FIELD DESCRIPTION 14

3.1 DRILL CENTERS 14 3.2 WATER DEPTH 14

4 RISER AND FLOWLINE SYSTEM DATA 15

4.1 DESIGN CONDITIONS 15 4.2 LINE CONFIGURATION 16

4.2.1 8” PRODUCTION LINE 16 4.2.2 3” SERVICE LINE 17 4.2.3 4” PRODUCTION FLOWLINE AT DP3 17

4.3 TRANSPORTED FLUID CHARACTERISTICS AND PRODUCTION PROFILE 20 4.3.1 8” PRODUCTION LINE TRANSPORTED FLUID CHARACTERISTICS 20 4.3.2 8” PRODUCTION LINE PRODUCTION PROFILE 22 4.3.3 3” SERVICE LINE TRANSPORTED FLUID CHARACTERISTICS 26 4.3.4 4” PRODUCTION LINE TRANSPORTED FLUID CHARACTERISTICS 26

4.4 VERTEBRAE DESIGN 26 4.5 END FITTINGS DESIGN 27 4.6 CHEMICAL INJECTION REQUIREMENTS 29 4.7 PIGGING PHILOSOPHY 29 4.8 TESTING 29

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5 ENVIRONMENTAL DATA 30

5.1 WAVES AND CURRENT DATA 30 5.1.1 ONE YEAR RETURN PERIOD 30 5.1.2 100-YEAR RETURN PERIOD 30 5.1.3 WAVE CHARACTERISTICS FOR FATIGUE ANALYSIS 31

5.2 WAVE THEORIES 31 5.3 WATER DEPTH 32 5.4 SEAWATER PROPERTIES 32 5.5 TEMPERATURES 32 5.6 SOIL DATA 33

5.6.1 SOIL CHARACTERISTICS 33 5.6.2 TRENCHING 33

5.7 MARINE GROWTH 34 5.8 SUNLIGHT EXPOSURE 34 5.9 HYDRODYNAMICS COEFFICIENTS 34

6 CATHODIC PROTECTION SYSTEM 35

6.1 GENERAL 35 6.2 CURRENT DENSITIES 35 6.3 SEAWATER RESISTIVITY 35 6.4 UTILISATION FACTOR 36 6.5 ANODE CHARACTERISTICS 36 6.6 EXPOSED AREAS 36 6.7 SELECTED ANODE TYPE 37

6.7.1 4’’ PRODUCTION LINE 37 6.7.2 8” PRODUCTION RISER & FLOWLINES FROM SSIV TO IC 37 6.7.3 3’’ SERVICE LINE & 8” PRODUCTION FLOWLINES FROM IC TO PLEM37

7 ON BOTTOM STABILITY 38

8 IN PLACE ANALYSIS 39

8.1 8” PRODUCTION LINE IN PLACE ANALYSIS 39 8.2 3” SERVICE LINE IN PLACE ANALYSIS 39

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9 INSTALLATION 40

9.1 INSTALLATION DYNAMIC AMPLIFICATION FACTOR 40 9.2 INSTALLATION TOLERANCES 40 9.3 CRUSHING CAPACITY 40

10 STATIC / SENSITIVITY ANALYSIS 41

10.1 INTRODUCTION 41 10.2 STATIC LOAD CASE MATRIX 41 10.3 SENSITIVITY ANALYSIS 42

11 FATIGUE ANALYSIS 43

12 INTERFERENCE ANALYSIS 43

APPENDIX A 8” PRODUCTION RISER I TUBE ASSEMBLY 44 APPENDIX B 3” SERVICE LINE RISER J TUBE ASSEMBLY 46 APPENDIX C OVERALL FIELD LAYOUT 48 APPENDIX D JACKET ELEVATION AT ROW 10 53 APPENDIX E END TERMINATION OF THE 4” PRODUCTION FLOWLINE AT DP3 56 APPENDIX F BOURI FIELD EAD: AXIAL & LATERAL PIPELINE RESISTANCE 59

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1 INTRODUCTION

1.1 PROJECT DESCRIPTION Technip France (TF) has been awarded an EPCI contract from AGIP Oil Company Limited, Libyan Branch (COMPANY) for flowlines, riser system, SSIV’s and umbilicals which form the basis of Work Package No2 associated with the overall extension of the the Bouri East Area Development located in Block NC-41, 120km offshore Libya in the Mediterranean Sea. The development shall include the tie-back of a subsea well cluster to the existing platform DP4 with water depths at the site ranging from 170-185m LAT. The cluster itself shall contain 4 wellheads centred around a PLEM structure located some 3.6km from the platform. The tie-back shall consist of 2 off Flexible Production flowlines and 1 off Flexible Service flowline between the DP4 platform and PLEM. In addition an electro/hydraulic umbilical shall be installed for control of both the PLEM and wellheads. The wellheads will be connected to the PLEM via rigid spools and controlled via flying leads. An SSIV structure will be required approx 100m from the DP4 platform. The two production lines shall be connected to this structure and linked via riser sections to the platform. Control of the SSIV will be made via a dedicated umbilical from the platform. The scope of work shall also involve the provision of twin I-Tubes, clamps and J-tube extensions on the platform as well as tie-in, spool installation, trenching, mattress laying, and pre-commissioning. Also included will be the recovery and replacement of an existing 4” flexible flowline at the Bouri DP3 platform area.

1.2 PURPOSE OF DESIGN PREMISE

The purpose of this design premise is: • To list main design data, environmental data and field layout information

necessary to complete the detailed design of the flexible lines. • To summarize the applicable codes and standards. • To outline a methodology for the detailed global design of the riser system. • To present the load matrix for the static analysis that will be performed during

detailed design.

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2 REFERENCES, STANDARDS AND SOFTWARE

2.1 REFERENCE The COMPANY Specifications and Drawings concerning flexible pipe will be used to perform the required flexible engineering work.

Document Reference (2) Ref Title

342700 BTSG 53776 A1 Scope of work

342700 FURB 54002 A2 Design premise

342700 BTST 53774 A3 Technical specification for engineering procurement, construction and installation

342700 BTST 53755 A4 Technical specification for corrosion laboratory testing for flexible pipe

342700 BTST 53779 A5 Corrosion control of vessel and pipelines during hydraulic tests, inactivity, shut down and cleaning operations

342700 BTSG 53757 A6 General specification, flexible pipes and risers for submarine applications

342700 BTSG 53768 A7 General specification, sacrificial anodes for sealines and risers

342700 BTSG 53772 A8 Cathodic protection system

342700 BPRA 18001 A9 Steady state hydraulic analysis

342700 BPRA 18002 A10 Flow assurance report – operation transient analysis

342700 BOFI 41007 A11 Flexible risers - “I” tube assembly

3414/JL/115790/1B A12 Jacket – risers and “J” tubes detailes “D” “E”

3414/JL/115575/1B A13 Jacket elevation at “10” – Lower side

3414/JL/115576/1B A14 Jacket elevation at “10” –Upper side

PK 10926 002 A15 4” End Fitting – Hub GRAYLOC 5 GR for Seal Ring 40

PK 10926 026 A16 4” End Fitting – 4” 1/16 Swivel Flange (API 17 SV 5000P) for Gasket SBX 155

IDP AOL001 A17 Sealine Survey DP4-B4-43SS Final Report

3427-130-D-DG-FMC-00048 A18 BOURI PLEM Piping GA Sheet 6 of 6

3427-800-D-DG-FMC-00020 A19 Subsea HXT Layout Field Layout

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3427-130-SP-FMC-00442 A20 Design Specification PLEM Specification

720705 A21 Well B3-26 Reservoir Oil Study

3414/JL/115784/1B A22 Jacket – Riser Future Location on row 10

06-2202-01-U-0-060-01 A23 Bouri PLEM 8” NB & 4” NB Jumper interface Tie-in spool general arrangement.

Table 2.1 a – Company specifications Notes:

1) BS 8010 part 3 “Pipelines Subsea; Design, Consctruction and Installation” is considered by CONTRACTOR as not applicable.

2) Refer to latest revision Others documents will be used:


11771 B1 Technical Qualifications / Clarifications / Queries

2030926 B2 Subsea wells project BOURI phase 2, Design Premise

2830926 B3 Subsea wells project BOURI phase 2, Flexible pipe design report

Negotiation meeting 24 May to 27 May 2004 B4 Minute of meeting

FAX N° TC5323, 5th July 2003 B5 Clarifications

B6 General Field Layout

B7 Platform & SSIV Laydown Area 11771V-DW-3724-0002 3427-000-D-DG-TPF-00001

B8 PLEM Laydown Area

11771V-DW-3731-0002 3427-800-S-DA-TPF-00020 B9 I-Tube Assembly Drawing (Dual I-Tube Arrangement)

MGS 70.002/02 B10 Offshore Geotechnical Investigation Final Report

11771V-020-RT-3690-001 3427-150-S-RT-TPF-00001 B11 Survey Report – Pre-Engineering Survey Services

11771V-DW-3725-0001 3427-880-S-DA-TPF-00011 B12 SSIV Structure – GA

Interface: E/TPF/FMC/052 B13 BOURI PLEM 35Deg spools

11771V-009-RT-3510-006 3427-150-P-RT-TPF-00006 B14 Hydraulic And Therrmal Analysis

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Document Reference (1) Ref Title 11771V-009-RT-3500-007 3427-150-P-RT- TPF-00014 B15 3” Service Line Inplace Analysis

FX / AOC / TPF / 0161 B16 3” Pipeline Trenching and Leak Test Pressure

IQ-TPF-FMC-091 B17 PLEM Cathodic Protection System

11771V-009-RT-3500-018 3427-150-P-RT-TPF-00028 B18 8” Production Line Inplace Analysis

11771V-010-RT-3600-002 3427-000-I-CA-TPF-00001 B19 Line Lengths Calculation

FX / AOC / TPF / 0300 B20 Installation of 35° Spools with PLEM

FX / AOC / TPF / 0299 B21 3’’ Pipeline Offshore Pressure Testing

11771V-DW-3730-0011 3427-150-S-DG-TPF-00012 B22 Track Chart, Cross Profile and Longitudinal Profile

TQ-TPF-AOC-0015 B23 Chemicals to be used in the Flexible Line

FX/AOC/TPF/0297 B24 Chemicals to be used in the Flexible Line

11771V-009-QCP-3511-003 3427-150-P-QA-TPF-00003 B25 8’’ Production Flowline Manufacturing Quality Plan

11771V-009-QCP-3511-004 3427-150-P-QA-TPF-00004 B26 8’’ Production Riser Manufacturing Quality Plan

Table 2.1 b – Others documents Notes: 1) Refer to latest revision

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2.2 DEFINITIONS AND ABBREVIATIONS

2.2.1 DEFINITIONS

In this document: COMPANY will designate AGIP Oil Company Limited, Libyan Branch. (AOC) CONTRACTOR will designate Technip France CSO SURF. (TPFR)

2.2.2 ABBREVIATIONS API : American Petroleum Institute DAF : Dynamic Amplification Factor EAD : East Area Development FTHP : Flowing Top Hole Pressure FBHP : Flowing Bottom Hole Pressure IC : Intermediate Connection ID : Internal Diameter LAT : Lowest Astronomical Tide MBR : Minimum Bending Radius PI : Datum Pressure (Corresponding to SBHP) PLEM : Pipe-Line End Manifold PMV : Produced Master Valve PVDF : Polyvinylidene Fluoride PWV : Production Wing Valve SBHP : Static Bottom Hole Pressure SSIV : Subsea Isolation Valve

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2.3 DESIGN CODES AND STANDARDS Flexible flowlines and risers will be designed in accordance with the following codes and standards:

Document Reference Ref. Title

API SPEC 17J C1 Specification for Unbonded Flexible Pipe

Veritec RP E305 C2 On-Bottom Stability Design of Submarine Pipelines

DNV RP B401 C3 Cathodic Protection Design

Table 2.3 a – Codes and Standards The following codes and standards can also be referred:

Document Reference Ref Title

NACE TM 0177 D1 Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking and Stress Corrosion Cracking in H2S Environments

API RP 17B D2 Recommended practice for Flexible Pipe (March 2002)

API17 TR2 D3 The Ageing of PA-11 in Flexible Pipes-First Edition

API RP 2RD D4 Design of Risers for Floating Production Systems and Tension-Leg platforms

API 17D D5 Specification for Subsea Wellhead and Christmas Tree Equipment

DNV OS-F101 2000 D6 Design Rules for Submarine Pipeline Systems

DNV Classification Note 30.5 D7 Environmental conditions and environmental loads (March

2000)

ASME B 31.8 D8 Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids

ASME B 16.5 D9 Pipe Flanges and Flanged Fittings NPS 1/2 Through NPS 24 Metric/Inch Standard

API RP 2SK D10 Recommended Practice for Design and Analysis of Stationkeeping Systems for Floating Structures

05 MET 122 rev 4 D11 Protection against corrosion of end-fittings and ancillary equipment by painting.

NACE TM 0284 D12 Evaluation of pipeline and Pressure Vessel Steels for Resistance to Hydrogen-Induced Cracking

Table 2.3 b – Codes and Standards

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2.4 SOFTWARE The softwares that will be employed for the design of the Bouri Field - EAD flowline are: • STRUCTURE : Design of the flexible structure • COLLAPSE : Calculation of collapse resistance • EFLEX : Stress calculation • THERM : Thermal calculation • PROCAT : Cathodic protection design • SLPM : Fatigue in pressure vault layers • LIFE : Fatigue in armour layers • PARABAQ : Crushing capacities • STABIL : Flowline stability on the seabed • TRENCH COAT : Upheaval Buckling phenomena study • EFNA2 : Design of flexible End-Fittings • MOLDI : Determination of the annulus fluid composition • PH : Calculation of the pH in the annulus or in the bore The analysis of the dynamic behaviour of the Flowline will be done with DEEPLINES or FLEXCOM3D software.

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3 FIELD DESCRIPTION

3.1 DRILL CENTERS The design co-ordinates of the drilling location, the PLEM and the "as installed" coordinates of the DP4 Platform are as follows:

Location UTM

WELL 1: B4-43 (B4-45 DIR) 3756426.16N 289184.85E

WELL 2: B4-44 (B4-46 DIR) 3756446.78N 289183.04E

WELL 3: B4-48 (B4-47 DIR) 3756447.84N 289195.15E

WELL 4: B4-50 (B4-48 DIR) 3756427.22N 289196.96E

PLEM 3756437 N 289190 E

DP4 Platform 3756116.92 N 285604.59 E

Table 3.1 a – Drilling locations (Ref./A19/ and /A2/) They are approximately located 3.6 km far from DP4 Platform. The general layout of the field is shown in Appendix [C] (Ref./B6/, /B7/, /B8/).

3.2 WATER DEPTH The water depths considered for the flowline system analysis are presented in the table below:

Localisation Water depth (m)

PLEM 181.0

SSIV 171.0 (1)

DP4 Platform 170.5 Table 3.2 a – Water Depth

Note: 1) Estimated value from Ref./B6/

The seabed is regular with a slope of 0.16° (assumed from Ref./A17/) decreasing from the DP4 Platform to the PLEM.

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4 RISER AND FLOWLINE SYSTEM DATA The purpose of this section is to present the relevant data taken in consideration for the riser and flowline design.

4.1 DESIGN CONDITIONS The following data have been extracted from COMPANY Design Premise (Ref./A2/) and CONTRACTOR Design Premise (Ref./B2/), findings from the Flow Assurance study will also be considered (Ref./B14/):

8” Production Properties Static riser Flowlines

3’’ Service line

4” Production flowline

Pipeline size 8” ID 8” ID 3” ID 4” ID Design life 25 years 25 years 25 years 20 years

Design pressure 175 bar 175 bar 345 bar 175 bar Operating pressure 29 bar 36 bar 250 bar (2) 124 bar

Factory test pressure 263 bar 263 bar 518 bar 263 bar Offshore test pressure 219 bar 219 bar 345 bar (1) 219 bar Design temperature 110°C 110°C 25°C 110°C

Operating temperature 91.6°C 113.2°C 25° C 110°C Trenching pressure N/A N/A 345 bar N/A Well Killing Pressure N/A N/A 276 bar (3) N/A

Table 4.1 a – Design conditions Notes: 1) Requirement from Ref./B15/ and Ref./B16/. 2) As per Ref./B16/ 3) As per Ref./B21/ As mentioned by COMPANY in Ref./A9/ a target U-value of 6 W/m.K for the flowline and 10 W/m.K for the riser will be considered in order to reach an arrival temperature of the crude oil at the platform DP4 in all production profile above the WAX Temperature (WAT), taken as 36°C as per Ref./B14/. All combinations of production scenarios: 2 wells per flowline, 3+1, 4+0 will be considered (Ref./A1/) in the flow assurance study (Ref./B14/). CONTRACTOR understands that the -30°C temperature level specified by COMPANY concerns the well bore. The temperature at the pressure sheath crimped in the end-fitting body will be certainly higher. The results from the related full scale tests confirm that the considered PVDF crimping is guaranteed at a temperature level above -5°C. (Ref./B1/ Item 82)

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4.2 LINE CONFIGURATION 4.2.1 8” PRODUCTION LINE

The nominal lengths are, as per Ref./B25/ for flowlines and Ref./B26/ for risers:

NFL01 SFL01 NFL02 SFL-02 SR & NR Nominal length 1793m 1813m 1782m 1775m 299m

Table 4.2.1 a – Nominal lengths The general arrangement at top side of the 8” Production Riser will be taken as specified in Appendix [A] (Ref./A12/). From the end of the I-Tube to the seabed the riser will be clamped to the DP4 Platform at various locations along its length as detailed in Ref./A22/. Due to this assembly only static line will be designed. The application of this line is SOUR service. Flow Assurance study (Ref./B14/) outcomes on the fluid internal temperature lead to the requirement of PVDF for the pressure sheath material of the 8” Production Flowline and riser. The flowline will be buried or mattress covered along the majority of the route depending on the inplace analysis results given in Ref./B18/. The following connection elevations have been considered:

• 0.780m as per Ref./B12/ at Riser/SSIV and Flowline/SSIV connection • 3.060m as per Ref./A18/ at Flowline/PLEM connection

From Ref./A3/ and Ref./A1/ the flowline and riser system end termination interfaces are as follow: Connector type at Top:

8” ND Grayloc connectors type, 1500lb Inconel 625 Fully Clad Connector type at SSIV piping:

Flange API 17D 9”, 5000psi, SBX157 Fully Cladded with Inconel 625

Swivel Connector type at the PLEM:

9” API 17D 17SS 5000psi WN Flange Bore, Face & Ring grooved clad with 3mm of UNS 06625 (Ref./B16/)

Spool angle is 35°. (Ref./B13/) Electrical insulation sealing is required at the connexion.

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4.2.2 3” SERVICE LINE The 3” Service Line riser will pass through a fixed J-tube as specified in Appendix [C] (Ref./A12/). Due to this assembly only static line will be designed. The nominal length of this line is 3890m (Ref./B19/). The flowline will be buried or mattress covered along the majority of the route depending on the inplace analysis results given in Ref./B15/. A connection elevation of 2.84m as per Ref./A18/ has been considered at Flowline/PLEM connection. From Ref./A3/ and /A20/ the flowline and riser system end termination interfaces are as follow: Connector type at top:

3” ND Grayloc connector, 5000psi connectors Ring groove Inconel 625 clad.

Connector type at the PLEM:

4 1/16” 5000psi API 17 D flange Inconel 625 partially clad. Spool angle is 35°. (Ref./B13/) Electrical insulation sealing is required at the connection.

The carcass of the flowline will be provided with Duplex raw material as specified in Ref./B1/ Item 77.

4.2.3 4” PRODUCTION FLOWLINE AT DP3 Due likely to fishing activities the external sheath of the str no. 101.10552 (Ref./B3/) linked to the B3-21 (Ref./B2/) well has been damaged. The overall flowline length to be replaced is 1320m (Ref./B2/). This section is from intermediate connection to wellhead. The new line overall length is 1332m as per Ref./B19/.

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The main physical and mechanical characteristics of this SOUR service flexible pipe are indicated in the following table.

N° LAYER DESCRIPTION UTS

(MPa) MYS

(MPa)Mass

(Kg/m) I.D.

(mm) Th.

(mm) SDP

(MPa)1 INTERLOCKED CARCASS

40.0 x 0.7 x 4.2 DUPLEX (FE 04) 660 - 5.69 101.60 4.20

2 PRESSURE SHEATH COFLON (TP 06) 3.68 110.00 6.00 3 FIRST ARMOUR LAY. 32C1 Y=700 (FI18)

24 Flat wires: 9 x 3 at -55.0 deg. 780 700 8.39 122.00 3.00 298

4 SECOND ARMOUR LAY 32C1 Y=700 (FI 18) 25 Flat wires: 9 x 3 at 55.0 deg.

780 700 8.74 128.00 3.00 273

5 HIGH STRENGTH TAPE G1/KV300/PROP 0.25 134.00 1.15

6 EXTERNAL SHEATH POLYETHYLENE (TP04) BLACK 1.89 136.30 4.50

THEORETICAL CHARACTERISTICS IMPERIAL METRIC

DIAMETER inside 4.00 in 101.60 mm DIAMETER outside 5.72 in 145.30 mm VOLUME internal 0.094 cf/ft 8.78 l/m VOLUME external 0.178 cf/ft 16.58 l/m WEIGHT in air empty 19.25 lbf/ft 28.64 kgf/m WEIGHT in air full of seawater 25.29 lbf/ft 37.64 kgf/m WEIGHT in seawater empty 7.82 lbf/ft 11.64 kgf/m WEIGHT in seawater full of seawater 13.87 lbf/ft 20.64 kgf/m SPECIFIC GRAVITY in sea water empty 1.69 1.69 PRESSURE Nominal bursting 5946 psi 410 bars HYDROSTATIC collapse pressure lay 2 1247 psi 86 bars DAMAGING PULL in straight line 53329 lbf 237.22 kN MINIMUM BENDING RADIUS for STORAGE 3.10 ft 0.94 m BENDING STIFFNESS at 20°C 16992 lbf.ft2 7.02 kN.m2 RELATIVE ELONGATION at design pressure 0.477831 % 0.477831 % THERMAL EXCHANGE COEFFICIENT at 20°C 4.36 Btu/hftF 7.55 W/m.K

Table 4.2.3 a – Structure no. 101.10552 data sheet

INTERNAL DIAMETER 4.00" SOUR SERVICE DESIGN PRESSURE 2538 psi 175 bars DESIGN TEMPERATURE 110 °C FACTORY TEST PRESSURE 3306 psi 228 bars FTP/DP 1.50

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The designed End Fittings are as follows: Flexible End Fitting at Xmas tree:

4” 1/16 FLANGE API 17D SV 5000 psi for gasket SBX 155 Standard Anode Connection See Appendix D (Ref./A15/)

Flexible End Fitting at intermediate connection:

HUB GRAYLOC 5 GR 40 Nitrogen tests Gas Release Valves Standard Anode Connection See Appendix D (Ref./A16/)

Bend restrictors will have to be provided at the Xmas tree end of the line. (Ref./A3/ page 43) if deemed required. Flowline/X-Tree connection elevation has been considered as 2.2m (Ref./B22/).

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4.3 TRANSPORTED FLUID CHARACTERISTICS AND PRODUCTION PROFILE

4.3.1 8” PRODUCTION LINE TRANSPORTED FLUID CHARACTERISTICS The following data are obtained from Ref./A2/. The fluid which will be transported through the 8” Flexible Production Flowline is sour crude oil with gas and water formation. Properties are given below: - Oil specific gravity : 0.904 (surface condition) - Water specific gravity : 1.032 (surface condition) Reservoir fluid composition from Ref./A21/ Chemical composition of Reservoir Oil Sample

Component Mole % Density (1)

Hydrogen Sulphide 0.32 Carbon Dioxyde 28.68

Nitrogen 3.87 Methane 18.63 Ethane 3.47

Propane 3.38 Iso-Butane 0.69 n-Butane 1.93

Iso-Pentane 1.11 n-Pentane 0.89 Hexanes 2.34 713.0 Heptanes 2.26 749.0 Octanes 2.41 768.0 Nonanes 2.45 784.0 Decanes 2.18 779.0

Undecanes 1.22 793.0 Dodecanes 1.46 804.0

Tridecanes Plus 22.71 924.0 Total 100

Table 4.3.1 a – Reservoir fluid composition Note: 1) kg/m3 at 60°F

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Formation Water Composition The presence of at least two different formation/waters causes the production of water with a wide range of characteristics. The maximum and minimum values encountered are listed below:

MAX MIN pH(@ room pressure and temperature) 7.12 (P) 5.65 (L) H = Well B4-16 Salinity (NaCl), mg/l 67.390 (O) 38.890 (L) L = B4-24 Alkalinity (Bicarbonate), mg/l 1535 (L) 752 (H) Na, mg/l 22.899 (O) 12.685 (L) N = B4-26 K, mg/l 420 (H) 169 (L) Ca, mg/l 2285 (O) 552 (L) P = B3-20 Mg, mg/l 405 (O) 73 (L) Ba, mg/l 5.6 (O) 1.7 (H) O = B3-05 Sr, mg/l 349 (O) 113 (L) Fe, mg/l 12 (H) 0.7 (K) Mn 1.3 (H) 0.12 (P) NH4, mg/l 817 (L) 78 (O) SiO2 140 (H) 118 (K) Cl, mg/l 40.876 (O) 22.378 (L) SO4 mg/l 328 (O) 174 (H) HCO3 1.263 (N) 351 (H) F, mg/l < 30 < 9 Br, mg/l 210 (O) 108 (L) I, mg/l 23 (N) 15 (L) H3BO3 701 (P) 433 (H) Relative density, at 60/60°F 1.0487 (O) 1.0294 (L) Resistivity, Ohm-m @ 20°C 0.12 (O) 0.18 (L)

Table 4.3.1 b – Formation water composition

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4.3.2 8” PRODUCTION LINE PRODUCTION PROFILE The 8” Production Line profiles are shown in the following tables.

B4-43ER (B4-45 DIR) Oil Gas Water SBHP FBHP FTHP P1 Year

STB/D MSCF/D B/D (PSIA) (PSIA) (PSIA) (STB/D/PSIA) 2005 3.499,0 2.414,9 0,6 3.351,4 2.846,5 661,2 8,3 2006 3.499,0 2.575,2 1,0 3.237,0 2.703,9 585,5 8,0 2007 3.495,3 2.560,2 4,7 3.169,5 2.627,6 545,1 7,9 2008 3.484,5 2.485,5 15,5 3.140,5 2.589,8 515,1 7,7 2009 3.452,2 2.457,5 47,8 3.109,9 2.528,1 473,1 7,2 2010 3.404,5 2.320,1 95,5 3.087,4 2.371,8 367,4 5,6 2011 3.357,1 2.207,8 142,9 3.084,4 2.333,8 331,5 5,2 2012 3.231,9 2.107,5 200,0 3.079,8 2.299,0 300,5 5,0 2013 3.060,1 1.993,0 256,6 3.075,0 2.293,8 300,0 4,7 2014 2.936,7 1.955,5 316,6 3.089,9' 2.288,5 300,0 4,4 2015 2.812,8 1.781,4 375,0 3.100,7 2.301,9 300,0 4,2 2016 2.669,8 1.673,8 434,6 3.103,0 2.313,3 300,0 4,1 2017 2.529,1 1.573,1 496,2 3.104,5 2.316,8 300,0 3,9 2018 2.380,4 1.467,0 568,3 3.113,9 2.326,1 300,0 3,7 2019 2.180,4 1.342,1 647,0 3.127,3 2.349,3 300,0 3,5 2020 1.986,5 1.223,7 725,4 3.139,1 2.372,4 300,0 3,2 2021 1.815,0 1.120,3 808,3 3.152,8 2.397,0 300,0 2,9 2022 1.673,9 1.037,7 889,2 3.169,9 2.425,0 300,0 2,7 2023 1.521,4 946,8 944,9 3.186,2 2.451,3 300,0 2,6 2024 1.361,7 850,3 975,1 3.199,7 2.494,7 300,0 2,4 2025 1.230,0 770,7 1.001,0 3.211,9 2.538,7 300,0 2,2 2026 1.118,4 703,2 1.026,1 3.223,1 2.578,8 300,0 2,1 2027 1.020,5 643,0 1.045,4 3.232,3 2.614,5 300,0 2,0 2028 914,8 576,8 1.043,7 3.241,3 2.652,2 300,0 1,9 2029 822,0 519,7 1.037,1 3.251,1 2.697,2 300,0 1,8 2030 739,0 468,8 1.045,6 3.259,5 2.744,3 300,0 1,7 2031 670,3 424,5 1.033,4 3.266,3 2.787,3 300,0 1,7 2032 604,4 384,2 998,1 3.278,6 2.847,6 300,0 1,7 2033 551,9 352,1 969,6 3.287,1 2.892,0 300,0 1,7 2034 379,9 242,9 702,2 3.293,5 2.927,9 300,0 1,7 2035 0,0 0,0 0,0 3.329,3 - - -

Table 4.3.2 a – Well B4-43 (B4-45 DIR) Production profile

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B4-44 ER (B4-46 DIR)

Oil Gas Water SBHP FBHP FTHP P1 Year STB/D MSCF/D B/D (PSIA) (PSIA) (PSIA) (STB/D/PSIA)

0,0 2005 3.499,6 2.819,9 0,4 3.277,6 3.013,8 876,0 17,0 2006 3.499,5 4.928,7 0,5 3.277,6 3.013,8 876,0 17,0 2007 3.499,3 6.323,2 0,7 3.208,1 2.922,5 993,6 16,3 2008 3.498,5 7.445,4 1,5 3.176,5 2.884,0 937,0 16,2 2009 3.495,0 9.276,7 5,0 3.138,0 2.829,9 823,3 15,7 2010 3.484,1 8.392,5 15,9 3.113,2 2.785,8 745,8 14,9 2011 3.451,1 7.639,2 48,9 3.115,9 2.766,3 792,6 13,4 2012 3.335,0 7.519,5 165,0 3.107,6 2.692,9 725,3 10,8 2013 2.860,0 6.529,2 640,0 3.097,1 2.619,9 637,3 8,6 2014 2.261,6 4.975,4 1.238,4 3.101,4 2.562,1 551,1 5,7 2015 1.957,3 3.972,7 1.542,7 3.110,1 2.584,2 524,8 4,9 2016 1.758,6 3.136,3 1.741,4 3.112,8 2.611,1 490,4 4,5 2017 1.638,9 2.391,1 1.861,1 3.116,6 2.644,2 486,4 4,4 2018 1.550,0 1.715,6 1.950,0 3.129,5 2.687,3 397,2 4,4 2019 1.391,3 1.230,9 1.927,6 3.143,5 2.723,9 312,0 4,3 2020 975,7 655,6 1.539,7 3.159,4 2.813,6 300,0 4,3 2021 282,2 174,8 547,9 3.189,6 2.992,9 300,0 4,1 2022 0,0 0,0 0,0 3.240,1 - - -

Table 4.3.2 b – Well B4-44 (B4-46 DIR) Production profile

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B4-48ER (B4-47 DIR)


2005 2.631,5 1.723,0 5,5 3.265,1 2.724,1 582,1 7,6 2006 3.445,0 2.277,2 55,0 3.265,1 2.724,1 582,1 7,6 2007 3.314,4 2.192,2 185,6 3.207,2 2.474,5 414,5 5,3 2008 3.120,0 2.067,9 338,5 3.179,7 2.382,2 334,9 4,6 2009 2.792,6 1.854,5 459,2 3.157,3 2.335,0 300,0 4,0 2010 2.566,5 1.682,6 544,1 3.142,1 2.330,3 300,0 3,7 2011 2.414,2 1.562,6 599,4 3.140,7 2.338,6 300,0 3,5 2012 2.280,6 1.470,3 642,6 3.140,8 2.351,4 300,0 3,4 2013 2.170,3 1.391,1 683,0 3.137,9 2.360,5 300,0 3,2 2014 2.106,8 1.336,1 722,7 3.141,9 2.376,5 300,0 3,1 2015 2.036,3 1.290,3 757,9 3.151,1 2.392,2 300,0 3,1 2016 1.955,3 1.239,8 788,6 3.150,4 2.400,4 300,0 3,0 2017 1.888,8 1.194,6 818,0 3.150,4 2.408,9 300,0 2,9 2018 1.841,2 1.159,2 850,0 3.155,0 2.419,6 300,0 2,9 2019 1.795,8 1.129,0 884,8 3.164,6 2.433,2 300,0 2,8 2020 1.748,8 1.099,1 922,1 3.172,8 2.445,4 300,0 2,8 2021 1.707,0 1.072,9 959,2 3.181,9 2.459,6 300,0 2,7 2022 1.663,2 1.046,6 987,9 3.192,2 2.475,8 300,0 2,7 2023 1.609,1 1.015,7 1.014,9 3.204,8 2.495,4 300,0 2,6 2024 1.554,0 983,8 1.040,3 3.214,9 2.514,3 300,0 2,5 2025 1.511,2 959,2 1.063,3 3.223,9 2.531,3 300,0 2,5 2026 1.468,5 934,3 1.081,7 3.232,2 2.546,6 300,0 2,5 2027 1.421,7 906,2 1.096,9 3.239,6 2.562,5 300,0 2,4 2028 1.374,2 877,7 1.113,3 3.246,6 2.579,4 300,0 2,4 2029 1.335,3 854,7 1.130,7 3.254,0 2.595,3 300,0 2,3 2030 1.299,8 833,6 1.149,1 3.260,1 2.611,0 300,0 2,3 2031 1.271,9 816,5 1.169,7 3.265,3 2.626,3 300,0 2,3 2032 1.249,7 804,3 1.194,2 3.273,8 2.642,2 300,0 2,2 2033 1.223,0 788,7 1.215,5 3.280,1 2.657,1 300,0 2,2 2034 1.195,2 771,1 1.236,2 3.284,7 2.671,7 300,0 2,2 2035 1.207,2 780,2 1.274,4 3.296,2 2.688,6 300,0 2,2 2036 1.195,4 777,1 1.301,2 3.311,3 2.700,4 300,0 2,2 2037 1.165,8 759,3 1.319,3 3.316,8 2.712,6 300,0 2,2 2038 1.129,1 736,3 1.338,7 3.320,4 2.725,0 300,0 2,2 2039 1.092,3 713,3 1.382,5 3.323,7 2.745,0 300,0 2,2

Table 4.3.2 c – Well B4-48 (B4-47 DIR) Production profile

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B4-50 ER (B4-48 DIR)


0,0 2005 1.764,2 3.215,8 0,2 3.237,8 2.942,5 925,4 15,6 2006 3.334,5 12.977,1 0,6 3.237,8 2.942,5 925,4 15,6 2007 2.742,8 15.100,0 0,6 3.160,7 2.809,4 300,0 11,4 2008 2.635,5 15.169,8 0,6 3.130,3 2.784,6 300,0 10,3 2009 2.672,9 14.837,0 0,7 3.098,7 2.762,1 300,0 10,7 2010 2.777,6 14.449,1 0,9 3.071,7 2.742,3 300,0 11,1 2011 3.107,3 13.643,2 1,5 3.066,2 2.734,9 300,0 11,9 2012 3.466,1 12.579,2 2,4 3.055,2 2.724,2 300,0 13,7 2013 3.496,2 10.763,7 3,8 3.043,3 2.722,8 502,2 14,9 2014 3.494,2 8.586,4 5,7 3.054,8 2.738,6 700,2 14,8 2015 3.491,7 6.993,9 8,3 3.064,4 2.747,0 781,8 14,5 2016 3.487,8 6.341,3 12,1 3.066,4 2.744,1 817,8 14,1 2017 3.482,6 5.856,9 17,4 3.067,5 2.736,8 826,5 13,5 2018 3.475,8 5.109,1 24,2 3.080,6 2.742,0 851,1 13,0 2019 3.466,9 4.540,3 33,1 3.095,0 2.748,1 819,2 12,5 2020 3.455,9 4.044,5 44,1 3.107,0 2.748,1 758,9 11,9 2021 3.444,5 3.548,1 55,5 3.125,8 2.754,5 717,2 11,3 2022 3.436,4 3.059,8 63,7 3.154,7 2.784,8 689,2 11,2 2023 3.425,6 2.739,4 74,4 3.174,7 2.810,8 670,9 11,3 2024 3.409,3 2.583,6 90,7 3.187,3 2.826,4 660,3 11,4 2025 3.384,4 2.488,1 115,6 3.197,8 2.833,1 653,1 11,2 2026 3.353,1 2.408,5 146,9 3.207,4 2.837,6 645,1 10,9 2027 3.317,5 2.337,7 182,5 3.215,3 2.839,9 636,3 10,6 2028 3.277,0 2.272,1 223,0 3.223,0 2.844,7 628,5 10,4 2029 3.220,4 2.215,0 279,6 3.230,9 2.849,1 620,5 10,2 2030 3.150,3 2.159,7 349,7 3.237,3 2.846,2 606,1 9,8 2031 3.066,1 2.113,6 433,9 3.244,1 2.839,5 588,3 9,2 2032 2.970,7 2.082,1 529,3 3.258,3 2.834,8 573,4 8,5 2033 2.878,4 2.024,8 621,6 3.265,2 2.822,2 553,3 7,8 2034 2.791,2 1.942,0 708,8 3.270,1 2.812,2 530,4 7,3 2035 2.714,0 1.854,8 786,0 3.279,7 2.813,2 508,3 7,0 2036 2.631,5 1.788,0 868,5 3.293,7 2.818,5 491,6 6,6 2037 2.546,7 1.721,7 953,3 3.299,8 2.815,1 471,3 6,3 2038 2.464,9 1.656,7 1.035,1 3.303,8 2.810,1 451,0 6,0 2039 2.385,3 1.594,6 1.114,7 3.307,5 2.805,4 432,4 5,7

Table 4.3.2 d – Well B4-50 (B4-48 DIR) Production profile

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4.3.3 3” SERVICE LINE TRANSPORTED FLUID CHARACTERISTICS As specified in Ref./A2/ the Service Line is provided to allow general well services/operational intervention (flushing, depressurisation, well killing, etc…) Fluid transported characteristics are as per clarification received during the tender phase and are summarised as follows (Ref./B5/): - Diesel, - Sea water - Glycol / Methanol (occasionally) - Completion fluid - Produced Fluid from reservoir (occasionally) CONTRACTOR will calculate the maximum time of exposure to the occasional fluids (i.e Glycol/Methanol) produced fluid from reservoir.

4.3.4 4” PRODUCTION LINE TRANSPORTED FLUID CHARACTERISTICS The same fluid reservoir composition as the one of the 8” Production Line will be considered (see § 4.3.2).

4.4 VERTEBRAE DESIGN This section describes the vertebrae design philosophy if they are deemed required. The aim of the vertebrae, or bend restrictors, is to lock the flexible pipe at a radius above its Minimum Bending radius allowed during installation or production. They are constituted of interlocked rings (plastic) in 2 parts. Generally, this MBR is taken equal to MBR for storage or the Minimum radius to avoid any crushing in the line. The flexible pipe locked in the vertebrae is considered as static, therefore, as per API 17J, the vertebrae radius can be chosen equal to 1 time the MBR. Contractor design their vertebrae with 1.5 times the MBR but restrictions due to the reel radius will be considered if they are not installed offshore. Vertebrae are structurally checked against the bending moment induced by the flexible line catenary tension.

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4.5 END FITTINGS DESIGN The end-fitting provides the link between the flexible pipe structure and the termination. It fulfils the following main functions: - To seal the external and the intermediate plastic layers of the flexible pipe

structure. - To anchor the tensile armours to ensure the transmission of the axial loads to

the support structure. - To allow the fitting of a pulling / laydown head for the initiation and laydown

purposes. The end-fitting can be thought of being comprised of three main parts: 1) The body: inside which the pipe layers are terminated. 2) The termination: the interfaces between adjacent structures, e.g. a flange or

a hub.

3) The neck: which connects the body to the termination. Each end-fitting body is designed to withstand an internal pressure equal to the bursting pressure of the flexible pipe structure to which it is attached. Materials for the end-fitting are chosen with full consideration of the composition, temperature, pressure and fluid velocities of the product to be transported. Diffused gas from the pipeline travels along the annulus formed between the pressure sheath and the external sheath to the end-fitting gas vent ports or gas release valves. The gas vent ports (on the risers topside end-fittings) are to be connected to the Jacket gas venting system. Each end-fitting design is completed following CONTRACTOR field proven design techniques utilizing the CONTARCTOR CAD system and the internal program EFNA2. The program validity has been established by extensive testing and is Bureau Veritas approved. The following End Termination type will be designed:

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Table 4.5 a – 8” Production line - End fittings

PLEM connection DP4 Platform

connection

3" Service Line 4" 1/16 API Flange 17SV

Swivel 5000 psi ISOLATION GASKET

GRAYLOC 4 GR 31

Table 4.5 b – 3” Service Line - End fittings

It can be noticed that all these terminations will be internal protected to corrosion with inconel 625 cladding. No tapering of any of the end-fittings to accommodate a change of inside diameter is envisaged. This is to be confirmed through interface communication. At the PLEM connection, current drainage from PLEM to Flowline will be avoided using “electrical insulation sealing” located at End fittings and 35°spools interface as per Ref./B20/.

PLEM connection Intermediate

connection SSIV connection DP4 Platform connection

8" Production Flowline

9” API Flange 17 SV Swivel 5000 PSI

ISOLATION GASKET

GRAYLOC 10 H 84

9” API Flange 17SS 5000 PSI

GASKET SBX157

GRAYLOC 10 H 84

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4.6 CHEMICAL INJECTION REQUIREMENTS The following chemicals are planned to be used in the 8” Production and 3” service Lines as per Ref./A2/B22/B23. Function Product Treatment

Dehydrate Glycol/Methanol When required

Scale Inhibitor NALCO EC-6146-A Continuous injection at a concentration of 2-10ppm of produced fluid

Baker Chemicals – Petrolite CF2237

Batch – at a concentration of 23% wt. diluted in Xylene(1)

Wax Inhibitor

NALCO Exxon EC6431A Batch – at a concentration of 7.5% wt diluted in Solvesso 150(1)

Bactericides/Corrosion Inhibitor EC-6210-A Short period of time after well start up and major workover at a concentration of 1.5%.

Oxygen scavenger EC-6303-A Short period of time after well start up and major workover at a concentration of 0.1%.

Table 4.6 a – Chemicals. Note: 1) Concentration of solvent – Solvesso and Xylene – could be ranged from 80-90%.

4.7 PIGGING PHILOSOPHY The dual 8” flowline system arranged in a loop through the PLEM will allow pigging, depressurisation and flushing of the flowlines. The flowline system will be designed to facilitate pigging operations, including gauging, dewatering and intelligent pigging. In this respect, ID changes shall be minimised and 5D radius bends shall be used (Ref./A3/ page 30). No pigging is required for the flexible flowlines less than 4" ID if these are laid filled with water. If these flexible flowlines are installed empty then out-of-roundness of the pipe internal section shall be checked through the passage of pigs of an adequate size before the hydrostatic testing (Ref./A2/).

4.8 TESTING Fresh water will be used for hydraulic test as per Item 47 of Ref./B1/ during the Factory and Offshore leak testing.

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5 ENVIRONMENTAL DATA

5.1 WAVES AND CURRENT DATA

5.1.1 ONE YEAR RETURN PERIOD As per Ref./A2/, 1-year return period waves are given in the following table:

Direction from which waves approach N NE E SE S SW W NW

Maximum wave height (m) 10.4 9.9 9.2 7.7 7.5 7.7 8.3 9.0 Significant wave height (m) 5.6 5.3 4.9 4.1 4.0 4.1 4.5 4.8

Minimum period (s) 8.2 8.0 7.7 7.1 7.0 7.1 7.3 7.6 Maximum period (s) 12.5 12.2 11.7 10.7 10.6 10.7 11.2 11.5 Significant period (s) 9.4 9.2 9.0 8.6 8.6 8.6 8.6 9.0

Table 5.1.1 a – Wave one year return period The associated current speed to be used for all directions is given in table 5.1.1 b, current profile will be considered linear between these water depths.

Depth (below LAT) Speed at sea surface 0.70 m/s at -86.0 m 0.30 m/s at seabed 0.30 m/s

Table 5.1.1 b – Associated current with one year return period

5.1.2 100-YEAR RETURN PERIOD As per Ref./A2/, 100-Year return period waves are given in the following table:

Direction from which waves approach N NE E SE S SW W NW

Maximum wave height (m) 16.5 15.7 14.6 12.2 11.9 12.2 13.1 14.3 Significant wave height (m) 8.8 8.4 7.9 6.6 6.4 6.6 7.0 7.7

Minimum period (s) 10.4 10.1 9.7 8.9 8.8 8.9 9.2 9.6 Maximum period (s) 15.7 15.4 14.8 13.5 13.4 13.5 14.0 14.6 Significant period (s) 11.4 11.2 10.8 10.0 9.9 10.0 10.3 10.7

Table 5.1.2 a – Wave 100 year return period The associated current speed to be used for all directions is given in table 5.1.1 b, current profile will be considered linear between these water depths.

Depth (below LAT) Speed at sea surface 1.10 m/s

at -86.0 m 0.50 m/s at seabed 0.40 m/s

Table 5.1.2 b – Associated current with 100 year return period

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5.1.3 WAVE CHARACTERISTICS FOR FATIGUE ANALYSIS The long term wave data to be used for fatigue analysis are reported in the following table with a total number of waves: 151 950 971

Wave height category Average height Average period m m s

No of waves

0-1 0.4 4.6 127 217 082 1-2 1.4 7.1 19 604 731 2-3 2.4 8.1 3 883 306 3-4 3.4 8.7 910 944 4-5 4.4 9.1 237 988 5-6 5.4 9.4 67 340 6-7 6.4 9.6 20 223 7-8 7.4 9.7 6334 8-9 8.4 9.8 2045

9-10 9.4 9.9 660 10-11 10.4 10.3 219 11-12 11.4 10.5 68 12-13 12.4 11.2 22 13-14 13.4 11.7 7 14-15 14.4 13.2 2

Total 151 950 971 Table 5.1.3a – Wave for fatigue analysis

5.2 WAVE THEORIES

The JONSWAP parameterization for wave spectral energy will be considered

Where the associated values of the alpha parameter can be determined using α = (5/16) ⋅ (Hs²ωp4/g²) ⋅ (1-0.287ln(γ)) From DNV Classification Notes 30.5, section 3.2.2. (Ref./D7/), as no further information was available and because of the relative insensitivity to the spectral shape, the JONSWAP width parameters are fixed at the mean JONSWAP experiment values of 0.07 and 0.09 for σa and σb, respectively. Linear Airy or Stokes 5th order wave theories will be used to evaluate the wave induced velocity near the seabed to be used for the on-bottom stability calculations.

−−−

− ⋅

⋅−=

2

..5.0exp4

5

45exp.²..)(

p

p

pgS

ωσωω

γωωωαω

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5.3 WATER DEPTH The chart datum corresponds to the Mean Low Water Springs. The still water depth during a storm is defined as the total of the chart depth, the storm tide and the highest astronomical tide, which are given below for the following location 33° 55' N, 12° 35' E: - Mean Low Water Springs : +0.00 m (chart datum) - Highest Astronomical Tide (HAT) : +0.79 m - Lowest Astronomical Tide (LAT) : -0.15 m - 1 Year Storm Tide : +0.18 m - 100 Years Storm Tide : +0.30 m The chart depth at the Bouri field location is between 168m and 188m.

5.4 SEAWATER PROPERTIES - Water density: 1026 kg/m3 - pH: 7.72 - Resistivity: 23 Ω.cm - Salinity: 36.6g/l - Oxygen content of the sea water (Ref./A2/):

O2 concentration at Surface 8 ppm O2 concentration at Seabed 7 ppm

5.5 TEMPERATURES

Max (°C)

Min (°C)

Seawater at surface 25.6 15.6 Seawater at seabed 13.9 7.0 Air 35.5 5.0

Table 5.5 a – Temperatures

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5.6 SOIL DATA

5.6.1 SOIL CHARACTERISTICS The shallow soils along the flexible routes consist primarily of very sandy SILT with inter-bedded layer of VERY SOFT to SOFT CLAY and numerous fine shell fragments. Details can be found in Appendix F. The marine sediment resistivity will be taken equal to 112 Ω.cm as per Ref./B10/. Axial and Lateral friction coefficients to be used are given in Appendix F. The soil thermal conductivity will be considered as 2.0 W/K.m as per Item 81 Ref./B5/.

5.6.2 TRENCHING The 8” Production Flowline and the Service Flowline will be trenched with a target trench depth to top of pipe equal to 0.6m from natural seabed level. For the Service Flowline due account will be given to upheaval buckling requirements during design to confirm the depth of lowering and the backfill level required. For the 8” Production Flowlines armouring angles have been adjusted so that within the manufacturing tolerances, structure always tend to shorten under pressure in order to avoid upheaval buckling out of the trench The natural backfill will be estimated according to Ref./A17/ and based on trenchability assessment following Pre-Engineering survey.

8’’ Production Riser trenching philosophy At DP4 the 8” Production Risers will not be trenched but will be mattresses covered up to the SSIV. At SSIV, several meters (depending on laydown curves) will be considered for the expansion zone.

8” production flowline trenching philosophy: The 8” production flowline will be laid on the seabed and mattress covered from DP4 Platform to the SSIV skid and then will be trenched between the SSIV skid and the PLEM as far as possible. At SSIV and PLEM connection several meters (depending on laydown curves) will be considered for trench transition, free span, expansion zone.

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3” service line trenching philosophy The Service Flowline will be laid on the seabed and mattresses covered from DP4 Platform to 100m and then will be trenched as far as possible up to the PLEM. At the PLEM connection several meters (depending on laydown curves) will be considered for trench transition, free span, expansion zone.

4’’ production flowline trenching philosophy At DP3 the 4” Production Flowline will not be trenched and will not be mattresses covered.

5.7 MARINE GROWTH The marine growth profile is presented below and the levels are relative to L.A.T.

Elevation (wrt to L.A.T) Thickness +2.0 m 0.05 m

-10.0 m 0.05 m

-70.0 m 0.01 m

Seabed 0.01 m Table 5.7 a – Marine growth thickness

Thickness of marine growth between the levels indicated above will be estimated by linear interpolation. Marine growth specific gravity in air has been taken equal to 1300 Kg/m3.

5.8 SUNLIGHT EXPOSURE Solar radiation 946 W/m2 (instant extreme) (Ref./A2/) The flexible lines will not be subjected to sunlight exposure after installation.

5.9 HYDRODYNAMICS COEFFICIENTS The hydrodynamics coefficients for flexible risers will be assumed as:

Coefficient Riser with marine growth

Riser without marine growth

Normal drag coefficient 1.2 0.9 Normal inertia coefficient 1.8 2.0

Table 5.9 a – Hydrodynamics coefficients

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6 CATHODIC PROTECTION SYSTEM

6.1 GENERAL Cathodic protection by sacrificial anodes is a common technique used to protect steel exposed to sea water; the system shall be designed to provide adequate protection during the whole design life of the lines. This protection system will be used to protect the flexible lines as well as the subsea end-fittings. This system has also been designed to cover the cathodic protection of the three 35° spools located at PLEM area (two for both 8’’ Production Flowlines and one for the 3’’ Service Line). According to Ref./B20/, isolation gaskets are located at Line/Spool interface and then the cathodic protection of these spools will be covered by the PLEM protection system. Nevertheless, the additional anode required for the spools cathodic protection will be kept as contingency. The anode current output should be checked in the initial and final stage. The final stage is considered to be when the anode is consumed to the utilization factor. When checking the anode lifetime a mean current density should be used. The cathodic protection design will be performed following DNV Recommended Practice DNV-RP-B401 (Ref./C3/). The calculations to determine anode quantities will be performed during detailed design phase using an "in-house" computer program called PROCAT based on DNV-RP-B401 recommendations (Ref./C3/).

6.2 CURRENT DENSITIES The current densities will be selected in agreement with DNV recommendations (Ref./C3/). As the yearly average surface water temperature at the BOURI EAD field location corresponds to the sub tropical area:

Untrenched area Depth 0-30m Depth >30m

Trenched area

Initial (A/m2) 0.17 0.15 0.020 Mean (A/m2) 0.08 0.07 0.020 Final (A/m2) 0.11 0.09 0.020

Table 6.2 a – Current densities

6.3 SEAWATER RESISTIVITY The current output of anodes is dependent on the resistivity of the seawater. The resistivity of the seawater is around 23Ω.cm as per Ref./A2/.

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6.4 UTILISATION FACTOR This utilisation factor depends on the shape of the anode; the choice of the utilisation factor is taken in agreement with DNV recommendations:

0.80 in case of bracelet anodes or short slender.

0.90 in case of long slender.

6.5 ANODE CHARACTERISTICS The anode material considered in this analysis is an indium activated tertiary aluminium alloy type, widely employed in offshore applications for pipelines containing products at high temperatures:

Element Max % Min % Zinc (Zn) 5.5 2.5 Indium (In) 0.040 0.015 Iron (Fe) 0.090 - Silicon (Si) 0.100 - Copper (Cu) 0.005 - Others (Each) 0.020 Aluminium (Al) Remainder

Table 6.5 a – Anode material characteristics The following electro-chemical properties are used: • Potential (Ag/AgCl) in seawater: 1050mV • Electrical efficiency: 2000 Ah/kg

6.6 EXPOSED AREAS The proposed cathodic protection is based on a damage area corresponding to a tear up percentage of the external surface of the flowline section. This breakdown factor has been set to a maximum of:

Breakdown factor Line Untrenched Trenched

4" Production Flowline 0.15% - 8" Production Flowline - 0.10%

8" Production riser 0.50% - 3" Service Flowline - 0.10%

Table 6.6 a – Exposed area

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6.7 SELECTED ANODE TYPE

6.7.1 4’’ PRODUCTION LINE Cathodic protection of the 4’’ Production Flowline will be covered by bracelet anode clamped on the line.

6.7.2 8” PRODUCTION RISER & FLOWLINES FROM SSIV TO IC Cathodic protection of both 8’’ Production Risers and both 8’’ Production Flowlines (sections form SSIV to IC) will be covered by long slender anodes welded on the SSIV protective structure.

6.7.3 3’’ SERVICE LINE & 8” PRODUCTION FLOWLINES FROM IC TO PLEM Cathodic protection for 3’’ Service Line and both 8’’ Production Flowlines (sections form IC to PLEM) will be covered by short slender anodes welded on a supporting skid connected to EF through jumper straps.

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7 ON BOTTOM STABILITY In order to ensure that the flexible pipeline resting on the seabed will be stable, on-bottom pipeline stability is checked with a computer program developed by CONTRACTOR, named STABIL. This is performed according to DNV Recommended Practice E305 for installation. The stability of the pipe laying on the seabed is directly related to the submerged weight, the environmental forces and the resistance developed by the seabed soil. Consequently the aim of the stability design is to verify that the submerged weight of the pipe is sufficient to meet the required stability criteria. In a conservative approach, the 100-year return period wave and current will be used: • Hs: 8.8m • Tp : 11.4s • Vc: 0.40m/s at 1 m above sea bottom The calculation will be related to the on-bottom stability of proposed flowline during the installation phase, between the laying phase and the trenching phase. Therefore, in case it is considered necessary the current profile and wave amplitude could be reduced using the 1-year return period.

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8 IN PLACE ANALYSIS

8.1 8” PRODUCTION LINE IN PLACE ANALYSIS For the Bouri EAD, the armours are laid in the CONTRACTOR factory at an angle close to 55° of the pipe axis. This type of structure tends to slightly elongate or shorten under pressure, depending on the angle value (greater or smaller than the equilibrium angle, which is close to 55°). For the proposed structures, angles have been adjusted so that within the manufacturing tolerances, structure always tend to shorten under pressure in order to avoid upheaval buckling out of the trench. However, in buried conditions, the flexible line is restrained from shortening.

8.2 3” SERVICE LINE IN PLACE ANALYSIS For the 3” ID service line, the upheaval behaviour is different from the 8” ID Production Design here above explained. In order to avoid any buckling of this 3” ID service line during its service life, the following installation/trench/test have to be as follows:

- Lay the flexible pipe on seabed - Pressurize the flexible pipe at a required pressure (generally 1.25 x DP)

on seabed - The flexible pipe will tend to elongate and snake laterally on seabed - Trench the flexible pipe under pressure - Relax the pressure - The flexible pipe will tend to shorten in trench - Start the service pressure which will be lower than the in-situ test one

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9 INSTALLATION

9.1 INSTALLATION DYNAMIC AMPLIFICATION FACTOR For stress analysis calculation the estimation of the tension at installation phase will be done with the following coefficients: Catenary coefficient : 1.05 DAF : 1.20

9.2 INSTALLATION TOLERANCES The installation tolerances are as follows: SSIV Orientation : 86° +/-10° Position accuracy : +/-5m Installation target : 3m radius PLEM Orientation : 85° +/-10° * Position accuracy : +/-3m * * Installed by others hence to be confirmed

9.3 CRUSHING CAPACITY The maximum allowable tension of the flexible flowline during installation is used for: - a hub of 2.2m radius - a hub of 4m radius The maximum tightening load which can be applied on the 8” Production Line and 3” Service Line will be estimated considering a 3.5m long tri-caterpillar tensioner with pads of 160° or 135° opening angle. The calculations will be performed by using Parabaq computer program which is based on ABAQUS general purpose finite element analysis code. API 17J (Ref./C1/) utilisation factor versus the ultimate capacity of the pipe will be applied.

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10 STATIC / SENSITIVITY ANALYSIS

10.1 INTRODUCTION The purpose of this section is to define the load case matrix which will be checked to validate the suitability of the 8’’ flexible Production Riser. It can be noted that for the 3’’ Service Line only a static analysis will be performed as it is guided in a J-Tube from topside down to the seabed. The 8’’ Production Riser configuration will be analysed with two internal fluid conditions, i.e. seawater filled and empty. Nevertheless, the nominal configuration will be given for the operational fluid condition.

10.2 STATIC LOAD CASE MATRIX The static analysis is performed to check the geometrical suitability of the flexible line. Results will be provided for the following items: - Top tension (at the flexible riser’s upper connection point) - Maximum admissible loads at the top end fitting exchanged with the topside pipework. - Bottom tension (at TDP) - Top angle at bellmouth of the I-Tube (with respect to vertical) - Minimum bending radius along the riser - Horizontal distance between riser hang-off and TDP. - Tension, loads, bending moment and angle (with respect to vertical) at each Riser/platform connection - Loads to the existing platform elements and supports. Different conditions will be investigated in the static analysis: - riser empty - riser filled with sea water - riser filled with operating fluids (oil/gas), For all cases the marine growth will be taken into account.

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Case name Fluid Current (from)

E-SE Empty SE FW-SE Full of water SE E-NE Empty NE FF-NE Full of fluid NE FW-NE Full of water NE E-NW Empty NW

FW-NW Full of water NW Table 10.2 a – Load case matrix

Other analyses will be performed at the PLEM connection in order to calculate the loads if the catenary is not supported by grout bags.

10.3 SENSITIVITY ANALYSIS From the previous analysis, the worst case in term of: - Minimum bending radius along the riser - Top tension (at the flexible riser’s upper connection point) - Bottom tension (at TDP) - Bottom collar loading will be computed adding the 100 years wave coming from the North East direction. The mechanical damping coefficient which to be used for this analysis will be as follow: Axial damping coefficient: 20% Bending damping coefficient: 20% Other sensitivity analysis will be performed regarding the TDP location due to installation tolerances.

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11 FATIGUE ANALYSIS According to the sensitivity analysis results, a fatigue analysis methodology may be elaborated if required.

12 INTERFERENCE ANALYSIS Only interference between the unprotected part of the Production Riser and DP4 platform will be check using the static analysis FF-NE model. The DP4 platform elevation at ROW 10 is provided in Appendix D.

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APPENDIX A 8” PRODUCTION RISER I TUBE ASSEMBLY

(1 sheet)

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Confidentiality category: C.2. CONFIDENTIAL TECHNIP FRANCE, DO NOT DISCLOSE WITHOUT ITS AUTORIZATION

This document contains confidential information. Property of Technip France S.A.- Copyright Technip France - All rights reserved.

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APPENDIX B 3” SERVICE LINE RISER J TUBE ASSEMBLY

(1 sheet)

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APPENDIX C OVERALL FIELD LAYOUT

(4 sheets)

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APPENDIX D JACKET ELEVATION AT ROW 10

(2 sheets)

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APPENDIX E END TERMINATION OF THE 4” PRODUCTION

FLOWLINE AT DP3

(2 sheets)

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APPENDIX F BOURI FIELD EAD: AXIAL & LATERAL PIPELINE

RESISTANCE

(30 sheets)

OFFSHORE BRANCH TECHNIP OFFSHORE UK LIMITED

BOURI FIELD EAST AREA DEVELOPMENT

AXIAL & LATERAL PIPELINE RESISTANCES

11771-R-002 REV C PAGE 1 OF 30

Confidential Category: C2 - ‘Confidential Technip Offshore Branch, Do Not Disclose Without Their Authorisation’ C:\Documents and Settings\fmarcel\Desktop\db\AppendixF.doc ‘TECHNIP OFFSHORE BRANCH – This document contains confidential information.

Property of TECHNIP FRANCE. Copyright TECHNIP FRANCE – All rights reserved’

Enterprise Drive Telephone: (01224) 271000

Westhill, ABERDEEN Telefax: (01224) 271271

AB32 6TQ Telex: 739186

DOCUMENT No:

11771-R-002

Page 1 of 30

Department:

OED Project:


Document Title:

Axial & Lateral Pipeline Resistances

C Final 19/05/05 JOL AMAC AMAC B Issue 20/04/05 JOL AMAC AMAC A For Comment 17/03/05 JOL AMAC AMAC

Rev Reason for Issue Issue Date Prepared Checked Approved Client

Approval




11771-R-002 REV C PAGE 2 OF 30



PROCEDURE REVISION RECORD

DOCUMENT TITLE:

Axial & Lateral Pipeline Resistances PROJECT DOCUMENT NO. :

11771-R-002 REV. NO.

REVISED SECTION

PARA NO.

DESCRIPTION OF CHANGES

B General Equivalent undrained friction factors have been included for the 8” production pipeline under operational conditions, and the service line under flooded conditions. These cover for the three cases 1) on the seabed, 2) under the mattress and 3) in the jetted trench.

C 3.0 Figure 3.0.1 with accompanying text inserted.

5.2.2 & 5.3.2 Text and tables modified to allow for change in effective weight of mattress based on 2.5 x OD of flowline.




11771-R-002 REV C PAGE 3 OF 30



CONTENTS

1.0 INTRODUCTION .......................................................................................................................4

2.0 PIPELINE PARAMETERS........................................................................................................5

3.0 SOIL PARAMETERS.................................................................................................................6

4.0 GEOTECHNICAL EQUATIONS & PARAMETERS ............................................................8

4.1 Pipelines on the Seabed .................................................................................................................. 8 4.2 Buried Pipelines............................................................................................................................ 11

5.0 RESULTS ...................................................................................................................................13

5.1 Initial Pipeline Embedment .......................................................................................................... 13 5.2 Axial Resistance & Equivalent Friction Factor ............................................................................ 14 5.3 Lateral Resistance & Equivalent Friction Factor.......................................................................... 22

6.0 SUMMARY................................................................................................................................29

7.0 REFERENCES ..........................................................................................................................30




11771-R-002 REV C PAGE 4 OF 30



1.0 INTRODUCTION

The Bouri Field East Area Development is located in block NC-41, Mediterranean Sea

approximately 120 km North of Tripoli, Libya. The field is operated by the AGIP Oil Company.

AGIP have awarded the contract for the development of the Bouri East field to Technip Offshore

International (TOINT).

Part of the Bouri East Development involves the installation and trenching of three flexible

products and an associated control umbilical from the DP4 platform to the B4-4355 manifold. A

8” production riser will also be installed between the flexible flowline and the DP4 platform.

Site specific data is available along the pipeline routes (Ref. 1). The shallow soils consist

primarily of very sandy SILT with inter-bedded layers of VERY SOFT to SOFT CLAY and

numerous fine shell fragments. Available laboratory data would indicate that these silty soils are

sensitive to disturbance i.e. may result in significant reduction in shear strength.

The TOUK OED Geotechnics Team have been asked by TOINT to give recommendations on the

axial and lateral resistances for the following three cases:

Case I: 8” Flowline, 8” Riser and 3” Service Line on Seabed

Case II: Case I with Mattress Cover

Case III: 8” Flowline and 3” Service Line in Jetted Trench

The results are presented in the form of friction factors based on the flooded, empty and

operational submerged weights for the 8” production pipeline and on the empty and flooded

submerged weights for both the 8” riser and 3” service line.

The axial and lateral resistances of the pipelines will depend on whether or not loading on the

line induces either a drained or undrained response from the surrounding soil. As the rate of

straining of the soil is not known, both undrained and drained conditions have been considered

throughout. The worst case condition can then be selected for subsequent analysis.




11771-R-002 REV C PAGE 5 OF 30



2.0 PIPELINE PARAMETERS

Submerged Weight (kN/m) Pipeline OD (m) Empty (W′e) Flooded (W′f) Operational (W′o)

Production 8” (0.291) 0.297 0.645

0.331 (Oil Density = 101

kg/m3)

0.322 (Oil Density = 78 kg/m3)

Riser 8” (0.2724) 0.304 0.652 TBC

Service 3” (0.1255) 0.209 0.258 TBC Table 2.0.1 Pipeline Parameters (Ref. 2)




11771-R-002 REV C PAGE 6 OF 30



3.0 SOIL PARAMETERS

Soil parameters have been interpreted from the geotechnical investigation report (Ref. 1) and are

summarised in Table 3.0.1. The mudline soil along the pipeline routes consists of very sandy

SILT with inter-bedded layers of VERY SOFT to SOFT CLAY and numerous fine shell

fragments.

Soil Parameter Value Average In-Situ Submerged Unit Weight (kN/m3) 8.0 Lower Bound Undrained Shear Strength Profile (kPa) 2 + 0.6z Best Estimate Undrained Shear Strength Profile (kPa) 5 + 0.7z Upper Bound Undrained Shear Strength Profile (kPa) (Fig. A6.3) 12 + 1.2z Sensitivity, St 2.0 – 4.0 Drained Peak Angle of Shearing Resistance (°) 33 - 37 Drained Residual/Critical State Angle of Shearing Resistance (°) (Ref. 3) 30

Table 3.0.1 Seabed Soil Parameters

Undrained shear strength test data has been plotted in Figure 3.0.1 along with the lower bound,

best estimate and upper bound undrained shear strength profiles. The axial and lateral friction

factors have been calculated for these profiles corresponding to the undrained shear strengths at

mudline.




11771-R-002 REV C PAGE 7 OF 30



0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

0 5 10 15 20Undrained Shear Strength,Su (kPa)

Dep

th b

elow

Mud

line,

z (m

)

Hand Vane

Hand VaneRemouldedTriaxial UU

Triaxial UURemouldedLow er Bound

Best Estimate

Upper Bound

Figure 3.0.1 Undrained Shear Strength Profiles




11771-R-002 REV C PAGE 8 OF 30



4.0 GEOTECHNICAL EQUATIONS & PARAMETERS

It is recommended that the following equations and parameters be adopted for calculating the

axial and lateral resistances of the pipelines.

4.1 Pipelines on the Seabed

4.1.1 Axial Resistance

For pipelines on very sandy SILT seabed then the axial resistance should be calculated according

to the least resistance given by Equation A or Equation B below:

pa WR ′= µ Equation A

Where:

Ra = Axial (kN/m)

µ = Resistance coefficient (= f.tanφ where f is a resistance factor dependent on the

relative roughness of the pipe and φ is the mobilised drained angle of

shearing resistance and is a function of the axial displacement of pipeline)

pW ′ = Submerged weight of the pipeline (kN/m)

cDSSuu ASR = Equation B

Where: DSS

US = Direct simple undrained shear strength = 0.80 x SuC (kN/m2) at pipe invert

Ac = Contact area between pipeline and seabed (m2/m)




11771-R-002 REV C PAGE 9 OF 30



The contact area, Ac, can be established from the following:

20)21(cos 1 Dzfor

DzDAC ≤≤−= − Equation C

22DzforDAC >=

π Equation D

Where:

z = initial depth of embedment of the pipeline (m)

The initial depth of embedment is inter-alia a function of the effective pipeline weight (W′p), its

outside diameter (D) and the undrained shear strength of the soil (SuC). The following equation

is recommended for calculating the average initial embedment depth (Ref. 4):

2

4375.0

′=

uo

p

DSW

Dz Equation E

Where:

Suo = operational undrained shear strength of the clay

= t

cu

SS

Where St is the soil sensitivity.




11771-R-002 REV C PAGE 10 OF 30



The effective pipeline weight W′p (kN/m) is defined by:

( )ofelayp WWWkW ′′′×=′ ,,max Equation F

Where:

W′e = empty pipeline submerged weight

W′f = flooded pipe submerged weight

W′o = operational pipe submerged weight

klay = a multiplier to account for the touchdown reaction during pipelay.

The value of klay in very soft clay is typically 2.0 to 3.0 (Ref. 4).

4.1.2 Lateral Resistance

The lateral resistance can be calculated from the least resistance given by Equation G or

Equation H

250.02 zzSSbR CU

DSSUl ⋅′⋅+⋅+⋅= γ Equation G

Where:

50.022

222

−−

⋅= zDDb

C

US = Average compressive undrained shear strength over embedment depth z and all

other symbols have been defined above.




11771-R-002 REV C PAGE 11 OF 30



2

2zKWR ppl ⋅′⋅+′⋅= γµ Equation H

Where:

Kp = Passive pressure coefficient =

+ 245tan 2 φ

4.2 Buried Pipelines

For a pipeline, with backfill placed directly on top, the axial resistance can be calculated from the

least resistance given by Equation I or Equation K.

DRa πµσ '= Equation I

Same notation as above and:

D = Outside diameter of the pipeline (m)

µ = φtan⋅f

σ' = Average effective vertical stress on the pipeline (kN/m2) according to

equation J:

( )

′+

++= DWDHKH pa /

2'2'225.0' γγσ Equation J

Where:

aK = Coefficient of Active Earth Pressure

H = Height of backfill to top of pipeline (m)

γ ' = Submerged unit weight of backfill material




11771-R-002 REV C PAGE 12 OF 30



DSSua SDR ⋅⋅= π Equation K

Where:

DSS

US = Average direct simple undrained shear strength = 0.80 x SuC (kN/m2) around

pipeline

The lateral resistance can be calculated from the least resistance given by Equation L or Equation

M.

+⋅⋅′⋅+⋅⋅′⋅=

2

2DDHKDR pl γπσµ Equation L

( ) 25.02 DHSDSDR cu

DSSul ⋅′⋅+⋅′+⋅+⋅⋅= γγπ Equation M

Where:

C

US = Average compressive undrained shear strength over embedment depth (H+D).




11771-R-002 REV C PAGE 13 OF 30



5.0 RESULTS

5.1 Initial Pipeline Embedment

The initial pipeline embedments have been calculated using equation E for the water flooded

production flowline and production riser and for the empty service line and are presented in

Table 5.1.1 for the lower bound, best estimate and upper bound undrained shear strengths. The

base case values given in Table 5.1.1 assume a klay = 1.0 but for comparison purposes the values

in brackets assume klay = 2.0.

Initial Pipeline Embedment (m)

Lower Bound

Su = 2.0 kPa

Best Estimate

Su = 5.0 kPa

Upper Bound

Su = 12.0 kPa Pipeline

St = 2.0 St = 4.0 St = 2.0 St = 4.0 St = 2.0 St = 4.0

8” Flowline 0.017

(0.067)

0.034

(0.134)

0.003

(0.011)

0.005

(0.021)

0.001

(0.002)

0.001

(0.004)

8” Riser 0.018

(0.073)

0.037

(0.146)

0.003

(0.012)

0.006

(0.023)

0.001

(0.002)

0.001

(0.004)

3” Service Line 0.004

(0.016)

0.008

(0.033)

0.001

(0.003)

0.001

(0.005)

0.0001

(0.0005)

0.0002

(0.001)

Table 5.1.1 Initial Pipeline Embedments




11771-R-002 REV C PAGE 14 OF 30



5.2 Axial Resistance & Equivalent Friction Factor

The axial resistance of the pipeline will depend on whether or not loading on the line induces

either a drained or undrained response from the surrounding soil. As the rate of straining of the

soil is not known, both undrained and drained conditions will be considered throughout.

5.2.1 Case I: Pipeline on Seabed

Undrained Condition Using Equation B

Tables 5.2.1, 5.2.2 and 5.2.3 provide the initial contact areas with resulting peak axial resistances

for the range of soil undrained shear strengths and klay set at 1.0. Also included are the

equivalent friction factors based on flooded (W′f), empty (W′e) and operational (W′o) submerged

weights for the production pipeline and flooded (W′f) and empty (W′e) submerged weights for

both the 8” riser and 3” service line.

Soil Strength at

Mudline

Contact Area

(m2/m)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent

Peak Friction

Factor, µpf

(Rap/W′f)

Flooded

Condition

Equivalent

Peak

Friction

Factor, µpf

(Rap/W′e)

Empty

Condition

Equivalent

Peak Friction

Factor, µpf

(Rap/W′o)

Operational

Condition

(ρo = 78 kg/m3)

Equivalent

Peak Friction

Factor, µpf

(Rap/W′o)

Operational

Condition

(ρo = 101

kg/m3)

Lower Bound

of 2.0 kPa 0.141 – 0.201 0.226 – 0.323 0.35 – 0.50 0.76 – 1.09 0.70 – 1.0 0.68 – 0.97

Best Estimate

of 5.0 kPa 0.056 – 0.079 0.224 – 0.317 0.35 – 0.49 0.75 – 1.07 0.70 – 0.98 0.68 – 0.96

Upper Bound

of 12.0 kPa 0.023 – 0.033 0.223 – 0.316 0.35 – 0.49 0.75 – 1.06 0.69 – 0.98 0.67 – 0.95

Table 5.2.1 Peak Axial Resistances & Equivalent Friction Factors for 8” Flowline




11771-R-002 REV C PAGE 15 OF 30



Soil Strength at

Mudline

Contact Area

(m2/m)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent Peak

Friction Factor, µpf

(Rap/W′f)

Flooded Condition

Equivalent Peak

Friction Factor,

µpf

(Rap/W′e)

Empty Condition

Equivalent Peak


(Rap/W′e)

Operational

Condition

(ρo = 78 kg/m3)

Lower Bound

of 2.0 kPa 0.143 – 0.204 0.228 – 0.327 0.35 – 0.50 0.75 – 1.08 0.69 – 0.99

Best Estimate

of 5.0 kPa 0.057 – 0.080 0.226 – 0.321 0.35 – 0.49 0.74 – 1.06 0.68 – 0.97

Upper Bound

of 12.0 kPa 0.024 – 0.033 0.226 – 0.320 0.35 – 0.49 0.74 – 1.05 0.68 – 0.97

Table 5.2.2 Peak Axial Resistances & Equivalent Friction Factors for 8” Riser

Soil Strength at Mudline

Contact Area (m2/m)

Peak Axial Resistance, Rap (kN/m)

Equivalent Peak Friction Factor, µpe

(Rap/W′e)

Lower Bound of 2.0 kPa 0.045 – 0.065 0.073 – 0.104 0.35 – 0.50

Best Estimate of 5.0 kPa 0.018 – 0.026 0.072 – 0.103 0.35 – 0.50

Upper Bound of 12.0 kPa 0.008 – 0.011 0.072 – 0.102 0.35 – 0.50

Table 5.2.3 Peak Axial Resistances & Equivalent Friction Factors for 3” Service Line

The undrained equivalent friction factors for the 3” service line when it is flooded during

hydro-testing can be obtained from Table 5.2.4.

Soil Strength at

Mudline

Contact Area

(m2/m)

Peak Axial Resistance,

Rap (kN/m)

Equivalent Peak


(Rap/W′e)

Lower Bound

of 2.0 kPa 0.056 – 0.080 0.09 – 0.129 0.35 – 0.50

Best Estimate

of 5.0 kPa 0.022 – 0.032 0.089 – 0.127 0.35 – 0.49

Upper Bound

of 12.0 kPa 0.009 – 0.013 0.089 – 0.126 0.35 – 0.49

Table 5.2.4 Peak Axial Resistances & Equivalent Friction Factors for

3” Service Line during Hydro-Testing




11771-R-002 REV C PAGE 16 OF 30



The mobilisation distance over which the peak axial resistances given in Tables 5.2.1, 5.2.2,

5.2.3 and 5.2.4 are mobilised is up to 5.0 mm. Axial displacements post-peak will result in a

reduction in axial resistance until a residual value is achieved at displacements of the order of

100 mm. The corresponding residual axial resistance is of the order 50% lower than the peak

axial resistances.

Drained Condition Using Equation A

The drained friction factors are shown in Table 5.2.5. The peak value is appropriate up to axial

displacements of the order of 2 to 3 mm, while the residual friction factor is relevant post-peak.

Axial Displacement Condition Friction Factor

Average Peak 0.70

Residual 0.58

Table 5.2.5 Drained Friction Factors

5.2.2 Case II: Pipeline on Seabed with Mattress Cover

Undrained Condition

The placement of a concrete mattress on top of the pipeline will result in further penetration due

to the additional weight provided. Two sizes of mattresses have been considered: 2.5 Te (5.0 m

long by 2 m wide) and 3.75 Te single mattress (5.0 m long by 3.0 m wide). It has been assumed

that the additional weight on the 3” Service Line is equivalent to a mattress width of 2.5 x OD of

pipeline. And the additional weight on the 8” Production Flowline and Riser is equivalent to 1/3

of the mattress width. The effective mattress weights as given in Table 5.2.6:

Effective Mattress Weight (kN/m) Pipeline

3.75 Te Mattress 2.5 Te Mattress

8” Production 1.635 1.635

8” Riser 1.635 1.635

3” Service Line 0.77 0.77

Table 5.2.6 Effective Weights of Mattresses Contributing to Additional Weight on Pipeline




11771-R-002 REV C PAGE 17 OF 30



The results shown in the Tables 5.2.7/8/9/10 present the peak axial resistances and equivalent

peak friction factors for the range of undrained shear strengths expected at mudline and for single

mattress cover.

Soil Strength at

Mudline

Increased

Embedment

Depth (m)

Contact Area

(m2/m)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent

Peak Friction

Factor, µpf

(Rap/W′f)

Flooded

Condition

Equivalent

Peak Friction

Factor, µpo

(Rap/W′o)

Operational

(ρo = 101 kg/m3)

Equivalent Peak

Friction Factor,

µpo

(Rap/W′o)

Operational

(ρo = 78 kg/m3)

Lower Bound

of 2.0 kPa 0.209 – 0.419 0.457 0.731 1.13 2.21 2.27

Best Estimate

of 5.0 kPa 0.033 – 0.067 0.201 – 0.291 0.806 – 1.165 1.25 – 1.80 2.43 – 3.51 2.50 – 3.62

Upper Bound

of 12.0 kPa 0.006 – 0.012 0.083 – 0.117 0.792 – 1.125 1.23 – 1.74 2.39 – 3.39 2.46 – 3.49

Table 5.2.7 Peak Undrained Axial Resistances for 8” Flowline with Mattress Cover

Soil Strength at

Mudline

Increased

Embedment

Depth (m)

Contact Area

(m2/m)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent Peak


(Rap/W′f)

Equivalent Peak

Friction Factor, µpo

(Rap/W′o)

Operational

(ρo = 78 kg/m3)

Lower Bound

of 2.0 kPa 0.225 – 0.45 0.428 0.685 1.05 2.07

Best Estimate

of 5.0 kPa 0.036 – 0.072 0.203 – 0.294 0.811 – 1.177 1.24 – 1.80 2.45 – 3.56

Upper Bound

of 12.0 kPa 0.006 – 0.013 0.083 – 0.118 0.795 – 1.129 1.22 – 1.73 2.41 – 3.42

Table 5.2.8 Peak Undrained Axial Resistances for 8” Riser with Mattress Cover




11771-R-002 REV C PAGE 18 OF 30



Soil Strength at

Mudline

Increased

Embedment

Depth (m)

Contact Area

(m2/m)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent Peak


(Rap/W′e)

Lower Bound

of 2.0 kPa 0.089 – 0.179 0.197 0.315 1.51

Best Estimate

of 5.0 kPa 0.014 – 0.029 0.086 – 0.125 0.346 – 0.50 1.66 – 2.39

Upper Bound

of 12.0 kPa 0.003 – 0.005 0.035 – 0.050 0.340 – 0.483 1.63 – 2.31

Table 5.2.9 Peak Undrained Axial Resistances for Empty 3” Service Line with Mattress Cover

Soil Strength at

Mudline

Increased

Embedment

Depth (m)

Contact Area

(m2/m)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent Peak


(Rap/W′f)

Lower Bound

of 2.0 kPa 0.099 – 0.197 0.197 0.315 1.22

Best Estimate

of 5.0 kPa 0.016 – 0.032 0.091 – 0.131 0.364 – 0.528 1.41 – 2.04

Upper Bound

of 12.0 kPa 0.003 – 0.005 0.037 – 0.053 0.357 – 0.507 1.39 – 1.97

Table 5.2.10 Peak Undrained Axial Resistances for Flooded 3” Service Line with Mattress Cover

Drained Condition

The drained friction factors presented in Table 5.2.5 are also applicable in Case II.




11771-R-002 REV C PAGE 19 OF 30



5.2.3 Case III: Pipeline in Jetted Trench

Base Case: Here it has been assumed that the pipeline will be lowered by jetting to the bottom of

a trench with natural backfill occurring. For analyses purposes, the make up of this backfill will

either be a SILT slurry with a water content at least twice its liquid limit or a very loose SAND

(Relative Density, RD< 0.15/0.20).

Option 1 (Undrained Condition only): A simultaneous lowering and eduction operation will be

utilised to remove the slurry backfill from the trench. The success of this operation will depend

much on the potential for trench wall collapse as well as on the efficiency of the eduction system

(Ref. 5).

Undrained Condition

Base Case & Option1

Equation K has been used to calculate the undrained axial resistance. Estimation of DSSuS has

been separated into the strength of the silt at the base of the trench and the strength of the silt

slurry on top of the pipeline. The base of the trench will be disturbed as a result of the jetting

operation. It is expected that the undrained shear strength will be represented by the lower bound

strength given in Table 3.0.1. Testing carried out as part of the Centrica Bains project in

Liverpool Bay, England, on soils very similar to those expected at Bouri East, would indicate

that the silt slurry has no measurable shear strength until 2 weeks post-jetting where 0.10 kPa

was measured (Ref. 6). Option 1 therefore gives the peak axial resistance when no backfill is

present or when the silt slurry backfill has no measurable shear strength. The base case on the

other hand provides the peak lateral resistance with silt slurry backfill 2 weeks after trenching.




11771-R-002 REV C PAGE 20 OF 30



The results are presented in Table 5.2.11/12/13.

Base Case

(2 weeks after trenching)

Option 1

(Immediately after trenching) Pipeline Peak Axial

Resistance, Rap

(kN/m)

Equivalent Peak


(Rap/W′)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent Peak

Friction Factor, µpe

(Rap/W′)

8” Production 0.288 – 0.384 0.45 – 0.60 0.226 – 0.322 0.35 – 0.50

3” Service Line 0.100 – 0.130 0.48 – 0.62 0.073 – 0.104 0.35 – 0.50

Table 5.2.11 Peak Undrained Axial Friction Factors for Pipelines in Jetted Trench Based on Flooded Weight

for 8” and Empty Weight for 3” Pipelines

Base Case


Option 1

(Immediately after trenching)

Pipeline Peak Axial

Resistance, Rap

(kN/m)

Equivalent Peak

Friction Factor,

µpo (Rap/W′)

Operational

(ρo = 101 kg/m3)

Equivalent Peak

Friction Factor,

µpo (Rap/W′)

Operational

(ρo = 78 kg/m3)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent

Peak Friction

Factor, µpo

(Rap/W′)

Operational

(ρo = 101 kg/m3)

Equivalent

Peak Friction

Factor, µpo

(Rap/W′)

Operational

(ρo = 78 kg/m3) 8” Production 0.288-0.384 0.87 – 1.16 0.89 – 1.19 0.226 – 0.322 0.68 – 0.97 0.70 – 1.0

Table 5.2.12 Peak Undrained Axial Friction Factors for Pipelines in Jetted Trench Based on Operational

Weights for 8” Pipeline

Base Case


Option 1

(Immediately after trenching)

Pipeline Peak Axial

Resistance, Rap

(kN/m)

Equivalent Peak

Friction Factor,

µpf

(Rap/W′)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent

Peak Friction

Factor, µpf

(Rap/W′)

3” Service Line 0.100 – 0.130 0.39 – 0.50 0.073 – 0.104 0.28 – 0.40

Table 5.2.13 Peak Undrained Axial Friction Factors for Pipelines in Jetted Trench Based on Flooded Weight

for 3” Pipeline




11771-R-002 REV C PAGE 21 OF 30



Drained Condition

Equation I has been used to calculate the drained axial friction factors for a range of cover

heights H = 0.20, 0.40 and 0.60 m. Recent research on the uplift resistance of post-jetted sand

has indicated that the soil will be in a very loose condition with a angle of shearing resistance, φ,

between 15 and 20 degrees (Ref. 7). The peak axial resistances and resulting peak friction

factors for the 8” flowline and 3” service line are presented in Table 5.2.14.

8” Flowline 3” Service Line

Height of

Backfill, H

(m)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent Peak


(Rap/W′f)

Peak Axial

Resistance, Rap

(kN/m)

Equivalent Peak

Friction Factor, µpe

(Rap/W′e)

0.20 0.531 – 0.676 0.82 – 1.05 0.194 – 0.248 0.93 – 1.19

0.40 0.842 – 1.070 1.31 – 1.66 0.328 – 0.420 1.57 – 2.00

0.60 1.150 – 1.470 1.79 – 2.28 0.462 – 0.590 2.21 – 2.83

Table 5.2.14 Peak Drained Axial Friction Factors for Range of Expected

Backfill Heights Based on Flooded Weight for 8” and Empty Weight for 3” Pipelines




11771-R-002 REV C PAGE 22 OF 30



5.3 Lateral Resistance & Equivalent Friction Factor

The lateral resistance of the pipeline will depend on whether or not loading on the line induces

either a drained or undrained response from the surrounding soil. As the rate of straining of the

soil is not known, both undrained and drained conditions will be considered throughout.

5.3.1 Case I: Pipeline on Seabed

Undrained Conditions using Equation G

The equivalent peak undrained friction factors for the range of undrained shear strengths

expected at mudline are provided in Tables 5.3.1, 5.3.2 and 5.3.3.

Soil Strength at

Mudline

Peak Lateral

Resistance, Rlp

(kN/m)

Equivalent Peak

Friction Factor,

µllp(Rlp/W′f)

Flooded

Equivalent Peak

Friction Factor,

µllp(Rlp/W′e)

Empty

Equivalent Peak

Friction Factor,

µllp(Rlp/W′o)

Operational

(ρo = 78 kg/m3)

Equivalent Peak

Friction Factor,

µllp(Rlp/W′o)

Operational

(ρo = 101 kg/m3)

Lower Bound

of 2.0 kPa 0.285 – 0.436 0.44 – 0.68 0.96 – 1.45 0.89 – 1.35 0.86 – 1.32

Best Estimate

of 5.0 kPa 0.249 – 0.367 0.39 – 0.57 0.84 – 1.24 0.77 – 1.14 0.75 – 1.11

Upper Bound

of 12.0 kPa 0.234 – 0.338 0.36 – 0.52 0.79 – 1.14 0.73 – 1.05 0.71 – 1.02

Table 5.3.1 Peak Lateral Resistances & Equivalent Friction Factors for 8” Flowline




11771-R-002 REV C PAGE 23 OF 30



Soil Strength at

Mudline

Peak Lateral

Resistance, Rlp

(kN/m)

Equivalent Peak

Friction Factor,

µllp(Rlp/W′f)

Flooded

Equivalent Peak

Friction Factor,

µllp(Rlp/W′e)

Empty

Equivalent Peak

Friction Factor,

µllp(Rlp/W′e)

Operational

(ρo = 78 kg/m3)

Lower Bound

of 2.0 kPa 0.293 – 0.449 0.45 – 0.69 0.96 – 1.48 0.89 – 1.36

Best Estimate

of 5.0 kPa 0.253 – 0.375 0.39 – 0.57 0.83 – 1.23 0.77 – 1.13

Upper Bound

of 12.0 kPa 0.238 – 0.343 0.36 – 0.53 0.78 – 1.13 0.72 – 1.04

Table 5.3.2 Peak Lateral Resistances & Equivalent Friction Factors for 8” Riser

Soil Strength at

Mudline

Peak Lateral

Resistance, Rlp

(kN/m)

Equivalent Peak

Friction Factor,

µllp(Rlp/W′e)

Lower Bound of 2.0 kPa

0.088 – 0.132 0.42 – 0.63

Best Estimate of 5.0 kPa

0.079 – 0.115 0.38 – 0.55

Upper Bound of 12.0 kPa

0.075 – 0.108 0.36 – 0.52

Table 5.3.3 Peak Lateral Resistances & Equivalent Friction Factors for 3” Service Line

The undrained equivalent lateral friction factors for the 3” service line when it is flooded during

hydro-testing can be obtained from Table 5.3.4.

Soil Strength at Mudline

Peak Lateral Resistance, Rap

(kN/m)

Equivalent Peak Friction Factor, µpf

(Rap/W′e)

Lower Bound of 2.0 kPa 0.112 – 0.170 0.44 – 0.66

Best Estimate of 5.0 kPa 0.099 – 0.145 0.38 – 0.56

Upper Bound of 12.0 kPa 0.093 – 0.135 0.36 – 0.52

Table 5.3.4 Peak Lateral Resistances & Equivalent Friction Factors

for 3” Service Line during Hydro-testing




11771-R-002 REV C PAGE 24 OF 30



The mobilisation distance over which the peak lateral resistances given in Tables 5.3.1, 5.3.2,

5.3.3 and 5.3.4 are mobilised is up to 15 mm, 14 mm, 6 mm and 6 mm respectively.

Drained Conditions Using Equation H

For the range of initial embedments indicated in Table 5.1.1 for klay = 1.0, the peak drained

friction factors presented in Table 5.2.5 are still considered applicable.

5.3.2 Case II: Pipeline on Seabed with Mattress Cover

Undrained Condition

The results shown in the Tables 5.3.5/6/7/8 present the peak lateral resistances and equivalent

peak friction factors for the range of undrained shear strengths expected at mudline. Embedment

of the pipeline has been limited to its OD.

Soil Strength at

Mudline

Increased

Embedment

Depth (m)

Peak Lateral

Resistance, Rap

(kN/m)

Equivalent

Peak Friction

Factor, µpf

(Rap/W′f)

Flooded

Equivalent Peak

Friction Factor,

µllp(Rlp/W′o)

Operational

(ρo = 78 kg/m3)

Equivalent Peak

Friction Factor,

µllp(Rlp/W′o)

Operational

(ρo = 101 kg/m3)


0.209 – 0.291 1.478 – 1.970 2.29 – 3.05 5.49 – 6.10 3.46 – 5.91


0.033 – 0.067 1.082 – 1.668 1.68 – 2.59 3.36 – 5.18 3.26 – 5.03


0.006 – 0.012 0.922 – 1.374 1.43 – 2.13 2.86 – 4.27 2.78 – 4.14

Table 5.3.5 Peak Undrained Lateral Resistances for 8” Flowline with Mattress Cover




11771-R-002 REV C PAGE 25 OF 30



Soil Strength at

Mudline

Increased

Embedment

Depth (m)

Peak Lateral

Resistance, Rap

(kN/m)

Equivalent

Peak Friction

Factor, µpf

(Rap/W′f)

Equivalent

Peak Friction

Factor, µpf

Operational

(ρo = 78 kg/m3)


0.225 – 0.2724 1.538 – 1.820 2.36 – 2.79 4.65 – 5.51


0.036 – 0.072 1.103 – 1.702 1.69 – 2.61 3.34 – 5.15


0.006 – 0.013 0.933 – 1.395 1.43 – 2.140 2.82 – 4.22

Table 5.3.6 Peak Undrained Lateral Resistances for 8” Riser with Mattress Cover

Soil Strength at

Mudline

Increased

Embedment

Depth (m)

Peak Lateral

Resistance, Rap

(kN/m)

Equivalent

Peak Friction

Factor, µpf

(Rap/W′e)


0.089 – 0.1255 0.591 – 0.766 2.83 – 3.66


0.014 – 0.029 0.463 – 0.711 2.21 – 3.40


0.003 – 0.005 0.395 – 0.589 1.89 – 2.82

Table 5.3.7 Peak Undrained Lateral Resistances for Empty 3” Service Line with Mattress Cover

Soil Strength at

Mudline

Increased

Embedment

Depth (m)

Peak Lateral

Resistance, Rap

(kN/m)

Equivalent

Peak Friction

Factor, µpf

(Rap/W′e)


0.099 – 0.1255 0.634 – 0.766 2.46 – 2.97


0.016 – 0.032 0.492 – 0.755 1.91 – 2.93


0.003 – 0.005 0.418 – 0.624 1.62 – 2.42

Table 5.3.8 Peak Undrained Lateral Resistances for Flooded 3” Service Line with Mattress Cover




11771-R-002 REV C PAGE 26 OF 30



Drained Condition

For the increased embedment depths given in Tables 5.3.5/6/7/8, the following range of drained

peak lateral friction factors given in Table 5.3.9 are considered appropriate. The upper bound

peak friction factors correspond with full embedment of the pipeline.

Friction Factor Lateral Displacement

Condition 8” Flowline 8” Riser 3” Service Line

Average Peak 0.70 – 2.64 0.70 – 2.38 0.70 – 1.81

Residual 0.58 – 2.15 0.58 – 1.94 0.58 – 1.48

Table 5.3.9 Drained Friction Factors

5.3.3 Case III: Pipeline in Jetted Trench

Undrained Condition

Equation M has been used to calculate the undrained lateral resistance. Estimation of DSSuS has

been separated into the strength of the silt at the base of the trench and the strength of the silt

slurry on top of the pipeline. The values used are those adopted for the undrained axial case

presented in Section 5.2.3.

The average compressive undrained shear strength, cuS , has been taken as 0.10 kPa. This

represents a lower bound on the passive lateral resistance where the pipe will be located in the

silt slurry produced from the jetting operation and will apply 2 weeks after trenching has

occurred. If the pipe moves laterally against the walls of the formed trench then the lateral

passive resistance will be considerably higher than that of the silt slurry. This condition has not

been considered further in this report.

The peak undrained lateral friction factors are presented in Tables 5.3.10 and 5.3.11.




11771-R-002 REV C PAGE 27 OF 30



Height of

Backfill

(m)

Equivalent Peak

Lateral Resistance,

Rap (kN/m)

Equivalent Peak


(Rap/W′f)

Flooded

Equivalent Peak

Friction Factor,

µllp(Rlp/W′o)

Operational

(ρo = 78 kg/m3)

Equivalent Peak

Friction Factor,

µllp(Rlp/W′o)

Operational

(ρo = 101 kg/m3)

0.0 0.226 – 0.322 0.35 – 0.50 0.70 – 1.0 0.68 – 0.97

0.20 1.088 – 1.184 1.69 – 1.84 3.38 – 3.68 3.28 – 3.57

0.40 1.554 – 1.650 2.41 – 2.56 4.83 – 5.12 4.69 – 4.98

0.60 2.020 – 2.116 3.13 – 3.28 6.27 – 6.57 6.09 – 6.38

Table 5.3.10 Peak Undrained Lateral Friction Factors for Pipelines in Jetted Trench Based on Flooded and

Operational Weights for 8” Production (Applicable 2 weeks after trenching)

Height of

Backfill

(m)

Peak Lateral

Resistance, Rap

(kN/m)

Equivalent Peak

Friction Factor,

µpe

(Rap/W′e)

Empty

Equivalent Peak

Friction Factor,

µpe

(Rap/W′f)

Flooded

0.0 0.073 – 0.104 0.35 – 0.50 0.28 – 0.40

0.20 0.362 – 0.393 1.73 – 1.88 1.40 – 1.52

0.40 0.563 – 0.594 2.69 – 2.84 2.18 – 2.30

0.60 0.764 – 0.795 3.66 – 3.80 2.96 – 3.08

Table 5.3.11 Peak Undrained Lateral Friction Factors for Pipelines in Jetted Trench Based on Flooded and

Empty Weights for 3” Pipelines (Applicable 2 weeks after trenching)




11771-R-002 REV C PAGE 28 OF 30



Drained Condition

Equation L has been used to calculate the drained lateral friction factors for a range of cover

heights. The peak lateral resistances and resulting peak friction factors for the 8” flowline and 3”

service line are given in Table 5.3.12. If the pipe moves laterally against the walls of the formed

trench then the lateral passive resistance will be higher than that of the very loose sand produced

during the jetting operation. This condition has not been considered further in this report.

8” Flowline 3” Service Line

Height of

Backfill

(m)

Peak Lateral

Resistance, Rap

(kN/m)

Equivalent Peak

Friction Factor,

µpf

(Rap/W′f)

Peak Lateral

Resistance, Rap

(kN/m)

Equivalent Peak

Friction Factor,

µpf

(Rap/W′e)

0.20 1.90 – 2.32 2.94 – 3.59 0.64 – 0.79 3.07 – 3.76

0.40 3.00 – 3.66 4.65 – 5.68 1.12 – 1.37 5.35 – 6.54

0.60 4.10 – 5.00 6.36 – 7.77 1.59 – 1.95 7.62 – 9.32

Table 5.3.12 Peak Drained Lateral Friction Factors for Range of

Expected Backfill Heights Based on Flooded Weight for 8” and Empty for 3” Pipelines




11771-R-002 REV C PAGE 29 OF 30



6.0 SUMMARY

• The shallow soils along the pipeline routes consist primarily of very sandy SILT with

inter-bedded layers of VERY SOFT to SOFT CLAY and numerous fine shell fragments.

• Recommendations have been made on the equations and parameters to use for calculating

representative axial and lateral resistances of three pipelines as part of the Bouri Field East

Area Development.

• Axial and lateral resistances, equivalent undrained and drained friction factors and

mobilisation displacements have been calculated for the following cases:

Case I: 8” Flowline, 8” Riser and 3” Service Line on Seabed

Case II: Case I with Mattress Cover

Case III: 8” Flowline and 3” Service Line in Jetted Trench

• The equivalent undrained friction factors are representative of an undrained response of the

soil subject to fairly rapid loading. Drained friction factors have also been calculated to

reflect slow or sustained loading. In general, for on-bottom stability analysis such as the

stability assessment of lay curves during dynamic loading, then the undrained results are

recommended, while for thermal expansion of the pipelines then the drained results would

be more appropriate. However, the results presented enable the problem to be bounded

between the undrained and drained conditions thus allowing the worst case condition to be

established.




11771-R-002 REV C PAGE 30 OF 30



7.0 REFERENCES

1. Marine Geosystem, Bouri Field East Area Development Project Offshore Libya, WP #2

– Flowline & Riser System & Umbilical Installation, Offshore Geotechnical

Investigation, Final Report, Rev.0, 09/02/2005.

2. Technip Offshore Branch, Flexi France, Structure 2.2 – Technical Data Sheet, Reference

76.10276, 203.11346 & 203.11347, 30/11/2004.

3. Carter, M & Bentley, S.P., Correlations of Soil Properties, Pentech Press, London, 1991.

4. SAFEBUCK JIP, Safe Design of Pipelines with Lateral Bucking, Pipe-Soil Interaction,

Report No. BR02051/SAFEBUCK/A, August 2004.

5. Bouri Field East Area Development, Trenching Risk Assessment, OED Report No.

11771-R-0001, 22/02/2005.

6. Fugro, Bains Reconsolidation Testing, Laboratory Testing Report, Report No. 22250-

076, 17/07/2002.

7. Thales Geosolutions, Upheaval Buckling Resistance of Post-Jetted Sands, Rev. 02,

09/02/2004.

8. Survey Report Pre-Engineering Survey Services, Report No. 3427-150-S-RT-00001, 11771V-020-RT-3690-001.

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