Flow Assurance Guidelines

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SHELL NIGERIA EXPLORATION AND PRODUCTION

COMPANY Ltd.

Bonga FPSO Bonga FPSO Bonga FPSO Bonga FPSO

Plant Operating Procedures Manual Plant Operating Procedures ManualPlant Operating Procedures Manual Plant Operating Procedures Manual

Volume 2D Volume 2D Volume 2D Volume 2D

FLOW ASSURANCE GUIDELINES FLOW ASSURANCE GUIDELINES FLOW ASSURANCE GUIDELINES FLOW ASSURANCE GUIDELINES

OPRM OPRM OPRM

OPRM---2003-200320032003----0302D0302D0302D0302D

Version: 1.1

This document is confidential.

The Copyright of this document is vested in Shell Nigeria Exploration and Production Company Limited. All rights reserved. Neither the whole nor any part of this document may be reproduced, stored in any retrieval system or transmitted in any form or by any means (electronic, mechanical, reprographic, recording or otherwise) without the prior written consent of the copyright owner.

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OPRM-2003-0302D Page iii of xi 30-April-2006

2.0 2.0 2.0

2.0 PURPOSEPURPOSEPURPOSEPURPOSE

The purpose of this document is to provide guidance on the safe, efficient and environmentally aware operation of the Subsea Facilities, Flowlines and Risers.

It is one Volume within an overall suite of Volumes, which comprise the Bonga FPSO Plant Operating Procedures Manual (POPM). The full listing of Volumes is as follows:

Volume 1 Field and Facilities Overview Volume 2A Subsea Production System Volume 2B Subsea Waterflood System Volume 2C Subsea Control System Volume 2D

Volume 2D Volume 2D

Volume 2D Flow Assurance GuidelinesFlow Assurance GuidelinesFlow Assurance Guidelines Flow Assurance Guidelines Volume 3 Oil Separation and Treatment

Volume 4 Oil Storage, Handling and Ballast Systems Volume 5 Oil Metering and Export System

Volume 6 Vapour Recovery Compression System Volume 7 Field Gas Compression System

Volume 8 Gas Dehydration/Glycol Regeneration Systems Volume 9 Gas Export/Import/Lift Systems

Volume 10 Flare and Vent Systems

Volume 11 Produced Water Treatment Systems Volume 12 Waterflood System

Volume 13 Chemical Injection and Methanol Injection System Volume 14 Fuel Gas System

Volume 15 Heating Medium System Volume 16 Drainage Systems

Volume 17 Sewage Treatment Systems

Volume 18 Bilge and Oily Water Separation Systems Volume 19 Inert Gas System

Volume 20 Nitrogen Generation System Volume 21 Seawater System

Volume 22 Fresh and Potable Water Systems Volume 23 Diesel Fuel System and Incinerator Volume 24 Aviation Fuel System

Volume 25 Instrument and Utility Air System Volume 26 Deck Hydraulic Systems

Volume 27 Fire Protection Systems and Equipment Volume 28 Safety and Lifesaving Equipment

Volume 29 PSCS and ESS

Volume 30 Power Generation and Distribution Systems Volume 31 Black Start Procedures

Volume 32 HVAC Systems

Volume 33 Deck Machinery and Mechanical Handling Systems (Cranes, etc) Volume 34 Telecommunications

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OPRM-2003-0302D Page iv of xi 30-April-2006

This document provides detailed reports and studies carried out to provide guidelines for the safe operation of the Bonga subsea facilities. The studies also include step-by-step guidance on the operation of the system under both normal and abnormal operation.

4.0 4.0 4.0

4.0 TARGTARGTARGTARGET READERSHIPET READERSHIPET READERSHIPET READERSHIP

All SNEPCO staff who may be involved in the operation of the Subsea Systems onboard the Bonga FPSO.

5.0 5.0 5.0

5.0 SPECIAL NOTESPECIAL NOTESPECIAL NOTESPECIAL NOTE Not applicable. 6.0

6.0 6.0

6.0 DEFINITIONS AND ABBREVIATIONSDEFINITIONS AND ABBREVIATIONSDEFINITIONS AND ABBREVIATIONSDEFINITIONS AND ABBREVIATIONS

The definitions and abbreviations used within this document are listed at the end of these introductory pages.

7.0 7.0 7.0

7.0 REFERENCE INFORMATION/SUPPORTING DOCUMENTATIONREFERENCE INFORMATION/SUPPORTING DOCUMENTATIONREFERENCE INFORMATION/SUPPORTING DOCUMENTATIONREFERENCE INFORMATION/SUPPORTING DOCUMENTATION

The primary reference/supporting documents, which have been either used or referred to in the development of this document, are listed at the end of these introductory pages. These are part of the available Operational Documentation, which SNEPCO Offshore Operations (OO) has in place to support its day-to-day operations. These and many other documents are available within the SNEPCO Livelink System. Where appropriate, these documents have been cross-referenced within this document.

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OPRM-2003-0302D Page v of xi 30-April-2006

Definitions and Abbreviations

Definitions Definitions Definitions Definitions Arrival Temperature

Flowing temperature of the fluids at the FPSO boarding valve. Backpressure Pressure on back of valve against which equalising pressure

is applied to reduce differential

Blowdown Action performed to depressurise the flowline, designed to reduce the maximum flowline pressure and thus reduce the risk of hydrates at ambient conditions (4°C) in the event of an extended shutdown.

Bubble Point The bubble point is the pressure at which gas first comes out of hydrocarbon liquid phase for a given temperature.

Cloud Point The cloud point is the temperature at which wax crystals begin to precipitate in the fluid. This is commonly taken to be the temperature for the onset of wax deposition, also called the Wax Appearance Temperature.

Cold Earth Start

Start-up in which the wellbore, wellbore fluids and all subsea equipment are initially at ambient temperature.

Equalising Pressure

Pressure applied to equalise pressure across the valve (ideally this should be greater than the downstream pressure).

Forward Pressure

Pressure on front of valve prior to equalising pressure being applied.

Gas Void Fraction

Technically defined as the ratio of the gas volume to the flowline volume, but it is more appropriately defined as the minimum gas volume required to achieve a successful flowline blowdown.

Hot Oiling Precirculating heated dry hydrocarbons or diesel around a flowline loop to warm the flowlines and manifold prior to a cold well start-up.

Hydrate Dissociation/ Formation Temperature

The temperature at a given pressure above which hydrates will not form or the temperature at a given pressure below which hydrates will form.

No-touch Time

The period of time following a shut-in during which the equipment is allowed to cool and production may be restarted without the need to inhibit the system.

Pour Point The pour point of a petroleum fluid is the lowest temperature at which the fluid ceases to flow when brought to the temperature under specified conditions.

Safe Condition The condition at which the subsea system has attained the desired temperature required to achieve minimum cooldown time.

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OPRM-2003-0302D Page vi of xi 30-April-2006

Safe Condition Temperature

The temperature at which any section of the subsea system has the minimum specified cooldown time (8 hours for wellbore and 12 hours for the rest of the subsea system).

Safe Condition Time

The time taken to reach safe condition temperature. Warm-up

Time

The time that it takes the systems to reach a temperature sufficient to give the desired number of hours of cool down.

Abbreviations Abbreviations Abbreviations Abbreviations

API American Petroleum Institute

ASTM American Society for Testing and Materials

Ba Barium

BaSO4 Baryte

BIST Bonga Integrated Studies Team BLPD Barrels Liquid Per Day

BoD Basis of Design

BOOR Bonga Oil Offloading Riser BS&W Base Sediment and Water

BSET Bonga Systems Engineering Team

CaCO3 Calcite

CIV Chemical Injection Valve

CPM Cross-polar Microscopy

CWDT Critical Wax Deposition Temperature DTI Department of Trade and Industry EPIC Engineer, Procure, Install and Construct

ESDV Emergency Shutdown Valve

FAST Flow Assurance Sub-team, Houston FDP Field Development Plan

FEAST Fluids Evaluation and Stability Testing FPSO Floating Production, Storage and Offloading

FPT Field Planning Tool

FWHP Flowing Wellhead Pressure FWHT Flowing Wellhead Temperature GLIV Gas Lift Injection Valve

GLR Gas Lift Riser

GoM Gulf of Mexico

GOR Gas/Oil Ratio

HDP Hydrate Dissociation Pressure HDT Hydrate Dissociation Temperature HRGC High Resolution Gas Chromatography HS&E Health, Safety and Environment HSE Health and Safety Executive

HTGC High Temperature Gas Chromatography

ID Inside Diameter

ITT Invitation to Tender KHI Kinetic Hydrate Inhibitor LDHI Low Dosage Hydrate Inhibitor

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OPRM-2003-0302D Page vii of xi 30-April-2006

MBOPD Thousand Barrels Oil Per Day MBWPD Thousand Barrels Water Per Day

MEG Monoethylene Glycol

MeOH Methanol

MIV Methanol Injection Valve MMBO Million Barrels Oil

MoC Management of Change

MPT Model Pipeline Test

NORM Naturally Occurring Radioactive Material NLNG Nigerian Liquefied Natural Gas

OD Outside Diameter

OGGS Offshore Gas Gathering Plant OPEX Operating Expenditure

PFL Production Flowline

PID Proportional Integral Derivative

PIP Pipe-in-pipe

PIV Pigging Isolation Valve

PM Production Manifold

PMV Production Master Valve

POPM Plant Operating Procedures Manual POV Ported Orifice Valve

PP Pour Point

PPD Pour Point Depressant

PSDV Pipeline Shutdown Valve

psia Pounds Per Square Inch Absolute

PU Polyurethane

PVT Pressure/Volume/Temperature

PWV Production Wing Valve

SBHP Shut-in Bottomhole Pressure

SC Safe Condition

SCF Standard Cubic Feet

SCSSV Surface Controlled Subsea Safety Valve SIEP Shell International Petroleum Maatschappij SITP Shut-in Tubing Pressure

SOI Shell Offshore Incorporated (SEPCo) SPM Single Point Mooring

SRTCA Shell Research and Technology Center, Amsterdam SSSV Subsurface Safety Valve

STB Stock Tank Barrels

SWV Sacrificial Wing Valve

TEG Triethylene Glycol

THF Tetrahydrofuran

UTH Umbilical Termination Header

VIT Vacuum Insulated Tubing

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WTC Westhollow Technology Center

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Reference Information/Supporting Documentation

(1) Bendiksen, KH, Malnes, D, Moe, R and Nuland, S (1991), ‘ The Dynamic

Two-fluid Model OLGA: Theory and Application’ , Soc of Petro Engr, May 1991, Page 171.

(2) Ellison, BT and Kushner, DS (1998) Subsea Oil Production System Design and Operations Methodology. Shell TIR (BTC-3534).

(3) Granherne (1998) Bonga Major: Technical Note – Flow Assurance (7471-BON-TN-C-00037).

(4) Granherne (1999) Riser Gas-lift System: Option Review and Recommendation (7471-BON-TN-U-00062).

(5) Mehta, A (1998) E-mail communication to BSET Team.

(6) Wasden, FK (1995) Mars Phase I Subsea Flowline Thermal Design Study. Shell TPR (BTC 9-95).

(7) Ratulowski, J et al 1999 Asphaltene Stability, Waxy Fluid Properties and Wax Deposition Potential of Crude Oils from the Bonga Prospect, Nigeria.

(8) Schoppa, W, Wilkens, RJ and Zabaras, GJ (1998), Simulation of Subsea Flowline Transient Operations. Facilities 2000 Proceedings, New Orleans, October 26-27.

(9) Van Gisbergen, S (1999) Email communication to BSET Team.

(10) Zabaras, GJ (1987) A New Vertical Two-phase Gas-liquid Flow Model for Predicting Pressure Profiles in Gas-lift Wells. Shell TPR (WRC 223-87).

(11) Westrich, JT, Predicting Wax-related Fluid Properties Away from Well Control at Bonga, Report number SIEP.99.6096, August 1999.

(12) Ratulowski, J, G Broze, J Hudson, N Utech, P O’ Neal, J Couch and J Nimmons. Asphaltene Stability, Waxy Fluid Properties and Wax Deposition Potential of Crude Oils from the Bonga Prospect, Nigeria. SEPTCo, Houston, March 1999.

(13) Broze, G, N Utech, P O’ Neal and J Nimmons, Summary Report: Waxy Fluid Properties of Crude Oil from the B1 well, 803 Sand of the Bonga Prospect, Nigeria. SEPTAR, Houston, July 1999.

(14) Bonga Integrated Studies Team. SDS-SNEPCo Bonga Joint Venture, Integrated Development Plan, Field Development Plan, Rev 5, December 2001.

(15) Schoppa, W, Flow Assurance Constraints for Bonga Production Forecasting: Wrap-up. SGSUS, May 2002.

(16) Schoppa, W and A Kaczmarski, Bonga Dynamic Flow Assurance Analysis – Evaluation of Conceptual Design. SGSUS, Technical Progress Report, February 2001.

(17) Stankiewicz, Artur, Matt Flannery, Pat O’ Neal, Nancy Utech and George Broze, Asphaltene Stability and Wax Properties of the Crude Oil from the OPL 212 Prospect, Well W6, Bonga, Nigeria, SGSUS, October 2001.

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OPRM-2003-0302D Page x of xi 30-April-2006

Gopalkrishnan of SDS, September 2000.

(19) Steve C Tsai, George Broze and Sabi Balkanyi, Bonga Production Flowline Wax Assessment. Shell Global Solutions, Houston, Texas, March 2003.

(20) Bonga Oil Offloading Risers Conceptual Designs Summary (SD 991080). Revision R1, September 1999.

(21) Pigging of Pipelines, State-of-the-Art, EP 95-2580, SIEP, The Hague, 1995. (22) SOI Deepwater Flowline Pigging Guidelines (similar to the guidelines for pigging

section in the DEP 31.40.00.10 report).

(23) Bonga System-wide Functionality Review in Amsterdam (Nov 2001) and email communications from H Duhon and A Kaczmarski.

(24) Tsai, A, Broze, G and S Balkanyi, Bonga Production Flowline Wax Assessment. Shell Global Solutions, April 2003.

(25) Westrich, JT, Predicting Wax-related Fluid Properties Away from Well Control at Bonga, Report No SIEP.99.6096, August 1999.

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OPRM-2003-0302D Page xi of xi 30-April-2006

Main Table of Contents

Document Status Information

Definitions and Abbreviations

Reference Information/Supportin

Reference Information/Supporting Documentation

g Documentation

Section 1 Section 1 Section 1

Section 1 Dynamic Flow Assurance AnalysisDynamic Flow Assurance AnalysisDynamic Flow Assurance AnalysisDynamic Flow Assurance Analysis Section 2

Section 2 Section 2

Section 2 Flow Assurance Production ConstraintsFlow Assurance Production ConstraintsFlow Assurance Production ConstraintsFlow Assurance Production Constraints Section 3

Section 3 Section 3

Section 3 Hydrate Remediation GuidelinesHydrate Remediation GuidelinesHydrate Remediation GuidelinesHydrate Remediation Guidelines Section 4

Section 4 Section 4

Section 4 Production Flowline Wax AssessmentProduction Flowline Wax AssessmentProduction Flowline Wax AssessmentProduction Flowline Wax Assessment Section 5

Section 5 Section 5

Section 5 Offloading Riser Wax AssessmentOffloading Riser Wax AssessmentOffloading Riser Wax AssessmentOffloading Riser Wax Assessment Section 6

Section 6 Section 6

Section 6 Pour Point Pour Point Pour Point Pour Point Depressant Risk AssessmentDepressant Risk AssessmentDepressant Risk Assessment Depressant Risk Assessment Section 7

Section 7 Section 7

Section 7 Scale ReviewScale ReviewScale ReviewScale Review Section 8

Section 8 Section 8

Section 8 RiskRiskRiskRisk----based Evaluation of Scaling Tendencies for the based Evaluation of Scaling Tendencies for the based Evaluation of Scaling Tendencies for the based Evaluation of Scaling Tendencies for the Subsea System

Subsea System Subsea System Subsea System

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Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D Page 1 of 89 30-April-2006

Section 1 Dynamic Flow Assurance Analysis

Table of Contents

1.0 EXECUTIVE SUMMARY...5

1.1 Hardware Design ...5

1.2 Operational Procedures ...5

2.0 ITEM OVERVIEW AND SPECIFICATIONS ...6

2.1 Introduction ...6

2.2 Reservoir Fluid...7

2.3 Wellbore Characteristics ...7

2.4 Subsea Flowline Details...9

2.5 Operating Conditions and Constraints...10

2.6 Objectives ...10

2.7 Computational Approach...11

3.0 COLD WELL START-UP: HYDRATE PREVENTION STRATEGIES ...18

3.1 Cold Earth Well Start-up ...18

3.2 Well Safe Condition Analysis ...20

3.3 Flowline Hot-oiling...21

4.0 STEADY-STATE PRODUCTION ...26

4.1 Steady-state Thermal Performance: Wellbore and Flowline...26

4.2 Terrain-induced (Severe) Slugging ...27

4.3 Riser Gas Lift: Thermal Considerations...30

4.4 Umbilical-based Design ...31

4.5 Large-bore Riser Design ...31

5.0 SUBSEA SYSTEM SHUTDOWN: HYDRATE PREVENTION STRATEGIES ...41

5.1 Cooldown Performance of Subsea Facilities ...41

5.2 Flowline Blowdown ...44

5.3 Gas Lift-assisted Blowdown ...45

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Table of Contents (cont’d) TABLES

Table 1.1 – Riser Gas Lift Requirements for Terrain Slug Suppression ...29

Table 1.2 – Cooldown Time as a Function of PU Foam Thickness Within ‘Pipe-in-pipe’ Flowlines ...43

FIGURES Figure 1.1 – Production Forecast for Bonga Phase I Development (refer to Bonga Basis of Design)...13

Figure 1.2 – Bonga Subsea Field Layout...14

Figure 1.3 – Bonga Production Well Design, Used for All Thermal-hydraulic Analysis...15

Figure 1.4 – Production Flowline Topography for (a) 10in West-side Flowlines, and (b) 12in East-side Flowlines...16

Figure 1.5 – Insulation Systems for 10in and 12in Pipe-in-pipe Flowlines (Left Panel), and Steel Catenary Risers (Right Panel) ...17

Figure 1.6 – Definition of Well Start-up Terminology...22

Figure 1.7 – Wellhead Warm-up Time to HDT, for Cold Earth Start-up of the Field’s Coldest Well (702p7) at 0% Watercut...22

Figure 1.8 – Treatable Liquid Rate for 18gpm MeOH Injection (Mehta, 1999) ...23

Figure 1.9 – Well Warm-up Time of 702p7: Dependence on Water Cut ...23

Figure 1.10 – Safe Condition Time for 8-hour Wellbore Cooldown ...24

Figure 1.11 – Influence of Watercut on Well Safe Condition Time for 702p7 ...24

Figure 1.12 – Safe Condition Time for 12-hour Cooldown of Tree/Jumper/Manifold, Based on Time for Wellhead Temperature to Reach 120°F...25

Figure 1.13 – Hot-oiling Performance: Return Temperature for 50MBOPD Circulation of 150°F Source Oil ...25

Figure 1.14 – Flowing Wellhead Temperatures Calculated for Initial-life Wells and the Field’s Coldest Well (702p7) with 0% Water Cut...33

Figure 1.15 – Arrival Temperatures Calculated for All Initial-life Wells with 0% Water Cut....33

Figure 1.16 – Cumulative Arrival Temperature for Initial-life Well Production, Relative to the 98°F Arrival Temperature Constraint for Waste Heat Capacity ...34

Figure 1.17 – Influence of Riser Gas Lift on Riser Froude Number, as a Means to Eliminate Riser Instability and Terrain Slugging Shown for the 12in East-side Risers ...34

Figure 1.18 – Riser Base Gas Lift Required for Complete Suppression of Terrain Slugging for 10in West-side Flowlines ...35

Figure 1.19 – Riser Base Gas Lift Required for Complete Suppression of Terrain Slugging for 10in East-side Flowlines ...35

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Table of Contents (cont’d) FIGURES

Figure 1.20 – Riser Base Gas Lift Required to Limit Terrain Slugging to Within 50bbl

Slugs for 12in East-side Flowlines ...36

Figure 1.21 – Slug Volumes Calculated for 12in East-side Flowlines and 50% Water Cut as a Function of Gas Lift Rate ...36

Figure 1.22 – Separator Level Fluctuation Calculated for 12in East-side Flowlines and 50% Water Cut as a Function of Gas Lift Rate...37

Figure 1.23 – Effect of Cold (40°F) Gas Lift Injection on Arrival Temperature for 10MBOPD Production and 25MMscfd Gas Lift for Slug Suppression ...37

Figure 1.24 – Gas Injection Temperatures at Mudline for Prior Umbilical-based Gas Lift Design...38

Figure 1.25 – Dependence of Gas Injection Temperature on Gas Lift Riser Diameter for an Insulating Value of U = 4W/m2-C ...38

Figure 1.26 – Dependence of Gas Injection Temperature on Gas Lift Riser Insulating Value for a 3.5in Tube Diameter ...39

Figure 1.27 – System Temperature Summary for Base-case Flexible Riser-based Gas Lift Design...40

Figure 1.28 – Definition of Contributions to Cooldown Time ...46

Figure 1.29 – Downtime Duration Statistics for Unplanned Shutdowns in GoM ...47

Figure 1.30 – Wellbore Cooldown at Wellhead for Hottest and Coldest 702 Wells ...47

Figure 1.31 – East-side 12in Riser Cooldown Performance for (a) 2in Carazite and (b) 4in Carazite ...48

Figure 1.32 – West-side 10in Riser Cooldown Performance for (a) 2in Carazite and (b) 4in Carazite ...49

Figure 1.33 – Pipe-in-pipe Cooldown for East-side 12in Flowlines ...50

Figure 1.34 – Pipe-in-pipe Cooldown for East-side 10in Flowlines ...50

Figure 1.35 – Pipe-in-pipe Cooldown for 10in West-side Flowlines ...51

Figure 1.36 – Illustration of Non-unique Relationship Between U Value and Cooldown...51

Figure 1.37 – Blowdown Performance: 10in West-side and Full Line-pack...52

Figure 1.38 – Blowdown Performance: 10in West-side and Immediate Choke Closure ...53

Figure 1.39 – Blowdown Performance: 12in East-side and Full Line-pack...54

Figure 1.40 – Blowdown Performance: 12in East-side and Immediate Choke Closure ...55

Figure 1.41 – Blowdown Performance for 50% Watercut, Illustrating Unsuccessful Blowdown for All Scenarios ...56

Figure 1.42 – Blowdown Performance with Riser Gas Lift Assist, for 12in East-side Flowlines...57

Figure 1.43 – Blowdown Performance with Riser Gas Lift Assist, for 10in East-side Flowlines...58

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Table of Contents (cont’d) FIGURES

Figure 1.44 – Pressure and Temperature Evolution During Cold Gas

Lift-assisted Blowdown ...59

Figure 1.45 – Benefit of Depressurisation for Unsuccessful Blowdown in Providing 24 Hours of Additional Cooldown Time...60

Figure 1.46 – Cold Start-up ...61

Figure 1.47 – Additional Well Start-up ...62

Figure 1.48 – Interrupted Start-up ...63

Figure 1.49 – Planned or Unplanned Shutdown from Steady-state ...64

Figure 1.50 – Blowdown ...65

APPENDICES Appendix 1A – Reservoir Fluid Properties ...66

Appendix 1B – Wellbore Modelling Summary and Production Forecast ...71

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1.0 EXECUTIVE SUMMARY

Using validated analytical and computational techniques, the dynamic thermal-hydraulic performance of the Bonga conceptual subsea system is evaluated with regard to Shell guidelines for flow assurance in deepwater applications, with particular focus on hydrate management. Through simulation of worst-case (albeit realistic) operational scenarios, the principal objective of this work is to ensure a robust design of the Bonga subsea system, to enable efficient, hydrate-free operations. Analysis presented herein validates the Bonga conceptual design with respect to hydrate management, upon implementation of the following modifications to hardware design and operational procedures.

1.1 Hardware Design

• Replacement of gas lift umbilical with flexible riser and addition of gas lift heating (MoC 16)

• Increase of carazite riser insulation thickness from 2in to 4in

• Increase of polyurethane foam thickness in pipe-in-pipe flowlines from 0.6in to 1.0in

• Inclusion of cooldown in riser/flowline thermal performance specifications (MoC 59)

• Replacement of 2in topsides blowdown valve with two-stage valve train with large orifice

• Added capability to isolate individual flowlines for dry-oil circulation • Added riser base pressure/temperature sensors (MoC 64)

1.2 Operational Procedures

• Identified need for well tubing Methanol (MeOH) bullheading for cold-earth start-up

• Developed separate well start-up procedures for low and high watercut

• Revealed that slug control not required for west-side flowlines, above 10MBLPD • Identified that well MeOH bullheading to Subsurface Safety Valve (SSSV)

required only for long shut-ins (> 2 days)

• Revealed that blowdown unsuccessful for watercuts 50% and higher • Illustrated that success of gas lift assist blowdown is not guaranteed

• Developed dual strategy for lengthy shutdowns: primary blowdown and secondary oil circulation

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2.0 ITEM OVERVIEW AND SPECIFICATIONS

2.1 Introduction

Bonga is a deepwater Nigerian oil prospect in Block OPL 212 in 1000m water depth, operated by Shell Nigeria Exploration and Production Company Limited in a joint venture with Esso (20%), Elf (12.5%) and Agip (12.5%). Bonga will be developed as a subsea network, with 1.9 to 9.2km tiebacks to a permanently moored Floating Production, Storage and Offloading vessel (FPSO). Anticipated peak production rates are 225MBOPD oil, 170MMscfd gas (including recycled riser gas lift) and 100MBWPD produced water (refer to production function in Figure 1.1). Reservoir pressure will be maintained via 16 subsea waterflood wells with a 300MBWPD total water injection capacity. Produced oil will be stored on the FPSO (2MMBO storage capacity) for tanker offloading, while Bonga gas will be exported 90km via a 16in pipeline to Riser Platform A of the Offshore Gas Gathering System (OGGS), which feeds the Bonny Nigerian Liquefied Natural Gas Plant (NLNG) plant.

The initial phase Bonga Field layout (refer to Figure 1.2) consists of four reservoirs (690, 702, 710/740, 803; roughly one half of reserves within 702) and 20 subsea production wells. Production wells contain a subsea tree (enabling surface controlled isolation valves, production choke and chemical injection valves) connected via short well jumpers to five subsea production manifolds. The subsea wells are produced through four pairs of piggable dual flowlines (three 10in pairs and one 12in pair), with pipe-in-pipe flowlines and externally insulated steel catenary risers. Each flowline is connected to a dedicated gas lift riser delivering up to 25MMscfd riser base gas lift. Riser base gas lift is critical for several Bonga operations, enabling:

• Riser unloading during start-up and blowdown • Severe slug suppression

• Production enhancement

As a subsea production system of unprecedented complexity in a new deepwater operating environment, Bonga entails several key flow assurance and systems engineering challenges. Additionally, unlike typical Shell Deepwater Gulf of Mexico (GoM) projects, independent EPIC (Engineer, Procure, Install and Construct) Contractors are responsible for the detailed design, construction and installation of all Bonga facilities. However, Shell has chosen to retain ‘ownership’ of flow assurance via design specifications in each EPIC contract, based on flow assurance analysis performed in-house within the Bonga Systems Engineering Team (BSET). Thus, the completeness of in-house analysis and the communication of results with (and among) contractors (facilitated by BSET) are key success factors for Bonga. The principal objective of this report is to validate the Bonga conceptual design with respect to Shell Deepwater Flow Assurance Guidelines (Ellison and Kushner, 1998), and to outline the Management of Change (MoC) identified by this analysis.

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2.2 Reservoir Fluid

The fluid composition and properties for each Bonga reservoir (690, 702, 710/740 and 803) are summarised in Appendix 1A Table 1A.1. The reservoir fluids exhibit the following variability in properties:

• Bubble point at reservoir temperature (145 to 190°F) = 3335 to 5015psia • Stock tank oil gravity = 29 to 33° API

• Gas/oil ratio = 550 to 1200 SCF/STB (single-stage flash)

Unless otherwise noted, simulations here are based on compositional Pressure/Volume/Temperature (PVT) models tuned to match the properties of the dominant 702 reservoir. All transient simulations in OLGA are based on the phase diagram shown in Figure 1.46, calculated for the 702 reservoir fluid. For purposes of analysis, the oil gravity and gas: oil ratio (not to be confused with the gas:liquid ratio) are relatively constant over the field life at 600SCF/STB. Based on the production forecast (refer to Figure 1.1), watercuts of 0%, 50%, and 80% are assumed for early, mid and late-life scenarios, respectively.

Hydrate dissociation curves (pressure (HDP) vs temperature (HDT)) for the 702 and 803 fluids are presented in Appendix A, calculated using MULTIFLASH (Mehta, 1998). The expected salinity is that of the seawater (due to significant waterflood), ie approximately 3wt % salt. As a result of this low salinity, compared to the typical 15% salinity of subsea GoM fields, hydrate management for Bonga is particularly challenging (ie HDT approximately 10°F higher). For conservatism, the hydrate dissociation conditions of the 803 fluid with 0% salinity (refer to Figure 1.48) are used as a worst-case for all flowline analysis in this report. At the minimum seabed temperature (40°F), this translates to a blowdown target pressure of HDP = 150psia. For subsea facilities (tree, well jumper and manifold) a target hydrate temperature of HDT = 74°F is used for the 702 wells considered here, corresponding to the maximum design shut-in pressure (4600psia).

2.3 Wellbore Characteristics

The November 1999 well design basis (Appendix 1B) indicates the following range of wellbore parameters:

• 702 Wells

– Water depth = 990 to 1105m

– Measured depth = 1770 to 2315m below mud line – True vertical depth = 1360 to 1730m below mud line

– Tubing = 4.89in ID x 5.5in OD or 5.92in ID x 6.625in OD: bare tubing

– Reservoir pressure (average) = 2520 to 4200psia – Reservoir temperature = 128 to 162°F

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• 690 Wells

– Measured depth = 2010 to 2875m below mud line – True vertical depth = 1500 to 1770m below mud line

– Tubing = 4.89in ID x 5.5in OD or 5.92in ID x 6.625in OD: bare tubing

– Productivity index (average) = 7 to 14 BLPD/psia • 710 Wells

– Measured depth = 1770 to 1965m below mud line – True vertical depth = 1485 to 1760m below mud line – Tubing = 5.92in ID x 6.625in OD: bare tubing

– Productivity index (average) = 6 to 27BLPD/psia • 803 Wells

– Measured depth = 2140 to 2570m below mud line – True vertical depth = 2030 to 2165m below mud line – Tubing = 5.92in ID x 6.625in OD: bare tubing

– Productivity index (average) = 10 to 12BLPD/psia

For conceptual design evaluation, we focus here on wells 702p7 (coldest) and 702p4 (hottest), which represent the flowing wellhead temperature extremes for the dominant 702 reservoir.

Note: Results here effectively bracket the thermal-hydraulic performance of all producing wells, which will be analysed individually as part of future detailed design and operability analysis.

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The well casing and annulus fluid design summarised in Figure 1.3 (from Van Gisbergen, 1999) is used for all transient and steady-state thermal wellbore analysis. A linear geothermal temperature gradient (from mid-perfs to mudline) is specified for the ambient formation temperature. The well specifications analysed herein are summarised as follows:

• 702p7 (coldest)

– Measured depth = 1870m below mud line – True vertical depth = 1380m below mud line – Tubing = 4.89in ID x 5.5in OD: bare tubing

– Reservoir pressure = 3200psia (early life) to 2200psia (late life) – Reservoir temperature = 128°F

– Productivity index (average) = 30BLPD/psia – Watercut = 0% (early life) to 80% (late life) • 702p4 (hottest)

– Measured depth = 2280m below mudline – True vertical depth = 1760m below mud line – Tubing = 5.92in ID x 6.625in OD: bare tubing

– Reservoir pressure = 4800psia (early life) to 3600psia (late life) – Reservoir temperature = 162°F

– Productivity index (average) = 80BLPD/psia – Watercut = 0% (early life) to 80% (late life)

2.4 Subsea Flowline Details

The conceptual design evaluation presented here is based on the 10in west side and 12in east side flowline topographies (refer to Figure 1.4), which capture the essential terrain features on either side of the FPSO.

Note: The significant difference in offset distance between the East (3.9 and 5.8 miles) and West (1.2 and 1.5 miles) flowlines (refer to Appendix 1C).

The riser gas lift injection is located 1150m horizontal distance upstream from the FPSO, at the flowline/riser connection (refer to Figure 1.4). In Appendix 1C, further flowline details are summarised, including individual flowline topographies, the catenary riser profile and profiles of (ambient) sea temperature and current.

With reference to the field layout in Figure 1.2, all production flowlines are of 10in nominal diameter, with the exception of the 12in east side flowlines PFL 3/4/5/6 (the ‘East-East’ flowline). As illustrated in Figure 1.5, pipe-in-pipe insulation is used for all production flowlines, with an insulating value of UOD=2.0 W/m2-C

(0.352 Btu/hr-ft2-F) or better.

Note: In Figure 1.5, U values as low as 1.4W/m2-C can be attained by filling the entire annulus space with foam (as recommended here based on cooldown considerations).

Based on both steady-state and cooldown performance, a 4in carazite (or equivalent) insulation has been specified for all production risers (refer to Figure 1.5).

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2.5 Operating Conditions and Constraints

As a tieback comprised of numerous subsea wells and flowlines, Bonga entails several key flow assurance constraints on system design and operation, including: • 12-hour minimum cooldown time for flowline and riser

• 8-hour minimum cooldown time for wellbore, subsea tree, well jumper and manifold

• Target minimum turndown rate of 10MBLPD per well and per flowline • Target blowdown pressure of 145psia

• Minimum boarding temperature of 98°F (@ maximum production) • Maximum boarding temperature of 153°F

• Separator pressure = (300, 150, 150) psia for (early, mid, late) field life In addition to general Shell subsea operating guidelines:

• Operation outside of stable hydrate region at all times, with chemical inhibition otherwise

• No wax deposition in the wellbore

2.6 Objectives

The principal objective of this report is to evaluate the conceptual design of the Bonga subsea system with respect to flow assurance, topsides and subsea system constraints, and operability. The main focus here is on hydrate prevention during all expected operating scenarios; detailed wax and asphaltene analysis appears separately in Ratulowski et al, 1999. In particular, detailed thermal hydraulic multiphase flow simulations (described in Paragraph 2.7) are used to analyse the following critical flow assurance issues:

• Well cold start-up • Well safe condition time

• Steady-state flowing wellhead temperature • Well cooldown

• Steady-state arrival temperature • Flowline cooldown

• Flowline blowdown Riser gas lift requirements: • Slug suppression • Riser unloading • Injection temperature

For limitations identified in the conceptual design, possible design improvements are suggested and evaluated. Preliminary operating logic charts, consistent with this conceptual design analysis, are also developed.

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2.7 Computational Approach

2.7.1 Steady-state and Transient Wellbore

For all wellbore analysis, the WELLTEMP software developed by ENERTECH is used. WELLTEMP fully models wellbore flow using Shell two-phase flow models, and both conductive and convective heat transfer in casing annuli are explicitly modelled. Heat transfer in the surrounding formation (eg 50ft radius) is simulated directly using finite-difference methods, coupled to finite-volume (ie conservation form) representations of multiphase flow in the well tubing and heat transfer in the casing strings. Refined wellbore pressure modelling is performed using the Shell NEWPRS software, which is also based on the Shell GZM two-phase flow model (described below) and allows bubble point specification.

2.7.2 Steady-state Flowline

The process simulation software HYSYS, marketed by HYPROTECH, is used for steady-state predictions of thermal-hydraulic multiphase flow in the Angus flowlines. Extensive testing has shown that HYSYS PVT thermodynamic modelling is superior to other marketed packages, and the Shell GZM two-phase flow model (Zabaras, 1987) is incorporated into HYSYS for proprietary use by Shell. The GZM model uses Taitel and Dukler phase transition criteria, combined with empirical correlations for interphase friction, entrainment, holdup and wall-wetted fraction.

2.7.3 Flowline/Riser Cooldown

Flowline cooldown results are obtained with the Shell COOLDOWN software (Wasden, 1995), which solves the full transient heat conduction equation for axisymmetric, radial heat transfer, including multiple insulation layers. Axial heat conduction within the fluid and pipe are neglected, since axial temperature gradients (ie heat fluxes) are generally orders of magnitude smaller than radial gradients. Average thermophysical properties of the fluid are obtained with HYSYS, and selected cases are validated using full transient thermal-fluid simulations (OLGA).

2.7.4 Transient Flowline

To model time-dependent two-phase flow in the subsea flowlines, the OLGA software marketed by SCANDPOWER is used. OLGA solves a set of six coupled first-order, non-linear, one-dimensional partial differential equations: three continuity equations (gas, liquid film and liquid droplets), two momentum equations (liquid film, and a combined gas and liquid droplet field) and a mixture energy equation. For numerical solution, a staggered mesh finite difference method is used for spatial discretisation, with semi-implicit time stepping. The momentum equations are mechanistic in nature, requiring correlations of friction factor, wetted perimeter, entrainment, and deposition, along with flow regime specification based on a minimum-slip concept (ie regime with minimum slip velocity chosen). Although the total fluid composition is constant within a given pipeline branch, the liquid and gas compositions (thus, liquid and gas physical properties) can change continuously, eg during a flash.

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Transient mass transfer between phases is modelled using a Taylor-series expansion of the equilibrium gas mass fraction in terms of pressure and temperature. Non-equilibrium gas fractions (eg gas pockets above the bubble point in shut-in wellbores) may be specified as initial conditions and will subsequently vary according to the mass transfer rate. Simulations fully account for important elements such as flowline topography, multi-layered pipe insulations (including wellbore casings), heat storage in pipe walls and buried earth, and time-dependent valve openings, boundary conditions, and source flowrates, among others. Additionally, the proximity of instantaneous pressure and temperature values to hydrate dissociation conditions can be tracked both in space and time. For further details of the OLGA modelling approach and transient flow assurance applications, refer to Bendiksen et al (1991) and Schoppa et al (1998).

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Figure 1.1 – Production Forecast for Bonga Phase I Development (refer to Bonga Basis of Design)

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Figure 1.3 – Bonga Production Well Design, Used for All Thermal-hydraulic Analysis

0.50 psi/ft water-based 0.54 psi/ft oil-based 0.52 psi/ft brine

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OPRM20030302D_001.ai 0 -200 -400 -600 -800 -1000 -1100 0 500 1000 Length (m) Elevation (m) 1500 2000 2500 0 -200 -100 -400 -500 -300 -600 -800 -700 -900 -1000 -1100 0 1000 2000 Length (m) Elevation (m) 3000 4000 5000 6000 7000 8000 Gas Lift Gas Lift

Figure 1.4 – Production Flowline Topography for (a) 10in West-side Flowlines and (b) 12in East-side Flowlines

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OPRM20030302A_011.ai 10in Production Flowline

Flowline 10.75in OD x 0.937in Steel PU Foam

Air Gap

14in OD x 0.563in Steel

10in Production Riser

12in Production Flowline 12in Production Riser

12.75in OD x 1.063in Steel PU Foam

Air Gap

16in OD x 0.625in Steel

10.75in OD x 1.0in Steel

12.75in OD x 1.126in Steel 4in Carazite (or equivalent) 4in Carazite (or equivalent)

Figure 1.5 – Insulation Systems for 10in and 12in Pipe-in-pipe Flowlines (Left Panel), and Steel Catenary Risers (Right Panel)

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3.0 COLD WELL START-UP: HYDRATE PREVENTION STRATEGIES

For flow assurance in the subsea wells, the hottest (702p4 – horizontal) and coldest (702p7 – conventional) 702 wells (described in Paragraph 2.3 and Appendix 1B) are evaluated with regard to: (i) cold-earth start-up, (ii) safe condition requirements and cooldown performance, and (iii) steady-state flowing wellhead temperature. All wellbore thermal analysis is performed using WELLTEMP, for the casing designs in Figure 1.3 and a linear geothermal temperature profile, from the reservoir temperature to 40°F at the wellhead. Production rates over the range 2.5 to 40MBLPD are considered for early, mid, and late-life conditions (0%, 50%, 80% watercut). A sample WELLTEMP input file, summaries of simulation cases and results appear in Appendix 1B Tables 1B.1 to 1B.5.

For wellbore transients, the relevant terminology illustrated in Figure 1.6 is defined as follows:

• Cold Earth Start-up – Well start-up in which the wellbore, tree and well jumper are initially at ambient temperature

• Well Warm-up Time – Elapsed time upon start-up required for the Flowing Wellhead Temperature (FWHT) to exceed HDT (HDT = 74°F at well shut-in pressure)

• Safe Condition (SC) Temperature – FWHT which must be reached after start-up such that 8 hours of cooldown time is available

• Safe Condition Time – Elapsed time upon start-up for safe condition temperature to be reached

3.1 Cold Earth Well Start-up

A critical aspect of well flow assurance for Bonga is cold earth well start-up, in

which the wellbore and surrounding formation are at ambient (geothermal) temperature, either at initial start-up or after an extended shut-in (ie longer than 1 week). In contrast to the common use of Vacuum Insulated Tubing (VIT) to provide fast warm-up of deeper subsea wells in the GoM, bare tubing is used for all Bonga wells. Although the relatively shallow depth of the Bonga wells makes bare tubing viable, careful evaluation is required of the relative hydrate risk at start-up. As a worst case, the start-up of the coldest well (702p7) is considered first for early life conditions. As shown in Figure 1.7, the well warm-up time to HDT = 74°F is moderately lengthy, particularly at low start-up rates.

Note: Although rapid well ramp-ups are anticipated for Bonga (eg 10MBLPD within 1/2 hour), a more moderate start-up rate (eg 5MBPLD average) is analysed as a design case.

At a start-up rate of 5MBLPD, the wellhead region is temporarily in the hydrate region for 80 minutes (refer to Figure 1.7).

Note: As a general guideline, based on operating experience and preliminary hydrate kinetics research (which must be used carefully), a hydrate exposure longer than 60 minutes with greater than 10°F, subcooling is considered an unacceptable risk for subsea wells (with significant cost of intervention/ remediation).

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As a possible operational solution, bullheading of MeOH into the entire wellbore prior to start-up significantly reduces the hydrate risk, as reflected by the MeOH residence time (time required for one well pass) in Figure 1.7 (eg hydrate exposure time reduced from 80 minutes to 40 minutes at 5MBLPD).

Notes:

(1) Although the current well and subsea system design permit bullheading of MeOH past the SSV, it is undesirable to expose the bottomhole hardware to MeOH. Thus, precise operating and MeOH monitoring procedures will be required for whole-well bullheading.

(2) The MeOH volumes required: 150bbl for 4.9in ID well tubing and 250bbl for 5.9in ID.

In summary, the well warm-up times for cold earth start-up do pose a hydrate concern, but the risk is relatively small at expected start-up rates and can be reduced significantly by whole-well MeOH bullheading, if necessary (yielding hydrate exposure times comparable to currently operating GoM subsea wells). The decision whether to bullhead MeOH into the entire wellbore or only to the SSSV will be made on a well-by-well basis, as a part of ongoing operability and hydrate kinetics analysis (conducted in-house).

In summary, the wellbore hydrate exposure times for each bullheading option are: • 0% watercut:

Bullheading Option Hydrate Exposure (5MBLPD)

No MeOH in well 80 minutes

MeOH to SSSV (50 to 75bbl) 65 minutes

MeOH to perfs (150 to 250bbl) 40 minutes

• 50% watercut:

Bullheading Option Hydrate Exposure (5MBLPD)

No MeOH in well 50 minutes

MeOH to SSSV (50 to 75bbl) 35 minutes

MeOH to perfs (150 to 250bbl) 10 minutes

At higher watercuts, an additional issue that arises is the maximum start-up rate for which the resulting water production is treatable by MeOH delivery capacity (ie 18gpm per subsea tree). That is, whereas faster well start-up is desirable from a wellbore hydrate viewpoint (refer to Figure 1.7), at significant watercuts (50 to 80%), the MeOH rate becomes insufficient to protect the tree and well jumper. The treatable liquid rate at 18gpm MeOH injection is illustrated in Figure 1.8 as a function of watercut (based on MULTIFLASH calculations, Mehta, 1999). For the anticipated average start-up rate of 5MBLPD, Figure 1.8 indicates a watercut limit of ~20% for sufficient MeOH protection of the tree and jumper.

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At 50 to 80% watercut, an MeOH injection rate of 54 to 90gpm would be required, which is infeasible from an umbilical delivery viewpoint (leading also to significant MeOH production contamination). Thus, an additional factor to be considered during future operability analysis is whether or not to constrain start-up rates at high watercut, to protect the tree and jumper at the expense of the wellbore.

Preliminary operability analysis suggests a possible dual start-up strategy:

(1) Low watercut (below 20%): constrained start-up rate to yield MeOH-treatable (at 18gpm) water rates, with full hydrate protection of the tree and jumper.

(2) High watercut (above 20%): unconstrained (fast) start-up rate (ie limited only to prevent well/reservoir impairment) to ‘outrun’ the finite time hydrate kinetics in the wellbore, tree and jumper.

Note: For the fortunate result in Figure 1.9, the well warm-up time to HDT is much faster at higher watercut (due to higher heat capacity of water), which reduces the relative hydrate risk of the high watercut strategy.

Further development and testing of low dosage hydrate inhibitors will also be undertaken to further reduce the hydrate risk in the tree and jumper, for watercuts up to 80% and subcoolings up to 30°F (Mehta, 2001).

3.2 Well Safe Condition Analysis

The concept of a well safe condition is motivated by the risk of hydrate formation in

the wellbore in the event of an aborted start-up. In this way, operations staff can determine whether immediate MeOH treatment is required in the event of an aborted start-up. Before well safe condition has been reached during a well start-up, immediate operator action (eg well bullheading) is required before safe condition (without any no-touch time), in contrast to the full 8-hour cooldown period available after safe condition.

Note: The SC definitions are based on 8 hours of required cooldown time for the wellbore, tree and well jumper (eg 3 hours no-touch time + 5 hours MeOH treatment time).

During well start-up, hydrate inhibition via MeOH injection at the tree is generally recommended until the SC time is reached (Ellison and Kushner, 1998).

Note: If MeOH usage/storage is a concern, special operating guidelines may be developed to treat until 5 hours of cooldown are available (the MeOH treatment time), or even only to the (shorter) warm-up time to HDT.

These less conservative procedures are based on the idea that in an aborted start-up of a single well, no-touch time is unnecessary and only the well being started must be treated immediately. For Bonga, the condition for termination of MeOH injection at the tree will be determined as part of future operability analysis. For the coldest (702p7) and hottest (702p4) 702 wells, and early-life conditions, the wellbore SC times are shown in Figure 1.10 as a function of the average rate during start-up. For a moderate start-up rate of 5MBOPD, these results bracket the SC times for all 702 wells to between 5 to 10 hours, translating to 130 to 260bbls MeOH volume per well, for an 18gpm injection rate. At higher watercuts (eg greater than 50%), the SC time is significantly reduced (ie faster warm-up due to higher heat capacity of water), as illustrated in Figure 1.11 for the 702p7 well.

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The corresponding SC analysis for the tree and well jumper is based on the specification (for the subsea contractor) that these components must provide at least 12 hours of cooldown from 120°F to 73°F.

Note: This tree/jumper cooldown period is longer than the 8-hour cooldown allotted to the well tubing, to allow an additional operational margin for the field complexity of Bonga.

The SC temperature for the tree and well jumper is 120°F, for which the corresponding SC time is shown in Figure 1.12.

Note: The steady-state FWHT for well 702p7 does not reach 120°F, so its SC temperature in Figure 1.12 is modified to 110°F for purposes of comparison (an exception for 702p7 to be accounted for in operability analysis).

Owing to the rather lengthy tree/jumper SC times (eg greater than 10 hours at 5MBOPD), operating procedures for less than 12 hours of cooldown (ie more immediate action upon aborted start-up) may be necessary in lieu of MeOH injection until the tree/jumper SC time is reached.

Note: For treatment until a 12-hour SC, production at higher watercuts would have to be constrained for several hours to maintain a MeOH-treatable water rate, with the additional cost of deferred production.

3.3 Flowline Hot-oiling

Flowline preheating via hot-oiling is an effective means to prevent hydrate risk in the flowlines during cold start-up. Topsides hot-oiling facilities provide two oil circulation pumps capable of delivering 50MBOPD each, with heating of the (dry) supply oil to 150°F. The maximum oil supply pressures, based on 5mph circulation of an initially ambient flowline, are calculated as 520psia for the west-side flowlines and 770psia for the east-side flowlines (for a 250psia flowline outlet pressure). In Figure 1.13, the hot-oiling performance is shown for 50MBOPD circulation of 150°F source oil. For the west-side flowlines, a return temperature of 140°F is attained in 3 hours, with 130°F reached in 7 hours for the east-side flowlines. Preliminary start-up analysis indicates that hot-oiling provides at least 6 hours of cooldown (reaction) time in the event of an aborted start-up, provided that a steady state is established within 8 hours after hot-oiling.

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OPRM20030302D_002.ai 120 100 80 60 40 0 4 HDT SC Time 2 6 Time (hours) W ellhead T emperature (ºF) 8 10 12 14 Warm-up Time SC Temperature

Figure 1.6 – Definition of Well Start-up Terminology

OPRM20030302D_003.ai

4000 6000 8000 10,000 2000

0

Average Start-up Rate (BLPD)

200 250 300 150 100 50 0 T

ime After Star

t-up (minutes) Hydrate Exposure Time

Wellbore Outside Hydrate Region Time for one well pass Time to HDT

Figure 1.7 – Wellhead Warm-up Time to HDT, for Cold Earth Start-up of the Field’s Coldest Well (702p7) at 0% Watercut

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OPRM20030302D_004.ai 40 60 80 100 20 0 Watercut (%) 8000 10,000 6000 4000 2000 0 T

reatable Liquid Rate (oil + water) (BLPD)

Figure 1.8 – Treatable Liquid Rate for 18gpm MeOH Injection (Mehta, 1999)

OPRM20030302D_005.ai

4000 6000 8000 10,000

2000 0

120 180 240 60 0 T

ime to Reach HDT (minutes)

Wellbore Outside Hydrate Region Time for one well pass 50% wc

0%wc

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OPRM20030302D_006.ai

8 10 12 14 16

6 4

Average Start-up Rate (MBOPD)

8 10 6 4 12 2 0 SC T ime (hours):

Guarantee 8-hour Cooldown

702p4 horiz 702p7

Figure 1.10 – Safe Condition Time for 8-hour Wellbore Cooldown (refer to Figure 1.6 for definition)

OPRM20030302D_007.ai

10,000 15,000 20,000 5000

0

15 20 10 25 5 0 W ell SC T ime (hours):

50% wc 0% wc

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OPRM20030302D_008.ai

10 15 20 25 30

5 0

Average Start-up Rate (MBOPD)

15 10 20 5 0 SC T ime (hours):

702p7 702p4 horiz

Figure 1.12 – Safe Condition Time for 12-hour Cooldown of Tree/Jumper/Manifold, Based on Time for Wellhead Temperature to Reach 120°F

OPRM20030302D_009.ai 4 6 8 10 2 0 Time (hours) 140 80 100 120 West East 160 60 40 Arrival T emperature (ºF)

Figure 1.13 – Hot-oiling Performance: Return Temperature for 50MBOPD Circulation of 150°F Source Oil

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4.0 STEADY-STATE PRODUCTION

Steady-state system modelling typically focuses on the hydraulic capacity of the well/flowline system in delivery of the production forecast, which for Bonga has been addressed extensively using PIPESIM (refer to Granherne, 1998; Hartwik and Lindsey, 2000). Additionally, several key aspects of flow assurance are linked to steady-state system performance, including:

• Arrival temperatures in relation to topsides oil heating capacity

• Riser base temperatures governing available flowline/riser cooldown time • Slugging

• Production fluid cooling by riser base gas lift

4.1 Steady-state Thermal Performance: Wellbore and Flowline

Since prior wellbore analysis (Granherne, 1998) has been based on the approximation of constant U value for the wellbore (ie U=2.0Btu/hr-ft2-F), the more rigorous thermal modelling in WELLTEMP is used here to obtain refined FWHT predictions. The range of FHWT predicted for the six initial-life production wells is shown in Figure 1.14, along with 702p7, the field’s coldest well (which fortunately produces through the short-offset West flowline PFL11). At the minimum well production rate of 10MBLPD specified in the Basis of Design (BoD), the FWHT lies in the range 115 to 165°F. The lower end of this FWHT range is noticeably colder than that typical of (deeper) GoM subsea oil wells, which should be accounted for in building upon GoM subsea operating experience.

Note: Production rates lower than 10MBLPD (eg as low as 5MBLPD) are also operable from a thermal point of view, although well stability must also be accounted for in specifying the minimum turndown rate.

Later in field life, the FWHT increases slightly for all flowrates (eg by 5°F for 80% watercut), due to the enhanced thermal heat capacity of water (which may be offset to some degree by reservoir cooling due to waterflood).

With regard to the thermal performance of the coupled well/flowline system, there are three key constraints which govern the minimum operable arrival temperature for steady-state production:

• Flowline operation outside of hydrate regime: arrival T > 60°F • Minimum 12-hour cooldown of riser/flowline: arrival T > 90°F

• Sufficient topsides oil temperature for available waste heat capacity at high production rates (~200MBOPD): arrival T > 98°F

In Figure 1.15, the arrival temperatures for the six initial-life wells/flowlines are shown as a function of production rate.

Note: Each initial-life well produces through a dedicated flowline, with an initially inactive West flowline pair PFL8/9.

For all pipe-in-pipe flowlines, an overall heat transfer co-efficient of Uod = 2W/m2-C is

used, corresponding to a polyurethane foam thickness of ~0.6in (leaving ~0.4in of air gap, refer to Figure 1.4).

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Note: Cooldown requirements will likely require an entirely foam-filled gap (ie MoC 59, discussed in Paragraph 5.1), for which the arrival temperatures will be slightly higher than those reported here (particularly at low production rates).

The 12-hour cooldown constraint (detailed analysis presented in Paragraph 5.1) translates to a minimum turndown production rate of approximately 10MBOPD for the four east-side flowlines. Although slightly lower production rates may be possible for special operations which are manageable with less than 12 hours of cooldown, production rates less than 5MBOPD are inoperable due to onset of flowing conditions in the hydrate regime. With regard to the topsides heat requirement at high production rates, the cumulative oil temperature for all six initial-life wells/flowlines (with equal production from each; refer to Figure 1.16) indicates that the 98°F constraint is met even at turndown conditions (ie >50MBOPD), with a 20°F margin in arrival temperature at flowrates greater than 150MBOPD. Thus, the available topsides waste heat for oil heating is not of concern at initial field life, which serves as the worst case since oil production will subsequently decrease (accompanied by increasing water production).

4.2 Terrain-induced (Severe) Slugging

The phenomenon of severe slugging induced by undulations in flowline terrain is predicted to be significant at Bonga in the absence of mitigating control, due to: • Significant downhill flow near the riser base for east-side flowlines

(~30m elevation drop, refer to Figure 1.49) • Production of high watercuts (80 to 90%) • Large diameter flowlines (10in to 12in) • Significant water depth (~1000m)

Note: The distinction between shorter hydrodynamic slugs (up to ~50 diameters in length) in locally horizontal or uphill flow and longer terrain slugs (proportional to the length of downhill flow), which are more problematic for topsides facilities and process control.

That terrain slugging is outside the scope of steady-state simulations, which cannot capture at all the adverse effects of higher well backpressure and order-of-magnitude fluctuations in liquid production rate. In the following, Olga2000 is used to define the terrain slugging operability envelope, including detailed assessment of slug suppression via riser gas lift.

For terrain slugging to occur in a flowline/riser system, three necessary conditions must be satisfied simultaneously (Vreenegoor, 1999):

(1) The Pots slugging number less than order unity in the flowline:

l g ss m m Lg zRT & & α = π < O(1)

(2) The densimetric Froude number less than order unity in the riser:

gD

U

Fr

g l g sg

)

(

ρ

−

ρ

=

< O(1)

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Physically, the slugging number condition:

• Reflects the fact that sufficient gas compressibility (‘capacitance’) is required for slugs not to be expelled from the flowline. The Froude number condition

• Indicates that unstable riser flow (ie liquid surging and fallback in the riser) is necessary to initiate a flow blockage at the riser base

• Enables growth of the liquid slug

For representative Bonga conditions at 10MBLPD and 50% watercut, the slugging numbers for each flowline are:

• East 12in: πss = 0.3

• East 10in: πss = 0.2

• West 10in: πss = 0.7

Furthermore, the Froude number (without gas lift) is on the order of 0.05 and stratified flow is predominant in the downhill flow regions near the riser base. Thus, based on this simple conceptual analysis, severe terrain slugging is predicted at Bonga without riser gas lift, particularly for the east-side flowlines.

Although it has not yet been field-proven for large-diameter deepwater risers, a potentially effective slug control technique involves gas injection at or near the riser base. With reference to the necessary conditions for terrain slugging, gas lift can eliminate the riser instability required for slug initiation (ie Froude number greater than order unity). For the 12in east Bonga flowline, riser gas lift increases the Froude number from order 0.05 to order 1 (refer to Figure 1.17), and hence is expected to be effective in slug suppression. In the following, Olga2000 computations are used to investigate in detail the effectiveness of riser gas lift in suppressing terrain slugging.

In Figures 1.18 to 1.20, the gas lift required to suppress terrain slugging is shown as a function of liquid production rate. In Olga2000, terrain slugging can be isolated from smaller, less problematic hydrodynamic slugs (ie by switching Slugtracking off), to yield a sharp transition from terrain to hydrodynamic slugging. For all west-side 10in flowlines (refer to Figure 1.18), no riser gas lift is required at the minimum turndown rate of 10MBLPD, even at 80% watercut. This result is in contrast to prior studies (Granherne, 1998), which indicated that 5MMscfd gas lift was required, apparently due to inaccurate modelling of the riser-base topography.

Note: Slugging may be suppressed at turndown rates as low as 5MBLPD, by gas lift rates up to 10MMscfd (refer to Figure 1.18).

For the 10in east-side flowlines, 5 to 10MMscfd gas lift is required to eliminate slugging for the minimum rate of 10MBLPD at 0 to 80% watercut (refer to Figure 1.19). Due to the more adverse east-side topography, the gas lift requirement for flowrates lower than 10MBLPD is much more significant for the 10in east flowlines, compared to the 10in west results. Thus, even at the gas lift capacity of 25MMscfd per flowline, signficant slugging will occur for the east-side flowlines for turndown rates lower than approximately 8MBLPD (refer to Figure 1.19).