Flow Assurance Guidelines

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SHELL NIGERIA EXPLORATION AND PRODUCTIONSHELL NIGERIA EXPLORATION AND PRODUCTIONSHELL NIGERIA EXPLORATION AND PRODUCTIONSHELL NIGERIA EXPLORATION AND PRODUCTION

COMPANY Ltd.COMPANY Ltd.COMPANY Ltd.COMPANY Ltd.

Bonga FPSOBonga FPSOBonga FPSOBonga FPSO

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

Volume 2DVolume 2DVolume 2DVolume 2D

FLOW ASSURANCE GUIDELINESFLOW ASSURANCE GUIDELINESFLOW ASSURANCE GUIDELINESFLOW ASSURANCE GUIDELINES

OPRMOPRMOPRMOPRM----2003200320032003----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

2.02.02.02.0 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 2DVolume 2DVolume 2DVolume 2D Flow Assurance GuidelinesFlow Assurance GuidelinesFlow Assurance GuidelinesFlow 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 SystemVolume 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 SystemVolume 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

Volume 35 Ancillary Living Quarters (ALQ)




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

3.03.03.03.0 SCOPESCOPESCOPESCOPE

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.

4.04.04.04.0 TARGTARGTARGTARGET READERSHIPET READERSHIPET READERSHIPET READERSHIP

All SNEPCO staff who may be involved in the operation of the Subsea

Systems onboard the Bonga FPSO.

5.05.05.05.0 SPECIAL NOTESPECIAL NOTESPECIAL NOTESPECIAL NOTE

Not applicable.

6.06.06.06.0 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.

7.07.07.07.0 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 areavailable within the SNEPCO Livelink System. Where appropriate, these

documents have been cross-referenced within this document.




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

Definitions and AbbreviationsDefinitions and AbbreviationsDefinitions and AbbreviationsDefinitions and Abbreviations

DefinitionsDefinitionsDefinitionsDefinitions

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/

FormationTemperature

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.




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.

AbbreviationsAbbreviationsAbbreviationsAbbreviations

API American Petroleum InstituteASTM American Society for Testing and Materials

Ba BariumBaSO4 BaryteBIST Bonga Integrated Studies Team

BLPD Barrels Liquid Per DayBoD Basis of DesignBOOR Bonga Oil Offloading RiserBS&W Base Sediment and WaterBSET Bonga Systems Engineering Team

CaCO3 CalciteCIV Chemical Injection ValveCPM Cross-polar MicroscopyCWDT 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, HoustonFDP Field Development PlanFEAST Fluids Evaluation and Stability TestingFPSO Floating Production, Storage and OffloadingFPT Field Planning ToolFWHP Flowing Wellhead PressureFWHT Flowing Wellhead Temperature

GLIV Gas Lift Injection ValveGLR Gas Lift RiserGoM Gulf of Mexico

GOR Gas/Oil RatioHDP Hydrate Dissociation PressureHDT Hydrate Dissociation TemperatureHRGC High Resolution Gas ChromatographyHS&E Health, Safety and EnvironmentHSE Health and Safety ExecutiveHTGC High Temperature Gas Chromatography

ID Inside DiameterITT Invitation to Tender

KHI Kinetic Hydrate Inhibitor

LDHI Low Dosage Hydrate InhibitorLP Low Pressure






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

WSV Well Switching Valve

WTC Westhollow Technology Center

XOV Crossover Valve




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

Reference Information/Supporting DocumentationReference Information/Supporting DocumentationReference Information/Supporting DocumentationReference 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.






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

Main Table of ContentsMain Table of ContentsMain Table of ContentsMain Table of Contents

Document Status InformationDocument Status InformationDocument Status InformationDocument Status Information

Definitions and AbbreviationsDefinitions and AbbreviationsDefinitions and AbbreviationsDefinitions and Abbreviations

Reference Information/SupportinReference Information/SupportinReference Information/SupportinReference Information/Supporting Documentationg Documentationg Documentationg Documentation

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

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

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

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

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

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

Section 7Section 7Section 7Section 7 Scale ReviewScale ReviewScale ReviewScale Review

Section 8Section 8Section 8Section 8 RiskRiskRiskRisk----based Evaluation of Scaling Tendencies for thebased Evaluation of Scaling Tendencies for thebased Evaluation of Scaling Tendencies for thebased Evaluation of Scaling Tendencies for the

Subsea SystemSubsea SystemSubsea SystemSubsea System



Shell Nigeria E & P Company Ltd. Unrestricted

Section 1 Dynamic Flow Assurance Analysis

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

Section 1Dynamic 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

6.0 CONCLUDING REMARKS AND PRELIMINARY OPERATING LOGIC.....................60






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 ThicknessWithin ‘Pipe-in-pipe’ Flowlines ...........................................................................43

FIGURES

Figure 1.1 – Production Forecast for Bonga Phase I Development (refer to Bonga Basisof 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’sColdest 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 Circulationof 150°F Source Oil ........................................................................................25

Figure 1.14 – Flowing Wellhead Temperatures Calculated for Initial-life Wells andthe 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, Relativeto 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 toEliminate Riser Instability and Terrain Slugging Shown for the 12inEast-side Risers .............................................................................................34

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

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







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 Cutas a Function of Gas Lift Rate ........................................................................36

Figure 1.22 – Separator Level Fluctuation Calculated for 12in East-side Flowlinesand 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 for10MBOPD Production and 25MMscfd Gas Lift for Slug Suppression .............37

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

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

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

Figure 1.27 – System Temperature Summary for Base-case Flexible Riser-basedGas 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 UnsuccessfulBlowdown for All Scenarios ............................................................................56

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

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







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 Providing24 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

Appendix 1C – Production Flowlines: Topography and Ambient Temperature Data .............79






1.0 EXECUTIVE SUMMARY

Using validated analytical and computational techniques, the dynamic thermal-hydraulic performance of the Bonga conceptual subsea system is evaluated withregard 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 toensure a robust design of the Bonga subsea system, to enable efficient,hydrate-free operations. Analysis presented herein validates the Bonga conceptualdesign with respect to hydrate management, upon implementation of the followingmodifications to hardware design and operational procedures.

1.1 Hardware Design

• Replacement of gas lift umbilical with flexible riser and addition of gas liftheating (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 withlarge 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-earthstart-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 andsecondary oil circulation






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 jointventure with Esso (20%), Elf (12.5%) and Agip (12.5%). Bonga will be developed asa subsea network, with 1.9 to 9.2km tiebacks to a permanently moored FloatingProduction, Storage and Offloading vessel (FPSO). Anticipated peak productionrates are 225MBOPD oil, 170MMscfd gas (including recycled riser gas lift) and100MBWPD produced water (refer to production function in Figure 1.1). Reservoirpressure will be maintained via 16 subsea waterflood wells with a 300MBWPD totalwater injection capacity. Produced oil will be stored on the FPSO (2MMBO storagecapacity) for tanker offloading, while Bonga gas will be exported 90km via a 16inpipeline to Riser Platform A of the Offshore Gas Gathering System (OGGS), whichfeeds 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 subseaproduction wells. Production wells contain a subsea tree (enabling surfacecontrolled isolation valves, production choke and chemical injection valves)connected via short well jumpers to five subsea production manifolds. The subseawells are produced through four pairs of piggable dual flowlines (three 10in pairsand one 12in pair), with pipe-in-pipe flowlines and externally insulated steel catenaryrisers. Each flowline is connected to a dedicated gas lift riser delivering up to25MMscfd riser base gas lift. Riser base gas lift is critical for several Bongaoperations, enabling:

• Riser unloading during start-up and blowdown

• Severe slug suppression

• Production enhancement

As a subsea production system of unprecedented complexity in a new deepwateroperating environment, Bonga entails several key flow assurance and systemsengineering 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 installationof all Bonga facilities. However, Shell has chosen to retain ‘ownership’ of flowassurance via design specifications in each EPIC contract, based on flow assuranceanalysis 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 withrespect to Shell Deepwater Flow Assurance Guidelines (Ellison and Kushner, 1998),and to outline the Management of Change (MoC) identified by this analysis.






2.2 Reservoir Fluid

The fluid composition and properties for each Bonga reservoir (690, 702, 710/740and 803) are summarised in Appendix 1A Table 1A.1. The reservoir fluids exhibitthe 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 compositionalPressure/Volume/Temperature (PVT) models tuned to match the properties of thedominant 702 reservoir. All transient simulations in OLGA are based on the phasediagram shown in Figure 1.46, calculated for the 702 reservoir fluid. For purposes ofanalysis, 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 forearly, mid and late-life scenarios, respectively.

Hydrate dissociation curves (pressure (HDP) vs temperature (HDT)) for the 702and 803 fluids are presented in Appendix A, calculated using MULTIFLASH(Mehta, 1998). The expected salinity is that of the seawater (due to significantwaterflood), ie approximately 3wt % salt. As a result of this low salinity, compared tothe typical 15% salinity of subsea GoM fields, hydrate management for Bonga isparticularly challenging (ie HDT approximately 10°F higher). For conservatism,the hydrate dissociation conditions of the 803 fluid with 0% salinity (refer toFigure 1.48) are used as a worst-case for all flowline analysis in this report. At theminimum seabed temperature (40°F), this translates to a blowdown target pressure

of HDP = 150psia. For subsea facilities (tree, well jumper and manifold) a targethydrate 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 rangeof 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

– Productivity index (average) = 20 to 110BLPD/psia






• 690 Wells




– 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




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




• 803 Wells








For conceptual design evaluation, we focus here on wells 702p7 (coldest) and702p4 (hottest), which represent the flowing wellhead temperature extremes for thedominant 702 reservoir.

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






The well casing and annulus fluid design summarised in Figure 1.3 (from VanGisbergen, 1999) is used for all transient and steady-state thermal wellboreanalysis. 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


– 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


– 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 sideand 12in east side flowline topographies (refer to Figure 1.4), which capture theessential terrain features on either side of the FPSO.

Note: The significant difference in offset distance between the East (3.9 and 5.8miles) 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 theFPSO, at the flowline/riser connection (refer to Figure 1.4). In Appendix 1C, furtherflowline details are summarised, including individual flowline topographies, thecatenary 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 10innominal 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 isused 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/m 2 -C can be attained by filling theentire annulus space with foam (as recommended here based on cooldownconsiderations).

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).






2.5 Operating Conditions and Constraints

As a tieback comprised of numerous subsea wells and flowlines, Bonga entailsseveral 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 andmanifold

• 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 inhibitionotherwise

• No wax deposition in the wellbore

2.6 Objectives

The principal objective of this report is to evaluate the conceptual design of theBonga subsea system with respect to flow assurance, topsides and subsea systemconstraints, and operability. The main focus here is on hydrate prevention during allexpected operating scenarios; detailed wax and asphaltene analysis appears

separately in Ratulowski et al, 1999. In particular, detailed thermal hydraulicmultiphase flow simulations (described in Paragraph 2.7) are used to analyse thefollowing 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 aresuggested and evaluated. Preliminary operating logic charts, consistent with thisconceptual design analysis, are also developed.






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 explicitlymodelled. Heat transfer in the surrounding formation (eg 50ft radius) is simulateddirectly using finite-difference methods, coupled to finite-volume (ie conservationform) representations of multiphase flow in the well tubing and heat transfer inthe casing strings. Refined wellbore pressure modelling is performed using theShell NEWPRS software, which is also based on the Shell GZM two-phase flowmodel (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 issuperior to other marketed packages, and the Shell GZM two-phase flow model(Zabaras, 1987) is incorporated into HYSYS for proprietary use by Shell. The GZMmodel uses Taitel and Dukler phase transition criteria, combined with empiricalcorrelations 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 foraxisymmetric, radial heat transfer, including multiple insulation layers. Axial heatconduction 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, andselected 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 OLGAsoftware marketed by SCANDPOWER is used. OLGA solves a set of six coupledfirst-order, non-linear, one-dimensional partial differential equations: three continuityequations (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 aremechanistic in nature, requiring correlations of friction factor, wetted perimeter,entrainment, and deposition, along with flow regime specification based on aminimum-slip concept (ie regime with minimum slip velocity chosen). Although thetotal fluid composition is constant within a given pipeline branch, the liquid and gascompositions (thus, liquid and gas physical properties) can change continuously,eg during a flash.








Figure 1.1 – Production Forecast for Bonga Phase I Development

(refer to Bonga Basis of Design)






Figure 1.2 – Bonga Subsea Field Layout






Figure 1.3 – Bonga Production Well Design,

Used for All Thermal-hydraulic Analysis

0.50 psi/ft

0.54 psi/ft

0.52 psi/ft






OPRM20030302D_001.ai

0

-200

-400

-600

-800

-1000

-1100

0 500 1000

Length (m)

E l e v a t i o n ( m )

1500 2000 2500

0

-200

-100

-400

-500

-300

-600

-800

-700

-900

-1000

-1100

0 1000 2000

Length (m)

E l e v a t i o n ( 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






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)






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 requirementsand cooldown performance, and (iii) steady-state flowing wellhead temperature.

All wellbore thermal analysis is performed using WELLTEMP, for the casing designsin Figure 1.3 and a linear geothermal temperature profile, from the reservoirtemperature to 40°F at the wellhead. Production rates over the range 2.5 to40MBLPD are considered for early, mid, and late-life conditions (0%, 50%, 80%watercut). A sample WELLTEMP input file, summaries of simulation cases andresults appear in Appendix 1B Tables 1B.1 to 1B.5.

For wellbore transients, the relevant terminology illustrated in Figure 1.6 is definedas 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 FlowingWellhead Temperature (FWHT) to exceed HDT (HDT = 74°F at well shut-inpressure)

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

• Safe Condition Time – Elapsed time upon start-up for safe conditiontemperature 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, inwhich the wellbore and surrounding formation are at ambient (geothermal)temperature, either at initial start-up or after an extended shut-in (ie longer than1 week). In contrast to the common use of Vacuum Insulated Tubing (VIT) toprovide fast warm-up of deeper subsea wells in the GoM, bare tubing is used for allBonga wells. Although the relatively shallow depth of the Bonga wells makes baretubing 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 earlylife conditions. As shown in Figure 1.7, the well warm-up time to HDT = 74°F ismoderately lengthy, particularly at low start-up rates.

Note: Although rapid well ramp-ups are anticipated for Bonga ( eg 10MBLPD within1/2 hour), a more moderate start-up rate ( eg 5MBPLD average) is analysedas a design case.

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

Note: As a general guideline, based on operating experience and preliminaryhydrate kinetics research (which must be used carefully), a hydrate exposure

longer than 60 minutes with greater than 10 ° F, subcooling is considered anunacceptable risk for subsea wells (with significant cost of intervention/remediation).






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

Notes:

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

(2) The MeOH volumes required: 150bbl for 4.9in ID well tubing and 250bbl for5.9in ID.

In summary, the well warm-up times for cold earth start-up do pose a hydrateconcern, but the risk is relatively small at expected start-up rates and can bereduced 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 SSSVwill be made on a well-by-well basis, as a part of ongoing operability and hydratekinetics 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 ratefor 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 awellbore 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 afunction of watercut (based on MULTIFLASH calculations, Mehta, 1999). For theanticipated average start-up rate of 5MBLPD, Figure 1.8 indicates a watercut limit of~20% for sufficient MeOH protection of the tree and jumper.








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

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

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

Note: The steady-state FWHT for well 702p7 does not reach 120 ° F, so its SCtemperature 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 at5MBOPD), operating procedures for less than 12 hours of cooldown (ie moreimmediate 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 haveto 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 theflowlines during cold start-up. Topsides hot-oiling facilities provide two oil circulationpumps capable of delivering 50MBOPD each, with heating of the (dry) supply oilto 150°F. The maximum oil supply pressures, based on 5mph circulation of aninitially ambient flowline, are calculated as 520psia for the west-side flowlinesand 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 of150°F source oil. For the west-side flowlines, a return temperature of 140°F isattained 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 ofcooldown (reaction) time in the event of an aborted start-up, provided that a steadystate is established within 8 hours after hot-oiling.








OPRM20030302D_004.ai

40 60 80 100200

Watercut (%)

8000

10,000

6000

4000

2000

0

T r e a t a b l e L i q u i d R a t e ( o i l + w a t e r ) ( B L P D )

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

OPRM20030302D_005.ai

4000 6000 8000 10,00020000

Average Start-up Rate (BLPD)

120

180

240

60

0

T i m e t o R e a c h H D T ( m i n u t e s )

Wellbore Outside

Hydrate Region

Time for one well pass

50% wc

0%wc

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






OPRM20030302D_006.ai

8 10 12 161464

Average Start-up Rate (MBOPD)

8

10

6

4

12

2

0

S C T i m e ( h o u r s ) :

G u a r a n t e e 8 - h o u r C o o l d o w n

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 20,00015,00050000

Average Start-up Rate (BLPD)

15

20

10

25

5

0

W e l l S C T i m e ( h o u r s ) :


50% wc0% wc

Figure 1.11 – Influence of Water Cut on Well Safe Condition Time for 702p7






OPRM20030302D_008.ai

10 3015 20 2550

Average Start-up Rate (MBOPD)

15

10

20

5

0

S C T i m e ( h o u r s ) :


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

4 106 820

Time (hours)

140

80

100

120

West

East

160

60

40

A r r i v a l T e m p e r a t u r e ( º F )

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






4.0 STEADY-STATE PRODUCTION

Steady-state system modelling typically focuses on the hydraulic capacity of thewell/flowline system in delivery of the production forecast, which for Bonga has beenaddressed extensively using PIPESIM (refer to Granherne, 1998; Hartwik andLindsey, 2000). Additionally, several key aspects of flow assurance are linked tosteady-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 theapproximation of constant U value for the wellbore (ie U=2.0Btu/hr-ft2-F), the morerigorous thermal modelling in WELLTEMP is used here to obtain refined FWHTpredictions. The range of FHWT predicted for the six initial-life production wells isshown in Figure 1.14, along with 702p7, the field’s coldest well (which fortunatelyproduces through the short-offset West flowline PFL11). At the minimum wellproduction rate of 10MBLPD specified in the Basis of Design (BoD), the FWHT liesin the range 115 to 165°F. The lower end of this FWHT range is noticeably colderthan that typical of (deeper) GoM subsea oil wells, which should be accounted for inbuilding upon GoM subsea operating experience.

Note: Production rates lower than 10MBLPD (eg as low as 5MBLPD) are alsooperable 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 offsetto some degree by reservoir cooling due to waterflood).

With regard to the thermal performance of the coupled well/flowline system, thereare three key constraints which govern the minimum operable arrival temperaturefor 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 highproduction rates (~200MBOPD): arrival T > 98°F

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

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

For all pipe-in-pipe flowlines, an overall heat transfer co-efficient of Uod = 2W/m2-C isused, corresponding to a polyurethane foam thickness of ~0.6in (leaving ~0.4in ofair gap, refer to Figure 1.4).






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

The 12-hour cooldown constraint (detailed analysis presented in Paragraph 5.1)translates to a minimum turndown production rate of approximately 10MBOPD forthe four east-side flowlines. Although slightly lower production rates may be possiblefor special operations which are manageable with less than 12 hours of cooldown,production rates less than 5MBOPD are inoperable due to onset of flowingconditions in the hydrate regime. With regard to the topsides heat requirement athigh production rates, the cumulative oil temperature for all six initial-lifewells/flowlines (with equal production from each; refer to Figure 1.16) indicates thatthe 98°F constraint is met even at turndown conditions (ie >50MBOPD), with a 20°Fmargin in arrival temperature at flowrates greater than 150MBOPD. Thus, theavailable 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 ispredicted 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 inlength) in locally horizontal or uphill flow and longer terrain slugs (proportionalto the length of downhill flow), which are more problematic for topsidesfacilities and process control.

That terrain slugging is outside the scope of steady-state simulations, whichcannot capture at all the adverse effects of higher well backpressure andorder-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 conditionsmust be satisfied simultaneously (Vreenegoor, 1999):

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

l

g

ssm

m

Lg

zRT

&

&

α=π < O(1)

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

gDU Fr

gl

g

sg)( ρ−ρ

ρ= < O(1)

(3) Stratified flow pattern in the riser base region of the flowline.








For the 12in east flowlines, terrain slugging cannot be totally eliminated by feasibleriser gas lift rates. Hence, for these 12in flowlines, the gas lift required to reduce theterrain slug size to <50bbl is shown in Figure 1.20. Due to the larger diameter, thegas lift requirements are more stringent compared to the 10in east-side results.

In particular, gas lift approaching 20MMscfd is required at the minimum rate of10MBLPD and 80% watercut (refer to Figure 1.20). In addition, marginal gas liftvolumes are needed at higher production rates as well (eg ~5MMscfd at 20MBLPD),suggesting that gas lift (albeit at varying rates) may be frequently required for the12in east flowlines, even very early in field life. The required gas lift volumes at theminimum anticipated turndown rate of 10MBLPD are summarised for all flowlines inTable 1.1.

Flowline WatercutMinimum Stable

Production Without

Gas Lift

Gas LiftRequired for

10MBLPD

Production

10in West

PFL 8/9

PFL 11/12

0%

50%

80%

10MBLPD

10MBLPD

10MBLPD

0

0

0

10in East

PFL 1/2

0%

50%

80%

30MBLPD

35MBLPD

35MBLPD

5MMscfd

8MMscfd

10MMscfd

12in East

PFL 3/4/5/6

0%

50%

80%

30MBLPD

35MBLPD

40MBLPD

10MMscfd

17MMscfd

17MMscfd

Note: The requirements for the 12in east flowline are based on a maximum slugvolume of 50bbl, while results for other flowlines reflect complete terrain slugsuppression.

Table 1.1 – Riser Gas Lift Requirements for Terrain Slug Suppression

To address severe slugging and the mitigating effect of riser gas lift in greater detail,an Olga Slugtracking Analysis was performed for the 12in east flowline, whichexhibits the worst-case slugging (refer to Table 1.1). The Olga Slugtracking modelcaptures the accumulation at the riser base of smaller hydrodynamic slugsgenerated in the flowline, which may enhance terrain slugging. Additionally,the effect of slugging on topsides vessel level control is modelled as an inletseparator attached to the flowline outlet, with the following specifications (in accordwith the Bonga topsides conceptual design):

• 132in diameter x 50ft seam-seam inlet separator (reflecting one of two availableseparators)

• 75MBLPD oil dump capacity (qualitative surge capacity for oil train)






• Oil dump valve Proportional Integral Derivative (PID) controller:

– Gain = 10

– Integral const = 60 s (fast-acting level control)

For the 12in east flowline at 50% watercut, significant slug volumes on the order of800bbl are predicted at turndown rates of 10 to 20MBLPD in the absence ofriser gas lift (refer to Figure 1.21). As a consequence of these large slug volumes(without gas lift), separator level fluctuations of 10 to 20% occur at 10 to 20MBLPD(refer to Figure 1.22), magnitudes considered by Bonga topsides engineers to beunacceptably large for efficient separation and overall process control. Riser gas liftis seen to be particularly effective in reducing the slug volume, as manageable slugvolumes of 50 to 100bbl and separator level fluctuations of 2 to 3% are attained withonly 10MMscfd gas lift (Figures 1.21 and 1.22).

Note: There is no benefit of gas lift rates higher than 10MMscfd, due to smaller(~50bbl) hydrodynamic slugs generated in the flowline and accelerated

through the riser.

In summary, modest gas lift rates on the order of 10MMscfd per flowline arepredicted to manage severe slugging at Bonga to an acceptable degree, for aminimum turndown rate of 10MBLPD. Nevertheless, it is important to apply asignificant design margin to these results, noting the modelling complexity and lackof field data for riser gas lift in deepwater systems. In particular, further experimentalstudies are clearly needed for gas lift in large-diameter risers, to confirm theeffectiveness of gas lift in lifting riser liquid during flowing conditions(ie extending recent experimental analysis of gas lifting of a static liquid column;Zabaras and Schoppa, 2001). Additionally, the ‘resonance’ of multiphase flow in theflowline with topsides process flows (shown to intensify severe slugging in recent

industry publications) is a detailed design issue beyond the scope of this report.Such coupling of subsea/topsides flows is the subject of extensive ongoing dynamicsimulation work for Bonga (Duhon and Schoppa, 2001).

4.3 Riser Gas lift: Thermal Considerations

Continuous riser base gas lift will be used during steady-state production for twoexpected operational scenarios:

• Slug suppression at turndown rates (particularly for the east-side flowlines)

• Production enhancement at high watercut (eg as high as 80 to 90% at late life)

Thus, the thermal impact of (potentially cold) gas lift injection at the riser base is

considered here in detail, with respect to available riser cooldown time and arrivaltemperature. The thermal limitations of a prior umbilical-based gas lift design areoutlined, and an improved large-bore design is presented (ie MoC 16).

In prior conceptual analysis (Granherne, 1998), it was incorrectly assumed that theinjected gas would have negligible influence on the production fluid temperature.For example, for a gas lift injection rate of 25MMscfd (for terrain slug suppression)and 10MBLPD production, cold gas injected at 40°F reduces the production fluidtemperature by 20°F throughout the riser (ie see temperature drop at gas lift locationin Figure 1.23).








The thermal performance of the large-bore gas lift design is evaluated below withrespect to the following constraints:

• Minimum injection temperature for 5 to 25MMscfd gas lift > 90°F

• Inlet temperature to gas lift riser (downstream of topsides choke) < 160°F

• Gas heater temperature (upstream of topsides choke) < 200°F

As illustrated in Figure 1.12, for a 25MMscfd gas lift rate, the riser diameter stronglyinfluences the gas injection temperature, as a 3.5in riser produces a 15°F higherinjection temperature compared to a 3in riser. This is due to the fact that for smallerdiameters, less topsides choking is required (more pressure drop in riser) and thegas heater temperature must be reduced to satisfy the 160°F riser inlet temperatureconstraint. At the minimum gas lift rate of 5MMscfd, the riser insulation dominatesthe thermal performance, for which an insulating value of approximatelyU = 4W/m2-C is needed to attain the 90°F injection target (refer to Figure 1.26).This U value corresponds to a 2.5in carazite insulation thickness (or equivalent)

applied externally to the gas lift riser.

In summary, the recommended design parameters, serving as a base case to beoptimised during detailed design, are a 3.5in ID central gas lift pipe with an effectiveU value of 4W/m2-C. As illustrated in Figure 1.27, this large-bore riser designsatisfies all requirements for gas lift, providing a gas injection temperature of at least90°F over the entire range of gas rates. In this design, topsides heating of thegas lift stream is an effective approach to prevent a significant gas lift coolingpenalty on arrival temperature and riser cooldown. This analysis culminated in thepreparation and acceptance of MoC 16, which specified the gas lift heatingrequirements and large-bore riser design described above.








OPRM20030302D_012.ai

100 250150 200500

Cumulative Rate (MBOPD)

120

90

100

110

130

80

70

B u l k A r r i v a l T e m p e r a t u r e ( º F )

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

OPRM20030302D_013.ai

15 3520 30255 100

Riser Gas Lift (MMSCFD)

0.1

1

0.01

F r o u d e #

FR < 0(1): Riser instability

and possible slugging

Figure 1.17 – Influence of Riser Gas lift on Riser Froude Number, as a Means toEliminate Riser Instability and Terrain Slugging Shown for the 12in East-side Risers






OPRM20030302D_014.ai

10 20 30 400

Liquid Production Rate (MBLPD)

10

5

15

20

0

R e q u i r e d G a s L i f t ( M M S C F D )

0%wc

50%wc

80%wc

Figure 1.18 – Riser Base Gas Lift Required for Complete Suppression ofTerrain Slugging for 10in West-side Flowlines

OPRM20030302D_015.ai

10 20 30 400


20

10

30

40

0

R e q u i r e d G a s L i f t ( M M S C F D )

0%wc

50%wc

80%wc

Figure 1.19 – Riser Base Gas Lift Required for Complete Suppression ofTerrain Slugging for 10in East-side Flowlines






OPRM20030302D_016.ai

10 20

0%wc

50%wc

80%wc

30 400


10

20

30

0

R e q u i r e d G a s L i f t ( M M S C F D

)

Figure 1.20 – Riser Base Gas Lift Required to Limit Terrain Slugging toWithin 50bbl Slugs for 12in East-side Flowlines

OPRM20030302D_017.ai

5 10

10MBLPD20MBLPD

40MBLPD

15 20 250

Gas Lift Rate (MMSCFD)

400

200

600

800

0

M a x i m u m S l u g V o l u m e ( b b l )

Figure 1.21 – Slug Volumes Calculated for 12in East-side Flowlines and50% Water Cut as a Function of Gas Lift Rate






OPRM20030302D_018.ai

5 10

10MBLPD

20MBLPD

40MBLPD

15 20 250

Gas Lift Rate (MMSCFD)

10

5

15

20

0

M a x i m u m S e p a r a t o r L e v e l F l u c t u a t i o n ( % )

Figure 1.22 – Separator Level Fluctuation Calculated for 12in East-side Flowlines and50% Water Cut as a Function of Gas Lift Rate

OPRM20030302D_019.ai

Horizontal Length (m)

0 1000 2000 3000 4000 5000 6000 700060

70

80

90

100

110

120

130

º F

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






OPRM20030302D_020.ai

5 10 15 20 250

Effective U of Each Umbilical Tube (W/m^2-C)

50

30

40

70

60

80

20

G a s I n j e c t i o n T e m p e r a t u r e

( º F )

Tin = 120ºF

Tin = 140ºF

Figure 1.24 – Gas Injection Temperatures at Mudline forPrior Umbilical-based Gas Lift Design

OPRM20030302D_021.ai

2.5 3 3.5 4 4.5 52

Gas Lift Tube ID (in)

105

115

110

120

100

G a s I n j e c t i o n T e m p e r a t u r e ( º F )

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








OPRM20030302D_023.ai

5 10

Heater T (ºF)

Heater T

Production Riser

Gas Lift Riser

3.5in ID

UID = 4W/m2-C

Topsides

Subsea

Riser Inlet T

Injection T

From Gas Heater

Riser Inlet T (ºF)

Injection T (ºF)

15 20 25 300

Gas Rate (MMSCFD)

200

180

160

140

120

100

220

80

G a s I n j e c t i o n T e m p e r a t u r e ( º F )

Spec = 90ºF

Figure 1.27 – System Temperature Summary for Base-case FlexibleRiser-based Gas Lift Design






5.0 SUBSEA SYSTEM SHUTDOWN: HYDRATE PREVENTION STRATEGIES

A critical aspect of hydrate management for deepwater subsea systems isprevention of hydrate formation by system cooling during shut-ins of widely varyingduration. Operationally, subsea shut-ins are inherently complex with multipledecision gates (particularly for a subsea network of the scope of Bonga),with operating procedures which depend on the shutdown duration.

5.1 Cooldown Performance of Subsea Facilities

To aid Operations staff, who must simultaneously work to troubleshoot the shutdownand to protect the subsea system from hydrates, subsea facilities must be designedwith sufficient cooldown time. In general terms, cooldown is defined as the timerequired for the inner wall of the flowpath to reach the hydrate formationtemperature, somewhere in the system. The contributions to the cooldown timeanticipated for Bonga (refer to Figure 1.28) consist of:

• ‘No-touch’ time• Time to treat the well tubing and wellhead equipment

• Time allotted for flowline blowdown

The no-touch time is defined as the time during which Operations staff can act torectify the shutdown cause, without having to undertake operations to protect thesubsea system from hydrates. The 3-hour no-touch time specified for Bonga isbased on GoM platform statistics for unplanned shutdowns (refer to Figure 1.29),which indicate that 80% of typical process and instrumentation interrupts wereanalysed and corrected within 3 hours. Figure 1.29 indicates a rapidly diminishingbenefit of no-touch times longer than 3 hours.

5.1.1 Well Tubing

Based on the timing illustrated in Figure 1.28, the well tubing must provide at least8 hours of cooldown time, accounting for a well MeOH treatment time of 5 hours(ie well tubing cooldown time > 3-hour no-touch + 5-hour MeOH well treatment).An important benefit of bare well tubing is the lengthy wellbore cooldown providedby thermal energy generated in the surrounding formation during (steady-state)production. As shown in Figure 1.30, for early-life production at minimum rate(10MBOPD), at least 48 hours of cooldown are available in the wellbore (eg 100ftdepth and below). Thus, MeOH bullheading of the well to the SSSV will be requiredonly for very lengthy shut-ins, ie greater than 2 days (expected to be rare).For shorter duration shut-ins, only the top portion of the wellbore (a few hundred

feet) have to be topped with MeOH during the allotted 8-hour well cooldown time.For these shut-ins, less than 2 days will be required and they are expected to bemuch more frequent (refer to Figure 1.29). The required MeOH treatment time willgenerally be less than the 5 hours allotted. As an added benefit, this surplus time dueto quicker MeOH treatment may be used to increase the no-touch time and/or theflowline blowdown time.






5.1.2 Subsea Tree/Jumper/Manifold

As for the well tubing, the subsea tree, well jumper and manifold must provide atleast 8 hours of cooldown, accounting for 5 hours allotted for MeOH displacement ofthese components. Although the chemical injection system is sized to treat all wellswithin 5 hours, 12 hours of cooldown time are specified for the wellhead facilities inthe Subsea ITT as an added margin to assist Operations. In particular, the followinggas cooldown specification appears in the Subsea Invitation to Tender (ITT).

• Upstream of choke (subsea tree)

– 120°F (49°C) to 73°F (23°C) in no less than 12 hours

• Downstream of choke (subsea tree + well jumper + manifold)


The starting wellhead temperature of 120°F is satisfied for all initial-life wells at ratesgreater than 5MBOPD (refer to Figure 1.14). However, the field’s coldest well

(702p7) does not reach 120°F at any rate and hence will require well-specificoperating procedures. The final temperatures reflect the HDT at the well shut-inpressure (4600psia) upstream of the choke and the anticipated flowline shut-inpressure downstream of the choke.

5.1.3 Flowline and Riser

For both the pipe-in-pipe flowlines and steel catenary risers, a 12-hour cooldown isspecified in the flowline/riser ITT, for gas-filled (methane) components at 28bara:

• West-side 10in flowlines


• East-side 10in and 12in flowlines


The work presented herein culminated in approval of MoC 59, which specifies thatboth this cooldown requirement and a U value requirement of Uod ≤ 2.0W/m2-C mustbe met for the cylindrical cross-sections of the flowline and riser.

Note: The more conservative specification of gas cooldown is based on restartconsiderations, ie the hydrate risk of wet fluid passing through cold, originallygas-filled sections upon restart.

The starting temperatures for cooldown are based on the minimum anticipated riserbase temperatures for 10MBOPD production, including margins for cooling by risergas lift and possible reservoir cooling by waterflood. With these conservativemargins, the starting riser base temperatures are comparable to the arrival temperatures at 10MBOPD (refer to Figure 1.15). The west-side startingtemperature is 11°F than the east-side flowlines due to the significantly shorteroffsets (hence lesser heat losses) of the west-side flowlines.

The final temperatures are based on the HDT at the flowline shut-in pressure, usingthe hydrate dissociation conditions of the 803 fluid with 0% salinity for conservatism.Furthermore, the effect of a 10-minute choke closure time on the flowline shut-inpressure is explicitly accounted for. Due to their longer offsets, the east-sideflowlines experience less partial packing and hence a lower shut-in pressure, whichis why the final temperature for east-side cooldown is lower (61°F for east-sideversus 66°F for west-side).






For the steel catenary risers, prior conceptual analysis (Granherne, 1998)had specified a 2in carazite insulation for (liquid-filled) cooldown. However,Figure 1.31(a) and 1.32(a) indicate that 2in of carazite does not satisfy the gas-filledcooldown requirement (typical for deepwater GoM), even at higher production rates.

Figures 1.31(b) and 1.32(b) demonstrate that a 4in carazite (or equivalent) riserinsulation is required to attain 12 hours of cooldown at the minimum turndown rateof 10MBOPD per flowline. The added benefit of a Ported Orifice Valve (POV)upstream of the choke is not accounted for, which will yield lower flowline shut-inpressures and hence longer cooldown times (ie results closer to the immediatechoke closure curves in Figures 1.31 and 1.32). At anticipated production rates of30 to 40MBOPD (according to the production function), 18 to 20 hours of gascooldown are available, providing Operations staff additional time to react and/orsecure the system against hydrates.

For the base-case pipe-in-pipe flowline design (refer to Figure 1.5), theU = 2.0W/m2-C requirement can be met by filling only 0.6in of the ~1in annular gap

with polyurethane foam. However, the cooldown analysis presented here indicatesthat the annular gap must be filled with foam (at marginal additional cost) to meetthe 12-hour gas cooldown requirement. In Figures 1.33 to 1.35, the cooldownperformance of each pipe-in-pipe flowline is shown for 0.6in (U = 2.0W/m2-C)and 1in (foam-filled annulus) foam thicknesses. As summarised in Table 1.2,10 to 11.5 hours of cooldown are attained with a 0.6in foam thickness. In each case,a foam-filled annular gap (with a 5mm tolerance for manufacturing) is required tomeet the 12-hour gas cooldown specification.

In summary, this analysis reveals that the base case flowline with U = 2.0W/m2-C(without foam filling of the annular gap) does not satisfy the 12-hour cooldownrequirement. The U value requirement is based only on steady-state thermalperformance, which does not uniquely determine the cooldown performance.That is, significantly different cooldown performance can occur for the sameU value, depending on the ‘thermal mass’ of the pipe and insulation system.As illustrated in Figure 1.36, a carrier pipe with a 0.94in wall thickness meets the12-hour cooldown target, while a 0.75in wall provides only 10 hours of cooldown,although the corresponding U values are identical. The situation is complicatedfurther for alternative pipe diameters and wall thicknesses, which may be explored inthe detailed design process. Thus, to ensure adequate flowline/riser cooldownperformance, MoC 59 specifies that both the U value and cooldown specificationsshall be satisfied simultaneously.

East 12in East 10in West 10in

0.6in PU foam(U = 2W/m2-C)

11.5 hours 10.5 hours 10 hours

1in PU foam(foam-filled gap)

13.5 hours 13 hours 12.5 hours

Table 1.2 – Cooldown Time as a Function of PU Foam ThicknessWithin ‘Pipe-in-pipe’ Flowlines






5.2 Flowline Blowdown

With reference to Figure 1.28, for subsea shutdowns lasting longer than 8 hours,depressurisation of producing flowlines (blowdown) must commence to securethe continuously cooling flowline against hydrate formation. To remain within the12-hour cooldown window (the minimum cooldown at turndown rates), all flowlinesmust be blown down within approximately 4 hours (ie 12-hour cooldown ≥ 3-hourno-touch + 5-hour well MeOH treatment + 4-hour blowdown). Due to the lengthy welltubing cooldown, the well treatment may take only 3 to 4 hours, which will allow5 to 6 hours of blowdown time. The precise breakdown of the available cooldowntime will be the subject of future operability analysis.

The principal objective of blowdown is to prevent hydrate formation in the flowlines,for lengthy shut-ins. By reducing the flowline pressure to below the HDP at theambient seafloor temperature of 40°F, the flowline will be secured against hydrateformation for an indefinite shut-in. For conservatism, a blowdown target ofHDP = 145psia (10bara) is used throughout this analysis, based on the worst case

of 803 fluid with 0% salinity (refer to Appendix 1A Table 1A.3). This targetis ~70psia lower than the dominant 702 fluid production (with HDP~220psia),a depressurisation margin which is necessary for successful hydrate remediation.The flow assurance and topsides constraints on blowdown are summarisedas follows:

• Maximum flowline pressure after blowdown < 145psia

• Blowdown time < 4 hours (all eight flowlines)

• Gas flare rate (instantaneous radiant heat capacity) < 200MMscfd

• Oil carryover rate (instantaneous flare scrubber capacity) < 75MBOPD

In Figures 1.37 to 1.40, the blowdown performance for the 10in west-side and 12ineast-side flowlines is summarised in terms of pressure, gas outlet rate and liquidcarryover, for initial-life conditions at 0% watercut. Results are shown for thefollowing scenario, with both immediate choke closure and full line-packingconsidered to bracket the full design range:

40MBOPD steady-state → Shut-in (immediate or full line-pack) → 3-hour cooldown → Blowdown to 20psia @ topsides (0.5in to 2inblowdown valve)

Note: The line-packing cases capture the maximum design gas and liquid ratesduring blowdown, while the immediate choke closure cases reflect the typicaloperating scenario.

With respect to the topsides facility constraints, none of the blowdown cases inFigures 1.37 to 1.40 exceed the 200MMscfd gas flare capacity or the 75MBOPD oilscrubber capacity. For the west-side flowlines, the maximum gas and liquid rates forthe worst-case line-packing scenario are 27MMscfd and 45MBOPD (refer toFigure 1.37). For the 12in east-side flowlines, the peak rates are 40MMscfd and70MBOPD (refer to Figure 1.39). Due to the short duration of these peak rates,simultaneous blowdowns of multiple flowlines may be pursued, provided that eachblowdown is staggered by at least 30 minutes.






For the flow assurance targets, blowdown is successful for the 10in west-sideflowlines provided that the blowdown valve size is at least 2in (Figures 1.37(a)and 1.38(a), to enable sufficient liquid removal from the flowline. For the westflowlines, the blowdown is completed within 1 hour. In contrast, blowdown for the

12in east-side flowline is unsuccessful for immediate choke closure (refer toFigure 1.40(a), with a final pressure of 600psia which is well above the 145psiatarget. The counterintuitive result that blowdown is successful for a line-packedeast flowline is due to the additional liquid carryover driven by the highershut-in pressure.

Significantly, for a 50% watercut (which will be attained early in field life), blowdownis unsuccessful for all scenarios, as indicated in Figure 1.41. Thus, to secureflowlines for indefinite shut-ins, alternatives to a traditional, totally passive blowdownmust be considered (eg riser gas lift assist or dry-oil circulation).

5.3 Gas Lift-assisted Blowdown

In light of the unsuccessful blowdowns predicted for the 12in east-side flowlines andthe 10in west-side flowlines at higher watercuts, the possibility of riser gas lifting toremove riser liquid during blowdown is now considered. The specific worst-casescenario analysed below consists of:

30MBLPD production (50% watercut) → Immediate shut-in at time ofmaximum riser liquid during severe slugging → 3-hour cooldown → Open 2into 10in blowdown valve (@ t = 4 hours) → Inject riser gas lift pulse of10MMscfd for 1 hour → Stop gas lift → 7-hour flowline/riser settle-out

Gas lift blowdown results for the 12in east-side flowlines are shown in Figure 1.42,indicating the counter-intuitive result that riser gas lift does not guarantee blowdownsuccess (refer to Figure 1.42a). If the blowdown valve is not sufficiently large,back-pressure at the flowline outlet prevents slug-like removal of riser liquid, whichinstead falls back to the riser base resulting in churn-like flow. To attain pressuresbelow 145psia, a very rapid blowdown with a 10in valve is required, with anassociated peak liquid outlet rate of 200MBLPD (refer to Figure 1.42b). Althoughthis exceeds the flare scrubber capacity, any overflow will empty (by gravity feed)into a 24,000bbl slop tank. The peak outlet gas rate of 70MMscfd is well withinthe instantaneous flare capacity (200MMscfd).

Note: After gas lift ceases (@ t = 5 hours in Figure 1.42), the flowline pressureslowly increases to approximately 170psia as liquid in the flowline and risersettles out. Similar results are obtained for the 10in east-side flowlines (referto Figure 1.43), with a more effective blowdown (final pressure near 155psia)

and lesser liquid volumes resulting from a smaller riser diameter.

A potential concern for gas lift assisted blowdown is the hydrate risk of injecting40°F lift gas into the flowline, which contains wet fluids which have cooled severalhours (near the end of the 12-hour cooldown period). To address this concern,the hydrate condition tracking feature of OLGA is applied to the following scenario:

15MBLPD production (0 to 50% watercut) → Immediate shut-in → 10-hourcooldown → Open blowdown valve → Inject 10MMscfd gas lift @ 40°F for2 hours → Stop gas lift






As shown in Figure 1.44(a), the cold gas lift injection causes a localpressure/temperature within 1°F of hydrate conditions. The fact that hydratecondition subcooling does not occur is due to the rapid riser-base depressurisationby gas lifting (refer to Figure 1.44(c). Due to the residual heat in the flowline

liquid and pipe wall, this depressurisation outruns the gas lift cooling (refer toFigure 1.44(b), preventing a local hydrate condition. In light of this depressurisationeffect, it is critical that the topsides blowdown valve is fully open before thegas lifting operation commences, as a significant (~20°F) subcooling of wet fluids atthe riser base will occur otherwise.

In summary, although riser gas lift can significantly reduce the flowline pressure,several additional design and operability modifications were required to enablehydrate-free indefinite-length shut-ins. In particular, the requirement of a largeblowdown valve orifice for effective gas lift assisted depressurisation resulted inreplacement of the prior fixed 2in blowdown valve with a two-stage blowdown valvetrain containing a smaller variable choke and a large fixed orifice. Furthermore,

it was revealed that gas lift-assisted blowdown does not guarantee successfulblowdown below 145bara, due to pressure recovery resulting from liquid settle-out inthe flowline and riser. Hence, a backup strategy was formulated for more lengthyshut-ins, consisting of flowline displacement by dry oil circulation at 3 to 5mph.Associated topsides modifications were also made to improve the timing and controlof the dry-oil circulation operation. Additionally, a pressure/temperature sensor wasadded to each riser base (at the gas-injection tee) to enable Operations toaccurately determine the effectiveness of gas lift assisted blowdown operations(captured by MoC 64).

Since blowdown is marginally effective for the east-side 12in flowline, it is logical toquestion whether a primary dry-oil circulation strategy should be used in place ofgas lift-assisted blowdown. There are two key advantages of blowdown as a primaryshut-in strategy. First, it is an essentially passive operation which can beperformed under unexpected or emergency topsides shutdowns. Secondly, even anunsuccessful blowdown provides significant extra reaction time for trouble-shootingand a secondary dry-oiling operation if necessary (eg blowdown to 250psia provides24 hours of additional cooldown time; refer to Figure 1.45).

3 hours 3 to 5 hours 4 to 6 hours

“No-touch” Well MeOH Treating Blowdown

Figure 1.28 – Definition of Contributions to Cooldown Time






OPRM20030302D_024.ai

120

100

80

60

40

20

0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 22 23 24

Hours

P e r c e n t a g e s ( %

)

21

Figure 1.29 – Downtime Duration Statistics for Unplanned Shutdowns in GoM

OPRM20030302D_025.ai

10

HDT

20 30 40 500

Time After Shut-in (hours)

110

90

80

100

140

130

120

150

70

M i n i m u m W e l l b o

r e T e m p e r a t u r e ( º F )

702p4

702p7

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






OPRM20030302D_026.ai

Initial Riser Base Temperature (ºF)

Production Rate (MBOPD)

G a s C o o l d o w n T i m e ( h o u r s )

60 70

10 20 40

80 90 100 110 120 130 1400

2

4

6

8

10

12

Target

14

Immediate Choke Closure

10-minute Closure

Full Line-pack



G a s

C o o l d o w n T i m e ( h o u r s )

60 70

10 20 40

80 90 100 110 120 130 1400

5

10

15

20

25

Target

30


10-minute Closure

Full Line-pack

Figure 1.31 – East-side 12in Riser Cooldown Performance for

(a) 2in Carazite and (b) 4in Carazite






OPRM20030302D_027.ai



G a s C

o o l d o w n T i m e ( h o u r s ) Target

Target

80 90

5 10 20 40

100 110 120 1300

2

4

6

8

10

12

14

16


10-minute Closure

Full Line-pack



G a s C o o l d o w n T i m e ( h o u r s )

80 90

5 10 20 40

100 110 120 1300

25

20

15

10

5Immediate Choke Closure

10-minute ClosureFull Line-pack

Figure 1.32 – West-side 10in Riser Cooldown Performance for

(a) 2in Carazite and (b) 4in Carazite






OPRM20030302D_028.ai

Time (hours)

G a s T e m p e r a t u r e ( º C )

Foam-filled

U = 2

0 2 4 6 8 10 12

0

5

10

15

20

25

30

35

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

OPRM20030302D_029.ai

Time (hours)


Foam-filled

U = 2

0 2 4 6 8 10 120

5

10

15

20

25

30

35

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






OPRM20030302D_030.ai

Time (hours)


Foam-filled

U = 2

0 2 4 6 8 10 120

5

15

10

20

25

30

35

40

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

OPRM20030302D_031.ai

Time (hours)

G a s T e m p e r a t u r e

( º C )

0 2 4 6 8 10 1215

20

25

30

35

40

Initial T = 36ºC 0.94in wt and U = 1.4W/m^2-K

0.75in wt and U = 1.4W/m^2-K

Minimum CDT = 12 hours

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






OPRM20030302D_033.ai

Time (hours)

M a x i m u m F l o w l i n e P r e s s

u r e ( p s i a )

0 2

0.5in valve

2in valve

1in valve

Target:

HDP = 145psia 4 6 8 10

2150

1150

3150

4150

5150

Line-pack Blowdown

Time (hours)

O u t l e t O i l R a t e ( M B O P D )

0 2 4 6 8 100

20

10

30

40

50

Time (hours)

O u t l e t G a s R a t e ( M M S C F )

0 2 64 8 10 120

20

15

10

5

25

30

0.5in valve

2in valve

2in valve: 480bbl

1in valve: 360bbl

0.5in valve: 160bbl

1in valve

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






OPRM20030302D_032.ai

Time (hours)

M a x i m u m F l o w P r e s s u r e ( p s i a )

0 2

0.5in valve

1in valve

2in valve

Target:

HDP = 145psia

BlowdownShut-in

4 6 8 100

350

550

750

950

Time (hours)


0 2

2in valve: 45bbl

4 6 8 100

20

10

30

40

50

Time (hours)

O u t l e t G a s R

a t e ( M M S C F / D )

0 2

2in valve

64 8 10 120

10

5

15

20

0.5in valve

1in valve

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






OPRM20030302D_035.ai

Time (hours)

M a x i m u m F l o w l i n e

P r e s s u r e ( p s i a )

0 2

Target:

HDP = 145psia4 6 8 10 12 14 16

5150

4150

3150

2150

1150

Line-pack Blowdown

Time (hours)


0 2 4 6 8 100

40

30

20

10

50

60

70

Time (hours)

O u t l e t G a s R a

t e ( M M S C F / D )

0 10 155 200

30

25

20

15

10

5

35

40

1in valve

2in valve

0.5in valve

0.5in valve

2in valve

1in valve

2in valve 1360bbl

0.5in valve 620bbl

1in valve: 910bbl

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








OPRM20030302D_036.ai

Time (hours)

5 10 15 200

350

Target:145pisa

550

750

950

1150

M a x i m u m F l o w l i n e

P r e s s u r e ( p i s a )

West – Immediate closure

West – Full line-pack

East –Immediate closure

East – Full line-pack

Figure 1.41 – Blowdown Performance for 50% Water Cut, Illustrating Unsuccessful

Blowdown for All Scenarios






5.5

OPRM20030302D_037.ai

Time (hours)

M a x i m u m F l o w l i n e P r e s s u r e ( p s i a )

4 5 6 7 8 9 10 11 12

500

400

450

350

300

250

100

200

150

2in valve

4in valve

10in valve

Target HDP = 145psia

Time (hours)

O u t l e t O i l R a t e ( M B L P D )

4 4.5 5 6

250

200

0

100

150

50

2in valve

4in valve

10in valve

5.5

Time (hours)

O u t l e t G a s R a t e ( M M S C F / D )

4 4.5 5 6

70

40

50

60

30

-10

10

20

0

2in valve

4in valve

10in valve

Figure 1.42 – Blowdown Performance with Riser Gas Lift Assist,

for 12in East-side Flowlines






OPRM20030302D_039.ai

Time (hours)

M a x i m u m F l o w l i n e P r e s s u r e ( p s i a )

4 5 76 9 11108 12

500

250

300

400

450

350

200

100

150

2in valve

4in valve

8in valve

Target HDP = 145psia

Time (hours)

O u t l e t O i l R a t e ( M B L P D )

4 4.5 5 5.5 6

100

60

80

40

0

20

4in valve

2in valve

8in valve

Time (hours)

O u t l e t G a s R a t e ( M M S C F / D )

4 4.5 5 5.5 6

50

20

40

30

10

-10

0

4in valve

2in valve

8in valve

Figure 1.43 – Blowdown Performance with Riser Gas Lift Assist,

for 10in East-side Flowlines






OPRM20030302D_038.ai


P r o x i m i t y t o H y d r a t e C o n d i t i o n :

F l o w l i n e M a x i m u m ( H D T - T ) ( º F )

0 5 10 15 20

0

-30

-20

-10

-40

-60

-50

Shut-in Gas Lift On Gas Lift Off

Hydrate

No Hydrate50% Water Cut

0% Water Cut


T e m p e r a t u r e a t G a s L i f t L o c a t i o n ( º F )

0 5 10 15 20

120

70

80

100

110

90

60

40

50

50% Water Cut

0% Water Cut


T e m p e r a t u r e a t G

a s L i f t L o c a t i o n ( p s i a )

0 5 10 15 20

1400

400

600

1000

1200

800

0

200

50% Water Cut

0% Water Cut

Figure 1.44 – Pressure and Temperature Evolution During

Cold Gas Lift-assisted Blowdown










YesNoSteady-state operation.

For additional wells:

Go to Top

Full system cooldown not available.

Shutdown requires immediate

action: Go to 'Interrupted Start-up'

OPRM20030302D_042.ai

Is theFWHT > 95ºF?

FWHT (all) > 120ºFand Arrival Temp > 85ºF?

Yes

No

Line up subsea equipment

for new well start-up

Adjust riser base gas lift

as appropriate for new well

Stop MeOH injection and

continue well ramp-up

5-hour wellbore

cooldown available

Continue MeOH injection

Additional Start-up

Start-up of new (cold) well

into producing flowline

System Conditions

Cold well bullheaded with MeOH

Cold tree and jumper

flushed w/MeOH

Flowline producing at steady-state:

Arrival T > 85ºF

Producing wells FWHT > 120ºF

Sufficient MeOH available on FPSO

Start-up new well,as per Start-up Guidelines:

Start MeOH injection

upstream of choke

Open subsea choke and

start specified ramp-up

Figure 1.47 – Additional Well Start-up






Steady-state condition:

Go to 'Shutdown

from steady-state'

Blow down Flowlines ASAP

Go to 'Blowdown'

Blow down Flowlines ASAP

Go to 'Blowdown'

Bullhead well with MeOH

Complete within 5 hours

Jumper, Tree and Manifold

Optional:

Blow down flowlines

(contain dry oil and

inhibited fluid only)

Optional:

Displace jumpers and manifold

with MeOH (already treated)

Bullhead wells and displace tree,

jumper, manifold with MeOH.

Complete within 8 hours

Wellbore and flowline

uninhibited

Wellbore, tree, jumper, manifold,

flowline cooldown not secured

Displace tree, jumpers and

manifold with MeOH ASAP

OPRM20030302D_043.ai

Treetemperature

> 95ºF?

Treetemperature

> 120ºF?

Arrivaltemperature

> 85ºF?

Yes

No

Yes

No

Yes

No

5-hour wellbore

cooldown available

Continuous MeOH

injection at tree

Flowline inhibited:

treated water and dry oil

Displace tree and bullhead

well with MeOH ASAP

(refer to MeOH table)

MeOH

MeOH Table

Duration hours

hours

GPM 9 18

2

2

20

24

9

3.88

50

100

124

1

2

20

24

18

1.94

50

100

124

GPM

bbls

bbls

bbls

Vol jumper

Vol manifold

Total bbls used

MeOH

Duration/well

Vol/well

Two Wells – Total bbls Used

Total System bbls Used

Well Treatment

Interrupted Start-up

System shutdown

prior to steady-state

System Conditions

Flowlines hot-oiled prior

to well start-up:

Untreated water present:

Wellbore, jumper, manifoldand/or flowline

Full cooldown not available

Immediate action required

Figure 1.48 – Interrupted Start-up



S e c t i on1

D yn a

mi cF l ow

A s s ur an c eA n al y si s

O P R M- 2 0 0 3 - 0

3 0 2 D

P a g e

6 4 o f 8 9

3 0 - A p r i l - 2 0 0 6

No

No

Yes

Bullhead wells with MeOH

(refer to MeOH table)

Planned or Unplanned

Shutdown for Steady-state

Go to 'Cold Start'

Displace tree, jumpers and

manifold with MeOH.

Complete within 8 hours of

shutdown (refer to MeOH table)

Blow down all flowlines

within 12 hours of shutdown

Go to 'Blowdown'

Canproduction be resumed

within 3 hours? (5 hours of treatment timealotted for wells, jumpers and

manifold)

No

Yes

Jumper, Tree and Manifold

MeOH

MeOH Table

Duration hours

hours

GPM 9 18

2

2

20

24

9

3.88

50

100

124

1

2

20

24

18

1.94

50

100

124

GPM

bbls

bbls

bbls

Vol jumper

Vol manifold

Total bbls used

MeOH

Duration/well

Vol/well

Two Wells – Total bbls Used

Total System bbls Used

Well Treatment

Close tree chokes and PSDVs

Allow flowlines to evacuate

to LP separator

Stop riser gas lift

Planned Shutdown

System Conditions (Steady-state)

FWHT (all wells) > 120ºF

Arrival T > 85ºF

Topsides facilities and

export available

Minimum available cooldown times:


within 8 hours?


within 48 hours?

• Wellbore: 48 hours• Tree, jumper, manifold: 8 hours

• Flowline: 16 hours

• Riser: 12 hours

F i g ur e1 .4 9 –P l ann e d or U n pl a

nn e d S h u t d ownf r om S t e a d y

- s t a t e






Close boarding valve

Flowline secure for

indefinite shut-in

Initiate gas lift at each riser base:

15MMSCFD for 1 hour

Initiate dry-oil circulation

at 3 to 5mph

Option: Launch pig

Open appropriate

blowdown valves

Depressure until gas/

liquid rates diminish

OPRM20030302D_045.ai

Manifoldpressure > 10bara?

(or gas-assist known tobe necessary?

Manifoldpressure > 10bara?

(or gas-assist known tobe insufficient?

Yes

No

No

Yes

System Conditions

Flowlines isolated at

platform and tree

Manifold pigging iso valve closed

Untreated water present in flowline

Flowline at/near 8-hour cooldown

Blowdown

Secure flowlines for

indefinite shut-in

Line up topsides for

blowdown to flare system

Figure 1.50 – Blowdown




Section 1 Appendix 1A Reservoir Fluid Properties


Appendix 1AReservoir Fluid Properties

Table of Contents

TABLES

Table 1A.1 – Measured Fluid Properties for Each Reservoir (from Bonga BoD)...................67

Table 1A.2 – Hydrate Dissociation Data for 702 Reservoir Fluid (from A Mehta, 1998) ........69

Table 1A.3 – Hydrate Dissociation Data for 803 Reservoir Fluid (from A Mehta, 1998) ........71

FIGURESFigure 1A.1 – Phase Envelope for 702 Reservoir Fluid, Calculated in OLGA .......................67

Figure 1A.2 – Hydrate Dissociation Curves for 702 Reservoir Fluid (Data in Table 1A.2).....68

Figure 1A.3 – Hydrate Dissociation Curves for 803 Reservoir Fluid (Data in Table 1A.3).....70






Table 1A.1 – Measured Fluid Properties for Each Reservoir (from Bonga BoD)

Figure 1A.1 – Phase Envelope for 702 Reservoir Fluid, Calculated in OLGA






40 45 50 55 60 65 70 75 80 85

Temperature, F

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

P r e

s s u r e ,

p s i a

1 0

w t %

S a l t

3 w

t % S a

l t

F r e s h W

a t e r

Hydrate StabilityRegion

Non-Hydrate Region

Figure 1A.2 – Hydrate Dissociation Curves for 702 Reservoir Fluid (Data in Table 1A.2)






252.0 40.0

500 48.9

750 54.0

1000 57.5

2000 65.2

3000 69.4

4000 71.2

5000 72.9

6000 74.6

7000 76.1

8000 77.7

9000 79.3

10000 80.8

418.8 40.0

500 42.3

750 47.3

1000 50.7

2000 58.2

3000 62.2

4000 64.0

5000 65.8

6000 67.5

7000 69.1

8000 70.7

9000 72.3

10000 73.8

Fresh Water

3 wt% Salt

10 wt% Salt

P (ps ia) T (F)

218.1 40.0

500 50.8

750 55.9

1000 59.4

2000 67.2

3000 71.4

4000 73.2

5000 74.9

6000 76.6

7000 78.2

8000 79.8

9000 81.3

10000 82.8

Table 1A.2 – Hydrate Dissociation Data for 702 Reservoir Fluid

(from A Mehta, 1998)








Section 1 Appendix 1B Wellbore Modelling Summary and Production Forecast

OPRM-2003-0302D Page 72 of 89 31-December-2004

Appendix 1BWellbore Modelling Summary and Production Forecast

Table of Contents

1.0 RESERVOIR PRESSURE AND TEMPERATURE SUMMARY ..................................76

2.0 WELL PRODUCTION SUMMARY............................................................................. 77

3.0 DESIGN BASIS AND PRODUCTION FORECAST: 702 RESERVOIR ......................78




TABLES

Table 1B.1 – Sample WELLTEMP Input File, for Well 702p4 ...............................................73

Table 1B.2 – WELLTEMP Input Data for 702p4, Representing the Hottest 702 Well............74

Table 1B.3 – Wellhead Temperatures Calculated in WELLTEMP for 702p4,for Cold-earth Start-up (t = 0 to 1440 hours) and Cooldown(t = 1440 to 1488 hours)..................................................................................74

Table 1B.4 – WELLTEMP Input Data for 702p7, Representing the Coldest 702 Well...........75

Table 1B.5 – Wellhead Temperatures Calculated in WELLTEMP for 702p7,for Cold-earth Start-up (t = 0 to 1440 hours) and Cooldown(t = 1440 to 1488 hours)..................................................................................75






TITLE:Bonga Well 1000 BOPD 0 BWPD 15000 BOPD 0 BWPDCSEBare Tubing 6.625inVERSION3.4TUBING125.9 6.625 2000 2000 15.9 6.625 7477 7477 1CASING 4 18.670 9.625 7477 6477 2112.330 13.375 3637 2637 3118.710 20.000 2000 0 8127.000 30.000 200 0 8WELLBORE

360 02000 20002200 22122400 24382700 28285780 7477INITIAL TEMP240 0162 5780PVYP FLUIDS31 1 10.0 1 0 602 2 10.4 10 7 60

3 1 9.63 14 7 60ASOLID37 488 0.113 24.88 180 0.5 0.59 0.001 0.25 0.005NATURAL GAS110 0.7885 0.0663 0.0671 0.0391 0.0 0.0158PRINT OPTIONS1 0 1 1 0 11000.PF0 25 0OPTIONS3 3 0.0006 1 1 -8.83+08

0 1 0 0ENDCHANGE0.5 'HR'SINGLE FLOW2 2 10 162 15000 'BPD' 0 4612.5 9 0 29

Table 1B.1 – Sample WELLTEMP Input File, for Well 702p4(refer to the schematic in Figure 1.3)








INPUT----------------------------------------------------------------------------------------------------------------------

common filename -----> 702p7

P-res GOR PI bare tubing insulated FBHP

MBPD WC (%) (PSI) °API (SCF/STB) (BLPD/PSI) BHT (°F) file number file number BOPD BWPD MMSCFD (PSI)

2.5 0 3200 29 600 30 128 1 16 2500 0 1.500 3117

5 0 3200 29 600 30 128 2 17 5000 0 3.000 3033

10 0 3200 29 600 30 128 3 18 10000 0 6.000 2867

15 0 3200 29 600 30 128 4 19 15000 0 9.000 2700

20 0 3200 29 600 30 128 5 20 20000 0 12.000 2533

2.5 50 3200 29 600 30 128 6 21 1250 1250 0.750 3117

5 50 3200 29 600 30 128 7 22 2500 2500 1.500 3033

10 50 3200 29 600 30 128 8 23 5000 5000 3.000 2867

15 50 3200 29 600 30 128 9 24 7500 7500 4.500 2700

20 50 3200 29 600 30 128 10 25 10000 10000 6.000 2533

2.5 80 2200 29 600 30 128 11 26 500 2000 0.300 2117

5 80 2200 29 600 30 128 12 27 1000 4000 0.600 2033

10 80 2200 29 600 30 128 13 28 2000 8000 1.200 1867

15 80 2200 29 600 30 128 14 29 3000 12000 1.800 1700

20 80 2200 29 600 30 128 15 30 4000 16000 2.400 1533

Table 1B.4 – WELLTEMP Input Data for 702p7,Representing the Coldest 702 Well

BARE TUBING RESULTS:

time T(°F) T(°F) T(°F) T(°F) T(°F) T(°F) T(°F) T(°F) T(°F) T(°F) T(°F) T(°F) T(°F)

(hr) 702p71 702p72 702p73 702p74 702p75 702p76 702p77 702p78 702p79 702p710 702p711 702p712 702p713

2.5 MBPD 5 MBPD 10 MBPD 15 MBPD 20 MBPD 2.5 MBPD 5 MBPD 10 MBPD 15 MBPD 20 MBPD 2.5 MBPD 5 MBPD 10 MBPD

0.5 54.19 60.88 71.75 80.23 86.59 54.76 64.21 79.62 90.98 98.94 55.91 66.79 83.99

1 57.90 67.76 83.06 93.28 99.50 60.68 74.82 94.75 105.48 110.97 62.80 78.73 99.47

2 63.71 77.95 96.19 104.68 108.49 69.89 89.01 107.82 114.18 116.73 73.37 93.81 111.00

3 68.23 84.90 102.31 108.63 111.00 76.65 97.13 112.11 116.31 118.01 80.90 101.60 114.22

6 77.33 95.37 108.12 111.90 113.13 88.71 106.32 115.41 118.08 119.22 93.32 109.13 116.65

12 86.01 101.88 111.00 113.61 114.33 97.78 110.62 117.13 119.14 120.00 101.64 112.57 118.05

24 92.84 105.56 112.70 114.71 115.19 103.09 112.96 118.25 119.91 120.54 105.98 114.50 118.96

48 96.90 107.74 113.83 115.45 115.74 105.99 114.40 119.00 120.40 120.93 108.33 115.69 119.5796 99.49 109.33 114.71 116.07 116.21 107.96 115.60 119.63 120.82 121.25 110.13 116.67 120.08

120 100.36 109.77 114.99 116.25 116.35 108.66 115.98 119.80 120.94 121.34 110.62 116.99 120.23

1440 105.98 113.23 116.86 117.55 117.31 112.98 118.40 121.08 121.81 122.00 114.31 119.01 121.29

1441 104.18 111.53 115.24 115.96 115.73 111.45 116.86 119.53 120.24 120.40 112.64 117.27 119.46

1443 100.17 107.31 110.92 111.62 111.39 107.39 112.54 115.08 115.72 115.83 108.30 112.63 114.61

1446 95.14 101.79 105.17 105.83 105.62 101.93 106.69 109.04 109.63 109.71 102.72 106.69 108.50

1448 92.54 98.91 102.15 102.79 102.60 99.05 103.60 105.86 106.42 106.51 99.84 103.64 105.39

1451 89.46 95.49 98.56 99.17 99.01 95.63 99.92 102.06 102.61 102.70 96.43 100.03 101.71

1452 88.58 94.51 97.53 98.13 97.98 94.64 98.87 100.98 101.52 101.62 95.45 98.99 100.66

1464 81.21 86.29 88.89 89.42 89.31 86.39 90.01 91.84 92.31 92.42 87.17 90.23 91.69

1488 73.02 77.13 79.25 79.70 79.61 77.20 80.16 81.63 82.04 82.13 77.88 80.38 81.58

Table 1B.5 – Wellhead Temperatures Calculated in WELLTEMP for 702p7,for Cold-earth Start-up (t = 0 to 1440 hours) and Cooldown (t = 1440 to 1488 hours)






1.0 RESERVOIR PRESSURE AND TEMPERATURE SUMMARY

S Van Gisbergen, A Hartwijk and S Lindsey (1999).

Medium Skin P50

702 T@midperfs Initial Pavg 690 T@midperfs Initial Pavg

702p2 142 3421 b690p1 164 4586

702p3 132 2518 b690p2 147 3826

702p4 162 4503 b690p3 156 3722

702p5 153 3366 b690p4 138 4201

702p6 136 2830 b690p5 139 3138

702p7 128 2648

702p9 148 4317

702p10 148 4312

702p15 139 4183


803p1 179 5211 710p1 146 4455

803p2 186 5299 710p2 134 4238710p3 144 4464

710p4 158 4649

High Skin P50

702 T@midperfs Initial Pavg 690 T@midperfs Initial Pavg702p2 142 3679 690p1 164 4586

702p3 132 2690 690p2 147 4042

702p4 162 4503 690p3 156 3739

702p5 153 3252 690p4 138 4201

702p6 136 2987 690p5 139 3118

702p7 128 2862

702p9 148 4317

702p10 148 4312702p15 139 4183


803p1 179 5211 710p1 146 4455

803p2 186 5315 710p2 134 3964

710p3 144 4197

710p4 158 4468

Low Skin P50


702p2 142 690p1 164 4586

702p3 132 690p2 147

702p4 162 4503 690p3 156

702p5 153 690p4 138

702p6 136 690p5 139

702p7 128

702p9 148 4317

702p10 148 4312

702p15 139 4183


803p1 179 5211 710p1 146

803p2 186 710p2 134

710p3 144

710p4 158






2.0 WELL PRODUCTION SUMMARY

S Van Gisbergen, A Hartwijk and S Lindsey (1999).

Phase 1 Wells

well year flowline months

702p4 Q1 2003 PF1 0

702p9 Q1 2003 PF3 0

702p10 Q1 2003 PF6 0

702p15 Q1 2003 PF11 0

690p1 Q1 2003 PF2 0

803p1 Q1 2003 PF12 0

Phase 2 Wells

well year flowline months

710p1 Q1 2004 PF8 8

702p2 Q1 2004 PF12 11

690p2 Q2 2004 PF4/PF3 14

803p2 Q2 2005 PF6/PF5 26

710p4 Q4 2005 PF12 29

710p3 Q1 2006 PF8/PF9 32

702p5 Q4 2006 PF3 44

710p2 Q1 2007 PF9 47

690p3 Q2 2007 PF2 48702p6 Q1 2008 PF11 59

702p7 Q1 2008 PF11 60

690p4 Q1 2008 PF11 62

702p3 Q3 2008 PF8 65

690p5 Q1 2009 PF5 71

Well Year Max. rate

702p2 Q1 2004 22000

702p3 Q3 2008 20000

702p4 Q1 2003 54000

702p5 Q4 2006 24000

702p6 Q1 2008 20000

702p7 Q1 2008 20000

702p9 Q1 2003 50000

702p10 Q1 2003 50000

702p15 Q1 2003 50000

b690p1 Q1 2003 20000

b690p2 Q2 2004 20000

b690p3 Q2 2007 17000

b690p4 Q1 2008 16000

b690p5 Q1 2009 18000

803p1 Q1 2003 24000

803p2 Q2 2005 27000

710p1 Q1 2004 30000

710p2 Q1 2007 30000

710p3 Q1 2006 28000710p4 Q4 2005 30000






3.0 DESIGN BASIS AND PRODUCTION FORECAST: 702 RESERVOIR

Refer to the Field Development Plan Rev 5 for production profiles.

4.0 DESIGN BASIS AND PRODUCTION FORECAST: 690 RESERVOIRRefer to the Field Development Plan Rev 5 for production profiles.








Section 1 Appendix 1C Production Flowlines: Topography and Ambient Temperature Data


Appendix 1CProduction Flowlines: Topography andAmbient Temperature Data

Table of Contents

1.0 TEMPERATURE AND SALINITY PROFILES.............................................................86

TABLES

Table 1C.1 – West-side Flowline Topography Data Extracted fromRev D Field Layout (Corresponding to Figure 1.49) ........................................82

Table 1C.2 – Steel Catenary Riser Profile Data(Corresponding to Figure 1.50: Phifer 1998) ...................................................85

Table 1C.3 – Representative Ambient Sea Temperature Profile...........................................87

Table 1C.4 – Salinity and Density Profiles (Parts per Thousand)..........................................88

Table 1C.5 – Anticipated Bonga-area Water Current Velocities............................................89

FIGURES

Figure 1C.1 – Flowline Topography for West-side Flowlines (Rev D Layout)........................80

Figure 1C.2 – Steel Catenary Riser Profile (Phifer 1998)......................................................84






Flowline Topography

PFL - 11/12 (West South)-10"

-1 120

-1 100

-1 080

-1 060

-1 040

-1 020

-1 000

- 980

- 960

0 500 1 000 1 500 2 000 2 500

Distance, m

W a t e r D e p t h , m

Rev. D

Riser Base

Flowline Topography

PFL - 08/09 (West North)-10"

-1 120

-1 100

-1 080

-1 060

-1 040

-1 020

-1 000

- 980

- 960

0 500 1 000 1 500 2 000 2 500 3 000

Distance, m


Rev. D

Riser Base

Figure 1C.1 – Flowline Topography for West-side Flowlines (Rev D Layout)






Flowline Topography

PFL - 01/02 (East West)-10"

-1 120

-1 100

-1 080

-1 060

-1 040

-1 020

-1 000

- 980

- 960

0 1 000 2 000 3 000 4 000 5 000 6 000 7 000 8 000 9 000 10 000

Distance, m


Rev. D

Riser Base

Flowline Topography

PFL - 03/04/05/06 (East East)-12"

-1 120

-1 100

-1 080

-1 060

-1 040

-1 020

-1 000

- 980

- 960

0 1 000 2 000 3 000 4 000 5 000 6 000 7 000

Distance, m


Rev. D

Riser Base

Figure 1C.1 – Flowline Topography for East-side Flowlines (Rev D Layout) (cont’d)






Rev. D Rev. D

0 -1028 manifold 0 -1000 manifold

105.2632 -1026 131.5789 -998184.2105 -1024 473.6842 -996

263.1579 -1022 1052.632 -998

315.7895 -1020 1184.211 -997

394.7368 -1018 1236.842 -998

447.3684 -1016 1315.789 -1000

500 -1014 1342.105 -1002

578.9474 -1012 1368.421 -1004

631.5789 -1011 1421.053 -1004

657.8947 -1012 1447.368 -1002

710.5263 -1012 1500 -1002

736.8421 -1010 1526.316 -1000

763.1579 -1008 1578.947 -998

789.4737 -1006 1657.895 -996

815.7895 -1004 1710.526 -996

868.4211 -1002 1763.158 -998

1105.263 -1000 1789.474 -10001263.158 -998 1815.789 -1002

1421.053 -998 1842.105 -1004

1447.368 -1000 1868.421 -1006

1473.684 -1002 1921.053 -1006

1500 -1000 1947.368 -1004

1552.632 -998 1973.684 -1002

1578.947 -996 1973.684 -1000

1894.737 -994 2000 -998

2000 -994 riser base 2026.316 -996

2078.947 -994

2263.158 -995

2289.474 -994

2342.105 -992

2368.421 -990

2394.737 -988 riser base

West South, PFL - 11/12 West North, PFL - 08/09

Table 1C.1 – West-side Flowline Topography Data Extracted from

Rev D Field Layout (Corresponding to Figure 1.49)






X, m Rev. D Rev. D

0 -1106 manifold 0 -1038 manifold

131.5789 -1104 78.94737 -1036

263.1579 -1102 236.8421 -1034

368.4211 -1100 342.1053 -1032

447.3684 -1098 447.3684 -1030

578.9474 -1096 552.6316 -1028657.8947 -1094 631.5789 -1027

815.7895 -1092 684.2105 -1028

894.7368 -1090 710.5263 -1029

1000 -1088 763.1579 -1028

1052.632 -1086 789.4737 -1026

1131.579 -1084 842.1053 -1024

1236.842 -1082 947.3684 -1022

1342.105 -1080 1078.947 -1020

1447.368 -1078 1184.211 -1018

1526.316 -1076 1289.474 -1016

1605.263 -1074 1421.053 -1014

1684.211 -1072 1526.316 -1012

1763.158 -1070 1657.895 -1010

1868.421 -1068 1789.474 -1012

1921.053 -1066 1842.105 -1010

2000 -1064 1868.421 -1008

2105.263 -1062 1921.053 -1006

2210.526 -1060 2000 -10042342.105 -1058 2026.316 -1006

2447.368 -1060 2052.632 -1008

2473.684 -1062 2131.579 -1009

2500 -1062 2184.211 -1008

2526.316 -1060 2210.526 -1006

2578.947 -1058 2236.842 -1004

2631.579 -1056 2263.158 -1002

2684.211 -1054 2289.474 -1000

2710.526 -1052 2315.789 -998

2736.842 -1050 2342.105 -996

2815.789 -1052 2368.421 -994

2894.737 -1048 2421.053 -992

2921.053 -1046 2552.632 -990

2947.368 -1044 2605.263 -992

2973.684 -1042 2657.895 -990

3000 -1040 2684.211 -988

3052.632 -1038 2710.526 -986

3105.263 -1036 2736.842 -984

3157.895 -1034 2789.474 -9823210.526 -1032 2868.421 -980

3315.789 -1030 3000 -978

3394.737 -1028 3289.474 -976

3473.684 -1026 3578.947 -978

3552.632 -1024 3684.211 -980

3684.211 -1022 3736.842 -982

3789.474 -1020 3789.474 -984

3973.684 -1018 3815.789 -986

4052.632 -1016 3842.105 -988

4131.579 -1014 3868.421 -990

4210.526 -1012 3894.737 -992

4289.474 -1010 3921.053 -994

4368.421 -1008 3973.684 -996

4447.368 -1006 4026.316 -998

4552.632 -1004 4131.579 -996

4684.211 -1002 4236.842 -994

4815.789 -1000 4315.789 -996

4868.421 -998 4342.105 -998

4947.368 -996 4394.737 -9995131.579 -994 4447.368 -998

5184.211 -992 4631.579 -1000

5289.474 -990 4763.158 -1002

5394.737 -988 4868.421 -1004

5526.316 -986 4947.368 -1006

5710.526 -985 5000 -1008

5815.789 -986 5026.316 -1010

5973.684 -984 5078.947 -1008

6052.632 -982 5131.579 -1009

6157.895 -981 5210.526 -1008

6236.842 -982 5368.421 -1010

East West, PFL - 01/02 East East, PFL - 05/06

Table 1C.1 – East-side Flowline Topography Data (cont’d)






6289.474 -984 5421.053 -1012

6342.105 -986 5447.368 -1014

6421.053 -988 5473.684 -1014

6473.684 -990 5552.632 -1016

6526.316 -992 5578.947 -1018

6578.947 -994 5605.263 -1016

6631.579 -996 5631.579 -10146684.211 -998 5657.895 -1012

6763.158 -1000 5684.211 -1010

6947.368 -1002 5736.842 -1008

7078.947 -1002 5789.474 -1006

7131.579 -1003 5894.737 -1004

7210.526 -1002 5947.368 -1002

7342.105 -1001 6105.263 -1000

7578.947 -1002 6157.895 -998

7736.842 -1004 6184.211 -996

7815.789 -1006 6210.526 -994

7868.421 -1008 6236.842 -992

7947.368 -1009 6263.158 -990

8131.579 -1010 6289.474 -988

8394.737 -1012 6315.789 -986

8657.895 -1010 6342.105 -984 riser base

8842.105 -1008 0

8921.053 -10069052.632 -1004

9105.263 -1002

9131.579 -1000

9157.895 -998

9184.211 -996

9210.526 -994

9236.842 -992

9263.158 -990

9289.474 -988 riser base

Table 1C.1 – East-side Flowline Topography Data (cont’d)

-500.00

0.00

500.00

1,000.00

1,500.00

2,000.00

2,500.00

3,000.00

3,500.00

0 1000 2000 3000 4000

Horizontal Distance, Feet

E l e v

a t i o n ,

F e e t

Figure 1C.2 – Steel Catenary Riser Profile (Phifer 1998)






Riser top angle = 9.5 degrees from vertical

Riser top elevation = 3230 feet

X Y X Y

(ft) (ft) (ft) (ft)

0 3,230.00 640.3 835.933.16 3,211.14 656.99 801.52

6.32 3,192.28 674.08 767.32

9.5 3,173.43 691.6 733.33

12.69 3,154.58 709.55 699.56

15.9 3,135.73 727.96 666.05

19.13 3,116.89 746.85 632.81

22.37 3,098.05 766.24 599.85

25.62 3,079.21 786.15 567.21

28.9 3,060.37 806.61 534.9

32.19 3,041.54 827.64 502.96

38.82 3,003.88 849.26 471.43

45.52 2,966.23 871.51 440.33

52.29 2,928.60 894.4 409.7

59.13 2,890.98 917.97 379.59

66.04 2,853.37 942.24 350.04

73.03 2,815.77 967.24 321.11

80.1 2,778.19 993.01 292.86

87.25 2,740.63 1,019.56 265.34

94.47 2,703.08 1,046.92 238.64

101.78 2,665.55 1,075.12 212.81

109.17 2,628.03 1,104.17 187.96

116.64 2,590.53 1,134.10 164.16

128.02 2,534.31 1,164.91 141.52

139.6 2,478.14 1,196.60 120.14

151.4 2,422.01 1,229.16 100.14

163.41 2,365.92 1,262.58 81.62

175.65 2,309.88 1,296.82 64.72

188.12 2,253.90 1,331.79 49.55

200.84 2,197.97 1,367.40 36.24

213.81 2,142.10 1,385.39 30.33

227.04 2,086.29 1,403.46 24.92

240.55 2,030.55 1,421.57 20.04

254.34 1,974.87 1,439.67 15.7

268.43 1,919.27 1,457.68 11.91

282.83 1,863.75 1,475.50 8.67

297.56 1,808.32 1,492.99 5.98

312.62 1,752.97 1,509.98 3.83

328.03 1,697.73 1,526.20 2.21

343.82 1,642.58 1,541.31 1.08

359.99 1,587.55 1,544.16 0.91

370.99 1,550.93 1,546.94 0.75

382.18 1,514.37 1,549.65 0.61

393.57 1,477.87 1,552.28 0.48

405.15 1,441.42 1,554.82 0.37

416.93 1,405.05 1,557.28 0.27

428.93 1,368.74 1,559.64 0.19

441.15 1,332.51 1,561.89 0.11

453.59 1,296.35 1,564.04 0.05

466.27 1,260.27 1,566.06 0

479.19 1,224.28 1566.06 0492.36 1,188.39 1569.94 -0.09

505.8 1,152.59 1573.81 -0.16

519.51 1,116.89 1577.68 -0.23

533.5 1,081.30 1581.56 -0.28

547.78 1,045.83 1585.43 -0.33

562.36 1,010.49 1589.3 -0.37

577.27 975.27 1593.18 -0.4

592.5 940.2 1597.05 -0.43

608.07 905.28 1600.93 -0.45

624 870.52 1604.8 -0.46

1953 -0.46

Table 1C.2 – Steel Catenary Riser Profile Data

(Corresponding to Figure 1.50: Phifer 1998)






1.0 TEMPERATURE AND SALINITY PROFILES

G FORRISTALL (1998)

Temperature and salinity profiles were constructed by averaging all of the profiles on

the US National Oceanographic Data Center CD-ROM for the area between 4° to 6°Nand 4° to 6°E. Our experience is that deepwater temperatures do not vary muchover such an area. All of the profiles were averaged over depth bins, and thestandard deviation of the temperature in each bin was also found. The columns inTable 1C.3 give the mean depth in the bin, the mean temperature, the standarddeviation of the temperature, the mean +/- the standard deviation and n, the numberof observations in the depth bin.

There are many more observations at shallow depths than deep in the water, but thestandard deviations of the observations are also much higher at shallow depths.This variability is natural, largely due to seasonal effects in the temperature and riverrunoff in the salinity. The average temperatures and salinities are, for engineering

purposes, nearly constant at great depth, and the average values in the tables canbe used with confidence despite the small numbers of observations.

Average values of seawater density were computed from the average temperature,salinity and depth, and are given in the last column of Table 1C.4. The density isgiven in units of kg/m3. Temperatures, salinities and densities at other depths can befound by interpolation in the table.






Depth Avg Avg+std Avg-std Std n

1.98 27.90 29.26 26.54 1.36 129.00

12.70 27.72 29.13 26.32 1.40 112.00

22.40 26.94 28.70 25.18 1.76 124.00

32.58 24.32 26.90 21.74 2.58 123.00

43.14 21.59 24.25 18.92 2.67 108.00

52.48 19.53 21.78 17.29 2.24 89.00

62.84 17.98 19.70 16.27 1.72 69.00

73.09 17.25 18.91 15.58 1.66 77.00

82.76 16.54 18.15 14.92 1.61 63.00

93.25 16.14 17.64 14.65 1.50 67.00

118.00 15.31 16.78 13.85 1.46 235.00

170.49 14.52 15.81 13.23 1.29 98.00

222.63 12.88 14.16 11.61 1.28 88.00

269.80 11.31 12.50 10.12 1.19 71.00

323.66 10.07 11.03 9.11 0.96 41.00

371.86 9.42 10.99 7.85 1.57 37.00

421.94 8.38 9.27 7.50 0.88 32.00

475.56 7.32 7.66 6.97 0.34 34.00

523.77 6.78 7.11 6.45 0.33 22.00

574.00 6.35 6.74 5.96 0.39 22.00

626.60 5.87 6.20 5.55 0.33 20.00

676.75 5.58 5.85 5.31 0.27 20.00

722.00 5.33 5.66 5.01 0.33 19.00

766.44 5.02 5.24 4.79 0.22 16.00

830.33 4.82 4.86 4.79 0.03 3.00

978.33 4.43 4.48 4.37 0.05 3.00

1000.00 4.43 4.43 4.42 0.00 2.00

Table 1C.3 – Representative Ambient Sea Temperature Profile






Depth AvgAvg+std

Avg-std

Std nAvg

Density

0.19 32.27 37.37 27.17 5.10 27.00 1020.4

11.78 33.70 35.47 31.94 1.77 18.00 1021.6

21.69 34.12 35.32 32.93 1.19 29.00 1022.1

31.81 35.30 35.71 34.88 0.42 26.00 1023.9

42.18 35.59 35.72 35.46 0.13 11.00 1024.9

50.75 35.69 35.73 35.64 0.05 12.00 1025.7

61.67 35.83 35.83 35.83 0.00 3.00 1026.2

74.36 35.73 35.74 35.72 0.01 11.00 1026.480.00 35.80 35.80 35.80 0.00 1.00 1026.6

95.40 35.76 35.76 35.76 0.00 5.00 1026.7

117.11 35.63 35.64 35.62 0.01 19.00 1026.9

168.38 35.49 35.50 35.49 0.00 13.00 1027.2

217.33 35.33 35.34 35.31 0.01 12.00 1027.5

270.77 35.13 35.14 35.12 0.01 13.00 1027.6

300.83 35.00 35.00 35.00 0.00 6.00 1028.4

381.00 34.83 34.84 34.83 0.00 8.00 1028.6

400.00 34.82 34.82 34.81 0.00 4.00 1028.6

483.80 34.71 34.71 34.71 0.00 5.00 1029.3

515.33 34.68 34.68 34.68 0.00 3.00 1029.6

585.00 34.69 34.69 34.69 0.00 1.00 1029.9

682.33 34.55 34.55 34.55 0.00 3.00 1030.3

700.00 34.57 34.57 34.57 0.00 2.00 1030.5

978.33 34.69 34.69 34.69 0.00 3.00 1032.0

1000.00 34.69 34.70 34.69 0.00 2.00 1032.0

Table 1C.4 – Salinity and Density Profiles (Parts per Thousand)






Depth (m) Current (m/s)

1100m 0.18

800 0.17

500 0.19

200 0.35

100 0.37

0 0.70

Table 1C.5 – Anticipated Bonga-area Water Current Velocities




Section 2 Flow Assurance Production Constraints


Section 2Flow Assurance Production Constraints

Table of Contents

1.0 OBJECTIVES ...............................................................................................................3

2.0 WELL STABILITY.........................................................................................................3

3.0 WELL KICK-OFF..........................................................................................................6

4.0 WAX DEPOSITION.......................................................................................................9

4.1 Flowline Wax Management..............................................................................11

4.2 East Flowlines..................................................................................................11

4.3 West Flowlines.................................................................................................11

5.0 WELLHEAD COOLDOWN .........................................................................................12

6.0 FLOWLINE/RISER COOLDOWN ...............................................................................12

7.0 FLOWLINE SLUGGING..............................................................................................13

8.0 CONCLUDING REMARKS.........................................................................................14

TABLES

Table 2.1 – Minimum Well Production Rates for Stable, Controllable Flow.............................4

Table 2.2 – Manifold Pressures for Various Hot-oiling Scenarios, With and Without Gas Lift .6

Table 2.3 – Flowing Wellhead Temperatures .......................................................................10

Table 2.4 – Wax Pigging Frequencies for Turndown 1 Well/1 Flowline Production(Tsai et al, 2002) ................................................................................................11

FIGURES

Figure 2.1 – Illustration of Multiple Solution Behaviour Associated with Well Instability ..........3

Figure 2.2 – Reservoir Pressure Required for Well Start-up to Stable Flowrates:Wells in Manifolds PM3 and PM4 (East-East Flowlines 3, 4, 5 and 6) ................7

Figure 2.3 – Reservoir Pressure Required for Well Start-up to Stable Flowrates:Wells in Manifold PM5 (East-West Flowlines 1 and 2)........................................7

Figure 2.4 – Reservoir Pressure Required for Well Start-up to Stable Flowrates:Wells in Manifold PM 1 (West-North Flowlines 8 and 9) .....................................8

Figure 2.5 – Reservoir Pressure Required for Well Start-up to Stable Flowrates:Wells in Manifold PM2 (West-South Flowlines 11 and 12)..................................8







FIGURES

Figure 2.6 – Arrival Temperature as a Function of Rate, for 1 Well/1 FlowlineProduction Scenarios .......................................................................................12

Figure 2.7 – Riser Gas Lift Required for Slug Control: West Flowlines .................................13

Figure 2.8 – Riser Gas Lift Required for Slug Control: East 10in flowlines............................14

APPENDICES

Appendix 2A – Well Design Basis – FDP Rev 5 ...................................................................15






1.0 OBJECTIVES

The principal objective’ of this study is to quantify flow assurance constraints forproduction forecasting, particularly minimum acceptable flowrates per well andflowline. It is important to note that results herein represent the absolute edge of theflow assurance envelope, with essentially all conservatism in analysis removed.As such, this analysis is intended for Shell Bonga project staff only and should notbe shared with Engineer, Procure, Install and Construct (EPIC) contractors, whocould misinterpret/misuse these results as a basis for systems design. The keyend-users of these results are:

• Bonga reservoir engineering staff (Bonga Integrated Studies Team (BIST)),to enable assessment and risking of production forecasts with respect to flowassurance

• Bonga operations staff, to outline the operating envelope for relevant flowassurance risks

Noting that well stability is found to be the governing constraint for minimum wellflowrate, the following analysis approach is used:

(1) Identification of minimum well rates for stable flow on a well-by-well basis.

(2) Verification of flow assurance requirements for wax, hydrate and slugging atthe minimum stable rates.

2.0 WELL STABILITY

With respect to minimum well production rates, a key consideration is well stability,particularly so for the larger tubing of the Bonga wells (5 1/2in and 6 5/8in).As illustrated in Figure 2.1, multiphase wells exhibit multivalued behaviour at lowerproduction rates (ie two possible flowrates at the same applied pressure drop).The low flowrate solution represents a liquid loaded well (usually with slugging at thewellhead), while the high flowrate solution has less liquid hold-up and a largerfrictional pressure drop. Hence, rates below the instability threshold (the minimum inFigure 2.1) are generally not controllable, as the past history of the well’s liquidloading will determine whether the low or high-flowrate solutions are attained.In general, if the well flowrate is reduced (from a higher rate) to below the instabilitythreshold (by choking), the well will load-up with liquid and shut-in if the wellheadpressure is not reduced.

Production rate

Well

∆p

Instability

Figure 2.1 – Illustration of Multiple Solution Behaviour Associatedwith Well Instability








In this report, well stability for Bonga was assessed on a well-by-well basis usingOlga2000, with thermal well modelling tuned to match WellTemp predictions.Well design parameters (ie productivities, deviation profiles, reservoir pressures etc)are based on Bonga Field Development Plan (FDP) Rev 5 (summarised in

Appendix 2A). The procedure for assessing well stability is as follows:(1) Initial conditions consist of a gas-filled well at ambient geothermal conditions.

(2) Reduce flowing wellhead pressure in 25psi increments until sustainedproduction occurs. If the Flowing Wellhead Pressure (FWHP) is too high, thewell will shut-in after liquid travels up the wellbore.

(3) The minimum acceptable flowrate for a well is the smallest sustainedproduction that can occur as calculated in Step (2).

Note: Production rates below the minimum rate for stability may simply beunattainable (even if sufficient reservoir pressure exists), as additionalchoking can cause the well to load-up and abruptly shut-in. That is,

intermediate rates below the threshold are unstable and may not beobservable in practice (much like the inherent instability of a pinbalanced on its tip).

As shown in Table 2.1, the minimum well rates for stability vary between 2 to7MBLPD.

Notes:

(1) The key discriminator between the lower and higher thresholds is the welltubing, since lower gas velocities obtained for the larger 6 5/8in tubing aremore conducive to well load-up and instability.

(2) The only wells with 6 5/8in production tubing are 702p9, 702p15, 702p10,

702p4, which are also horizontal completions (690p1 is the only otherhorizontal well, but with 5 1/2in tubing).

Noting the complexities in modelling multiphase flow and the discrete 25psiWWellhead Pressure (WHP) steps used in analysis, the limiting rate for both tubingsizes is interpreted as the stability threshold for controllable steady-state production:

• 5 1/2in: 5MBLPD minimum rate for stability

• 6 5/8in: 7MBLPD minimum rate for stability

These thresholds are consistent with previous steady-state analysis (analogous toFigure 2.1), summarised in van Gisbergen, 1999.






3.0 WELL KICK-OFF

Noting the relatively low Bonga reservoir pressures and the importance ofwaterflood for pressure maintenance, well kick-off requirements are evaluated withrespect to depletion predictions for each well. Figures 2.2 to 2.5 show the reservoirpressure required to start each well against a minimum attainable wellhead pressureof 600psi, relative to the minimum reservoir pressure (over the field life) predicted byGAP (GAP is a subsurface software used to model wells and flowline networks). The minimum reservoir pressures tend to occur in mid-life; assuming effectivewaterflood, the reservoir pressure rises later in field life. Note that a wellheadbackpressure of 600psi requires availability of gas lift if starting up into a hot oiled(or high water cut) flowline. The manifold pressures obtained during hot-oiling of the(worst-case) east flowloops are summarised in Table 2.2. To obtain manifoldpressures in the range of 600psi, the hot-oiling rate will have to be turned down(eg to 10MBOPD) if a well is started up while hot-oiling. Further, gas lift (of thereturn riser) is also required to reduce the riser hydrostatic head.

Flowloop Hot-oiling Rate Gas Lift Manifold P

E-E (12in) 50MBOPD 0MMscfd 1640psia

E-E 50 10 1025

E-E 10 0 1545

E-E 10 20 500

E-W (10in) 50 0 1870

E-W 50 10 1280

E-W 10 0 1550

E-W 10 10 500

Table 2.2 – Manifold Pressures for Various Hot-oiling Scenarios,With and Without Gas Lift






0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

R e q u i r e d r e s e r v o i r P

f o r s t a b l e f l o w [ p

s i a ]

0% wc

50% wc

80% wc

Min Reservoir P

702p5 702p9 702p10 803p2702p14

Figure 2.2 – Reservoir Pressure Required for Well Start-up toStable Flowrates: Wells in Manifolds PM3 and PM4

(East-East Flowlines 3, 4, 5 and 6)

Figure 2.3 – Reservoir Pressure Required for Well Start-up toStable Flowrates: Wells in Manifold PM5 (East-West Flowlines 1 and 2)






Figure 2.4 – Reservoir Pressure Required for Well Start-up toStable Flowrates: Wells in Manifold PM 1 (West-North Flowlines 8 and 9)

0

500

1000

1500

2000

2500

3000

3500

4000

R e q u i r e d r e s e r v o i r P

f o r s t a b l e f l o w [ p

s i a ]

0% wc

50% wc

80% wc

Min Reservoir P

690p4 702p2 702p6 702p7 702p15 710p4 803p1 803p3

Figure 2.5 – Reservoir Pressure Required for Well Start-up toStable Flowrates: Wells in Manifold PM2 (West-South Flowlines 11 and 12)






As shown in Figures 2.2 to 2.5, all wells except for 803p2 are able to start up againsta 600psi wellhead backpressure, for the worst-case scenario of an initiallyliquid-loaded well and the minimum reservoir pressures of each body over thefield life. The liquid-loaded initial condition is based on the restart scenario for a well

which falls below the stability threshold and loads up with liquid. For most wells,500 to 750psi of ‘spare’ reservoir pressure capacity is available, with lesser marginfor 702p2, 702p5, and the 803 wells. For 803p2, extra surveillance attention will beneeded to avoid loading it with liquid, as it may not be restarted at the minimum 803reservoir pressure. Also, the phasing of 803p2 with respect to stronger wells shouldbe assessed to assure that its production will not be backed out. These resultsunderscore the importance of effective waterflood for reservoir pressuremaintenance, as assumed in the GAP predictions.

In early field life, all wells are strong enough to start-up against a dead-oil filled riser(with the possible exception of 803p2, which has a minimal pressure margin).In fact, this additional riser hydrostatic head is needed for chilly choke management

in early life. Thus, an important surveillance activity will be to track the backpressurerequirements of individual wells, which will be necessary whenever wells in differentphases of life are to be started up and produced into the same flowline.

4.0 WAX DEPOSITION

The basic wax management strategy for Bonga is to flow above the Critical WaxDeposition Temperature (CWDT) in the wellbore and to pig flowlines during plannedshutdown operations. Recent wax analysis (Tsai et al 2002) indicates a maximumCWDT of 43°C (109°F) for B2ST3-702, at a (minimum) wellhead pressure of 400psi.As shown in Table 2.3, at the minimum rates for well stability (5MBLPD for 5 1/2intubing; 7MBLPD for 6 5/8in tubing), several wells are at or near the onset point for

wellhead wax deposition: 690p4, 702p3, 702p6, 702p7, 710p2. Hence, long-termturndown production (ie below 10MBLPD) should be avoided for these wells.Noting the relatively low deposition rate characteristic of the Bonga fluids, productionof these lower-T wells may be tolerable for shorter-term durations to accommodatetransient operations such as well testing or well flowline switching.

Note: In Table 2.3, all other wells are outside the wax deposition envelope at theminimum rates for stable flow.






WellMinimum Production

Rate (MBLPD)Turndown

Wellhead T (°F)

690p1 5 132

690p2 5 114

690p3 5 119

690p4 5 108

702p2 5 115

702p3 5 106

702p4 (6 5/8in) 7 136

702p5 5 117

702p6 5 109

702p7 5 99

702p9 (6 5/8in) 7 121

702p10 (6 5/8in) 7 123

702p14 5 117

702p15 (6 5/8in) 7 116

710p1 5 121

710p2 5 105

710p3 5 112710p4 5 126

803p1 5 140

803p2 5 141

803p3 5 139

Table 2.3 – Flowing Wellhead Temperatures

Table 2.3 gives the flowing wellhead temperatures (24 hours after warm-up) atminimum stable production rates of 5MBLPD (5 1/2in tubing wells), and 7MBLPD(6 5/8in tubing wells). Temperatures below CWDT = 109°F are highlighted.






4.1 Flowline Wax Management

Regarding flowline/riser wax management, the basic operating strategy is to pigflowlines for wax during scheduled or planned shut-ins, during hot or dry-oilingoperations. Based on the updated wax analysis in Tsai et al, 2002, piggingfrequency requirements at turndown conditions are shown in Table 2.4. The FlowingWellhead Temperature (FWHT) values of 100°F and 120°F are based on theminimum FWHT observed at rates of 5MBLPD and 7MBLPD, respectively (refer toTable 2.3, with slight exception of 116°F for 702p15 at 7MBLPD). Recall that theBonga Basis of Design (BoD) specifies a minimum turndown rate of 10MBLPD perflowline, so that these results apply to operations outside the design envelope.

4.2 East Flowlines

For wells with FWHTs in the order of 100°F, extended turndown production at5MBLPD (one well into one flowline) is not feasible for both East flowline loops,as 8 to 10 piggings per year would be required. This would likely involve system

shut-ins (or temporary well curtailment) solely for wax management, if plannedshutdowns are less frequent than once per month (as is expected in availabilityanalysis). At 7MBLPD, the pigging frequency decreases to six per year (East 10in)and 4 per year (East 12in), due to both the shorter residence time in the flowline andthe higher wellhead temperature (120°F, refer to Table 2.4). The feasibility of suchpigging frequencies will have to be determined based on operating experience andshutdown statistics (ie number of pigging opportunities). During surveillance, waxanalysis of the 690 wells (690p1, 690p2, 690p3) producing into the (worst-case)East 10in flowlines PFL 1 and 2 can be used (along with thermal modelbenchmarking) to further refine the 690 specific pigging requirements.

4.3 West FlowlinesDue to their much shorter offset, the West flowlines’ wax requirements are lesssevere, with four piggings per year required for 5MBLPD production (one well into1 flowline).

Note: In Table 2.3, the wellhead temperature for most wells exceeds 100°F at5MBLPD, so that this pigging frequency represents the upper limit.

As discussed above, post-start-up wax analysis should be included in thesurveillance programme, especially if such turndown production is anticipated forsome wells.

Flowline Rate(MBLPD)

FWHT(°F)

Pigging Frequency(No per Year)

5 100 10East 10in(PFL 1, 2) 7 120 6

5 100 8East 12in(PFL 3, 4, 5, 6) 7 120 4

5 100 4West 10in(PFL 8, 9, 11,12)

7 120 1

Table 2.4 – Wax Pigging Frequencies for Turndown 1Well/1 Flowline Production (Tsai et al, 2002)








Note: The West and East start temperatures differ due to offset differences, whilethe end temperatures differ due to the effects of line-packing (with anassumed 10 minimum choke closing time).

Arrival temperatures as a function of production rate for representative early-lifeone well/one flowline combinations are shown in Figure 2.6.

Note: The required riser base start temperatures translate to arrival temperatures ofapproximately 80°F (East) and 90°F (West).

In Figure 2.6, the 12-hour cooldown requirement corresponds to minimum rates ofapproximately 5MBLPD (West) and 7MBLPD (East). These results are alsoconsistent with the generalised thermal modelling in Tsai et al, 2002, for a wellheadtemperature of 120°F.

7.0 FLOWLINE SLUGGING

A key consideration for turndown production at Bonga is control of terrain slugging,noting recent slug-induced operational difficulties in the Gulf of Mexico (GoM).For Bonga, riser gas lift with up to 25MMscfd for a given riser is available for slugcontrol at turndown, but it is important to note that the total gas lift compressioncapacity is 65MMscfd (Bonga BoD). Hence, only a limited number of flowlines maybe operated simultaneously in an extended turndown condition. As illustrated inFigures 2.7 and 2.8, terrain slug control requires the 25MMscfd gas lift capacity atproduction rates of 5MBLPD (West) and 7MBLPD (East).

Note: The minimum flowrate for the East 12in flowlines is also approximately7MBLPD, with residual 50bbl slugs observed even at high gas lift rates(compared to complete slug suppression for the other flowlines).

OPRM20030302D_047.ai

10 20 30 400


10

5

15

20

0

R e q u

i r e d G a s

L i f t ( M M S C F D )

0% wc

50% wc

80% wc

Figure 2.7 – Riser Gas Lift Required for Slug Control: West Flowlines






Section 2 Appendix 2A Well Design Basis – FDP Rev 5


Appendix 2AWell Design Basis – FDP Rev 5

Compiled by Kelda McFee.

690 Wells

690p1 hz

Well Trajectory Summary Profile

MD(ft) SS TVD (ft) SS Inc (deg) Tubing size (I)

WD 3581 3581 0 PI@PSSS 20 bbl/day psia AHD ft (SS) ID (in) OD (in)

2 3600 3600 0 Initial Pavg 4511 psia 12931 4.892 5 1/2

3 3700 3700 0 Initial GOR 605 scf/bbl

4 3800 3800 0 T@midperfs 160 °F

5 3900 3900 0

6 4000 4000 0 SSSV

7 4100 4100 0 Depth ML (ft) 2300

8 4200 4200 0 ID (in) 4.56 Roughness 0.0018

9 4300 4300 0 Length (ft) 9.72 Geothermal profile Linear between reservoir and seabed

10 4400 4400 0 TVD (ft) SS 9447.2 Heat transfer coefficient 2

11 4500 4500 0

12 4600 4600 0

13 4700 4700 0

14 4800 4800 0

15 4900 4900 0

16 5000 5000 0

17 5100 5100 0

18 5200 5200 0

19 5300 5300 0

20 5400 5400 0

21 5500 5500 0

22 5600 5600 0

23 5700 5700 0

24 5800 5800 0

25 5900 5900 0

26 6000 6000 0

27 6100 6100 0

28 6200 6200 2.5

29 6300 6299.7 5

30 6400 6399.1 7.5

31 6500 6497.6 12.5

32 6600 6594.2 17.5

33 6700.3 6688.4 22.51

34 6800 6780.5 22.51

35 6900 6872.9 22.51

36 7000 6965.2 22.51

37 7100 7057.6 22.51

38 7200 7150 22.51

39 7300 7242.4 22.51

40 7400 7334.8 22.51

41 7500 7427.1 22.51

42 7600 7519.5 22.51

43 7700 7611.9 22.5144 7800 7704.3 22.51

45 7900 7796.7 22.51

46 8000 7889.1 22.51

47 8100 7981.4 22.51

48 8200 8073.8 22.51

49 8300 8166.2 22.51

50 8400 8258.6 22.51

51 8500 8351 22.51

52 8591.6 8435.6 22.51

53 8600 8443.3 22.93

54 8700 8533.6 27.93

55 8800 8619.8 32.93

56 8900 8701.3 37.93

57 9000 8777.4 42.93

58 9100 8847.5 47.93

59 9200 8911.2 52.93

60 9300 8967.9 57.93

61 9400 9017.3 62.93






690 Wells (cont’d)

690p1 hz

Well Trajectory

MD(ft) SS TVD (ft) SS Inc (deg)

62 9500 9058.8 67.93

63 9600 9092.3 72.9364 9701.3 9117.7 78

65 9800 9138.2 78

66 9900 9159 78

67 10001.3 9180.1 78

68 10100 9200.6 78

69 10200 9221.4 78

70 10289.9 9240.1 78

71 10300 9242.2 78.5

72 10409.6 9258.8 83.97

73 10500 9268.3 83.97

74 10600 9278.8 83.97

75 10700 9289.4 83.97

76 10800 9299.9 83.97

77 10900 9310.4 83.97

78 11000 9320.9 83.97

79 11026.7 9323.7 83.97

80 11041.4 9325.1 84.54

81 11044.1 9325.4 84.4

82 11100 9330.9 84.4

83 11200 9340.6 84.4

84 11300 9350.4 84.4

85 11400 9360.1 84.4

86 11500 9369.9 84.4

87 11600 9379.7 84.4

88 11700 9389.4 84.4

89 11800 9399.2 84.4

90 11874.8 9406.5 84.4

91 11900 9408.7 85.65

92 11945.5 9411.2 87.91

93 12000 9413.2 87.91

94 12100 9416.8 87.91

95 12200 9420.5 87.91

96 12300 9424.1 87.91

97 12400 9427.8 87.91

98 12500 9431.4 87.91

99 12600 9435.1 87.91

100 12700 9438.7 87.91

101 12800 9442.4 87.91

102 12900 9446 87.91

103 12931.2 9447.2 87.91

690p2



WD 3581.0 3581.0 0.00 PI@PSSS 25 bbl/day psia

2 5500.0 5500.0 0.00 Initial Pavg 4279 psia AHD ft (SS) ID (in) OD (in)

3 6400.0 6310.3 45.00 Initial GOR 605 scf/bbl 13689 4.892 5 1/2

4 7789.4 7292.7 45.00 T@midperfs 146 °F

5 8189.4 7521.0 65.001 10000.0 8286.2 65.00 SSSV

2 10435.0 8404.3 83.46 Depth ML (ft) 2300

3 12837.6 8678.0 83.46 ID (in) 4.56 Roughness 0.0018

4 13689.2 8775.0 83.46 Length (ft) 9.72 Geothermal profile linear

TVD (ft) SS 5881.0 Heat transfer coefficient 2







S690p3



Sidetrack of 702p4

WD 3568.0 3568.0 0.00 PI@PSSS 18 bbl/day psia AHD ft (SS) ID (in) OD (in)1 7300.0 7236.6 40.00 Initial Pavg 4365 psia 10590 4.892 5 1/2

2 7686.6 7489.2 58.11 Initial GOR 605 scf/bbl

3 10589.6 9023.0 58.11 T@midperfs 155 °F

SSSV

Depth ML (ft) 2300

ID (in) 4.56 Roughness 0.0018

Length (ft) 9.72 Geothermal profile linear

TVD (ft) SS 5868.0 Heat transfer coefficient 2

S690p4



Sidetrack of 702p2

WD 3369.0 3369.0 0.00 PI@PSSS 19 bbl/day psia AHD ft (SS) ID (in) OD (in)

1 6150.0 6147.6 7.50 Initial Pavg 4415 psia 10842 4.892 5 1/2


3 10841.9 8268.0 69.89 T@midperfs 137 °F

SSSV

Depth ML (ft) 2300

ID (in) 4.56 Roughness 0.0018

Length (ft) 9.72 Geothermal profile linear

Depth (ft) SS 5669.0 Heat transfer coefficient 2

702 Wells

702p2





3 6150.0 6149.1 7.50 Initial GOR 589.57 scf/bbl

4 6940.6 6838.1 47.03 T@midperfs 143 °F

5 8824.1 8121.9 47.03

6 9164.7 8387.4 30.00 SSSV

7 9256.6 8467.0 30.00 Depth ML (ft) 2300 Roughness 0.0018

8 9345.5 8544.0 30.00 ID (in) 4.56 Geothermal profile Linear between reservoir and seabed

9 9685.0 8838.0 30.00 Length (ft) 9.72 Heat transfer coefficient 2

TVD SS (ft) 5669.0

S702p3



Sidetrack of 710p1 PI@PSSS 20 bbl/day psia AHD ft (SS) ID (in) OD (in)

WD 3276.0 3276.0 0.00 Initial Pavg 4052 psia 9150 4.892 5 1/2


2 7095.7 6915.0 56.46 T@midperfs 130 °F

3 9150.2 8050.0 56.46

SSSV

Depth ML (ft) 2300 Roughness 0.0018

ID (in) 4.56 Geothermal profile Linear between reservoir and seabed

Length (ft) 9.72 Heat transfer coefficient 2

TVD SS (ft) 5576.0







702p5



1 3343.0 3343.0 0.00 PI@PSSS 35 bbl/day psia AHD ft (SS) ID (in) OD (in)

2 5500.0 5500.0 0.00 Initial Pavg 4351 psia 9831 4.892 5 1/23 6333.2 6261.7 41.66 Initial GOR 589.57 scf/bbl

4 9831.1 8875.0 41.66 T@midperfs 151 °F

SSSV




TVD SS (ft) 5643.0

S702p6






2 6790.5 6586.5 59.64 T@midperfs 136 °F

3 10014.0 8216.0 59.64

SSSV




TVD SS (ft) 5659.0

S702p7






2 7840.1 7357.1 79.43 T@midperfs 120 °F

3 10528.0 7850.0 79.43

4 10778.5 7869.1 91.82 SSSV


ID (in) 4.56 Geothermal profile linear


TVD SS (ft) 5659.0

702p14



WD 3327 3327 0 PI@PSSS 13 bbl/day psia AHD ft (SS) ID (in) OD (in)

1 5500 5500 0 Initial Pavg 4247 psia 14267 4.892 5 1/2

2 6500 6377.8 50 Initial GOR 589.57 scf/bbl

3 6909.6 6641.1 50 T@midperfs 144 °F

4 7409.6 6870.2 75

5 13957.9 8565 75 SSSV

6 14267 8645 75 Depth ML (ft) 2300 Roughness 0.0018

ID (in) 4.56 Geothermal profile linear


TVD SS (ft) 5627.0







702p9




2 3721.4 3721.4 0.09 Initial Pavg 4292 psia 3 4003.9 4003.9 0.35 Initial GOR 589.57 scf/bbl 4 4286.0 4286.0 0.31 T@midperfs 147 °F 5 4568.8 4568.8 0.18

6 4851.4 4851.4 0.18 SSSV

7 5133.7 5133.7 0.18 Depth ML (ft) 2300 8 5416.1 5416.1 0.22 ID (in) 4.56 9 5599.8 5599.8 0.13 Length (ft)* 9.72 10 5678.0 5678.0 0.45 TVD SS (ft) 5631.0 11 5764.0 5764.0 0.30

12 5866.0 5866.0 1.33

13 5960.0 5959.9 3.94 Roughness 0.0018

14 6051.0 6050.4 7.13 Geothermal profile Linear between reservoir and seabed

15 6143.0 6141.3 10.65 Heat transfer coefficient 2

16 6240.0 6235.9 15.04

17 6333.0 6324.2 21.29

18 6426.0 6408.6 28.27 Well Design/ Tubing Size

19 6520.0 6487.6 37.12

20 6615.0 6560.2 43.15 AHD ft (SS) ID (in) OD (in) Length (ft) Description 21 6709.0 6629.5 41.96 3545 4.892 6 45 Tubing Hanger

22 6804.0 6700.0 42.11 5545 5.921 7.191 2000 Tubing

23 6896.0 6767.0 44.43 5576.72 4.562 7.99 31.72 SSSV*

24 6989.0 6831.4 47.94 10576.72 5.921 7.191 5000 Tubing

25 7151.0 6935.9 51.95 12084.7 4.892 6.05 1508.0 Excluder Screens

26 7244.0 6991.1 55.29

27 7341.0 7044.7 57.73

28 7434.0 7095.2 56.47

29 7526.0 7146.9 55.16

30 7620.0 7201.9 53.17

31 7713.0 7259.1 51.00

32 7807.0 7320.1 48.10

33 7901.0 7383.7 46.70

34 7995.0 7448.9 45.47

35 8089.0 7516.0 43.32

36 8184.0 7585.1 43.37

37 8278.0 7655.0 40.65

38 8374.0 7729.5 37.46

39 8468.0 7804.2 37.36

40 8561.0 7878.5 36.49

41 8656.0 7955.3 35.73

42 8666.2 7963.4 37.92

43 8750.0 8029.3 38.51

44 8820.0 8085.1 35.78

45 8846.0 8106.3 34.77

46 8920.0 8165.8 38.21

47 9020.0 8241.8 42.86

48 9120.0 8312.2 47.51

49 9220.0 8376.7 52.16

50 9320.0 8434.8 56.81

51 9420.0 8486.1 61.46

52 9520.0 8530.2 66.1153 9620.0 8567.0 70.76

54 9720.0 8596.1 75.41

55 9820.0 8617.3 80.05

56 9853.7 8622.7 81.59

57 9920.0 8632.4 81.59

58 10020.0 8647.0 81.59

59 10120.0 8661.7 81.59

60 10195.5 8672.7 81.59

61 10216.0 8675.7 81.59

62 10220.0 8676.3 81.59

63 10266.0 8683.0 81.59

64 10320.0 8689.7 84.23

65 10392.2 8694.7 87.77

66 10420.0 8695.8 87.77

67 10520.0 8699.7 87.77

68 10620.0 8703.6 87.77

69 10720.0 8707.5 87.77

70 10820.0 8711.4 87.77







702p9



71 10920.0 8715.3 87.77

72 11020.0 8719.1 87.7773 11120.0 8723.0 87.77

74 11220.0 8726.9 87.77

75 11320.0 8730.8 87.77

76 11420.0 8734.7 87.77

77 11520.0 8738.6 87.77

78 11620.0 8742.5 87.77

79 11720.0 8746.4 87.77

80 11820.0 8750.3 87.77

81 11920.0 8754.2 87.77

82 12020.0 8758.1 87.77

83 12084.7 8760.6 87.77

702p15



WD 3359.0 3359.0 0.00

2 3369.0 3369.0 0.00 PI@PSSS 135 bbl/day psia

3 3420.0 3420.0 0.00 Initial Pavg 4168 psia


5 3620.0 3620.0 0.00 T@midperfs 140 °F

6 3720.0 3720.0 0.00

7 3820.0 3820.0 0.00 SSSV

8 3920.0 3920.0 0.00 Depth ML (ft) 2300

9 4020.0 4020.0 0.00 ID (in) 4.56

10 4120.0 4120.0 0.00 Length (ft)* 9.72

11 4220.0 4220.0 0.00 TVD SS (ft) 5659.0

12 4320.0 4320.0 0.00

13 4420.0 4420.0 0.00

14 4520.0 4520.0 0.00 Roughness 0.0018


16 4720.0 4720.0 0.00 Heat transfer coefficient 2 Btu/hr ft2 /°F

17 4820.0 4820.0 0.00

18 4920.0 4920.0 0.00


20 5120.0 5120.0 0.00

21 5220.0 5220.0 0.00 AHD ft (SS) ID (in) OD (in) Length (ft) Description

22 5320.0 5320.0 0.00 3545 4.892 6 45 Tubing Hanger

23 5420.0 5420.0 0.00 5545 5.921 7.191 2000 Tubing

24 5520.0 5520.0 0.00 5576.72 4.562 7.99 31.72 SSSV*

25 5620.0 5620.0 0.00 10576.72 5.921 7.191 5000 Tubing


27 5820.0 5820.0 0.00

28 5920.0 5920.0 0.00

29 6020.0 6020.0 0.00

30 6120.0 6120.0 0.00

31 6220.0 6220.0 0.00

32 6320.0 6320.0 0.00

33 6420.0 6420.0 0.00

34 6520.0 6520.0 0.00

35 6620.0 6620.0 0.0036 6720.0 6720.0 0.00

37 6820.0 6820.0 0.00

38 6920.0 6920.0 0.00

39 7020.0 7020.0 0.00

40 7120.0 7120.0 0.00

41 7170.8 7170.8 0.00

42 7220.0 7220.0 2.46

43 7320.0 7319.6 7.46

44 7420.0 7418.0 12.46

45 7520.0 7514.6 17.46

46 7620.0 7608.6 22.46

47 7720.0 7699.2 27.46

48 7820.0 7785.8 32.46

49 7920.0 7867.8 37.46

50 8020.0 7944.4 42.46

51 8120.0 8015.1 47.46

52 8220.0 8079.4 52.46

53 8320.0 8136.8 57.46







702p15

Well Trajectory


54 8420.0 8186.9 62.46

55 8520.0 8229.2 67.4656 8620.0 8263.5 72.46

57 8720.0 8289.4 77.46

58 8770.8 8299.4 80.00

59 8820.0 8307.9 80.00

60 8920.0 8325.3 80.00

61 9020.0 8342.6 80.00

62 9045.2 8347.0 80.00

63 9074.0 8352.0 80.00

64 9124.4 8360.7 80.00

65 9220.0 8373.7 84.46

66 9285.3 8378.2 87.51

67 9320.0 8379.7 87.51

68 9420.0 8384.1 87.51

69 9520.0 8388.4 87.51

70 9620.0 8392.7 87.51

71 9720.0 8397.1 87.51

72 9820.0 8401.4 87.51

73 9920.0 8405.8 87.51

74 10020.0 8410.1 87.51

75 10120.0 8414.4 87.51

76 10220.0 8418.8 87.51

77 10271.4 8421.0 87.51

78 10320.0 8424.1 85.09

79 10370.4 8429.5 82.58

80 10420.0 8436.0 82.58

81 10520.0 8448.9 82.58

82 10620.0 8461.8 82.58

83 10720.0 8474.7 82.58

84 10820.0 8487.6 82.58

85 10920.0 8500.5 82.58

86 11020.0 8513.5 82.58

87 11120.0 8526.4 82.58

88 11220.0 8539.3 82.58

89 11264.1 8545.0 82.58

702p10



WD 3178.0 3178.0 0.00

2 3558.0 3558.0 0.62

3 3808.0 3808.0 0.40 PI@PSSS 60 bbl/day psia



6 4641.0 4641.0 0.13 T@midperfs 146 °F

7 4946.0 4946.0 0.40

8 5217.0 5217.0 0.75 SSSV

9 5450.0 5450.0 0.40 Depth ML (ft) 2300

10 5517.0 5517.0 0.27 ID (in) 4.56

11 5611.0 5610.8 5.99 Length (ft)* 9.72

12 5706.0 5704.5 12.10 TVD SS (ft) 5478.013 5800.0 5795.5 17.17

14 5895.0 5884.4 23.73

15 5990.0 5968.6 31.36 Roughness 0.0018


17 6177.0 6121.4 38.23 Heat transfer coefficient 2 Btu/hr ft2 /°F

18 6271.0 6193.6 41.38

19 6366.0 6263.9 43.11

20 6458.0 6331.3 42.77 Well Design/Tubing Size

21 6555.0 6402.7 42.43


23 6744.0 6539.7 44.23 3545 4.892 6 45 Tubing Hanger

24 6838.0 6607.4 43.68 5545 5.921 7.191 2000 Tubing

25 6932.0 6676.6 41.46 5576.72 4.562 7.99 31.72 SSSV*

26 7026.0 6747.3 40.98 10576.72 5.921 7.191 5000 Tubing


28 7215.0 6888.4 43.20

29 7307.0 6954.5 44.93

30 7324.0 6966.5 45.52







702p10

Well Trajectory


31 7346.0 6982.0 45.05

32 7439.0 7047.0 46.2333 7533.0 7112.1 46.23

34 7627.0 7176.1 48.14

35 7722.0 7237.5 51.23

36 7816.0 7294.5 54.13

37 7911.0 7348.2 57.04

38 8005.0 7396.9 60.57

39 8100.0 7440.7 64.54

40 8194.0 7479.2 67.03

41 8288.0 7514.6 68.73

42 8382.0 7549.1 68.29

43 8476.0 7582.9 69.52

44 8571.0 7615.5 70.31

45 8665.0 7647.0 70.60

46 8760.0 7678.2 71.01

47 8854.0 7709.3 70.31

48 8948.0 7741.5 69.68

49 9043.0 7773.8 70.56

50 9137.0 7805.3 70.34

51 9200.0 7826.3 70.68

52 9226.5 7834.8 71.96

53 9320.0 7863.7 71.96

54 9420.0 7894.7 71.96

55 9520.0 7925.7 71.96

56 9620.0 7956.6 71.96

57 9720.0 7987.6 71.96

58 9820.0 8018.6 71.96

59 9920.0 8049.5 71.96

60 10020.0 8080.5 71.96

61 10120.0 8111.5 71.96

62 10220.0 8142.4 71.96

63 10320.0 8173.4 71.96

64 10420.0 8204.4 71.96

65 10520.0 8235.3 71.96

66 10620.0 8266.3 71.96

67 10720.0 8297.3 71.96

68 10820.0 8328.2 71.96

69 10920.0 8359.2 71.96

70 11020.0 8390.2 71.96

71 11120.0 8421.1 71.96

72 11220.0 8452.1 71.96

73 11320.0 8483.1 71.96

74 11420.0 8514.0 71.96

75 11520.0 8545.0 71.96

76 11620.0 8576.0 71.96

77 11720.0 8607.0 71.96

78 11778.1 8624.9 71.96

79 11808.3 8634.3 71.96

80 11820.0 8637.9 71.96

81 11858.3 8649.8 71.96

82 11920.0 8667.3 75.0383 12020.0 8688.9 80.01

84 12120.0 8701.9 85.00

85 12216.9 8706.3 89.82

86 12220.0 8706.3 89.82

87 12320.0 8706.6 89.82

88 12420.0 8707.0 89.82

89 12520.0 8707.3 89.82

90 12620.0 8707.6 89.82

91 12720.0 8707.9 89.82

92 12820.0 8708.2 89.82

93 12920.0 8708.5 89.82

94 13020.0 8708.8 89.82

95 13120.0 8709.2 89.82

96 13220.0 8709.5 89.82

97 13320.0 8709.8 89.82

98 13420.0 8710.1 89.82

99 13520.0 8710.4 89.82

100 13620.0 8710.7 89.82







702p10

Well Trajectory


101 13720.0 8711.0 89.82

102 13820.0 8711.4 89.82103 13920.0 8711.7 89.82

104 14019.3 8712.0 89.82

702p4






4 4470.0 4470.0 0.18 T@midperfs 161 °F

5 4748.0 4748.0 0.97

6 5027.0 5027.0 0.13 SSSV

7 5317.0 5317.0 0.22 Depth ML (ft) 2300

8 5599.0 5599.0 0.22 ID (in) 4.56

9 5791.0 5791.0 0.26 Length (ft)* 9.72

10 5905.0 5905.0 0.99 TVD SS (ft) 5868.0

11 6002.0 6001.9 1.41

12 6097.0 6096.9 1.92

13 6191.0 6190.8 1.62 Roughness 0.0018


15 6383.0 6382.8 1.85 Heat transfer coefficient 2 Btu//hr ft2 /°F

16 6477.0 6476.7 2.41

17 6571.0 6570.5 5.03


19 6758.0 6756.1 8.85


21 6945.0 6938.1 18.48 3545 4.892 6 45 Tubing Hanger

22 7039.0 7025.9 23.07 5545 5.921 7.191 2000 Tubing

23 7132.0 7109.2 29.79 5576.72 4.562 7.99 31.72 SSSV*

24 7225.0 7186.2 38.13 10576.72 5.921 7.191 5000 Tubing


26 7320.0 7258.4 42.16

27 7349.0 7279.9 42.16

28 7420.0 7333.7 39.20

29 7520.0 7413.4 35.10

30 7620.0 7497.2 31.09

31 7647.8 7521.1 30.00

32 7720.0 7583.6 30.00

33 7820.0 7670.2 30.00

34 7920.0 7756.8 30.00

35 8020.0 7843.4 30.00

36 8120.0 7930.0 30.00

37 8220.0 8016.6 30.00

38 8320.0 8103.2 30.00

39 8420.0 8189.9 30.00

40 8520.0 8276.5 30.00

41 8620.0 8363.1 30.00

42 8647.8 8387.1 30.00

43 8720.0 8448.5 33.51

44 8820.0 8529.4 38.4045 8858.8 8559.4 40.30

46 8920.0 8606.1 40.30

47 9020.0 8682.4 40.30

48 9120.0 8758.7 40.30

49 9138.7 8772.9 40.30

50 9220.0 8833.0 44.37

51 9320.0 8901.3 49.37

52 9420.0 8963.1 54.36

53 9520.0 9017.7 59.36

54 9620.0 9064.9 64.36

55 9720.0 9104.2 69.36

56 9820.0 9135.3 74.36

57 9920.0 9158.0 79.36

58 9932.8 9160.3 80.00

59 10020.0 9175.4 80.00

60 10120.0 9192.8 80.00

61 10132.8 9195.0 80.00

62 10220.0 9207.9 83.05







702p4

Well Trajectory


63 10320.0 9216.9 86.55

64 10406.2 9219.9 89.5765 10420.0 9220.0 89.57

66 10520.0 9220.7 89.57

67 10620.0 9221.5 89.57

68 10720.0 9222.2 89.57

69 10820.0 9223.0 89.57

70 10920.0 9223.7 89.57

71 11020.0 9224.5 89.57

72 11120.0 9225.2 89.57

73 11220.0 9226.0 89.57

74 11266.4 9226.3 89.57

75 11320.0 9227.6 87.69

76 11420.0 9234.7 84.19

77 11520.0 9247.8 80.69

78 11620.0 9267.0 77.19

79 11625.5 9268.2 77.00

80 11720.0 9289.5 77.00

81 11820.0 9312.0 77.00

82 11920.0 9334.5 77.00

83 11958.0 9343.0 77.00

710 WellsWell Trajectory Summary Profile





4 6695.1 6606.4 44.75 T@midperfs 147 °F

5 9544.7 8630.0 44.75

6 9706.6 8745.0 44.75 SSSV




TVD SS (ft) 5576.0

710p2






4 9332.2 7896.0 54.58 T@midperfs 128 F

5 9796.3 8165.0 54.58

SSSV




TVD SS (ft) 5578.0

710p3






4 9001.6 8364.0 36.08 T@midperfs 139 °F

5 9299.8 8605.0 36.08

SSSV




TVD SS (ft) 5578.0







710p4



Combined with 803p1 in a single wellbore PI@PSSS 18 bbl/day psia AHD ft (SS) ID (in) OD (in)

WD 3362.0 3362.0 0.00 Initial Pavg 4527 psia 9388 4.892 5 1/22 6150.0 6150.0 0.00 Initial GOR 1139.2 scf/bbl

3 6730.0 6705.5 29.00 T@midperfs 158 °F

4 9387.6 9030.0 29.00

SSSV




TVD SS (ft) 5662.0

803 Wells

803p1






4 9387.6 9030.0 29.00 T@midperfs 176 °F

5 10770.0 9910.9 79.31

6 10873.3 9930.0 79.31 SSSV


8 12379.0 10165.0 81.09 ID (in) 4.56 Geothermal profile Linear


TVD SS (ft) 5662.0

803p2






4 15607.7 12821.1 45.00 T@midperfs 179 °F

5 16007.7 13049.4 65.006 16465.8 13243.0 65.00 SSSV


ID (in) 4.56 Geothermal profile Linear


TVD SS (ft) 5495.0

803p3






4 7584.6 7494.9 45.00 T@midperfs 198 °F

5 11746.5 10437.8 45.00

6 12046.5 10675.1 30.00 SSSV


8 12369.7 10955.0 30.00 ID (in) 4.56 Geothermal profile Linear9 12884.7 11401.0 30.00 Length (ft) 9.72 Heat transfer coefficient 2

TVD SS (ft) 5659.0




Section 3 Hydrate Remediation Guidelines


Section 3Hydrate Remediation Guidelines

Table of Contents

1.0 INTRODUCTION...........................................................................................................3

1.1 Start-up..............................................................................................................3

1.2 Shutdown...........................................................................................................3

1.3 Steady-state.......................................................................................................4

2.0 HYDRATE CHARACTERISTICS OF THE BONGA FLUIDS ........................................6

2.1 Hydrate Curves..................................................................................................6

2.2 Methanol Treatment Curves...............................................................................9

2.3 Hydrate Plug Dissociation Times .....................................................................12

3.0 HYDRATE FORMATION RISK FOR SUBSEA SYSTEMS.........................................13

3.1 Start-up............................................................................................................16

3.2 Steady-state.....................................................................................................18

3.3 Shutdown.........................................................................................................18

3.4 Aborted Start-up ..............................................................................................19

4.0

HYDRATE PLUG DETECTION AND REMEDIATION ................................................20

4.1 Flowlines/Risers...............................................................................................21

4.2 Wellbore Jumper and Manifold.........................................................................29

4.3 Wellbore/Tree (Upstream of Inhibitor Injection Point) .......................................33

4.4 Umbilicals ........................................................................................................36

4.5 Gas Lift Riser ...................................................................................................38

4.6 Water Injection Wells .......................................................................................43

TABLES

Table 3.1 – Hydrate Temperatures for the Bonga Fluids ........................................................8

Table 3.2 – Hydrate Dissociation Pressure at 4.4°C (40°F) ....................................................9

FIGURES

Figure 3.1 – Hydrate Curves for the Bonga Fluids..................................................................7

Figure 3.2 – Maximum Treatable Flowrate for the 702 Oil with aMethanol Rate of 14gpm ..................................................................................10

Figure 3.3 – Methanol Volume Requirement for 702 Fluid....................................................10








1.0 INTRODUCTION

Bonga is a deepwater development offshore Nigeria in Block OML 118,in approximately 1000m water depth. Shell Nigeria E&P (SNEPCO) will operateBonga in a joint venture with Esso (20%), Elf (12.5%) and Agip (12.5%). Bonga isbeing developed as a subsea network with 1.9 to 9.2km tiebacks to a permanentlymoored Floating Production, Storage, and Offloading vessel (FPSO). Peakproduction rates are anticipated at 225,000 barrels of oil per day, 170MMSCF of gasper day (including recycled riser lift gas) and 100,000 barrels of produced waterper day. Reservoir pressures will be maintained via subsea waterflood wells with upto 300,000 barrels water per day injection capacity.

Bonga consists of four reservoirs (690, 702, 710/740 and 803) with roughly halfof the total reserves in the 702 reservoir. The production system contains subseatrees – enabling Surface Controlled Subsurface Safety Valves (SCSSVs),production chokes, and chemical injection valves – connected via short well jumpersto five subsea production manifolds. The subsea wells are produced through four

pairs of piggable dual pipe-in-pipe flowlines, with externally insulated steel catenaryrisers. Each flowline is connected to a dedicated gas lift riser delivering up to25MMSCF per day.

One of the biggest flow assurance challenges at Bonga is hydrate control. Bonga isexpected to operate under the philosophy of hydrate avoidance during all phases ofoperation – start-up, shutdown and steady state. This is achieved by the followingoperational strategies:

1.1 Start-up

The strategy is to hot oil the flowlines to protect them from hydrates. The strategy forthe trees, well jumpers and manifolds is to inject methanol/Low Dosage HydrateInhibitor (LDHI). In the absence of any methanol injection downhole, the well isramped up as quickly as practicable (notionally 5000 to 7000bpd, depending onwater-cut and pressure) such that the flowing wellhead temperature is greater thanthe hydrate dissociation temperature (approximately 24°C (75°F), but exacttemperature depends on fluid properties and pressure) within 30 minutes to 1 hour.

1.2 Shutdown

The strategy is to blow down the flowlines to a pressure below the hydratedissociation pressure at 4.4°C (40°F) before the cooldown period has expired(notionally 12 hours following production at minimum flowline flowrates of10,000bpd). The well jumpers and manifolds are displaced with methanol, before

the cooldown time has expired, to remove hydrateable fluids and replace them withmethanol. The wellbore is also bullheaded with methanol to the SCSSV in order toprotect it from hydrates during a shut-in that lasts longer than 2 days1.

1 Due to the bare tubing in the wellbore, cooldown times are much larger when the well has been operating atsteady state. Cooldown times are typically of the order of 2 days and hence bullheading must be done only if

shutdown is expected to last more than 2 days. However, the first 100ft of the wellbore must be treated immediatelyupon shut-in, since the cooldown time in this section is limited.






1.3 Steady-state

The strategy is to rely on the heat content of the system to avoid hydrates.The system flows well above hydrate forming temperatures and in fact flows at atemperature that guarantees at least 12 hours to cool down to the hydratetemperature during a shut-in.

However, in spite of the above philosophies, there are four major reasons whichmakes hydrate control at Bonga particularly challenging. These are:

• Low Water Salinity

The expected produced water salinity at Bonga is ~3wt% while typical Gulf ofMexico (GoM) produced water is between 6 to 22wt%. Assuming an averageof 10wt% salinity, the typical GoM system has a subcooling that is 3 to 4°C(6 to 7°F) less than Bonga, which means the system needs to be warmed 3 to4°C (6 to 7°F) less than Bonga to move the system outside the hydrate region.Alternatively, the pressure requirement during blow down is increased by 7 to

10bar (100 to 150psi) for produced brines with a salinity of 10wt%. This hasimportant implications for Bonga since current blowdown calculations with andwithout riser base gas lift indicate that the low blowdown pressure requirementchallenges the limits of the blowdown system (transient report on blowdownhas shown that the minimum blowdown pressure is 10bar±2bar (150psi± 30psi)2.

• Kinetics of Hydrate Formation in Bonga

The kinetics of hydrate formation is difficult to quantify since experimental datafor black oil systems is limited. There are a number of different factors thatdetermine the rate at which hydrates will form, including fluid properties,water cut and flow regime. In the case of the flow loop tests with the Bongacrude, plugging times were all very rapid. In all tests, the fluids were cooledfrom higher temperatures down into the hydrate region, and within a fewdegrees of cooling into the hydrate region the system was plugged.The formation of hydrates was so rapid that the waves in the oil phase(the system was operating in the wavy-stratified flow regime, with a water/oilemulsion) actually froze in place. This rapid hydrate formation has not beenobserved previously. While there are no other experiments done at the sameconditions as these for Bonga, tests with other crude oil systems in the flowloop were more difficult to plug.

• System Limitations

Bonga is expected to start producing water within 18 to 24 months of first oil

and up to a water-cut of 80 to 90%. In order to completely prevent hydrateformation at such high water rates, methanol injection rates of nearly 60 to90gpm are required. However, only 14gpm per well can be injected at Bonga(and it is certainly not practical to inject at rates of 60 to 90gpm). Whenoperating at such high water rates, Bonga depends on a uniquenever-before-used methanol/LDHI cocktail to prevent hydrate formation in thetrees, jumpers and manifolds during start-up. Although, laboratory tests haveindicated that this combination will work at Bonga, it must be understood thatthis strategy has not been field tested.

2 Wade Schoppa ‘Bonga Dynamic Flow Assurance Analysis – Evaluation of Conceptual Design’, February 2001.






• Lack of Operating Experience at Bonga

Experience has indicated that new facilities are prone to a lot of abortedstart-ups and extended shutdowns during their first few years of operation(eg Auger had nearly 253 unplanned shutdowns and 79 planned shutdownsduring its first 22 months of operation, while Mars had nearly 112 unplannedshutdowns and 29 planned shutdowns during its first 8 months of operations)3.

The subsea system is most vulnerable to hydrates during start-up andshutdown (especially before steady-state is attained), and the probability ofoperational errors is greatest during these transient events.

In view of the above reasons, hydrate formation/plugging is a credible risk at Bongaand hence, maximum precautions must be taken to ensure hydrate free operationsat Bonga.

The main purposes of this document are to:

•

Provide guidance to operations and surveillance staff on how to identify hydrateformation in the subsea system

• Provide the first steps of blockage remediation to operators/surveillance staff incase a hydrate blockage forms so that operators/surveillance staff can safelysecure the system and/or prevent the problem from getting worse

• Define safe procedures to start remediation of the subsea hydrate blockagebefore expert help can be summoned

• Provide examples from other fields (within and outside Shell) on how hydratesblockages were formed and were remediated along with important lessons learned

• Provide an evergreen document that can be updated when operating conditions

on the field significantly change (eg when LDHI comes on, LDHI charts shouldbe added) and to include any Bonga-specific hydrate incidents

This document is not meant to:

• Provide detailed procedures on how to remediate hydrates from various parts ofthe subsea system. (We view hydrate plugging as an abnormal event requiringexpert help. Each event is somewhat different and hence routine procedurescannot be written. Although some initial procedures can be initiated from theFPSO, we strongly recommend summoning expert help to complete remediationof a hydrate plug)

• Provide operating strategies to avoid hydrates in the Bonga system. These will

be covered in the POPMs, and control system warnings and interlocks will coversome of the critical operations. In fact, this document assumes that the reader isintimately familiar with Bonga’s operating strategies especially with respect tohydrate management

• Bypass normal operating procedures (POPMs during normal field operations).Some of the recommendations given in this document may be in conflict withthe POPMs and should only be followed if flow has stopped abruptly andhydrate formation is a strong suspect

3 Sada Iyer ‘Analysis for Full Thermal Cycles for Bonga Over a 20-year Period’, April 2003.






This document is structured as follows:

• Paragraph 2.0 describes the hydrate characteristics of the Bonga fluids.This includes hydrate curves, methanol treatment curves, blowdown pressures,and hydrate dissociation times

• Paragraph 3.0 describes the hydrate formation risks for various parts of thesubsea system

• Paragraph 4.0 describes remediation methodologies for each section of thesubsea system and contains guidelines for remediating hydrates once a plugis formed

• Appendix 3A gives a table of all relevant pressure tags that are of interest interms of hydrate detection and remediation

• Appendix 3B describes several different case studies involving hydrate plugformation and remediation. The case studies used were chosen because of their

general similarity to Bonga• Appendix 3C gives a listing of all abbreviations used in this report

2.0 HYDRATE CHARACTERISTICS OF THE BONGA FLUIDS

This paragraph is intended as a summary of the information used in determining thehydrate curves and methanol requirements4.

The hydrate curves are presented for all f luids to give some indication of the relativehydrate risk of each of the different oil systems. Methanol rates are only included forthe 702 oil (best-case) and the 710 oil (worst-case) to bracket the potential methanolrequirements at Bonga.

2.1 Hydrate Curves

The hydrate curves define the stability of hydrates in the Bonga system. The hydratecurves are dependent on the salinity of the produced water. Hydrate curves areincluded for a produced brine with a salinity of 3wt%. Due to the waterflood,the expected salinity of the produced water is about 3wt%, hence Figure 3.1 andTable 3.1 should be used in determining if the system is operating in thehydrate region.

For example, if the operating conditions are 200bar (2900psi) and 20°C (68°F),all four fluid systems are in the hydrate region (refer to Figure 3.1). If the pressure isdecreased to 150bar (2175psi), the 690 and 702 fluids are no longer in the hydratestability region, but the 803 and 710 fluids are still in the hydrate region. If thepressure is further reduced to 100bar (1450psi), the conditions are such that allfluids are now out of the hydrate region. Alternatively, if the temperature is increasedfrom 20°C (68°F) to 25°C (77°F) and the pressure remains constant at 200bar(2900psi), all four fluid systems are in the non-hydrate region.

4

For a more detailed description, refer to Peters, D, et al ‘Bonga Hydrate Risk Assessment and ManagementStrategy’, report OG.03.80057, 2003.






OPRM20030302D_063.ai

Hydrate

Stability

Region

Non-hydrate

Region

Temperature (ºF)

42

690

720

803

710/740

32 52 62 72 82

P r e s s u r e ( b a r )

P r e s s u r e ( p s i )

Temperature (ºC)

0 5 10 15 20 25 30

500

0

1000

1500

2000

2500

3000

3500

4000

4500

5000

0

50

100

150

200

250

300

Figure 3.1 – Hydrate Curves for the Bonga Fluids






Pressure(bar)

690HDT(°C)

702HDT(°C)

710/740HDT(°C)

803HDT(°C)

8.6 0.1 -0.4 3.1 1.6

11.6 2.2 1.7 5.2 3.8

15.7 4.3 3.8 7.3 6.0

21.1 6.4 6.0 9.5 8.2

28.5 8.5 8.1 11.6 10.3

38.4 10.6 10.3 13.6 12.5

51.7 12.7 12.4 15.6 14.5

69.7 14.6 14.4 17.5 16.5

94.0 16.5 16.3 19.3 18.3

126.7 18.3 18.1 20.9 20.0

170.7 20.0 19.9 22.5 21.6

230.2 21.2 21.5 24.1 23.2

310.3 22.5 22.6 25.5 25.0

Pressure(bar)

690HDT

(°F)

702HDT

(°F)

710/740HDT

(°F)

803HDT

(°F)

125 32.1 31.2 37.7 34.8

169 35.9 35.0 41.4 38.8

227 39.7 38.9 45.2 42.7

306 43.5 42.7 49.0 46.7

413 47.4 46.6 52.8 50.6

556 51.1 50.5 56.5 54.4

750 54.8 54.2 60.1 58.2

1011 58.4 57.9 63.6 61.7

1363 61.7 61.3 66.7 64.9

1837 64.9 64.6 69.7 68.0

2476 68.0 67.7 72.4 70.8

3338 70.2 70.7 75.3 73.8

4500 72.5 72.7 77.9 76.9

Table 3.1 – Hydrate Temperatures for the Bonga Fluids






2.1.1 Blowdown and Plug Remediation Pressures

An important aspect of the hydrate equilibriums curve is the Hydrate DissociationPressure (HDP) at the ambient seafloor temperature of 4.4°C (40°F). This is thepressure that will determine the blowdown requirement and the hydrate plugremediation pressure.

One of the key components to hydrate control at Bonga is the ability to blow downthe flowlines and move the flowline conditions outside of the hydrate region. Table 3.2shows the hydrate equilibrium pressure at 4.4°C (40°F).

Well HDP(psi)

HDP(bar)

690 202 13.9

702 216 14.9

710/740 130 9.0

803 162 11.1

Table 3.2 – Hydrate Dissociation Pressure at 4.4°C (40°F)5

The hydrate dissociation pressure at 4.4°C (40°F) is also important in the process ofhydrate plug remediation. The flowline pressure must be reduced below the HDP ofthe particular fluid in order for the hydrate plug to melt. During plug remediation,the flowline pressure should be reduced as low as possible to increase the rate atwhich the plug melts. If a flowline has fluids from more than one reservoir, then use

the fluid with the lowest HDP.

2.2 Methanol Treatment Curves

During early life, the hydrate strategy is to treat all produced water with methanol.Figures 3.2 and 3.4 show the highest treatable water cut that can be protected withthe 702 and the 710 fluids. Figures 3.3 and 3.5 give the methanol requirements in amore general format that can be applied to any flowrate. The minimum flowrateduring start-up is either 5000blpd or 7000blpd, depending on the well. At a givenpressure and flowrate, these figures can be used to determine how much water canbe treated. This is important in determining when to switch from the methanol-onlystrategy to the methanol/Kinetic Hydrate Inhibitor (KHI) strategy.

For example, if the 702 fluid is being produced at a rate of 5000blpd, the flowlinepressure is 150bar (2175psi) and the water cut is greater than 20%, then methanolalone (at 14gpm) is not enough to protect against hydrate formation and it is time toswitch to the methanol/KHI strategy.

Similarly, if the flowline is producing the 710 fluid at a rate of 5000blpd and apressure of 150bar (2175psi), then the highest water cut that can be treated is 17%.

5 The hydrate equilibrium values for fresh water have been used. These pressures are required for hydrate plug

remediation but give slightly conservative estimates for the blowdown pressure required to prevent hydrateformation.






OPRM20030302D_049.ai

70

60

50

40

30

20

10

Pressure (bar)

Pressure (psi)

0 50 100 150 200 250 300

0 500 1000 1500 2000 2500 3000 3500 4000 4500

0

M a x

i m u m

T r e a

t a b l e % W a

t e r

C u

t

Fluids can be

treated with

methanol

Fluids cannot

be treated with

methanol alone

5000blpd

7000blpd

Figure 3.2 – Maximum Treatable Flowrate for the 702 Oilwith a Methanol Rate of 14gpm

OPRM20030302D_050.ai

0.80

0.70

0.60

0.50

0.40

0.30

0.20

% Water Cut0 5

34.5bar (500psia)

10 15 20 25 30 35 40

0.10

m 3

M e

t h a n o

l / m 3 W a

t e r

241.3bar (3500psia)

68.9bar (1000psia)

317.2bar (4600psia)

103.4bar (1500psia)

Figure 3.3 – Methanol Volume Requirement for 702 Fluid








2.3 Hydrate Plug Dissociation Times

Figures 3.6 and 3.7 are intended to give approximate hydrate plug remediationtimes as a function of the pressure. In this case, approximate means an order ofmagnitude estimate. The intent of these predictions is to indicate if the plug meltingtime is days, weeks or months. This model has been compared with availableinformation on hydrate plug removal and was found to give reasonable estimates ofthe plug melting time6.

If the predicted dissociation time is a week, then the plug can be expected to take1 week, plus or minus a few days. If the plug is predicted to take a month to melt,then the plug can be expected to take 1 month, plus or minus a week.

These predictions are the amount of time required to establish pressurecommunication across the plug, not the time required to completely melt the plug.The two-sided depressurisation case (applicable generally to looped flowlines)assumes that there is a small (~3.5bar (50psi)) pressure drop across the plug.

The one-sided case (applicable generally to wellbore jumpers and wellbores)assumes a pressure drop of > 70bar (1000psi) across the plug. These figures weregenerated for the Bonga flowlines (10in and 12in), but similar results were obtainedfor the melting times of hydrate plugs in a line with a 5in diameter.

As was the case with the methanol predictions, the 702 and 710 reservoir fluids areused in the prediction of the hydrate remediation times. These two fluids bracket thepossible remediation times that are expected for Bonga.

OPRM20030302D_051.ai

Downstream Pressure (psia)

Downstream Pressure (bar)

1-sided dissociation

R e m e

d i a t i o n

T i m e

( D a y s )

H y

d r a

t e D i s s o c i a

t i o n

P r e s s u r e

6 7

87 100 113 126 139 152 165 178 191 204 217

8 9 10 11 12 13 14 150

5

10

15

20

25

30

2-sided dissociation

Figure 3.6 – Hydrate Remediation Times for the 702 Reservoir Fluid,Dashed Curves 12in PIP Flowline, Solid Curves 10in PIP Flowline

6 Walsh et al ‘Hydrate plug dissociation model’, EP 2001-3018, June 2001.






OPRM20030302D_065.ai

Downstream Pressure (bar)

H y d r a t e D i s s o c i a t i o n P r e s s u r e

Downstream Pressure (psia)

30

5

10

15

20

25

3044 54 64 74 84 94 104 114 124 134

4 5 6 7 8 9

R e m e d l a t i o n T i m e ( D a y s )

1-sided dissociation 2-sided dissociation

Figure 3.7 – Hydrate Remediation Times for the 710 Reservoir Fluid,Dashed Curves 12in PIP Flowline, Solid Curves 10in PIP Flowline

3.0 HYDRATE FORMATION RISK FOR SUBSEA SYSTEMSWhen assessing the hydrate risk in the subsea system, there is an importantdistinction to be made between hydrate formation and the formation of a hydrateplug. In an uninhibited system, if the subsea temperature and pressure are in thehydrate formation region, hydrates will form. The formation of a solid hydrate plug isnot predictable but, from laboratory and field experience, it is most likely to occurduring a restart. If a plug is not formed immediately upon restart, continuedoperation inside the hydrate region greatly increases the risk that sufficient hydrateswill accumulate and lead to the formation of a plug. How long the system canoperate in the hydrate region before a plug is formed depends on a number offactors, including the kinetics of hydrate formation and the ‘stickiness’ of the hydrate

particles that are formed. Unfortunately there is no accurate means of predictingwhen the hydrate particles will accumulate into a plug, but laboratory testing with theBonga fluids showed the rapid formation of hydrate plugs once the system wasinside the hydrate region.

There are several examples of GoM systems that operate in the hydrate regionwithout forming hydrate plugs even though hydrates are formed. However, theseexamples are typically gas condensate systems. For example, at South-east Tahoe,the formation of hydrates is detected as an increase in the pressure drop across theflowline. Once the pressure drop increases sufficiently, the production rate iscurtailed while the methanol pumps continue to run at full flowrates to flush thehydrates out of the flowline. This strategy can be used at South-east Tahoe sinceproduction is at the end of the field life and the consequences of forming a plug arenot severe (limited loss of production).








Event

Subsea SystemStart-up

SteadyState

ShutdownAbortedStart-up

Wellbore

Trees

Well Jumper

Production Manifold

Flowlines

Riser

Gas lift Sled/Umbilicals

Umbilicals

Water Injection Flowlines

Water Injection Tees

Water Injection Trees

High Risk Medium Risk Low Risk

Figure 3.8 – Risk Identification for Hydrate Plugging in Different Parts of the

Subsea System for Bonga

For the purposes of this document, we define the risk levels as follows:

High Risk

The system design itself does not guarantee protection against hydrates but hydratecontrol is achieved by a combination of design and active strategies. Examplesinclude the tree and jumper where the addition of methanol/LDHI is used to preventhydrates during start-up. If a methanol pump fails, it could lead to the formation ofhydrates. Another example is that for the wellbore, there is not the ability to treatwith methanol/LDHI to prevent hydrates during start-up and instead a strategy ofminimising the time of operation within the hydrate region by rapid production ramp

up and ‘outrunning’ the formation of a hydrate plug is used.

Medium Risk

The system design protects itself from hydrates, but that protection could be erodedby operational decisions. An example of this is deciding to start up into a warmflowline (without hot-oiling) that has partially cooled down. An aborted start-up at thisstage would leave the flowline in a state with an unknown cooldown time andpossibly allow the liquids in the system to cool inside the hydrate region prior tofollowing the procedure for a ‘normal’ aborted start-up.








The hydrate risk in the tree, well jumper and manifold is largely mitigated by the useof chemicals. During early life, methanol can be injected in sufficient quantities toprevent hydrates, so the only risk here is due to the failure of the methanol pumps.In this case, there are cold untreated fluids coming from the wellbore (possibly with

hydrates already present) flowing into a cold untreated section with many areaswhere water can accumulate and this greatly increases the risk of hydrate plugformation. If adequate measures are taken to ensure pump reliability, then this riskis decreased. However, based on the definition of risk, this is considered a high risksince the insulation alone does not provide protection from hydrates duringrestart and transition to steady-state, but instead hydrate mitigation relies uponchemical treatment.

Similarly, the chemical umbilical lines (especially flying leads) are susceptible tohydrates due to pressure fluctuations that occur during start-up (eg due to slugging).This might lead to backing up of chemicals and production fluids inside the umbilical,and the formation of hydrates.

The water injection trees and upper wellbore are also considered to be high risk.Since the water injectors are completed into the oil zone (and can flow under theirown pressure), gas can migrate past the SCSSV (towards the tree) during anextended shut-in and can form hydrates with the water in the well. This risk isgreatest when waterflood has just started for the first time and the well is shut inwithin a few days of initial start-up. This is because the gas front in the reservoirwould not have been pushed away from the wellbore and hence the gas will tend tomigrate back into the wellbore. As more and more water is injected into thereservoir, the risk continues to decrease as the gas front in the reservoir is pushedaway from the water injection wellbore (hence, the gas takes much longer to migrateback into the wellbore). This risk is difficult to quantify since the probability of gasmigration into the wellbore is unknown. Any hydrates that are formed will be a resultof these gas bubbles migrating up the wellbore. In the absence of any agitation, acolumn of hydrate bubbles will be established. With time, these hydrate bubbles willbe pushed up to the tree where they will accumulate and may also form deposits.The fate of these bubbles is open to speculation, but could easily collapse during theshut-in or the restart to form a hydrate ‘slush’ with the excess water in the wellbore.Depending on the volume of gas, slushy hydrates and deposits in the wellbore uponrestart, it may or may not be enough to stop flow and prevent the water frompushing this hydrate to below the SCSSV, where they will melt.

Even excluding this scenario of gas leaking past the SCSSV, gas and oil migrationwill pose a risk at start-up as the valve is opened with oil or gas trapped beneath itunless downward flow is established in a timely fashion. It should be emphasised

that any hydrate deposits that form in the tree or just beneath the tree in either casewill likely not be quickly melted even if flow is established since the incoming watertemperature is expected to be no higher than about 60°F and at pressures still withinthe hydrate region. Because of the uncertain nature of gas migration in the waterinjection system and the inability to inject any chemicals into the wellbore to preventor remediate hydrates, then the risk is considered high for the water injection treesand upper wellbore. Since this is a problem that occurs during shut-in and canprevent start-up, this risk is included in both the ‘start-up’ and ‘shutdown’ categoriesfor the sake of completeness.






Medium Risk

None.

Low Risk

Flowlines and risers have a low risk of hydrate formation during start-up since theywill always be started up with hot-oiling (or will be started up before their cooldowntime has expired). Hot-oiling ensures that the flowlines are always above theHydrate Dissociation Temperature (HDT) and have a guaranteed 12-hour cooldownto HDT.

Water injection flowlines and water injection tees have low risk of hydrate formationdue to the low probability of any gas migration to these parts. Any oil or gas thatmigrates into the well is likely to accumulate at the tree.

As per current Bonga procedures, the gas lift riser will be flushed with methanol(to displace potential hydrocarbons that might have backed into the gas lift valve

sleds and portions downstream of it towards the flowline) during shutdown.Moreover, the gas injection side is higher in pressure so as to prevent backflow ofhydrocarbons into the gas lift system (achieved by means of an orifice plate whichensures higher upstream pressure).

3.2 Steady-state

High Risk

None.

Medium Risk

None.

Low Risk

All sections of the Bonga subsea system are under low risk of hydrate formation dueto the design of the Bonga system. By design, every part of the subsea productionsystem is insulated to operate above hydrate dissociation temperatures and also toprovide 8 to 12 hours of cooldown outside of the hydrate region in case of a shut-in(8 hours for wellbore and 12 hours for the rest of the system). Similarly, we do notexpect any kind of backflow of hydrocarbons into umbilicals, water injection systemor the gas lift system during steady-state.

3.3 Shutdown

Shutdown risks are tricky to capture since any problem that occurs during shutdownwill be manifested only when we try to restart the system. However, this paragraphattempts to capture possible hydrate problems that are solely the result of a shut-inand not necessarily problems that occur during start-up.

High Risk

The highest risks at shutdown are hydrate formation within chemical umbilical lines,gas lift umbilical lines and water injection trees due to backflow of hydrocarbons.






In Bonga, the control system is designed such that the chemical valves at the treesare instructed to close as soon as the wells shut in. Similarly, the gas lift valves onthe gas lift sled are also designed to be shut in as soon as the FPSO flowlineboarding valves shut in. However, there has been past experience wherein hydrate

formation has occurred due to backflow. An example of this is the MalampayaProject wherein methanol lines were plugged with hydrates due to backflow from theproduction system into the umbilical.

Gas migration from the water injection reservoirs can also result in hydrate formationin the water injection trees. Gas migration can occur either during shut-in after ashort period of operation (say within the first few days of start-up when thehydrocarbon front has not been pushed far enough into the reservoir) or during along extended shut in (when gas eventually migrates back, as in the case of theTerra Nova Field in Canada)8.

The gas from the reservoir can migrate past the SCSSV towards the trees and canresult in plug formation.

Medium Risk

None.

Low Risk

All other parts of the subsea system have a low risk with respect to hydrateformation due to the fact that the Bonga production system is designed with aminimum 12-hour cooldown time after shut-in. Failure to protect the subsea sectionsagainst hydrate formation greatly increases the risk of forming a hydrate plugupon restart.

3.4 Aborted Start-up

High Risk

The aborted start-up has the highest risk of hydrate formation of any of theoperations at Bonga. The wellbore, well jumper, production manifolds, gas lift sled,umbilicals and water injection trees are all particularly susceptible to hydrates duringan aborted start-up.

The risk is similar to that of the start-up case (ie wellbore, well-jumper, productionmanifold, chemical umbilicals and water injection tree are all at high risk).In addition, the gas lift umbilical also becomes a high-risk candidate with respect tohydrate formation. This is due to the fact that the water-heated portion of the GasLift Riser (GLR) system below the GLR valves takes some time to reheat once the

system has cooled thus leaving the system vulnerable to hydrates.

The water injection trees are at a high risk because any gas that may have migratednear the wellbore and/or accumulated beneath the SCSSV during the shut-in wouldnot be moved very far during the initial start-up. This means that less time isrequired for the gas to migrate back to the wellbore or past the safety valve. Coldfluids have been moved further down into the wellbore where the pressure is higherand there is a greater likelihood of ‘seeing’ the gas as it bubbles up the wellbore.

8 At Terra Nova, this problem with gas migration only appeared during the first 6 weeks of water injection. However,

Terra Nova has a different water injection strategy (involving alternating periods of injection followed by extendedshut-in) and the properties of the reservoir are different than at Bonga.






Medium Risk

The flowlines are designed in such a way that they have a minimum of 12 hourscooldown after a shut-in from steady state. However, if a well has a warm start into aflowline during the cooldown period and this well has an aborted start-up, it is notvery easy to estimate the resulting cooldown time. This uncertainty in the cooldowntime necessitates identifying hydrate formation as a medium risk.

The second scenario is starting up a cold well into a flowline, which has just beenhot-oiled. The hot-oiling ensures that the flowline has a 12-hour cooldown prior tostarting up the well and also that the cold fluids from the well do not reduce theflowline temperature to below the HDT. However, an aborted start-up on this wellwill result in not knowing the exact temperature of the flowline and thus result in anuncertain cooldown time (and hence a hydrate risk).

Low Risk

The risk in the water injection flowlines/tees is low due to the low probability of gas

migration from the reservoir through the SCSSV and then past the tree.

4.0 HYDRATE PLUG DETECTION AND REMEDIATION

As seen in Figure 3.8, every portion of the subsea system (except for waterfloodflowlines and tees) is at risk with respect to hydrate formation either during start-up,shutdown or during an aborted start-up. Based on our current knowledge ofhydrates with respect to Bonga, it is unlikely that hydrate formation will be detectedin the system before a hydrate plug is formed. Therefore, this paragraph assumesthat a hydrate plug has formed and provides guidance for determining approximatelywhere the plug is in the subsea system and for remediating hydrate plugs.Lastly, there are examples for hydrate detection and remediation drawn fromdifferent fields from various parts of the world (Shell and non-Shell).

In this document the pressure measurement is the crucial parameter in determiningthe location of the hydrate plug. However, it should be noted that the temperaturemeasurement is important in determining if the system is in the hydrate formationregion. The temperature and pressure must be in the hydrate region before hydratescan form. Figure 3.1 or the Bonga tool can be used to determine if the systemtemperature and pressure are in the hydrate region. If the system is operatingoutside of the hydrate region and a blockage is formed, then the cause is somethingother than hydrates.

The location of hydrate plug can only be determined with limited accuracy. In the

case of Bonga (and the guidelines in this document), the hydrate plug position canbe determined to be between a particular pair of pressure sensors. Although notdiscussed in this document, there are other methods to determine a more exact pluglocation (eg ultrasonic sensors). The pressure sensors at Bonga can localisethe plug to specific sections of the subsea system, including the flowline, riser, jumper/manifold or the wellbore. For the hydrate remediation guidelines presented inthis document, this gross determination of plug location is sufficient. If the pluglocation needs to be determined more exactly, expert guidance is suggested.

Information is also presented for hydrate plugs that form in umbilical lines and thewaterflood lines. These lines are not equipped with instruments that help to locateand remediate a hydrate plug, as are the other portions of the subsea system.In these cases, more general information will be given.






4.1 Flowlines/Risers

Although the risk for hydrate formation in the flowline has been determined to below, it is important to have guidelines in place to remediate a hydrate plug in theflowline. The loss of a flowline can affect production from multiple wells (all wellsfrom that manifold), which has a significant impact on deferred productionand revenue.

4.1.1 Hydrate Plug Formation

Flowlines (Except PFL 03/04)

The most likely time that a hydrate plug will occur (or be detected) in theflowline/riser section is during a restart following an aborted start-up. Plugs mayoccur during the shutdown period, but they will not be detected until the flowline isrestarted. A hydrate plug during steady-state operation is considered unlikely sincethe flowing temperatures are outside of the hydrate region. However, the indications

of having formed a hydrate plug will be the same for a restart and steady-state flow.Figure 3.9 gives a simplified schematic of the flowline with the hydrate plug alongwith the affected subsea components. For simplicity, this figure can be used for anyflowline pair (except PFL 03/04). In all cases, Flowline 1 (not necessarily PFL 01)refers to the flowline with a hydrate plug and Flowline 2 (not necessarily PFL 02)refers to the second flowline in the pair that does not have a hydrate plug.

During production, the Pigging Isolation Valve (PIV) is closed and a hydrate plug inFlowline 1 results in a pressure increase at the manifold (and at the tree of the wellsflowing into Flowline 1) to the Shut-in Tubing Pressure (SITP). The pressure at thedownstream end of the plug (measured at the riser base and topsides of Riser 1)decreases. The plug in Flowline 1 does not affect Flowline 2, since the flowlines are

isolated when the PIV is closed.The lack of flow in the flowline also results in a decrease in flowline temperatures,however, due to the flowline insulation, this temperature decrease may be tooslow to recognise over the short time-scale that the plug is expected to form.Thus pressure measurements will be the primary means of detecting a hydrate plug.

Plug Formation in Flowlines (except PFL 03/04)

Refer to schematic in Figure 3.9 for relevant locations of pressure gauges.Use Appendix 3A to determine the pressure tags for the relevant pressure sensors.

• Increase in pressure at manifold (Flowline 1 side [Pm-1]) and at the tree

(wells flowing to Flowline 1) to SITP

– Manifold pressure and tree pressure upstream and downstream of thechoke read the same on the affected wells

• Decrease in pressure at the base of Riser 1 (Prb-1) and topsides of Riser 1

• Decrease in Riser 1 temperature topsides

– Due to flowline insulation, the temperature decrease may not readilyobserved








OPRM20030302D_059.ai

Manifold(PM3)

Flowline 2

Flowline 1

Manifold(PM4)

Manifold(PM4)

Pressure

Pm-1

PIV

Manifold(PM3)

Pressure

Flowlinesto FPSO

PFL 05/06

Hydrate Plug

Figure 3.10 – Schematic of Hydrate Plug in Flowline (PFL 03/04)

Riser

A hydrate plug that forms in the riser (Riser 1) will show the same indications as inthe flowline except for the pressure reading at the base of Riser 1. In this case, boththe manifold pressure (Flowline 1 side [Pm-1]) and the riser base pressure (Riser 1 [Prb-1])increase to the SITP. There will still be a decrease in pressure at the downstreamend of the plug (measured at Riser 1 topsides). The hydrate plug in Riser 1 will notaffect Flowline 2, since the PIV is closed.

Plug Formation in Riser

Please refer to the schematic in Figure 3.11 for relevant locations of pressure

gauges:• Same indication as in the flowline

– Pressure also increases at the base of the Riser 1 to SITP

OPRM20030302D_060.ai

Fig 3.11 Schematic of Hydrate Plug in Riser

Subsea

Manifold

TopsidesPressure

Riser BasePressure

ManifoldPressure

Riser 1

Hydrate Plug

Prb-2

Pm-2

Pm-1Prb-1

PIV

Flowline 2

Flowline 1

Riser 2

Figure 3.11 – Schematic of Hydrate Plug in Riser






4.1.2 Hydrate Plug Remediation

This document is only meant to help provide guidelines for relatively simple cases.Cases involving hydrate plugs in both flowlines are much more complex in terms ofsafely performing a remediation and hence are not discussed in this document.In these cases additional support is recommended before any plug remediationprocedures are attempted.

Flowlines (Except PFL 03/04)

The following discussion is based on Figure 3.9 and the convention that the hydrateblockage is in Flowline 1 (not necessarily PFL 01), and that Flowline 2 (notnecessarily PFL 02) does not have a hydrate blockage. Refer to Figure 3.12 for aflowchart representation of the procedures presented in this section.

Since the precise location of the blockage in Flowline 1 is not known,depressurisation of the flowline from both ends is the safest option. Four pressuresare monitored during this process:

• Prb-1, the pressure at the riser base of Flowline 1

• Pm-1, the pressure at the manifold of Flowline 1

• Pm-2, the pressure at the manifold of Flowline 2

• Prb-2, the pressure at the riser base of Flowline 2

Step 1 – Shut In Flowline 1

Once it has been determined that Flowline 1 has a blockage, the following stepsshould be followed as soon as possible:

• Shut in Flowline 1 by closing the topsides Flowline 1 shut-off valve

• Shut in the wells feeding Flowline 19

• Secure all wells flowing to Flowline 1

– Displace wellbore and jumper with methanol

Step 2 – Set-up for Blowdown

Configure topsides piping to allow blow down of Flowline 2 to the flare, and to allowblow down of platform end of Flowline 1 through the Low Pressure (LP) separator.

Step 3 – Shut In Flowline 2 Wells

Shut in Flowline 2 and the wells feeding Flowline 2 such that the pressure Pm-2 at the

subsea manifold is within 14bar (200psi) of Pm-1, but the smaller the pressure dropthe better. The pressure gradient across the manifold should be small in the eventthat the plug is near the manifold. A straightforward way to set a safe pressure at

Pm-2 is as follows:

(1) Shut in Flowline 2 by closing a topsides valve.

(2) Allow the pressure at the manifold, Pm-2, to rise to close to Pm-1, and then shut inthe wells feeding Flowline 2.

9 After the wells feeding flowline 1 have been shut in, the pressure at the manifold, Pm-1, is expected to be 500psi to

3000psi greater than the pressure at the riser base, Prb-1. The difference between these two pressures (Pm-1 – Prb-1) isthe pressure across the blockage, Pab. Pab times the pipeline internal diameter is the driving force on the blockage.








The case studies given in Appendix 3B Paragraph 2.0 give several examples whereplugs have been safely remediated by depressurising the flowline at both ends.These examples are meant to illustrate the wide range of conditions that lead tohydrate formation and the various locations (within the flowline) where a plug can

form. In all cases, the pressure in the flowline was safely reduced below the HDPand the plug melted. Particular note should be paid to the very well-documentedcase study of the ARCO hydrate plug. This plug formed in an insulated line and took23 days to remediate once the pressure was reduced, and further reinforces that theremoval of a hydrate plug is not a fast process and may take many days.

Riser

Remediation of a hydrate plug in the riser (Riser 1) can be handled in the same wayas in the case of a hydrate plug in one of the flowlines. However, extra cautionneeds to be taken to ensure that the pressure at the base of Riser 1 is less than thepressure topsides at Riser 1.

In this case, it may also be recommended to maintain a high pressure downstream(between hydrate plug and topsides) of the plug and to do a one-sideddepressurisation by aggressively blowing down Flowline 2. This will ensure that anyplug movement is away from the FPSO. Figure 3.13 presents a flowchart for plugremoval in the riser.

Note: Figure 3.13 states a pressure drop limitation across the plug of 28bar(400psi). This pressure drop may be exceeded if one-sided depressurisationis used.






Is therepressure communication

across plug?

Make sure pressure gradient

across plug does not exceed

14bar (200psig), measured as the

difference between the manifold

pressure (Pm-1) and the pressure

at the base of the riser 1 (Prb-1)

Begin blowdown of Flowline 2

(flowline without hydrate plug)

to flare. Blow down Flowline 1


to LP separator

Close in all wells flowing

to affected manifold

Use riser gas lift to further reduce

the pressure in the flowline

Maintain pressure drop of 7 to 14bar

(100 to 200psig) across the plug

Monitor pressure at the base

of riser 1 (Prb-1) for signs of

pressure communication

(eg sudden pressure decrease)

If possible, use gas lift to

further reduce the pressure

(whilst still maintaining an

acceptable pressure drop

across the plug)

Inject 50 barrels of methanol into

the flowline through the manifold

(via MIV 2). Start dead-oiling

(or hot-oiling if available) the flowline

from Flowline 2 to Flowline 1

Open PIV to equalise pressure

in Flowlines 1 and 2

OPRM20030302D_052.ai

Is themanifold pressure

below HDP?

Treat jumper and wellbore bydisplacing with methanol If hydrate plug is in PFL 03/04, then:(1) Close in all wells flowing to PM 3.

(2) Make sure the PIV at PM 3 is

closed.

(3) Use WSV to route flow from

Flowline 1 to either PFL 05 or 06.

(4) Route flow from Flowline 2 to

another flowline (PFL 06 or 05).

No

Yes

No

Yes

Figure 3.12 – Remediation Procedure for Hydrate Plug in Flowline






Is therepressure communication

across plug?

Ensure pressure gradient

across plug does not exceed

28bar (400psig), measured as the

difference between topside of

riser 1 and the base of riser 1

Begin blowdown of Flowline 2


to flare. Blow down Flowline 1


to LP separator

Close in all wells flowing

to affected manifold

Use riser gas lift to further reduce

the pressure. Note that this only

applies to riser 2

Maintain pressure drop of 7 to 14bar

(100 to 200psig) across the plug

Monitor pressure for signs of

pressure communication across

plug, either to decrease topsides

(riser 1) or a sudden pressure

increase (spike) at the base of

riser 1 (Prb-1)

Inject 50 barrels of methanol into

the flowline (via the gas lift riser).

Start dead-oiling the flowline

from Flowline 2 to Flowline 1

Open PIV to equalise pressure

in Flowlines 1 and 2

OPRM20030302D_053.ai

Is thepressure at the base

of riser 1 (Prb-1) belowHDP?

Treat jumper and wellbore by

displacing with methanol

No

Yes

No

Yes

Figure 3.13 – Remediation Procedure for Hydrate Plug in Riser






4.2 Wellbore Jumper and Manifold


A hydrate plug in the jumper or manifold prevents flow from a particular well into theflowline. When a plug is formed in the jumper (refer to Figure 3.14) or manifold,the pressure at the tree increases to the SITP even though the choke is open.The pressures upstream (production pressure) and downstream (outlet pressure)of the choke are the same. The downhole pressure increases to the Shut-inBottomhole Pressure (SBHP) and the pressure at the manifold begins to drop off.Temperature also begins to decrease at the tree, but this decrease may not benoticeable (since it will occur slowly).

Note: The temperature must be in the hydrate formation region in order to formhydrates.

When there is more than one well flowing to a single flowline, the same indications

of hydrate formation are present, including the decrease in pressure at the manifold.The manifold pressure continues to see contributions from the other wells so thepressure does not decrease as low as it would with only one well flowing to themanifold, but the change in pressure is significant enough to be detected.

Plug Formation in Jumper/Manifold

• Pressure at tree (production and outlet pressure) increases to SITP

– Pressure upstream (production pressure) and downstream (outlet pressure)of the choke equalise

• Downhole pressure increases to the SBHP

• Reduction in manifold pressure and temperature

– The magnitude of these decreases depends on the number of wells flowinginto the flowline

OPRM20030302D_066.ai

Hydrate Plug

Manifold

Manifold

PressureDownhole

Pressure

Flowlines

to FPSO

Outlet

Pressure

Production

Pressure

Choke

SWV

PIV

WSV

WSV

PWV

ASV PSV

XOV

AWV

PWV

A n n u l u s

Methanol Line

SCSSV

MIV 2

MIV 1

Figure 3.14 – Schematic of Hydrate Plate in Jumper







If a plug is formed in the jumper, two-sided depressurisation is not possible.One-sided depressurisation may be used to melt the plug, but due to safetyconsiderations, it should not be attempted unless the methanol remediationstrategy fails.

In order for methanol to melt the plug, the methanol must contact the hydrate.Due to the shape of the jumper section, it may not be possible to get methanol tothe hydrate surface. In order to have a reasonable chance of getting methanol to thehydrate surface, the methanol should be ‘rocked’ into the jumper. This strategy hasproved successful in the wellbore (refer to the Popeye case study), but has not beentried in a jumper.

The flowchart shown in Figure 3.15 gives the steps to follow in order to use thismethanol ‘rocking’ procedure. The first step is to isolate the affected jumper from themanifold by closing the WSV. Production from the wells flowing to the affected

manifold does not need to be stopped. If the methanol strategy does not work,then the production from the other wells will need to be stopped.

Methanol should first be bullheaded into the wellbore to protect that area againsthydrates. Once the well is protected, all valves should then be closed except for theSCSSV, Production Master Valve (PMV) and Sacrificial Wing Valve (SWV) and thechoke. Use MIV2 to inject methanol into the jumper. Once the pressure (productionand outlet) reaches a level that is 21bar (300psig) higher than the SITP, close MIV2.

Before initiating ‘rocking’, ensure that the SWV is open.

A ‘rock’ has three steps:

(1) Close the Production Wing Valve (PWV). Conduct a blockage-breach test

every four rocks or if a blockage breach has been indicated in Step 3 (refer tothe discussion below).

(2) Inject methanol through MIV2. This should increase the outlet pressure.Stop injecting methanol (close MIV2) when the outlet pressure is greater thanthe SITP by 300psi.

(3) For 60 to 90 minutes, monitor for blockage breach. Blockage breach may beindicated in several ways (refer to the discussion below). If the blockage is notbreached, then open PWV (and drop the outlet pressure to the downholepressure).

‘Rocking’ the methanol into the jumper is achieved by repeating these three stepsmany times. After every four ‘rocks’, a blockage-breach test (discussed below)should be conducted.

The success of this method depends on the proximity of the hydrate plug to the tree.Since the pressure increase in the line will be small in relation to the SITP,the volume of methanol that is injected during each pressure cycle will be small.Only for cases when the plug is reasonably close to the tree will this method work.






Blockage breach may be indicated by a rapid pressure reduction during methanolinjection or during the monitoring period; by a slow but significant pressure reductionduring the monitoring period; or by a significant increase in the amount of methanolthat is injected during Step 2 (over the amount injected in earlier ‘rocks’ to the

same pressure). After every four ‘rocks’ or after indication of a blockagebreach, a blockage-breach test should be conducted in Step 1 of a ‘rock’. Theblockage-breach test is:

(1) After completion of Step 3 of a ‘rock’ and closing of PWV, open WSV andobserve the well outlet and manifold pressures for 15 minutes.

(2) If the well outlet pressure remains constant and above the manifold pressure,then the blockage has not been breached – end of test.

(3) If the well outlet pressure drops significantly and drops to the manifoldpressure then blockage breach is indicated. Proceed to blockage-breachconfirmation (Step 5).

(4) If the well outlet pressure is about equal to the manifold pressure prior toopening WSV in Step 1, then it may not be clear whether the system behavesas described in Step 2 or Step 3. If this is the case, or it is not clear as towhether or not the blockage is breached for whatever reason, then MIV2 shouldbe opened very briefly. If opening MIV2 does not raise the outlet pressure,or the outlet pressure rises and then decays back down (within 15 minutes)too near the manifold pressure, then blockage breaching is indicated –proceed to Step 5. Otherwise, this is the end of the test.

(5) Confirm blockage breach by opening MIV2 (allowing methanol to flow into the jumper) and confirming that the outlet pressure does not increase. Continueuntil one jumper volume of methanol has been injected and until there is no

evidence of flow restriction in the jumper – once these conditions are met,the blockage has been cleared sufficiently to restart the well.

Once the blockage has been cleared, open the WSV and push any remaininghydrate debris into the manifold with (additional methanol and) well production.If production from the other wells was never stopped, the manifold should be warmand help to quickly melt the remaining hydrate.

The total time to remove a plug in this manner should be on the order of 1 day(24 hours). If the plug has not released within 3 days, then it is time to use analternative remediation method. The alternative methods include:

• One-sided pressure reduction

• Replacement of the jumper section

During execution of the methanol ‘rocking’ method, alternative remediation methodsshould be evaluated to determine the most feasible method for the current blockage.Both alternative methods listed require that production from the other wells to bestopped, so preparations should be made to shut in the other wells.






OPRM20030302D_054.ai

Didpressure decrease

at tree?

No

Yes

Treat wellbore by displacing with

methanol (should be done prior

to the cooldown time)

Close the following valves on the

affected tree: PWV, MIV1, MIV2,

AWV, XOV, ASV, PSV

Close WSV to isolate well

from mainfold

Open: PMV, SCSSV,

SWV, choke

Open MIV2 and inject methanol

injo jumper to 21bar (300psig)

above the SITP

Monitor pressure at tree

(outlet pressure) for any change

for 60 to 90 minutes

Open PWV and relieve pressure

in the jumper into wellbore

Conduct a blockage-breach

test every fourth cycle by

opening the WSV

Inject 20bbls of methanol intowellbore and jumper, then proceed

to start-up procedures

Close MIV2

Close PWV

Figure 3.15 – Remediation Procedure for Hydrate Plug in Jumper/Manifold






4.3 Wellbore/Tree (Upstream of Inhibitor Injection Point)


The formation of a plug in the wellbore is similar to the case of a plug formed in the jumper section. When a wellbore hydrate plug forms, the downhole pressure gaugeincreases to the SBHP, and the production and outlet pressures approach themanifold pressure regardless of the open choke setting.

Plug Formation in Wellbore/Tree

• Downhole gauge increases to SBHP

• Pressure at tree is the same as the manifold pressure (in spite of choke beingnot fully open)

• No change in production pressure as the choke opening is changed

OPRM20030302D_067.ai

Hydrate Plug

OutletPressure

Jumper to

Subsea Manifold

Choke

SWVPWV

Downhole

Pressure

Production

PressureASV PSV

AWV

XOV

PWV

A n n u l u

s

SCSSV

Methanol Line

MIV 2

MIV 1

Figure 3.16 – Schematic of Hydrate Plug in Wellbore







If a plug is formed in the wellbore, two-sided depressurisation is not possible.Generally, one-sided pressure reduction is not recommended for wellbore blockagesdue to the difficulty of safe execution in the wellbore environment. ‘Rocking’methanol into the well is recommended as the first means of removing the hydrateblockage. The flowchart in Figure 3.15 shows the ‘rocking’ procedure steps.

Once the plug is detected, close the WSV to isolate the affected well from themanifold. Production from the other wells does not need to be stopped immediately,but preparations should be made in case the hydrate plug cannot be easilyremoved. Open the SCSSV, PMV and the choke, and close all other valves (refer toFigure 3.16 for relevant valves). Use MIV2 to inject methanol into the well byopening PWV. Increase the production pressure until the maximum pressure isachieved (~345bar (5000psi) the rating of the tree) and then close MIV2 and monitorfor blockage breach for approximately 60 to 90 minutes. Then slowly open the SWVto relieve the wellbore pressure into the jumper. Allow the production pressure to

decrease to 21bar (300psig) less than the last known SITP, then close SWV.Repeat this cycle until the plug is melted and pressure communication is establishedbetween the downhole pressure and the production pressure.

Initially, the top of the wellbore may be filled with gas. The methanol can be used toremove the gas and fill the top section of the wellbore with liquid. This will preventthe plug from breaking free and having enough momentum to cause any damage atthe tree. Therefore, during the first few pressure cycles, the pressure should only bedecreased to 7bar (100psig) less than the last known SITP. When the wellbore isliquid filled, the pressure should begin to increase very quickly with the addition ofonly a small amount of methanol.

Pressure communication can be detected by a sudden change in the productionpressure, which may be either a sudden increase or decrease depending on whenin the pressure cycle communication is established. The downhole pressure sensorshould also fluctuate, but this may be less noticeable than the production pressure.The volume of methanol that can be injected into the wellbore will also increaseonce the hydrate blockage is breached.

Once the blockage is breached and pressure communication is established betweenthe downhole pressure sensor and production pressure sensor, close the SWV(the PWV should still be open) and inject ~50 barrels of methanol into well.As methanol is injected, there should be some indication (pressure increase) notedon the downhole pressure sensor. If this is all successful, production can be restarted.

This methanol ‘rocking’ has been successfully applied in the past (refer to thePopeye case study). At Popeye, the plug took roughly a day to remove once themethanol ‘rocking’ procedure commenced. In other cases, such as at Auger, acoiled tubing unit had to be brought in to melt a hydrate blockage which was muchlarger than the one experienced at Popeye.






OPRM20030302D_055.ai

Pressurecommunication?

No

Yes

Select affected well andclose the WSV to isolate well

from manifold

All valves should be closed,

except the SCSSV, PMV

and the choke

Inject methanol into the well

until maximum flowline

pressure is achieved

Open PWV and use MIV2 to

inject methanol into the well

Close MIV2Close SWV

Monitor wellbore pressure and

watch for pressure communication

for 60 to 90 minutes

Open SWV to relieve wellbore

pressure into jumper, pressure

should be decreased to 21bar

(300psig) below last known SITP.

(During the first few cycles,

the pressure should only be

decreased to 7bar (100psig)

below the last know SITP)

Inject 50bbls of methanol into

wellbore and proceed to well

start-up procedures

Figure 3.17 – Remediation Procedure for a Hydrate Plug in the Wellbore






4.4 Umbilicals


The risk of hydrate formation in the umbilical lines is highest during times whenthere are large pressure fluctuations in the flowline. Many control system interlocksare put in place to prevent pressure fluctuation-induced hydrate formation in theumbilical lines. Examples of this include: Chemical Injection Valves (CIVs) have tobe closed before reducing the choke and shutting in a well; CIVs automatically closewhen a well gets shut in etc). It should be noted that hydrate plugs in the umbilicalmight occur during steady-state operation due to pressure fluctuations created byslugging. These pressure fluctuations have the potential to push production fluidsinto the umbilical. Once production fluids are in the umbilical, it is relatively easy toform a hydrate plug due to the small diameter of the umbilical lines. Based on GoMexperience, the formation of hydrate plugs in umbilical lines is fairly common. Itshould be noted that most of the cases of hydrate plug in the umbilical line are due

to manual operation during transients (ie the correct operating logic was not followedand valves were opened/closed in the wrong order).

A plug in one of the umbilical lines will be detected as an increase in the injectionpressure of the affected chemical line and loss of flow of that particular chemical.The example in Figure 3.18 shows a hydrate plug formed in the methanol line,but there is the potential to form a hydrate plug in any of the umbilical lines.The detection and remediation process is the same for a plug formed in any of theumbilical lines.

OPRM20030302D_068.ai

Hydrate Plug

Outlet

Pressure

Jumper to

Subsea Manifold

Choke

SWVPWV

DownholePressure

Production

Pressure

PWV

A

n n u l u s

SCSSV

Methanol Line

MIV 2

MIV 1

Figure 3.18 – Schematic of Hydrate Plug in Umbilical Line








4.5 Gas Lift Riser


The risk of forming a hydrate plug in the gas lift riser is highest during a shutdownand an aborted start-up. A plug in this section is detected by lack of gas flow in theriser and an increase in the gas lift riser topside pressure. Determining whichpressure sensors are in communication with one another can help to localisethe hydrate plug. Upstream of the plug all pressures should read the same,and downstream of the plug all pressures should read the same as the riser basepressure sensor in the flowline. The hydrate plug is located between the twoadjacent pressure sensors not in pressure communication. If the gas lift riserpressure and the gas lift riser topside pressure are equal, then the plug is betweenthe gas lift riser pressure sensor and the flowline (refer to Figure 3.20). If the riserbase pressure and the gas lift riser pressure are equal, then the plug is between thegas lift riser and the gas lift riser pressure sensor (refer to Figure 3.21).

Note: These figures refer to the plug being either upstream or downstream of themethanol injection point.

There is a small risk that the plug is between the methanol injection point andthe pressure sensor, but due to the small volume between these sections, this ishighly unlikely.

Plug Formation in Gas Lift Riser

• Increase in gas lift riser topside pressure

• No flow in gas lift riser

Unlike other portions of the Bonga system, a plug in this riser is much easier toremediate should it form12.

OPRM20030302D_069.ai

Hydrate Plug

Flowline

GLIV1

GLIV2

Methanol Line

GLR Topside

Pressure

To Production

Riser

To Subsea

Manifold

Gas Lift Riser

Pressure

Riser Base

Pressure

G a s L i f t R i s e r

Figure 3.20 – Schematic of Hydrate Plug in Riser Gas Lift System(Between Methanol Line and Flowline)

12 Email from Sada Iyer, March 2003.






OPRM20030302D_070.ai

Hydrate Plug

Flowline

GLIV1

GLIV2

Methanol Line

GLR Topside

Pressure

To Production

Riser

To Subsea

Manifold

Gas Lift RiserPressure

Riser Base

Pressure

G a s L i f t R i s

e r

Figure 3.21 – Schematic of Hydrate Plug in Riser Gas Lift System(Between Methanol Line and GLR Topsides)

Since the gas lift riser is close to the FPSO and since methanol can easily bedelivered to the riser, the flowline does not need to be blown down to remove ahydrate plug in the gas lift riser. Flow in the flowline will actually help to remove theplug since it will warm up the lower portion of the gas lift riser.

Note: There are many possible scenarios regarding the plug location in the gas liftriser. It is assumed that the plug does not form between the gas lift riserpressure sensor and Gas Lift Injection Valve (GLIV) 1 or between the gas liftriser pressure sensor and the methanol injection point. If either of thesecases occur, the following remediation methods will still work, but thepressure gradient in the riser will tend to move the plug in the wrong direction(away from the flowline). However, due to the small volumes in thesesections, there is not enough energy to move the plug any significantdistance.

If the plug is located downstream of the gas lift riser pressure sensor in the gas liftriser, refer to Figure 3.20 for a description of the remediation process. The first step

should be to try and push the hydrate into the flowline. Close GLIV2, open GLIV1and then use the methanol line to pressurise the gas lift riser to the maximumpressure (pressure measured at the gas lift riser pressure). Maintain this pressureon the upstream end of the plug and monitor the rate at which methanol is beinginjected into the gas lift riser. If the hydrate plug is solid, then the methanol volumewill be very near zero. If the plug is moving or is porous enough to allow methanol toflow through, then some finite volume of methanol is needed to maintain thepressure in the gas lift riser. If after 6 hours, the pressure in the riser section has notchanged and the volume of methanol injected is zero, then this method is not likelyto work. Conversely, if methanol continually needs to be injected into thegas lift riser, then eventually the plug will either be melted or pushed into the flowline.






If increasing the pressure with methanol does not remove the hydrate plug, then thegas lift riser will need to be blown down in order to remove the hydrate plug.GLIV1 should be closed and then the gas lift riser can be fully depressurised(topside gas lift riser and gas lift riser pressure are as low as possible). The valve

upstream of the methanol injection point (GLIV2) is then closed and methanol isinjected to pressurise the section between GLIV1 and GLIV2. The valve betweenthe hydrate plug and the methanol-filled section (GLIV1) is then opened. Methanolcan then be used to pressurise the section of the gas lift riser between the hydrateplug and GLIV2. At this point, the pressure on the methanol side of the plug shouldbe greater than the flowline so that when the plug releases, it will move towards theflowline. If the plug does not release within 60 to 90 minutes, then the aboveprocess should be repeated. The time expected to remove a plug in the gas lift riserusing the above method should be less than 1 day (24 hours).

For the case when the plug is upstream of the methanol injection point, refer toFigure 3.21. The figure shows that the plug is between GLIV2 and the flowline,

but this may not necessarily be true. Therefore, the pressure in the gas lift risershould be increased (or decreased) to a pressure that is 14bar (200psig) greaterthan the riser base pressure, leaving GLIV2 open.

Open GLIV1 to relieve the pressure downstream of the plug to the flowline pressure,and then close GLIV1. Inject methanol into the gas lift riser and increase pressureuntil it is slightly less than the gas lift riser topsides pressure. Repeat this processevery 60 to 90 minutes until plug releases. The time required to remove a plug usingthis method should be in the order of a day. However, this case is less likely tosucceed than the other gas lift riser scenario (refer to Figure 3.20) and otherremediation techniques may be necessary.






OPRM20030302D_057.ai

Pressureequalisation within 60 to 90

minutes?

Is theinjected volume of

methanol greater thanzero?

No

Yes

Yes

No

Close GLIV1 and GLIV2Close GLIV2 and open GLIV1

Close GLIV2

Close GLIV1

Open GLIV1

Open GLIV2 and depressurise

the gas lift riser

Continue injecting methanol

until plug releases

Open GLIV2 and depressurise

the gas lift riser

Use methanol to increase gas lift

riser pressure to maximum

Use methanol to maintain

the maximum pressure in

the gas lift riser

Monitor the gas lift pressure for

6 hours for any sudden pressure

decrease and/or communication

with riser base pressure,

monitor amount of methanol

injected into gas lift riser

Monitor the gas lift pressure for

any sudden pressure decrease

and/or communication with

riser base pressure

Inject methanol into gas lift riser

to maximum pressure

Start methanol injection

and begin gas lift

Figure 3.22 – Remediation Procedure for a Hydrate Plug in the Gas Lift Riser

(Between Methanol Line and the Flowline)






No

Yes

Close GLIV1 and GLIV2

Open GLIV2

Close GLIV1 and GLIV2

Increase/decrease gas lift riser

topside pressure to 14bar (200psig)

above riser base pressure

Inject methanol into gas lift riser

until pressure equals the gas

lift riser topside pressure

Monitor gas lift pressure for

any sudden pressure increase

and/or communication with gas

lift riser topside pressure

Open GLIV1 to reduce

pressure at gas lift riser to

riser base pressure

OPRM20030302D_061.ai

Pressureequalisation?

Start methanol injection

and begin gas lift

Figure 3.23 – Remediation Procedure for a Hydrate Plug in the Gas Lift Riser

(Between Methanol Line and Topsides)






4.6 Water Injection Wells


The most likely scenario in which a plug may form in one of the water injector wellsis during a shut-in, which is performed within a few days of initial start-up. Since theBonga water injection wells are completed into the oil zone, it is possible for gas tomigrate back into the well and accumulate where the temperature and pressure arein the hydrate stable region. This involves the occurrence of two situations, gasmigration into the well (from the reservoir) and a leaking SCSSV that allows gas tomigrate up to the tree. Although hydrates would form during shut-in, they would notbe noticed until start-up. During water injection, there is no hydrate risk. The riskalso decreases with time as more water is injected into the reservoir and the gasfront is pushed further away from the wellbore, which will make migration less likelywithin the duration of shut-in. Based on experience at Petro-Canada, this problem ofgas migration was no longer a concern after about 6 weeks of water injection.

A hydrate plug in the water injection wells will be indicated by lack of flow into thewell (measured using the venturi meter). The pressure at the tree will also increase.If the plug is in the wellbore, both the injection and inlet pressure will be the same.If this is not the case, then the plug may be located in the tree or jumper instead ofthe wellbore.


Due to the lack of remediation options for the water injection wells, every attemptshould be made to minimise hydrates from forming. The best means for this is toensure that the SCSSV is closed during shut-in. Unfortunately, the SCSSV is notgastight and may still leak in the closed position.

During shut-in, the plug may not have formed a solid mass, so if there is any reasonto suspect gas migration into the well, the water injection should be started up asquickly as possible in an attempt to push any hydrate back down into the well.Once it is verified that there is a plug in the water injection wells, the water pressurecan be increased in an attempt to move the plug below the SCSSV. In order tomake sure that the plug is pushed back below the SCSSV, make sure that at least50 to 150 barrels of water are flowed into the well. However, this is unlikely to beeffective and may only create a more solid hydrate plug.

If a plug is detected during start-up, then every attempt should be made to localisethe plug and shut in the appropriate valves to prevent any further gas or hydratefrom moving back through the flowline even though this is a small risk. At this point

preparations should be made to intervene at the well to remediate the plug.






Section 3 Appendix 3A Pressure Tags

OPRM-2003-0302D Page 45 of 64 Issue 1.0 31-December-2004

Printed copies of this document may be obsolete. ‘Business Control Documents’ are online in SNEPCO Livelink.

Appendix 3APressure Tags

Table of Contents

TABLES

Table 3A.1 – Pressure Tags for Production Wells ................................................................46

Table 3A.2 – Pressure Tags for Production Flowlines ..........................................................47

Table 3A.3 – Pressure Tags for Water Injection Wells..........................................................48







Well NoDownholePressure

ProductionPressure

(Upstream of Choke)

OutletPressure

(Downstream of Choke)

690p1 01-PT-800 01-PT-801 01-PT-802

690p2 01-PT-804 01-PT-805 01-PT-806

702p14 01-PT-808 01-PT-809 01-PT-810

702p10 01-PT-812 01-PT-813 01-PT-814

702p15 01-PT-816 01-PT-817 01-PT-818

702p2 01-PT-820 01-PT-821 01-PT-822

702p4 01-PT-824 01-PT-825 01-PT-826

702p5 01-PT-828 01-PT-829 01-PT-830

702p9 01-PT-832 01-PT-833 01-PT-834

710p1 01-PT-836 01-PT-837 01-PT-838

710p2 01-PT-840 01-PT-841 01-PT-842

710p3 01-PT-844 01-PT-845 01-PT-846

710p4/803p1 01-PT-848 01-PT-849 01-PT-850

803p2 01-PT-852 01-PT-853 01-PT-854

803p3 01-PT-856 01-PT-857 01-PT-858

S690p3 01-PT-860 01-PT-861 01-PT-862

S690p4 01-PT-864 01-PT-865 01-PT-866

S702p3 01-PT-868 01-PT-869 01-PT-870

S702p6 01-PT-872 01-PT-873 01-PT-874

S702p7 01-PT-876 01-PT-877 01-PT-878

Table 3A.1 – Pressure Tags for Production Wells







Well NoProduction

ManifoldProductionFlowlines

ManifoldPressure

Riser BasePressure

TopsidePressure

Gas LiftRiser

Pressure(between

GLIV1

and GLIV2)

Gas LiftRiser

TopsidePressure

710p1 PFL 08 03-PT-800 04-PT-812 04-PIT-304 04-PT-804 31-PIT-013


710p3

PM1



710p4

803p3

PM2


702p14PM3

PFL 06 03-PT-805 04-PT-811 04-PIT-384 04-PT-803 31-PIT-053

702p5 PFL 03 03-PT-806 N/A N/A N/A N/A

702p9PM4

PFL 04 03-PT-807 N/A N/A N/A N/A



702p4

PM5

Table 3A.2 – Pressure Tags for Production Flowlines






Section 3 Appendix 3B Case Studies


.

Appendix 3BCase Studies

Table of Contents

1.0 HYDRATE FORMATION IN FLOWLINE ....................................................................50

1.1 Case Study: Popeye ........................................................................................50

2.0 HYDRATE REMOVAL IN FLOWLINE ........................................................................51

2.1 Case Study: Tahoe..........................................................................................51

2.2 Case Study: Petrobras.....................................................................................52

2.3 Case Study: Statoil ..........................................................................................52

2.4 Case Study: ARCO..........................................................................................53

3.0 HYDRATE REMOVAL IN WELL.................................................................................58

3.1 Case Study: Popeye ........................................................................................58

3.2 Case Study: Auger...........................................................................................59

4.0 HYDRATE REMOVAL IN A CHEMICAL INJECTION LINE........................................60

4.1 Oregano...........................................................................................................60






.

1.0 HYDRATE FORMATION IN FLOWLINE

1.1 Case Study: Popeye

Taken from: AP Mehta et al, ‘Fulfilling the Promise of Low-dosage HydrateInhibitors: Journey from Academic Curiosity to Successful Field Implementation’,SPE Production and Facilities, February 2003, p73.

During steady-state operation, the flowline was being treated with methanol.However, the volume of produced water was too large to be protected with themethanol and hence the flowline was operating in the hydrate region. What wasobserved during steady-state operation was that there was a slow gradual increasein the pressure drop along the flowline, which is attributed to the formation andaccumulation of hydrates in the flowline. The figure below indicates variables thatwould typically be measured and that show an observable indication of hydrateformation. The pressure drop in the flowline shows a steady increase with the gasrate showing a steady decline. Since the formation of hydrates in this system was

observable, actions could be taken to remove the hydrates before they accumulatedsufficiently to form a hydrate plug.










.

During dissociation the pressure was decreased in steps, and a slow bleedthroughwas observed from 0 to 73 hours, from 73 to 90, 95 to 105 hours, and from105 through 120 hours. During the time prior to 120 hours, the pressure was abovethe hydrate equilibrium pressure, and while the upstream pressure decreased

steadily, it never decreased to the downstream pressure, indicating that the plugwas not very permeable to black oil. A second mechanism was that the light oil endsmay have been flashing to maintain a constant pressure upstream. However,the increase in downstream pressure occurred much more rapidly as thedownstream pressure was lowered, indicating that the plug was porous, even to theblack oil.

After about 120 hours the line pressure was maintained between 145 to 261psiadownstream of the plug. The plug dissociated about 50 to 60 hours after thedownstream pressure had been reduced sufficiently for melting by heat influx fromthe ocean. This was indicated by a sudden upstream pressure decrease from1890psig to 1160psig, while the downstream pressure increased from 218psig to

1015psig during the same period. The pressure was decreased to 145psig and keptthere for over 30 hours to melt the remainder of the hydrates.

Restart of the well was accomplished 2 weeks after the original plug developed.This case is another indication of the long times required to remediate ahydrate plug.

In 1996 a Statoil black oil pipeline plug occurred in the Norwegian sector of theNorth Sea. After several precautions, the pipeline was depressurised from one sideof the plug, and when the plug had melted the line was maintained at atmosphericpressure for over 1 day to eliminate the light components, which mightform hydrates.

Before start-up, methanol was injected in the amount of 530 gallons in the 6in ID,1.6 mile line from the platform. The pipeline was then pressurised with diesel fromthe platform to the subsea valve in an amount which indicated that the pipeline wasnearly empty of liquid after the previous depressurisation to atmospheric conditions.A further injection of diesel corresponding to two pipeline volumes was pumped intothe pipeline and well. Subsequently the well and the pipeline were put intoproduction without any hydrate problems.

2.4 Case Study: ARCO

Taken from: ED Sloan, ‘Offshore Hydrate Engineering Handbook’, Case Study 14:Plug Formation

SettingThe gas field is located in the southern North Sea and consists of three subseawells, flowing into a subsea manifold with a capacity of four well inputs. This well’sgas compositions, temperature and pressure promote hydrate formation,consequently Monoethylene Glycol (MEG) is injected into the manifold andwellheads to thermodynamically inhibit hydrates. The inhibited water, gas andcondensate is then pumped through a 22 mile, trenched, insulated export pipeline toa processing platform where water is removed from the condensate. The MEG inthe pipeline is recycled and piped back to the manifold via a 3in pipelinepiggybacked to the export line.










.

Establishing Procedures/Permits

It took approximately 2 weeks to develop potential remediation processes.Procedures were then written to firmly establish the processes required for thepipeline depressurisation. Procedures considered the safety, process andco-ordination requirements between the diving rig and the FPSO. All parties wereeducated about the tasks involved. Government permits were applied for at theHealth and Safety Executive (HSE) Pipeline Inspectorate and the Department ofTrade and Industry (DTI) Oil and Gas Office for additional gas flaring and wellmodification. The permits were expedited by local agencies to prevent delay inhydrate removal. 2 weeks were required to prepare procedures and permits fordepressurisation. In the meantime, the FPSO and diving rig were being equipped forthe operation and moving to the field.

Depressurisation of the Pipeline

The divers first task was to manually locate the subsea manifolds fourth intake and

to isolate it from any trees or flow loops. The fourth well intake was then modifiedwith a spoolpiece for connection with the high-pressure riser. The valve skid wasnow ready to be put in place. Due to the sandy ocean bottom, it became necessaryto provide a foundation for the valve sled. The valve skid was placed on a concretemattress and then stabilised with gravel bag supports coupled with Tirfors,chain blocks and ground anchors. This insured that no movement would transferfrom the flexible riser to the valve skid. The valve skid contained ESDVs and a MEGinjection system for the pipeline.

The diving rig then inspected the flexible riser route to ensure that is was clear ofdebris. It proceeded to deploy 920ft of the high pressure riser via a tugger riggedwith a dead-man’s anchor. The MEG in the riser provided some buoyancy,consequently the line was anchored through concrete mattresses. A 5 tonne clumpweight was placed at the bottom of the riser with a buoyancy collar attached tothe surface.

The FPSO could only process gas at 600psig, consequently it required somemodification to process the 1300psig pipeline gas. Additionally, a quick-releasevalve (QVD) was needed to enable the FPSO to escape from the riser in case of anemergency. This complicated the design because current quick-release valves couldnot withstand pressures of 1300psig. Initial design placed choke valves in the riserto reduce pressure for the quick-release valve, however this caused controlproblems and was deemed impractical.

An innovative new quick-release valve was developed with a standard valve weak

link with three additional hydraulic jacks for manual release. This valve couldwithstand 1500psig of pressure, allowing choke valves to be placed on the ship’sdeck, which simplified control issues. This design enabled a safe, simplified, controlof gas pressures from the deck of the FPSO.

The buoyancy of the riser prohibited pipeline intake through the FPSO’s moonpool.Spoolpieces were used to allow riser intake from the side of the ship deck. The riserwas also steam traced with 1000ft of 1in piping to maintain the minimum processtemperature required by the FPSO. All valves and risers were tested and shown tobe in working order. Overall the modification and instalment procedures required1 week before pipeline depressurisation could begin.






.

Determining the Pipeline Minimum Pressure

Reducing pipeline pressure too much could result in ice formation. This causessignificant problems because ice melting might have required significantly moretime, than hydrate dissociation. Ice formation was prevented through use of thehydrate equilibrium curve for the field.

At constant low pressure, hydrates will continually dissociate, maintaining theequilibrium temperature at that given pressure. The equilibrium pressure at 32°Fwas 200psig. To prevent ice formation, the pipeline pressure could not drop below175psig. Consequently, the FPSO reduced the pipeline pressure to 185psig tomaximise hydrate dissociation without ice formation.

Depressurisation

23 days were required to completely dissociate the pipeline hydrate. Heat transferbetween the ocean and the pipeline was slow because the line was trenched andinsulated in the sea floor. Dissociation was slightly facilitated by occasional

backpressuring which drew methanol into the plug. Backpressuring also provedbeneficial in determining the location of the plug.

The pressure was monitored for 12 hours after the hydrate was thought to bedissociated. No pressure variation was noticed so the flexible riser was recoveredand the depressurisation apparatus dismantled. Throughout the whole operation,no equipment failure occurred and the operation progressed smoothly.

Recommissioning the Pipeline

After the hydrate was dissociated, there remained significant amounts of free waterin the pipeline. The pipeline had to be recommissioned carefully to preventreformation of hydrates. Above normal amounts of MEG were added to the system

before pipeline start-up. One gas well was opened and the platform flow was high tomaintain low pressure, preventing hydrate formation. The high intake caused a highgas velocity, which facilitated rapid water removal. The first 12-hour night shiftreported 7000ft3 of water received from the separator, the water which would resultfrom a 1.25 mile long (non-porous) hydrate plug. The high flow rate of gas wasmaintained until the water contained 40% MEG, ensuring that the line was fullyinhibited. The pressures and intakes were then returned to normal operating levels.

Conclusions

The remediation team removed the hydrate plug efficiently. They achieved amonumental task in a very short period of time, preventing more severe economiclosses. The procedure and methodology followed could be applied to many different

situations. Communication, clear objectives and excellent resources helped inremoving the hydrate plug.

Despite the efficient remediation effort, the economic impact of the hydrate plug wassubstantial. The cost of depressurising the pipeline was almost 3 million dollars,without counting lost production. On top of this, relations between the buyers andproducers were tested, due to lack of production. Fortunately, good initial relationsbetween the two reduced the impact of the disruption. This case study shows thepotential financial loss that can result from hydrate plugs. Hydrate prevention is keyin preventing significant economic and production losses.






.

3.0 HYDRATE REMOVAL IN WELL

3.1 Case Study: Popeye

WhereA hydrate plug was formed in the Popeye A4 well. The plug was detected uponinitial start-up after completion of the well. The well contained some residualcompletion fluids including an NH4Cl solution.

How

The well was shut-in with the residual completion fluids and a mixture of CaCl2 /MEGwas dumped into the well. It was believed that the CaCl2 /MEG mixture was sufficientto inhibit the formation of hydrates. However, later analysis revealed that thecombination of the CaCl2 /MEG mixture and the residual NH4Cl in the well did notprovide sufficient hydrate inhibition and hydrates were formed.

Plug AnalysisThe pressure at the wellhead varied between 3300psig (manifold pressure) and5500psig (reservoir pressure). Based on the amount of methanol that could beinjected into the well, the hydrate plug was determined to be near the top of the well.

Plug Remediation

The plug was removed by cycling methanol into the well. Methanol was pumped intothe well up to 5500psig. This was then left at that pressure for about 1 to 2 hours.Then the wellhead pressure was relieved to the manifold pressure of 3300psig.The wellhead pressure was then monitored for signs of a pressure increase, whichwas due to either the hydrate plug melting or gas leaking through the hydrate plug.Once the pressure stopped increasing, methanol was again pumped into the well upto 5500psig. With each successive pressure cycle, more methanol was able to bepumped (indicating that the plug was either melting or being pushed down the well)and the amount of time it took for the pressure to stabilise after opening to themanifold increased. During the final pressure cycle, as the methanol was beingpumped into the well, the plug broke free and the wellhead pressure did notincrease as more methanol was pumped. During all of the pressure cycles,the SCSSV remained open.

Key Learnings

In this case, the well was thought to contain fluids that were inhibited againsthydrate formation. If the well is to be shut in for any period of time, it is necessary to

verify exactly what fluids are currently present in the well and what needs to beinjected to ensure that hydrates will not form.






.

3.2 Case Study: Auger

Taken from: AP Mehta, ‘Hydrate Plug Blockage and Remediation: Case Studiesfrom Operations in the Gulf of Mexico’, EP 2001-3019.

Where

A hydrate plug had formed in the Auger A1 well soon after completion andcommissioning in July 1994. The well was producing oil with no detectable waterbased upon shake-out tests. The well had been shut-in soon after start-up due to ahurricane in the Gulf of Mexico.

How

The Auger hydrate plug was yet another reminder that an undetectable water cut,based upon shake-out tests, is not a good indicator of a fluids potential to formhydrates. Auger well A4 had been in production for at least 14 hours prior to beingshut in (by closing the wing valve). The subsurface safety valve was shut in 2 hours

later. Some completion fluids were expected to remain in the well even though it hadbeen flowing for 14 hours. Upon shut-in, it is believed that water droplets dispersedin the oil (present as BS&W, not free water) would have quickly settled out.In addition any slugs of completion fluids would also be settling out upon shut-in.These water droplets and completion fluids would possibly be forming a thin layer ofwater along the tubing wall (since the well flowed ‘liquid full’) and initiate hydrateformation. Further contact with falling water upon shut-in could easily result in ahydrate plug since no methanol was injected into the well prior to shut-in.

Plug Analysis

Auger Well A4 had a shut-in pressure of about 7200psig and the crude bubble pointis around 5500psig. The sea-bottom temperature is expected to be approximately

40°F. At 7200psig, the hydrate dissociation temperature is ~85°F, assuming that thewater is fresh. This provides a tremendous driving force of over 45°F for thehydrates to form when the oil/gas comes into contact with any free water.

The hydrate blockage at Auger formed during restart of the well. The SCSSV at adepth of 6000ft below the mudline could not be opened and it was initially suspectedto be the location of the hydrate plug. The well was pressured up to as highas 10,000psig and bled down several times to open up the SCSSV. These attemptswere unsuccessful. A wireline tagged the plug at 1290ft. It was decided by theremediation task force to use glycol or methanol to dissolve the hydrate plug byinjection of these inhibitors from the wellhead.

Plug Remediation

Initially, hot water was circulated down a 0.5in tubing string in the annulus to warmup and melt the hydrate, but no movement was observed. Glycol was then pumpedfrom the surface and methanol was injected about 100ft above the SCSSV, but thistoo did not help. At this stage a coiled tubing unit was mobilised.

A 1.25in coiled tubing unit was rigged up and a mixture of 50% methanol(by volume) in water was circulated through four 0.25in nozzled from the base ofthe tubing. The circulation rate was set at 0.5bbls/min. The unit first encounteredhydrates at 2136ft and these were easily washed down to 2970ft. Several hardplugs were observed at depths down to 3270ft, where the unit broke throughwashed down to 4700ft. According to Steve Norton of Shell Offshore Incorporated(SOI), the coiled tubing unit does not easily ‘feel’ the presence of hydrates but

recognised their presence only after breaking through them.








.

Cause of Plugging Event

While in preparation for normal monthly well testing, the Oregano #1 well wasshut in for preparation to test the Oregano #2 well. MeOH injection was started intothe OR1 tree to treat the wellbore, tree and jumper against hydrate formation.Pressure was bled off of the portion of the tree where the methanol was to beinjected through the CIT2 valve by closing the choke and opening the PipelineShutdown Valve (PSDV) downstream of the choke. At this point, pressure was bledto the flowline pressure, which was approximately 3000psi. The chart belowcontains the PI data recorded during the event. When the CIT2 valve was opened,the topsides methanol pump pressure was approximately 2000psi with acorresponding pressure at the CIT2 valve of 3200psi including the hydrostatic headof methanol. At this point there was sufficient topsides methanol pump pressure toinject chemical into the tree. During the operation, the choke was commanded openand the PSDV was commanded shut. This is normal operating procedure fortreating the tree and wellbore for shut-in as long as equalisation across the tree

valves is performed first. However, when the choke was opened and the PSDV wasclosed, the shut-in tubing pressure was allowed into the tree downstream of thechoke at the opened CIT2 valve and the topsides pump pressure plus methanolhydrostatic head was not sufficient to prevent the backflow of hydrocarbons into themethanol injection line. At the time the choke was commanded open and the PSDVwas commanded shut, the shut-in tubing pressure was approximately 5000psi.At this time, the topsides pump pressure was 2800psi. Including the head ofmethanol and friction losses in the line, the pressure differential across the valvewas on the order of 2000psi. It appears that backflow and plugging extendedthrough the OR1 steel flying lead to the Umbilical Termination Head (UTH) andpossibly up the main umbilical where the methanol circuit is common for both of theOregano wells. It is not clear at this time whether the plug is a hydrate, emulsion or

floc. As a result of the backflow into the common part of the umbilical, injection intoboth wells through the normal means is not currently possible.

System Redundancy

Methanol injection into the system is currently available through the annulus ventumbilical line. However, this line is the only means of annulus service for bothOregano and Serrano because the line is common to both fields. Therefore, extremecaution must be taken during operations involving this line such as annulus bleedsor methanol injection so that the ability to inject into the line is not jeopardised.Operations guidelines must be strictly adhered to at all times.

The Oregano system does have additional umbilical tubes that are not currently in

use that could potentially be used for methanol service. Specifically, the asphaltenesolvent and the scale inhibitor lines appear to be feasible substitutes. Plans arecurrently being developed to perform the work required to commission these linesfor use if remediation attempts prove to be unsuccessful.






Section 3 Appendix 3C Nomenclature


Appendix 3CNomenclature

AWV Annulus Wing Valve

bbls Barrelsblpd Barrels of liquid (oil and water) per daybpd Barrels per day

FPSO Floating Production, Storage and Offloading Vessel

GLIV Gas Lift Injection ValveGLR Gas Lift RiserGOM Gulf of Mexico

HDP Hydrate Dissociation Pressure

KHI Kinetic Hydrate Inhibitor

LDHI Low Dosage Hydrate InhibitorLP Low Pressure

MIV Methanol Injection ValveMMSCF Million Standard Cubic FeetMMSCFD Million Standard Cubic Feet per Day

PFL Production FlowlinePIV Pigging Isolation ValvePM Production ManifoldPMV Production Master Valve

PWV Production Wing Valve

SCSSV Surface Controlled Subsurface Safety ValveSITP Shut-in Tubing PressureSWV Sacrificial Wing Valve

VIT Vacuum Insulation Tubing

WC Water CutWSV Well Switching Valve

XOV Crossover Valve






Section 4 Production Flowline Wax Assessment


Section 4Production Flowline Wax Assessment

Table of Contents


1.1 Wax Deposition..................................................................................................4

1.2 Summary of Results...........................................................................................5

1.3 Recommendations.............................................................................................5

2.0 BACKGROUND............................................................................................................6

2.1 Sample Selection for the Present Study.............................................................6

2.2 Scope of Work ...................................................................................................7

3.0 PRODUCTION FLOWLINE LAYOUT AND PIPE CHARACTERISTICS.......................8

4.0 WAX-RELATED FLUID PROPERTIES.........................................................................9

4.1 Measurement Techniques..................................................................................9

4.2 Sampling and Basic Fluid Properties..................................................................9

4.3 Normal Paraffin Distributions ...........................................................................10

4.4 Critical Wax Deposition Temperatures.............................................................10

4.5 Kinetic Wax Deposition Rates..........................................................................12

5.0 WAX DEPOSITION SIMULATION RESULTS ............................................................13

5.1 East 10in Production Flowline Line ..................................................................14

5.2 East 12in Production Flowline Line ..................................................................17

5.3 West 10in Production Flowline Line .................................................................20

6.0 POUR POINT AND RESTART EVALUATION............................................................25

6.1 Dead Oil Pour Point .........................................................................................25

6.2 Live Oil Pour Point ...........................................................................................27

6.3 Gel Strength Measurement..............................................................................27

6.4 Effect of Bonga Fluid Blending.........................................................................28

6.5 Impact on Chemical Treatment........................................................................30

7.0 WAX RISKS AND WAX MANAGEMENT STRATEGY...............................................30

7.1 Risks and Basic Management Strategy............................................................30

7.2 Surveillance and Adjustments to Management Strategy ..................................30

8.0

HEALTH, SAFETY AND ENVIRONMENT (HSE) .......................................................31







TABLES

Table 4.1 – List of Bonga Fluids Whose Wax Properties Were Measured ..............................6

Table 4.2 – Production Flowline Data.....................................................................................8

Table 4.3 – Basic Properties of B1 803 Oil .............................................................................9

Table 4.4 – Comparison of Bonga Pour and Cloud Points....................................................10

Table 4.5 – Measured Pour Points for Bonga B1 803 Sample NIG-O-129A .........................26

Table 4.6 – Required Restart Pressures for Bonga Production Flowlines (PFL) ...................29

FIGURES

Figure 4.1 – Production Flowline Layout.................................................................................8

Figure 4.2 – Normal Paraffin Distributions for Various 803 Bonga Oils .................................11

Figure 4.3 – Critical Wax Deposition Temperatures for Various Bonga Oils .........................11

Figure 4.4 – Comparison of Kinetic Wax Deposition Rates for Bonga 803 Oils ....................12

Figure 4.5 – FPSO Arrival Temperatures – East 10in PFL ...................................................14

Figure 4.6 – Deposition Onset Location – East 10in PFL......................................................15

Figure 4.7 – Deposit Growth Rate (in Maximum Thickness) – East 10in PFL.......................15

Figure 4.8 – Deposit Growth Rate (in Volume) – East 10in PFL ...........................................16

Figure 4.9 – Estimated Pigging Frequency – East 10in PFL.................................................16

Figure 4.10 – FPSO Arrival Temperatures – East 12in PFL .................................................17

Figure 4.11 – Deposition Onset Location – East 12in PFL....................................................18

Figure 4.12 – Deposit Growth Rate (in Maximum Thickness) – East 12in PFL.....................18

Figure 4.13 – Deposit Growth Rate (in Volume) – East 12in PFL .........................................19

Figure 4.14 – Estimated Pigging Frequency – East 12in PFL...............................................20

Figure 4.15 – FPSO Arrival Temperatures – West 10in PFL ................................................21

Figure 4.16 – Deposition Onset Location – West 10in PFL...................................................22

Figure 4.17 – Deposit Growth Rate (in Maximum Thickness) – West 10in PFL...................22

Figure 4.18 – Deposit Growth Rate (in Volume) – West 10in PFL ........................................23

Figure 4.19 – Estimated Pigging Frequency – West 10in PFL..............................................24

Figure 4.20 – Pour Points of Bonga B1 702 and B1 803 Blends...........................................29







APPENDICES

Appendix 4A – Sensitivity Analysis of CWDTS and Deposition Rates...................................32

Appendix 4B – Pour Point Measurement Techniques and Uncertainties...............................37

Appendix 4C – Tables from Westrich (1999) Report (SIEP.99.6096)....................................38








1.2 Summary of Results

Wax Deposition

There is no wax risk in the short (1 mile) flowlines, west of the FPSO.

Recommended pigging frequency is once per year for maintenance andsurveillance.

The wax risks in the long flowlines (east of the FPSO) are minimal if the conditionsare base case or better. Using Qfl > 10MBPD, Tman > 49°C, and worst-case waxproperties, recommended pigging frequencies range from 2 to 3 times per year.

Wax risks increase substantially if either Qfl or Tman fall below base-case conditions.

Wax risks decrease substantially if the produced fluid has low wax deposition rates(found in the partially biodegraded oils).

Pour Point and Gel Strength

A study has been made of the B1 Well 803 sand fluid, which has the highest pourpoint of any Bonga fluid yet measured in our labs (maximum 4°C, minimum -7°C).We have determined that this fluid is unlikely to exhibit a yield stress/gel strengthunder shut-in pipeline conditions. We expect that no pour point depressant will berequired. These findings will be compared with those of chemical vendors when thechemical tender results become available.

1.3 Recommendations

The wax deposition study has used Tman as a variable rather than connectingspecific well production functions to manifold temperatures. For this reason,we recommend that a comparison be made of critical wax deposition temperaturesto case-specific manifold and arrival temperatures based on production functionsand wellbore thermal/hydraulic simulations.

Frequent surveillance is recommended for the produced fluid wax properties toensure that:

• The fluid is arriving above the critical wax deposition temperatures in eachflowline

• The produced fluid pour points have not increased








A sample of B1-Well 803 oil was found in storage in Nigeria and provided toShell Global Solutions for testing and evaluation; it is used in the present study.While it cannot be guaranteed to have the absolute worst wax-related propertiesat Bonga, it is certainly among the worst and should be adequate for wax flow

assurance measurements and models.

2.2 Scope of Work

The key points in the scope of work are listed below:

• Wax Deposition

– Measure wax-related fluid properties of a non-biodegraded, high pour pointfluid (B1 803): HTGC, pour point, cloud point, kinetic wax deposition rate

– Verify wax deposition strategy by comparing range of CWDTs to expectedarrival temperatures of production flowlines; run HYSYS Wax Deposition forselected cases if necessary

– Follow-up/validate pigging frequency results given in oil offloading report;report issued separately

• Gelling/Pour Point

– Challenge and assess if current strategy for treating high Pour Point (PP)wells is valid; develop detailed procedures if necessary

– Test gel strengths of high pour point fluid to determine level of concern; alsodo pipeline restart tests if/when sample volumes become available (possiblyget samples during unloading)

– Model restart of high pour point fluid if required

– Investigate effect of mixing oils at manifolds and topsides; determine ifexport oil should be treated for high pour point

• Surveillance/Analysis

– Specify requirements for sample analysis during development drilling and asa part of surveillance after first oil






3.0 PRODUCTION FLOWLINE LAYOUT AND PIPE CHARACTERISTICS

The Bonga production concept brings all produced fluids from five ProductionManifolds (PMs) to an FPSO located in the middle of the field. Each PM combinesmultiple wells with fluids from various pay sands. The West Field (ie west of theFPSO) consists of two Production Flowline Loops (PFLs), namely, PFL 8/9 andPFL 11/12 and the East Field consists of three PFLs, namely, PFL 1/2, PFL 3/4 andPFL 5/6. Since PFLs 3/4 and 5/6 are connected together, they are consideredas one PFL for realistic wax deposition simulation. According to contractualspecifications in the basis of design (Bonga Field Development Plan, 2001), all PFLsare of Pipe-in-pipe (PIP) configuration with an overall heat transfer coefficient (UOD)of 0.187 to 0.194 Btu/hr-ft2-°F (1.063 to 1.101W/m2-°C) depending on pipe size.Water depth is approximately 3400ft (1000m). Typical riser length is about 1700m.A simplified schematic of the production flowline layout is shown in Figure 4.1.

FPSO

West East

PFL 8/9

PFL 11/12PFL 1/2

PFL 5/6PFL 3/4

Figure 4.1 – Production Flowline Layout

The West PFLs are about a mile long (1.8km) and the pipe size is 10in with an ID of8.876in (22.6cm). The East PFLs range from 3.6 to 5.5 miles (5.8 to 8.8km) and thepipe sizes vary from 10in to 12in with an ID of 8.876in to 10.62in (22.6 to 27cm).Table 4.2 lists the flowline characteristics used in this study.

East 10in PFL

Parr (bar) WC (%)PIP ID(cm)

Gas LiftedPIP U Factor

(W/m2-C)

FlowlineLength

(km)

21 0 22.6 No 1.063 8.8

West 10in PFL



(W/m2-C)

FlowlineLength

(km)

21 0 22.6 No 1.063 1.8

East 12in PFL



(W/m2-C)

FlowlineLength

(km)

21 0 27 No 1.101 5.8

Table 4.2 – Production Flowline Data






4.0 WAX-RELATED FLUID PROPERTIES

One objective of the current study was to validate the B1 803 oil sample(NIG-O-129A) newly obtained from Nigeria. The sample was validated using cloudpoint and HTGC measurements, after which kinetic wax deposition rates weremeasured as input for the deposition studies. Appendix 4C contains all waxproperties obtained from Bonga Main fluids prior to the current report. The 670, 690,702 and 710 sands show lower wax-related properties than 803 oil. (As notedpreviously, the 709 sand in well 702W6 looks as bad or slightly worse than B1 803oil, but the 709 sample is questionable.) These data show that B1 803 oil isexpected to be the worst case for wax-related fluid properties.

4.1 Measurement Techniques

Wax-related properties are determined from several in-house measurements.These data are used as inputs and consistency checks to our thermodynamic andtransport models for wax deposition in flowlines and wells. Both the measurements

and models are described in Refs 11 and 12.

4.2 Sampling and Basic Fluid Properties

Data about samples and trends across the Bonga Main fields are available inRefs 11 to 13 and 17. Major conclusions in those studies are that wax-relatedproperties vary both between and within reservoirs. The primary cause of thisvariation is biodegradation, which metabolises paraffins and reduces cloud and pourpoints. From those studies, the B1-well 803-sand fluid was identified as a primary oil(in the geochemical sense; not biodegraded or otherwise altered) with the highestknown cloud and pour points of the available Bonga fluids. At the time in 1999,this fluid was not available to Shell, but a sample has since been made available.

This sample has been analysed and the basic results are given in Table 4.3.Cloud point was measured by the cold-finger technique, and maximum/minimumpour points were measured according to the ASTM D5853-95 protocol.

Cloud Point(°C)

Well Sand SAM ID WTC ID Gravity (API)Cold

FingerHTGC

Pour Points(°C)

B1 803 NIG-O-129A 6140 33.9 35.6 37.0 4/-7

Table 4.3 – Basic Properties of B1 803 Oil

Table 4.4 compares cloud points for Bonga Main fluids measured or derived byShell Global Solutions (and, previously, SEPTAR Flow Assurance) using consistentcold-finger and HTGC methods. B1 803 oil has the highest pour and cloud pointvalues of any of the fluids excluding the questionable 702W6 709 oil.

A brief comparison was done between B1 803 oil and Bonga South West fluids.The highest measured cloud points at Bonga SW were seen for the 803 and 812oils. However, these values (29 to 32°C including both cold-finger and HTGCtechniques) are lower than Bonga Main B1 803 oils. ASTM D97 pour points were 2to 4°C, similar to B1 803 oil. HTGC data were uniformly lower for the Bonga SW 803and 812 oils than for B1 803 oil over the full carbon number range. This is further

evidence than B1 803 is a suitable choice as a representative end-member fluid.






Pour Point (°C) Cloud Point (°C)

WellPay

SandSAM ID

ASTMD97

ASTMD5853

ColdFinger

HTGCThermoModel

B-3ST 690 NIG-O-88A 15 24 18

B-2ST3 702 NIG-O-85H <-45 22 32 31

B-2ST3 803 NIG-O-84H <-45 20 32 31

702W6 709 NIG-O-93X 10/7 29 to 33 38 34 to 35

B1 702 NIG-O-128A <-37/<-37

22 28

B1 803 NIG-O-129A 4/-7 36 37

Table 4.4 – Comparison of Bonga Pour and Cloud Points

4.3 Normal Paraffin Distributions

Normal paraffin distributions were measured using quantitative high-temperaturegas chromatography. Figure 4.2 shows distributions from the 702 and 803 sandssampled in the B1 and B2ST3 Wells. The B1 803 sample has the highestconcentrations over most of the carbon number range, which typically implies worsewax-related properties. Interpretation of the chromatogram did not find indications ofbiodegradation for this oil, indicating that is likely to be the (worst-case) end memberof the 803 fluids. The cloud point calculated from the HTGC correlation is 37°C,

in excellent agreement with the measured value of 35.6°C. This agreement is quitedifferent from the B2ST3 fluids (Ref 12), where the HTGC and lab values differed bymore than 10°C. The large difference in those values was speculated to be possiblekinetic inhibition of crystallisation from biodegradation products; the fact that theB1 803 fluid does not show this effect is indirect evidence that B1 803 shouldbehave as a primary oil.

4.4 Critical Wax Deposition Temperatures

Figure 4.3 shows the CWDTs calculated for three Bonga fluids: B2ST3 702, B2ST3803 and B1 803. (CWDTs for B1 702 oil are not shown because the oil isbiodegraded and its normal paraffin concentrations are uniformly lower than B1 803.

Therefore, it cannot be a worst case.) Although the paraffin distributions for B2ST3702 is lower than for B1 803, it has higher CWDTs owing to a lower API gravity(density effects). For this reason, some of the deposition simulations use mixedproperties (ie B1 803 deposition rate and B2ST3 702 CWDTs) as a sensitivity study.

Note: A recalibration of our thermodynamic model since the original studies(Ref 12) resulted in higher CWDTs for the B2ST3 fluids than in the originalreports. This effect is not substantial at expected arrival pressures. The newresults are used in this study.






1

10

100

1000

10000

20 30 40 50 60 70 80

Carbon Number

C o n c e n t r a t i o n , p p m w

t Bonga B2ST3 702Bonga B2ST3 803

Bonga B1 702

Bonga B1 803

Figure 4.2 – Normal Paraffin Distributions for Various 803 Bonga Oils

36

38

40

42

44

46

0 50 100 150 200 250 300 350 400

Pressure, bar

T e m p e r a t u r e ,

o C

B2ST3 803 Sand

B2ST3 702 Sand

B1 803 Sand

Figure 4.3 – Critical Wax Deposition Temperatures for Various Bonga Oils






4.5 Kinetic Wax Deposition Rates

Wax deposition rates were measured using the Shell cold-finger technique.Figure 4.4 shows a comparison of the whole-oil deposition rates (correlations ratherthan raw data are used to compare trends more easily). Looking at the B2ST3 803data, the deposition rate at the HTGC cloud point of 32°C yielded an extremely lowdeposition rate. When measured at the laboratory cloud point of 21°C, the rateincreased by more than an order of magnitude; however, the test temperature is wellbelow the expected arrival temperatures. The B1 803 oil sample, tested at its labcloud point of 36°C, shows deposition rates much higher than the B2ST3 oil at

32°C. Compared with the B2ST3 test at 21°C, the B1 oil is also higher, at low ∆Ts.(Since the flowlines have pipe-in-pipe insulation, the low-∆T range is the appropriaterange for comparison.) Therefore, the B1 803 wax deposition rate is the worst casefor the fluids we have tested. The B1 803 oil has a lower degree of biodegradationthan the B2ST3 702 and 803 sands and, in general, less benign wax properties thanother Bonga oils analysed (Ref 25) (B1 well 690, 702 and 710 oils, B2ST3 well 702

and 803 oils, B3ST well 690 and 702 oils). Therefore, we consider the B1 803 waxdeposition rate to be a likely worst case for the Bonga oils seen to date.

0.001

0.01

0.1

1

0 2 4 6 8 10

Oil-Wall ∆∆∆∆T, oC

D e p o s i t i o n R a t e , m

g / c m

2 - h r

Wax + Oil: B2ST3 @ 32 C

Wax + Oil: B2ST3 @ 21 C

Wax + Oil: B1 @ 36 C

Figure 4.4 – Comparison of Kinetic Wax Deposition Rates for Bonga 803 Oils






5.0 WAX DEPOSITION SIMULATION RESULTS

We used HYSYS steady-state simulator (Version 2.4.2, Build 3874) to simulate waxdeposition in three selected production flowlines (ie two east lines and one west line)that adequately represent the Bonga production scenario. A Shell proprietary waxmodel (SD-HYPR-Extensions_WAX-2.3-GS) and a multiphase hydraulic routine(GZM-NEWPRS) were also used. Pressure/Volume/Temperature (PVT) tuned fluidcompositions and flowline models (with topography, pipe and insulation properties)were provided by Wade Schoppa. Fluid composition of 702 sand was used in allsimulations since it is the primary pay sand with the highest CWDTs obtained fromB2ST3 sample.

We selected a matrix of three manifold temperatures, ie 100°F (38°C), 120°F (49°C)and 140°F (60°C), and three production rates, ie 5, 10 and 20MBLPD, to evaluatethe severity of wax deposition based on new deposition rates measured and newCWDTs. According to previous studies, a realistic low manifold temperature is about120°F at a low rate of 10MBLPD based on minimum turndown rates specified in the

basis of design (Schoppa and Kaczmarski, 2001 and Schoppa, 2002). Similarly,a manifold temperature of 100°F can be expected at 5MBPD according to aprevious study (Schoppa, 2002). Both flowing wellhead temperatures and pressuresas a function of rate as well as steady-state arrival temperatures at the FPSO fromeach PFL are not available to us at the start of the study.

All simulations were performed on a monthly basis (720 hours time period).

No water cut (ie 0%) is included in the production rates considered; thus, the resultsare more conservative. According to production data provided by Sada Iyer, watercut in late life can be as high as 80% in most PFLs.

Effect of gas lift at the riser base was also not included in this study. Possiblecooling could result from lift-gas injected at/near the riser base. Since heated lift-gas

is to be used (minimum specification of 90°F as it enters the flowline), its effect ontemperature drop is expected to be smaller. However, substantial cooling by theinjected gas may occur if the lift-gas in the injection line is allowed to cool down toseabed temperatures. Notice that this temperature reduction may result in higherwax deposition in the riser section or PFL downstream of the gas injection point.The effect is not quantifiable in this study.

Topside arrival pressure at the FPSO is set at about 300psi or 21bar (Bonga FieldDevelopment Plan, 2001). In late life, the topside arrival pressures will be 170psi(12bar) resulting in 1°F increase in CWDT at topside conditions. A sensitivity checkon the effect of this temperature increase at the topside in the presence of highwater cut on current wax mitigation strategy is not indicated to be significant.

As a sensitivity check, wax depositions were ran on all three sets of CWDTs fromB2ST3 702 sand, B2ST3 803 sand and B1 803 sand with the same B1 803 sanddeposition rates. The results indicate minimum variation on deposit volume and piggingfrequency over the selected conditions (refer to Appendix 4A Paragraphs 1.0 to 3.0).Results based on B2ST3 702 sand CWDTs are presented in Paragraph 5.1.

A sensitivity analysis was also performed on variation of the kinetic deposition rates(using B2ST3 803 sand and B1 803 sand data for comparison) on flowlinedeposition with the same B2ST3 702 sand CWDTs. The results indicate minimumvariation on deposit volume and pigging frequency over the selected conditionsusing B2ST3 deposition rates (refer to Appendix 4A Paragraph 4.0). Therefore,the use of deposition rates from B1 803 sand represents the worst case, as stated in

Paragraph 4.5.Tabulated data are listed in Appendix 4A.






5.1 East 10in Production Flowline Line

A 10in (22.6cm ID) East PFL with a flowline distance of 5.5 mile (8.8km) wasselected for simulation (representing PFL 1/2).

5.1.1 Arrival Temperatures at FPSO

Figure 4.5 illustrates the arrival temperature range at various manifold temperaturesand production rates. Range of CWDTs (39 to 43°C or 103 to 109°F) is provided toenhance comparison. As shown, the East 10in PFLs are in wax deposition rangefor most of the conditions simulated (below 60°C and 20MBLPD).

Bonga Main (East) - 8.8-km Flowline (22.6 cm ID)

0

10

20

30

40

50

60

0 5 10 15 20 25

Liquid Rate (MBLPD)

F P S O A r r i v a l T e m p e r a t u r e ( o C )

38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

CWDT at 21 bar

Figure 4.5 – FPSO Arrival Temperatures – East 10in PFL

5.1.2 Deposit Onset Location and Deposit Thickness

Figure 4.6 shows the location of wax deposition onset from topside and Figure 4.7shows the deposit growth rate (in maximum deposit thickness per month) at various

conditions. As shown, onset location is a strong function of manifold temperatureand production rate; whereas, maximum deposit thickness (near riser base in mostof the cases) is relatively insensitive to changes in temperature and rate due to thevery low kinetic deposit rates of Bonga fluids (lower than the oils of most Shell globalassets we tested). The deposit growth rate (in maximum thickness) is about 0.006in(0.15mm) per month. Notice this thickness is the maximum deposit thicknesspossible in the entire PFL per month, not an averaged thickness over the depositedarea. Therefore, maximum thickness does not always correlate with total depositvolume.






At 140°F (60°C) manifold temperature, waxes are likely to deposit only in the riserexcept for very low rates (such as 5MBLPD and below). If the manifold temperatureshappen to drop below 100°F (38°C), such as when the rates are low, wax depositionis predicted in the wellbore.


0

2000

4000

6000

8000

10000

12000

0 5 10 15 20 25

Liquid Rate (MBLPD)

D e p o s i t i o n O n s e t

L o c a t i o n f r o m

T o p s i d e ( m )

38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

Figure 4.6 – Deposition Onset Location – East 10in PFL


0.0

0.1

0.2

0.3

0.4

0.5

0 5 10 15 20 25

Liquid Rate (MBLPD)

M a x D e p o s i t T h i c k n e s s ( m m / m o n t h )

38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

Figure 4.7 – Deposit Growth Rate (in Maximum Thickness) – East 10in PFL






5.1.3 Deposit Volume and Pigging Frequency

Figure 4.8 illustrates the amount of wax deposit accumulated per month at variousconditions and Figure 4.9 illustrates the pigging frequency (number per year) basedon accumulated volume. As shown, the amount of waxes deposited and, thereforepigging frequency, are a strong function of manifold temperature and productionrate. Also, deposit volume and pigging frequency increase rapidly when rates arebelow 10MBLPD.

At a realistic low rate of 10MBLPD and 120°F (49°C) manifold temperature, lessthan 1bbl (about 0.1m3 or 100 litres) of waxes is deposited per month (ie depositgrowth rate in volume). This corresponds to a pigging frequency of aboutthree times per year in the 10in East PFLs at 10 MPLBD and 49°C at the PM.


0

50

100

150

200

250

300

350

400

0 5 10 15 20 25

Liquid Rate (MBLPD)

W a x D e p o s i t V o l u m e ( l i t e r / m o n t h )

38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

Figure 4.8 – Deposit Growth Rate (in Volume) – East 10in PFL


0

2

4

6

8

10

12

0 5 10 15 20 25

Liquid Rate (MBLPD)

P i g g i n g F r e q u e n c y ( # / y r )

38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

Figure 4.9 – Estimated Pigging Frequency – East 10in PFL






5.2 East 12in Production Flowline Line

A 12in (27cm ID) East PFL with a flowline distance of 3.6 mile (5.8km) was selectedfor simulation (representing PFLs 3/4 and 5/6).


Figure 4.10 illustrates the arrival temperature range at various manifoldtemperatures and production rates. Range of CWDTs is provided to enhancecomparison. As shown, the East 12in PFLs are in wax deposition range for mostof the conditions simulated (as long as they are below 60°C and 20MBLPD). Thearrival conditions are very similar to the East 10in PFL described in Paragraph 4.1.

Bonga Main (East) - 5.8-km Flowline (27 cm ID)

0

10

20

30

40

50

60

0 5 10 15 20 25

Liquid Rate (MBLPD)


38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

CWDT at 21 bar

Figure 4.10 – FPSO Arrival Temperatures – East 12in PFL

5.2.2 Deposit Onset Location and Deposit Thickness

Figure 4.11 shows the location of wax deposition onset from topside and Figure 4.12

shows the deposit growth rate (in maximum deposit thickness per month) at variousconditions. As shown, onset location is a strong function of manifold temperatureand production rates; whereas, maximum deposit thickness (near riser base in mostof the cases) does not show a large variation with respect to changes in temperatureand rate due to the very low kinetic deposit rates of Bonga fluids. The depositgrowth rate (in maximum deposit thickness) is about 0.01in (0.25mm) per month,slightly higher than the East 10in PFL case. Again, this is an indication of themaximum deposit thickness over the entire PFL per month of deposition.

At 140°F (60°C) manifold temperature, waxes are likely to deposit only in the riserexcept for very low rates (such as below 5MBLPD). If manifold temperatures dropbelow 100°F (38°C), wax deposition is predicted in the wellbore regardless of

production rates.










Bonga Main (East) - 5.8-km Flowline (27 cm ID)

0

1

2

3

4

5

6

7

8

0 5 10 15 20 25

Liquid Rate (MBLPD)


38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

Figure 4.14 – Estimated Pigging Frequency – East 12in PFL

5.3 West 10in Production Flowline Line

A 10in (22.6cm ID) West PFL with a flowline distance of 1.1 mile (1.8km) wasselected for simulation (representing PFLs 8/9 and 11/12).


Figure 4.15 illustrates the arrival temperature range at various manifoldtemperatures and production rates. Range of CWDTs is provided to enhancecomparison. As shown, the West 10in PFLs are out of wax deposition range ifmanifold temperatures are above 49°C (120°F) and above 5MBLPD. The arrivalconditions are with higher temperatures as compared to the East PFLs described inParagraphs 5.1 and 5.2 due to much shorter length.






Bonga Main (West) - 1.8-km Flowline (22.6 cm ID)

0

10

20

30

40

50

60

0 5 10 15 20 25

Liquid Rate (MBLPD)


38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

CWDT at 21 bar

Figure 4.15 – FPSO Arrival Temperatures – West 10in PFL

5.3.2 Deposition Onset Location and Deposit Thickness

Figure 4.16 shows the location of wax deposition onset from topside and Figure 4.17shows the deposit growth rate (in maximum deposit thickness per month) at variousconditions. As shown, onset location is a strong function of manifold temperatureand production rate; whereas, maximum deposit thickness (near riser base most ofthe cases) does not show a large variation with respect to changes in temperatureand rate due to the very low kinetic deposit rates of Bonga fluids. The depositgrowth rate (in maximum deposit thickness) is only about 0.006in (less than0.15mm) per month, much lower than the East PFL cases.

At 120°F (49°C) manifold temperature, waxes are likely to deposit only in the riser.If manifold temperatures drop below 100°F (38°C), wax deposition is predicted inthe wellbore regardless of production rates.







0

500

1000

1500

2000

2500

3000

3500

4000

0 5 10 15 20 25

Liquid Rate (MBLPD)

D e p

o s i t i o n O n s e t L o c a t i o n f r o m

T o p s i d e ( m )

38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

Figure 4.16 – Deposition Onset Location – West 10in PFL


0.00

0.05

0.10

0.15

0.20

0 5 10 15 20 25

Liquid Rate (MBLPD)

M a x D

e p o s i t T h i c k n e s s ( m m / m o n t h )

38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

Figure 4.17 – Deposit Growth Rate (in Maximum Thickness) –West 10in PFL






5.3.3 Deposit Volume and Pigging Frequency

Figure 4.18 illustrates the amount of wax deposit accumulated per month at variousconditions and Figure 4.19 illustrates the pigging frequency (number per year)based on accumulated volume. As shown, the amount of waxes deposited and,therefore, pigging frequency, are a strong function of manifold temperature andproduction rate. Also, deposit volume and pigging frequency increase rapidly whenrates are below 10MBLPD.

At a realistic low rate of 10MBLPD and 120°F (49°C) manifold temperature, lessthan 0.1bbl (0.01m3 or 8 litres) of waxes is deposited per month (ie deposit growthrate in volume). This corresponds to a pigging frequency of less than once peryear in the 10in West PFLs at 10MPLBD and 49°C at the PM. This means,for all practical purposes that the West PFLs should be pigged once peryear accordingly.


0

20

40

60

80

100

120

140

160

0 5 10 15 20 25

Liquid Rate (MBLPD)

W a x D e p o s i t V o l u m e ( l i t e r / m o n t h )

38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

Figure 4.18 – Deposit Growth Rate (in Volume) – West 10in PFL







0

1

2

3

4

5

0 5 10 15 20 25

Liquid Rate (MBLPD)


38 C, Manifold Temp

49 C, Manifold Temp

60 C, Manifold Temp

Figure 4.19 – Estimated Pigging Frequency – West 10in PFL






6.0 POUR POINT AND RESTART EVALUATION

Production of waxy crude oils can be a challenge due to the possible tendency togel at low temperatures. As these fluids are cooled, wax starts to precipitate andparticles become suspended in the fluid. As the temperature decrease continues,the concentration of wax particles increases and can ultimately reach a level atwhich an interlocking structural network is formed which changes the crude oil into agel with solid-like properties.

A commonly used indicator for the gelling temperature is the pour point. It should beemphasized however, that the pour point is not a well-defined rheological property.It is well known that the pour point of a crude oil is strongly dependent on thethermal history of the sample, causing the ‘minimum-maximum’ pour pointphenomenon. Depending on the thermal history, the measured pour point can varyover a temperature range. For some oils this range can be as large as 50°C, whileother waxy crudes hardly exhibit any difference.

The pour point is especially sensitive to the pre-conditioning temperature of the oil.The pre-conditioning temperature determines whether all the wax is entirelydissolved into the oil or if precipitates are already present in the fluid. If the coolingprocess is started with all the wax dissolved, the process will result in a minimumtype pour point, while starting at a lower pre-conditioning temperature will result inan increase of pour point. Additionally, the pour point of a crude oil is dependent onthe cooling rate. If the rate is sufficiently high, the cooling process can outrun thewax precipitation kinetics and thus lower the pour point.

As a result, it is therefore important that a pour point test is properly conducted.The sensitivity of pour point measurements is recognised by the American Societyfor Testing and Materials (ASTM) and special test procedures for crude oils havebeen developed to address these effects (a description of the different pour pointtests is given in Appendix 4B). Furthermore, it is also important to base designconsiderations on the most relevant data. The maximum pour point of an oil can beabove the minimum ambient conditions, while the minimum pour point can be belowthe ambient temperature. Generally speaking, for wellstream flows the operatingtemperatures are high and the cooling process continuous, a minimum pour point isthe most representative. However, in case of dead oil circulation or, for example, anoffloading line, due to the lower initial temperature and intermittent cooling processthe maximum pour point may be more appropriate.

Finally, it is not only the gelling temperature but also the gel strength and fluidrheology that determines whether it will be possible to restart a system after shut-in.In order to include these effects into an operability study, a model pipeline restart

test is necessary.

6.1 Dead Oil Pour Point

As with other wax-related properties, Bonga pour points show large variabilityacross the field (Ref 11). Reported measurements of pour points from eight Bongasamples ranged from less than -45°C to 15°C. The highest of the reliable resultswere obtained for Bonga B1 803 samples. The results were measured by SPDCWarri and indicate an upper pour point of 10°C. This is above the ambient seafloortemperature and was therefore a major driver for this study.






In order to determine if a possible gelling problem exists, a stored sample of B1 803oil (SAM ID NIG-O-129A; WTC ID 6140) was located and provided for further study.After it was validated that the sample had not been altered during storage/transfer,with use of High Temperature Gas Chromatography (HTGC), a series of pour point

measurements were conducted at Westhollow Technology Center (WTC) andOil-phase DBR.

The results of the pour point measurements on the NIG-O-129A sample under stocktank conditions are shown in Table 4.5. The minimum pour point measurementconducted at WTC indicates a lower pour point of -7°C, which is well below theambient seafloor temperature. This value was confirmed by Oilphase DBR, where aminimum pour point of -8°C was measured. The maximum pour points measured byWTC and Oil-phase DBR (via third-party lab) were found to be 4 and 3°Crespectively, in good agreement with each other. These results are just at theseafloor temperature but are several degrees lower than the upper pour point of10°C measured by the SPDC Warri lab. The observed difference is within the

reproducibility of the measurement as reported by ASTM. This difference in pourpoints could potentially lead to wrong conclusions with regard to whether or not arestart problem should be anticipated due to this the issue was further studied byconducting a Model Pipeline Test (MPT). The results of this test are discussed in alater section.

For a comparison of the Bonga 803 results to other Bonga sands, refer toAppendix 4C Paragraph 2.0.

Laboratory ProtocolUpper

Pour Point (°C)Lower

Pour Point (°C)

SPDC Warri ASTM D5853-95 10 N/A

Shell WTC ASTM D5853-95 4 -7

Oil-phase DBR ASTM D97 (modified) N/A -8

Oil-phase DBR(via third-party Lab)

ASTM D5853-95 3 N/A


ASTM D97 0 N/A

Table 4.5 – Measured Pour Points for Bonga B1 803 Sample NIG-O-129A






6.2 Live Oil Pour Point

Solution gas has an impact on the pour point of a crude oil, therefore Oil-phase DBRalso measured Bonga 803 oil pour point under live conditions.

The method used to measure the live oil pour point was similar to the modifiedASTM D97 used by Oil-phase DBR for the minimum pour point under stock tankconditions. For the live oil test the oil is introduced into a sapphire cell initially filledwith synthetic gas mixture at test pressure. After the cell is charged, the oil is thenheated to the reservoir temperature under seal (to avoid loss of light ends andoxidation) for an extended period of time. The composition of the synthetic gasmixture used for the measurement was based on the expected compositioncalculated by HYSYS using a Bonga 803 oil model. The test pressure of the testwas 300psig, which is representative for a blowndown flowline.

The pour point of the Bonga 803 oil under the described test conditions was -6°C+/- 1°C (21°F +/- 2°F). Comparison of the live oil results with the dead oil results

shows that the difference is small and within the uncertainties of the tests. It istherefore concluded that the effect of solutions gas is small to negligible at the testconditions.

6.3 Gel Strength Measurement

Although that a pour point is a good indicator whether or not a gelling problem mightexist, it is ultimately the gel strength that will determine if a pipeline can be restarted.Therefore in addition to the pour point measurements, Oil-phase DBR was alsoasked to conduct a gel strength measurement.

The gel strength was measured by simulating a restart situation of Bonga 803 oilusing an MPT. The MPT system consists of a 7mm ID × 6m long stainless steel coil

submerged in a temperature-controlled bath. The test is initiated by filling the loopwith oil and circulating it around to remove all entrapped air bubbles. Once this stepis completed, the flow is stopped and the test is started by cooling the oil at aspecified cooling rate. The cooling process is continued until the target temperatureis reached, after which the oil/gel is allowed to age for 12 hours to let the geldevelop its strength.

Once the gel is allowed to age, the restart process is started by pressurising the coilwith nitrogen gas. The nitrogen pressure is increased in steps of 1psi over a 0 to10psi range, 2psi over a 10 to 30psi range and 5psi thereafter, with 5 minutesbetween each pressure step to allow the oil to ungel. The lowest pressure at whichthe oil is observed to have started is then deemed as the yield pressure. Finally,

because the yield pressure is dependent on the diameter of the pipe, the yield/gelstrength is calculated by using a force balance:

L

D p yield

yield 4

=τ

Where: D = Coil diameter, L = Coil length






Similar to pour point measurements, MPT pre-conditioning temperature and coolingrates are important parameters. Generally, the pre-conditioning temperature, coolingrate and restart temperature are chosen such that they closely represent actual fieldconditions. For the present MPT test, however, a different approach was chosen.

The pour point measurements conducted as part of current study showed an upperpour point for the Bonga 803 sample that was 6°C lower than the value previouslymeasured by SPDC Warri. The seafloor temperature is 6°C below the Warri pourpoint and therefore we chose a restart temperature 6°C below the DBR-measuredpour point of 3°C (Trestart = -3°C). The ASTM pre-conditioning and cooldownprocedure for pour points was to assure gelling at this temperature. By doing this,we ensured that a gel would form and that the results would be conservative.

Following the procedure described above, the MPT resulted in a gel yield strength of3Pa at a restart temperature of -3°C for the Bonga 803 oil sample. In order todetermine if this would lead to any problems during a restart, the required restartpressure was calculated for the Bonga flowlines, refer to Table 4.6. The calculations

show that the required restart pressure for all the flowlines will be significantly lowerthan the maximum available pump pressure. The highest required restart pressureis expected for 10in East PFLs 1 and 2, as can be seen in the tables. However,even for this PFL the restart pressure is only 19% of the maximum available pumppressure. Based on these results, it is therefore concluded that no restart problemswill occur.

6.4 Effect of Bonga Fluid Blending

The pour point and restart analysis, as discussed in the previous paragraphs,focuses on pure Bonga 803 oil. However, the pipeline fluids will consist of a blend offluids with a pour point that is a function of the blend. The pour points of the otherBonga fluids were found to be significantly lower and Bonga 803 oil will only bepresent in a relatively small percentage, therefore the blend of 803 with other Bongaoils is expected to have a lower pour point. This effect is illustrated by Figure 4.6,which shows the pour point of a blend of 803 with 702 oil.






West 10in PFL East 10in PFL 1/2 East 12in PFL 3/4 and 5/6 East 12in PFL 5/6 only

Pipe ID 0.226m Pipe ID 0.226m Pipe ID 0.27m Pipe ID 0.27m

Pipe Length 7000m Pipe Length 21000m Pipe Length 15000m Pipe Length 9800m

YieldStress

(Pa)

RestartPressure

(bar)

YieldStress

(Pa)

RestartPressure

(bar)

YieldStress

(Pa)

RestartPressure

(bar)

YieldStress

(Pa)

RestartPressure

(bar)

1 1.24 1 3.72 1 2.22 1 1.45

2 2.48 2 7.43 2 4.44 2 2.90

31

3.72

31

11.15

31 6.67

3

14.36

6 7.43 6 22.30 6 13.33 6 8.71

12 14.87 12 44.60 12 26.67 12 17.42

24 29.73 16.14 60.002

24 53.33 24 34.84

30 37.17 27.00 60.002

30 43.56

48.43 60.002

41.33 60.002

1 Yield stress measured for Bonga 803 oil.

2 Maximum Pump Pressure.

Table 4.6 – Required Restart Pressures for Bonga Production Flowlines (PFL)

Figure 4.20 – Pour Points of Bonga B1 702 and B1 803 Blends

Blend Pour Points of Bonga B1 702 and 803 Oils

-40

-30

-20

-10

0

10

0 20 40 60 80 100

803 Oil Fraction, % vol

U

p p e r P o u r P o i n t , C

Upper limit; actual value may be lower.






6.5 Impact on Chemical Treatment

The maximum pour points were measured in the 4 to 10°C range, however a stronggel was not formed at these temperatures. Based on our results, we therefore do notsee a need to treat the Bonga oils for pour point depression. However,we recommend that ongoing surveillance be performed to confirm this withproduced fluids. Currently, vendors are preparing chemical tenders for Bonga.We will review their recommendations when they are submitted and compare toour results.

7.0 WAX RISKS AND WAX MANAGEMENT STRATEGY

7.1 Risks and Basic Management Strategy

In the course of this study, questions regarding wax risks have been answered.

The B1 803 oil has been established as a primary (ie non-biodegraded) oil and is

the likely worst-case fluid for wax properties (excluding CWDT, which is slightlyhigher for the B2ST3 702 oil).

The B1 803 kinetic wax deposition rate has been measured and used as the basisfor wax deposition calculations for the production system. From these calculations,a base-case pigging interval is recommended to be three times yearly for the eastPFLs and once yearly for the west PFLs.

Although the B1 803 pour point is found to be at seafloor temperature, the oil onlyformed a weak gel. Therefore, based on these fluid properties no restart problemsare anticipated and thus no pour point depressant is required.

7.2 Surveillance and Adjustments to Management Strategy

The key to managing wax risks is production surveillance. The surveillance plan forBonga fluids should include the following.

Monitor arrival temperatures and pressures and compare to relevant CWDT curves.Compare to pigging tables in Appendix 4A and adjust pigging frequency ifnecessary.

Monitor pigging returns to determine solid volumes. If volumes are large, morefrequent pigging is recommended.

Monitor pressure drop while pigging. Total pressure drop can be separatedas follows:

∆Ptotal = ∆Pflow + ∆Ppig + ∆Pwax

The pressure drop from flow resistance (∆Pflow) should be constant if oil circulationrate is constant. The pig itself will cause pressure drop (∆Ppig), but this should alsobe constant during the pig run. In addition, the wax removed will cause pressure

drop (∆Pwax), which will increase proportionally with the amount of wax removed asthe pig traverses the flowline loop. Unfortunately, random pressure fluctuations may

make it impossible to estimate ∆Pwax from the pressure data. However, if ∆Pwax canbe measured and it is greater than 50 to 100psi, pigging frequency should beincreased. If ∆Pwax is less than 50psi, follow recommendations in the pigging table.






Monitor produced fluid properties. It is recommended that the samples be taken on aper-well basis if possible. If not practical, samples should be taken from individualflowlines.

Samples should be taken at least every 6 months or more often if significantproduction changes occur (eg production from new wells or reservoirs, majorchange in production fraction from a given well or reservoir).

Cloud points should be measured and compared to the measured (cold-finger)values in Table 4.5. If higher-than-expected cloud points are measured and thesystem is operating in the deposition regime (arrival T below CWDT), operationsshould pig sooner than planned and check pigging returns for excessive volume.

Pour points should be measured. If upper pour point exceeds 10°C, pour pointdepressant should be injected as soon as possible. If possible, flowline shut-inshould be postponed until chemical injection has begun and at least one line fill oftreated oil has been produced. Treated production oil should be sampled and tested

to confirm pour point has been lowered.

8.0 HEALTH, SAFETY AND ENVIRONMENT (HSE)

Assessment of the potential risks associated with the interpretation, usage, andfield-implementation of the technical results of the present study was carried out.It was determined that such risks are very low. Additionally, it was determined thatthe engineering predictions and recommendations of this study do not raise anysignificant HSE issues or concerns. It is further advised that the users of thistechnical report conduct their own HSE risk assessment of the usage andimplementation of the results and recommendations of the present report.




Section 4 Appendix 4A Sensitivity Analysis of CWDTs and Deposition Rates


Appendix 4A

Sensitivity Analysis of CWDTs and Deposition Rates

Table of Contents

1.0 EAST 10IN PFL DATA AND CWDT SENSITIVITY – 720 HOURS SIMULATION ......................................................................................33

2.0 EAST 12IN PFL DATA AND CWDT SENSITIVITY – 720 HOURS SIMULATION ......................................................................................34

3.0 WEST 10IN PFL DATA AND CWDT SENSITIVITY – 720 HOURS SIMULATION ......................................................................................35

4.0 EAST 10IN PFL – DEPOSITION RATE SENSITIVITY – 720 HOURS SIMULATION ......................................................................................36






1.0 EAST 10IN PFL DATA AND CWDT SENSITIVITY –720 HOURS SIMULATION

Basis: 803 B1 Deposition Rates Basis: 803 B1 Deposition Rates Basis: 803 B1 Deposition Rates803 B2ST3 CWDT's 803 B1 CWDT's 702 B2ST3 CWDT's

702 Fluid Composition 702 Fluid Composition 702 Fluid Composition

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 17.8 23.8 29.9 5 17.8 23.8 29.9 5 17.8 23.8 29.9

10 23.7 32 40.4 10 23.7 32 40.4 10 23.7 32 40.4

20 27.6 37.3 47.1 20 27.6 37.3 47.1 20 27.6 37.3 47.1

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 10862 5913 1788 5 10862 6847 2359 5 10862 7575 3123

10 10862 1603 0 10 10862 2838 99 10 10862 4439 240

20 10862 302 0 20 10862 535 0 20 10862 1009 0

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 0.11938 0.13100 0.09006 5 0.11938 0.13230 0.14219 5 0.11938 0.13324 0.14308

10 0.07443 0.05161 0 10 0.07443 0.08216 0.02038 10 0.07443 0.08270 0.02451

20 0.04493 0.01264 0 20 0.04493 0.01927 0 20 0.04493 0.02513 0

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 324.1 197.7 69.7 5 324.1 230.2 98.1 5 324.1 255.5 125.2

10 204.7 35.4 0 10 204.7 68.6 1.6 10 204.7 101.6 4.7

20 125.6 2.9 0 20 125.6 5.6 0 20 125.6 13.0 0

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 35 57 161 5 35 49 115 5 35 44 90

10 55 317 -- 10 55 164 7013 10 55 111 2391

20 90 3913 -- 20 90 2004 10000 20 90 866 10000

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 10.4 6.3 2.2 5.0 10.4 7.4 3.1 5.0 10.4 8.2 4.0

10 6.6 1.1 0 10.0 6.6 2.2 0.1 10.0 6.6 3.3 0.2

20 4.0 0.1 0 20.0 4.0 0.2 0 20.0 4.0 0.4 0

FPSO Arrival Temperature (oC) FPSO Arrival Temperature (

oC) FPSO Arrival Temperature (

oC)

Manifold Temperature (oC) Manifold Temperature (

oC) Manifold Temperature (

oC)

Deposit Onset from Topside (m) Deposit Onset from Topside (m) Deposit Onset from Topside (m)



oC)

Max Deposit Thickness (mm) Max Deposit Thickness (mm) Max Deposit Thickness (mm)



oC)

Wax Deposit Volume (liter) Wax Deposit Volume (liter) Wax Deposit Volume (liter)



oC)

Pigging Interval (days) Pigging Interval (days) Pigging Interval (days)

Manifold Temperature (oC) Manifold Temperature (oC) Manifold Temperature (oC)

Pigging Frequency (#/yr) Pigging Frequency (#/yr) Pigging Frequency (#/yr)



oC)








3.0 WEST 10IN PFL DATA AND CWDT SENSITIVITY –720 HOURS SIMULATION

Basis: 803 B1 Deposition Rates Basis: 803 B1 Deposition Rates Basis: 803 B1 Deposition Rates

803 B2ST3 CWDT's 803 B1 CWDT's 702 B2ST3 CWDT's

702 Fluid Composition 702 Fluid Composition 702 Fluid Composition

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 26.3 35.2 44 5 26.3 35.2 44 5 26.3 35.2 44

10 29.2 39.2 49.2 10 29.2 39.2 49.2 10 29.2 39.2 49.2

20 30.8 41.5 52.1 20 30.8 41.5 52.1 20 30.8 41.5 52.1

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 3552 535 0 5 3552 811 0 5 3552 1035 0

10 3552 64 0 10 3552 240 0 10 3552 480 020 3552 0 0 20 3552 0 0 20 3552 116 0

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 0.13503 0.05478 0 5 0.13503 0.07290 0 5 0.13503 0.08300 0

10 0.07903 0.01859 0 10 0.07903 0.02337 0 10 0.07903 0.03408 0

20 0.04627 0 0 20 0.04627 0 0 20 0.04627 0 0

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 126.04 15.08 0 5 126.04 25.33 0 5 126.04 37.42 0

10 76.50 0.95 0 10 76.50 4.45 0 10 76.50 8.26 0

20 45.60 0 0 20 45.60 0 0 20 45.60 2 0

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 89 746 -- 5 89 444 -- 5 89 301 10000

10 147 11856 -- 10 147 2528 -- 10 147 1362 10000

20 247 10000 -- 20 247 10000 -- 20 247 6981 10000

803 B2ST3 803 B1 702 B2ST3

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 4.0 0.5 0 5.0 4.0 0.8 0 5.0 4.0 1.2 0

10 2.4 0.0 0 10.0 2.4 0.1 0 10.0 2.4 0.3 0

20 1.5 0 0 20.0 1.5 0 0 20.0 1.5 0.1 0


oC) FPSO Arrival Temperature (

oC)



oC)

Deposit Onset from Topside (m) Deposit Onset from Topside (m) Deposit Onset from Topside (m)



oC)

Max Deposit Thickness (mm) Max Deposit Thickness (mm) Max Deposit Thickness (mm)



oC)

Wax Deposit Volume (liter) Wax Deposit Volume (liter) Wax Deposit Volume (liter)



oC)

Pigging Interval (days) Pigging Interval (days) Pigging Interval (days)



oC)

Pigging Frequency (#/yr) Pigging Frequency (#/yr) Pigging Frequency (#/yr)



oC)






4.0 EAST 10IN PFL – DEPOSITION RATE SENSITIVITY –720 HOURS SIMULATION

Basis: 702 B2ST3 CWDT's Basis: 702 B2ST3 CWDT's

Dep Rates: 803 B2ST3 Dep Rates: 803 B1

Fluid Composition: 702 Fluid Composition: 702

803 B2ST3 803 B1

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 17.8 23.8 29.9 5 17.8 23.8 29.9

10 23.7 32 40.4 10 23.7 32 40.4

20 27.6 37.3 47.1 20 27.6 37.3 47.1

803 B2ST3 803 B1

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 10862 5913 1788 5 10862 7575 3123

10 10862 1603 0 10 10862 4439 240

20 10862 302 0 20 10862 1009 0

803 B2ST3 803 B1

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 0.00616 0.00846 0.01062 5 0.11938 0.13324 0.14308

10 0.00197 0 0 10 0.07443 0.08270 0.0245120 0.00057 0 0 20 0.04493 0.02513 0

803 B2ST3 803 B1

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 10.7 10.6 7.5 5 324.1 255.5 125.2

10 3.4 0 0 10 204.7 101.6 4.720 1.0 0 0 20 125.6 13.0 0

803 B2ST3 803 B1

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 1054 1062 1504 5 35 44 9010 3353 -- -- 10 55 111 239120 11590 -- -- 20 90 866 --

803 B2ST3 803 B1

Liquid Rate

(MBLPD)38 49 60

Liquid Rate

(MBLPD)38 49 60

5 0.3 0.3 0.2 5.0 10.4 8.2 4.0

10 0.1 0 0 10.0 6.6 3.3 0.2

20 0 0 0 20.0 4.0 0.4 0


oC)


oC)

Deposit Onset from Topside (m) Deposit Onset from Topside (m)


oC)

Max Deposit Thickness (mm) Max Deposit Thickness (mm)


oC)

Wax Deposit Volume (liter) Wax Deposit Volume (liter)


oC)

Pigging Interval (days) Pigging Interval (days)


oC)

Pigging Frequency (#/yr) Pigging Frequency (#/yr)


oC)




Section 4 Appendix 4B Pour Point Measurement Techniques and Uncertainties


Appendix 4BPour Point Measurement Techniques and Uncertainties

There are currently at least five ASTM pour point protocols, most of which are designed forpetroleum products rather than crude oils. The two most widely used are ASTM D97-96a andD5853-95. As implemented by Shell, these tests require 100 to 250ml of fluid. ASTM D97is an older petroleum-products pour point protocol that requires heating to a prescribedtemperature (60°C) and cooling in a series of baths until the oil gels or solidifies. Shell hasdevised a ‘mini’ D97 pour point that uses 30ml of sample. The ‘mini’ pour point has beencalibrated to the ASTM D97 method. The repeatability (95% confidence limits, same lab)of D97 pour points (measured on fuel oils) is reported by ASTM to be 5°F; the reproducibility(95% confidence limits, different labs) is 12°F. In addition, chemical vendors use variations ofASTM D-97 to screen chemicals and choose concentrations. They may use very smallvolumes (1 to 2ml per sample), and results have higher uncertainty than other protocols.

For that reason, validation after pre-screening is always recommended, using much closeradherence to standard protocols.

ASTM D5853 is designed specifically for crude oils and recognises the potentially strongeffect of thermal history on the oil gelling temperature. Two separate heating and coolingprotocols are employed in order to see the effects of two substantially different thermalhistories. The minimum pour point protocol requires heating to 105°C and cooling in air for20 minutes at room temperature before entering a series of cooling baths. This protocollowers the measured pour point in two ways:

• It ensures that all wax is in solution before cooling is started

• It cools relatively quickly, potentially ‘outrunning’ the wax kinetics and reaching a lower

temperature before the gel formsThe maximum pour point protocol requires heating to 60°C or less, cooling in air for24 hours, a short reheat to 45°C followed by the cooling baths. This protocol raises themeasured point by allowing a long time for ‘seed crystals’ to form at room temperature, whichin turn decreases the time for gel formation. ASTM D5853 is difficult to adapt to smallvolumes; therefore, we have devised no ‘mini’ technique for ASTM D5853. The repeatabilityof D5853 using crude oils is reported by ASTM to be 6 to 12°F, but the reproducibility is ashigh as 32 to 40°F(!). Clearly, minor variations between labs could have large consequences.ASTM D5853 addresses the problems specific to the pour points of crude oils, therefore it isregarded as the better test method.



Shell Nigeria E & P Company Ltd. Confidential

Section 4 Appendix 4C Tables from Westrich (1999) Report (SIEP.99.6096)


Appendix 4CTables from Westrich (1999) Report (SIEP.99.6096)

Table of Contents

1.0 FLUID PROPERTY DATA FOR BONGA OILS WAX MEASUREMENTSFOR STOCK-TANK (DEAD) CONDITIONS................................................................39

2.0 FLUID PROPERTY DATA FOR BONGA OILS: SELECTED GEOCHEMISTRYAND PVT PARAMETERS ..........................................................................................40

3.0 BEST ESTIMATES OF KEY WAX-RELATED PROPERTIES FOR BONGA OILSUNDER STOCK-TANK (DEAD) CONDITIONS .........................................................41





S e c t i on4 A p p en d i x4 C

T a b l e sf r omW e s t r i ch ( 1 9 9 9 ) R e p or t ( S I E P . 9 9 . 6 0 9 6 )

O P R M- 2 0 0 3 - 0

3 0 2 D

P a g e

4 0 o f 4 1

3 0 - A p r i l - 2 0 0 6

Gelchemistry(RTS)

PVT D(SIDS, Bon

PaySand

Well

Sample IDNo

(OMC # –RTS)

Depth Top(ss – ft)

APITotal AcidNumber(TAN)

1Stage ofBiodeg

(from HRGC)API

GoR(scf/bbl)

DU

670 B-1 OMC-7010 6756 21.2 1.42 W5 – Mod 21 325

671 B-2 OMC-8270 – – – W5 – Mod – –

690 B-3ST OMC-8074 9290 29.1 0.76 W4 – Mild 30 550

702 B-1 OMC-7011 8040 27.9 0.76 W3/W4 – Mild 28 660 702 B-2ST3 OMC-8441 8925 29.3 0.74 W3 – Mild 29 500

702 B-3ST – 9342 – – – 29 –

710 B-1 OMC-7012 9182 32.6 0.39 W1 – Onset 33 1090

803 B-1 OMC-7013 9920 34.9 0.35 W0 – None 35 1420

803 B-2ST3 OMC-8442 10,900 30.2 0.76 W2/W3 – Light 30 780

1 Stage of biodegradation is based on the criteria in Utech et al 1999, which relates the characteristics of whole oil/extent of biodegradation. The High Resolution Gas Chromatography (HRGC) data for the Bonga crudes, on which can be found in Buiskool Toxopeus and van der Veen (1999).



S e c t i on4 A p p en d i x4 C

T a b l e sf r omW e s t r i ch ( 1 9 9 9 ) R e p or t ( S I E P . 9 9 . 6 0 9 6 )

O P R M- 2 0 0 3 - 0

3 0 2 D

P a g e

4 1 o f 4 1

3 0 - A p r i l - 2 0 0 6

Based on Measured Data Predicted Values Based on Biodegradation Model

Pay Sand WellPour Point

(°C)Std Cloud Point

(°C)

1Stage of Biodegradation

(from HRGC)Pour Point

(°C)

670 B-1 < -35 W5 – Mod < -35

671 B-2 W5 – Mod < -35

690 B-3ST < -35 -3 to 15 W4 – Mild -33

702 B-1 < -35 24 W3/W4 – Mild -18

702 B-2ST3 < -35 22 to 23 W3 – Mild -18

702 B-3ST < -35 – –

710 B-1 6 to 10 W1 – Onset 12

740

803 B-1 9 to 15 21 to 24 W0 – None 12

803 B-2ST3 < -35 20 W2/W3 – Light -10

709* 702W6* 7 to 10* 29 to 33* W1 – Onset* 12*

1Stage of biodegradation is based on the criteria in Utech et al 1999, which relates the characteristics of whole oil/gextent of biodegradation. The HRGC data for the Bonga crudes, on which this interpretation is based, can be foundvan der Veen 1999.

* Inserted for comparison into Westrich’s (Ref 25) table from reference (Ref 17).




Section 5 Offloading Riser Wax Assessment


Section 5Offloading Riser (Wax Assesement)

Table of Contents


2.0 BACKGROUND............................................................................................................3

3.0 OIL OFFLOADING RISER LAYOUT AND CHARACTERISTICS.................................4

4.0 WAX DEPOSITION SIMULATION RESULTS ..............................................................6

4.1 Simulation Basis ................................................................................................6

4.2

Wax Deposition and Growth Rate......................................................................6

4.3 Pigging...............................................................................................................9

4.4 5-year Wax Deposition Profile..........................................................................11

4.5 Effect of Riser Buoy Insulation on Wax Deposition...........................................13

5.0 HEALTH, SAFETY AND ENVIRONMENT (HSE) .......................................................15

TABLES

Table 5.1 – BOOR Data – Basis.............................................................................................5

Table 5.2 – Wax Properties Basis ..........................................................................................6

FIGURES

Figure 5.1 – BOOR Layout .....................................................................................................4

Figure 5.2 – Ambient Temperatures as a Function of Water Depth ........................................5

Figure 5.3 – SPM Arrival Temperature ...................................................................................7

Figure 5.4 – Deposit Growth Rate – Maximum Thickness ......................................................8

Figure 5.5 – Effect of Offloading Rate and Inlet Temperature on Deposition Profile ...............8

Figure 5.6 – Deposit Growth Rate – Cumulative Deposit Volume...........................................9

Figure 5.7 – Estimated Pigging Frequency...........................................................................10

Figure 5.8 – Estimated Pigging Interval ................................................................................11

Figure 5.9 – 5-year Wax Deposition Profile ..........................................................................12

Figure 5.10 – Total Deposit Volume Over a 5-year Period – 32°C Inlet and 600MBPD ........12

Figure 5.11 – Effect of Buoy Insulation on Fluid Temperature Profile – 600MBPD ..............13







FIGURES

Figure 5.12 – Effect of Buoy Insulation on Wax Deposition Profile –600MBPD, 49°C Inlet .....................................................................................14

Figure 5.13 – Effect of Buoy Insulation on Wax Deposit Volume ..........................................14

Figure 5.14 – Effect of Buoy Insulation on Pigging Interval...................................................15

APPENDICES

Appendix 5A – Raw Data – 720-hour Simulation ...........................................................................16






1.0 EXECUTIVE SUMMARY

The wax deposition risk and pigging requirement of the Bonga Oil Offloading Riser(BOOR) was re-evaluated using updated wax-related fluid properties.

The key findings are:

• Wax deposition/risk in BOOR is less severe than previously predicted usingupdated wax-related fluid properties and models

• Pigging is recommended at least once per year upon startup. Pigging operationcan be optimised by checking deposits in the pig return and monitoring arrivaltemperatures

• Inlet temperature has a strong effect on deposit thickness, deposit volume andpigging frequency

• Effect of insulation (assumed C-float) from the buoyancy elements near themid-point of the riser on deposition profile is observed but not significant enoughto alter the pigging recommendation.

• If the BOOR is not pigged:

– Maximum wax deposit thickness is predicted to be 1mm (after 1 year)and 3mm (after 5 years) at 32°C (90°F) inlet temperature and 600MBPDoffloading rate

– Cumulative deposit volume is predicted to be 20bbl (after 1 year) and 60bbl(after 5 years) at 32°C (90°F) inlet temperature and 600MBPD offloading rate

We recommend pigs used in pigging BOOR be customised by pig manufacturers.Care should also be taken to design procedures for proper solid handling due to wax

precipitates in the FPSO hull when offload and deposits from pig return.

2.0 BACKGROUND

A wax deposition study of the BOOR was carried out in September 2000 (Ref 18).Since then, production functions have been updated with new fluid propertyinformation and Shell deposition models have been improved. A Bonga waxanalysis (Ref 19) was performed to reassess the wax-related fluid properties andwax deposition risks in the Bonga production flowlines to the FPSO. As a follow-upof the Bonga production flowline study, wax deposition and pigging requirementswere re-evaluated for the BOOR from the FPSO to the Single Point Mooring (SPM)offloading buoy (which connected to oil tanker) using updated wax properties

and models.








Pinlet Riser Length

(m)Riser ID

(in)

RiserThickness

(in)

Fusion-bondEpoxy

Coating (in)

Uod Factor(W/m2-°C)

34.5 2265 20 1 0.02 150

Tin (°C) No of Riser

BuoySection (m)

Offload(hr/5 days)

Oil Volume perOffload(MMbbl)

OffloadRate

(MBPD/line)

32-66 2 450 20 1 600

Table 5.1 – BOOR Data – Basis

Figure 5.2 – Ambient Temperatures as a Function of Water Depth






4.0 WAX DEPOSITION SIMULATION RESULTS

We used the HYSYS steady-state simulator (version 2.4.2, build 3874) to simulatewax deposition in the offloading riser. A Shell proprietary wax model (SD-HYPR-Extensions WAX-2.3-GS) and a multiphase hydraulic routine (GZM-NEWPRS)were also used. Processed and stabilised stock oil fluid composition was used torepresent the offloaded oils (predominantly 702 sand since it is the primary pay sand).

Tabulated raw data are listed in Appendix 5A.

4.1 Simulation Basis

The basis of simulation is listed below:

• Three offloading riser inlet temperatures ie 32°C (90°F), 49°C (120°F) and 66°C(150°F), were used to illustrate the effect of inlet temperature on wax deposition.According to previous design (Ref 23) oil is to be cooled to 43°C (110°F) viacrude cooler prior to entering the FPSO hull and the offloading temperature is

about 38 to 43°C (100 to 110°F)

• Two oil offload flow rates, ie 600MBPD (1mmbbl oil/offload) and 900MBPD(1.5mmbbl/offload), were used to illustrate the effect of flow rate on waxdeposition

• Simulations were performed on a basis of 20-hour offload operation every fivedays (eg 6 offloads over 30-day period)

• No water cut (ie 0%) is assumed in the oils offloaded and the Gas/Oil Ratio(GOR) is negligible (ie processed and stabilised oil)

• The same wax-related fluid properties used in the Bonga production flowline wax

study were used, ie Critical Wax Deposition Temperatures (CWDTs) of B2ST3702 sand and kinetic deposition rates of B1 803 sand listed in Table 5.2 (Ref 19)The CWDT is approximately 43°C (109°F) at 10 to 20bar range (< 300psi)

Wax Properties CWDTs Kinetic Disposition Rates

Sand 702 B2ST3 803 131

Table 5.2 – Wax Properties Basis

4.2 Wax Deposition and Growth RateFigure 5.3 illustrates the effect of inlet temperature on arrival conditions at SPM(oil tanker loading point) over the range of flow rates studied. It is clear that there willbe wax deposition in the risers over most of the conditions studied and in the FPSOhull. Cares should be taken to properly handle wax precipitates/solids as suggestedin previous study (Ref 18). However, no wax deposition occurs when inlettemperatures are above 52 to 55°C range (126 to 130°F) depending on flow ratessince the SPM arrival temperatures will be higher than the CWDTs. No informationabout the heating capacity of the FPSO is available to us.






Figure 5.4 illustrates the maximum deposit growth rate. The maximum rate isestimated to be < 0.1mm/month (< 0.004in/month).

Note: This is the maximum thickness change possible in the entire riser system.

The deposit thickness is not uniformly distributed due to variations in thetemperature profile. A higher rate of 900MBPD will result in thinner deposits owing

to smaller oil-wall ∆T caused by higher heat-transfer coefficients.

Figure 5.5 illustrates the BOOR deposition profile after a 30-day period (six offloads)at two flow rates and two inlet temperatures. At 49°C (120°F) inlet temperature,higher flow rates move the wax onset location further downstream and most ofdeposits are located near the SPM. However, 32°C (90°F) inlet temperature isbelow CWDT. Therefore, wax deposition begins at the riser inlet regardless offlowrate, and deposits are more uniformly distributed.

Figure 5.6 illustrates the cumulative deposit volume over a 30-day period.The effect of inlet temperature and flow rates can be clearly seen. At 32°C (90°F)

inlet temperature and 600MBPD, almost 1.6bbl/month of waxes are deposited.

Figure 5.3 – SPM Arrival Temperature






Figure 5.4 – Deposit Growth Rate – Maximum Thickness

Figure 5.5 – Effect of Offloading Rate and Inlet Temperature on Deposition Profile






Figure 5.6 – Deposit Growth Rate – Cumulative Deposit Volume

4.3 Pigging

Figure 5.7 illustrates the pigging frequency (yearly) required to clean the offloadingriser. We use a pigging criterion based on the pressure drop that would be caused ifthe pigged wax forms a plug in front of the pig, specifically OPPiu9 < 50psi (3.4bar).As shown in Figure 5.7, the pigging frequencies are small (ie intervals are long)and are relatively insensitive to variation in the conditions studied (where wax isdeposited).

Note: A pigging frequency less than once per year should be regarded as once forall practical purposes. On the other hand, the associated pigging interval at32°C (90°F) inlet temperature and 600MBPD is in the magnitude of 600 daysas shown in Figure 5.8. We recommend the offloading risers be pigged atleast once per year upon start-up. The amount of deposits collected in the pigreturn can then be examined to help optimise pigging operations afterstartup, along with arrival temperature monitoring.

In addition, an inlet temperature of 16°C (60°F) was studied as a sensitivity check(included in Appendix 5A). At this temperature, very large amounts of waxes wouldhave already precipitated/deposited prior to entering offloading risers.






Offloading risers are flexible lines. Based on Shell internal documents (Refs 21and 22) flexible lines can be pigged as normal carbon steel pipelines, provided thatthe radius of the bends in the flexibles is controlled (to avoid sharp bends, in theBOOR case, controlled via buoyancy elements). However, care should be taken on

the selection of materials for the pigs to avoid aggressive pigging behaviour thatmay cause carbon steel pick-up if a stainless steel carcass is applied in the flexible.This is because the oval flow path of the flexibles resulting from the slight change ofinternal ID as the carcass structure opens and closes when bending occurs.Also, pig brushes should be avoided if a plastic liner (typically acts as primarycorrosion barrier) is applied to maintain pipe integrity. The SPM should allow flowpath control elements for pig to pass through and come back via another riser tothe FPSO. The loading hose in the last section between the SPM and the tankershould not be pigged. This is because the soft linings of the hoses are likely tobe damaged if pigged and tankers are not usually capable of receiving a pig.We would recommend pigs used in pigging BOOR be customised by pigmanufacturers.

Figure 5.7 – Estimated Pigging Frequency






BOOR – 2.3km Flowline (20" ID)

Figure 5.8 – Estimated Pigging Interval

4.4 5-year Wax Deposition Profile

In the absence of pigging, we simulated wax deposition over a 5-year period using600MBPD flow rate. An inlet temperature of 32°C (90°F) was used to compare withprevious study in 2000 (Ref 18). The results are shown in Figure 5.9. The maximumdeposit thickness in the riser grows from almost 1mm (0.04in) at the end of the firstyear offloading operation to 3mm (0.12in) at the end of the fifth year. The totalcumulative deposit volume in the riser is predicted to be 20bbl in the first year and60bbl at the end of the 5-year period, as shown in Figure 5.10.

As a result, the 5-year deposition profile and total deposit volume are predicted to beless than the results from previous studies.

Note: The previous work is based on a different simulation basis eg wax-relatedfluid properties, simulation environment and simulator package.






Figure 5.9 – 5-year Wax Deposition Profile

Figure 5.10 – Total Deposit Volume Over a 5-year Period –32°C Inlet and 600MBPD






4.5 Effect of Riser Buoy Insulation on Wax Deposition

The possible insulation of the 450m buoy section near the mid point of the offloadingriser was taken into account to evaluate its impact on wax deposition. CommercialC-Float syntactic foam buoyancy elements rated up to about 1200m (4000ft) waterdepth was assumed. The thermal properties of the C-Float foam used in this studyare: thermal conductivity of 0.112W/m°C (0.065 Btu/hr-ft°F), density of 737kg / m3

(46lb/ft3) and specific heat capacity of 1674.7J/kg°C (0.4 Btu/Ib°F). This results invery small temperature decline over the continuous 450m buoyancy section (refer toFigure 5.11).

The effect of this buoy insulation on wax deposition profile can be seen inFigure 5.12 (deposit thickness profile) using 600MBPD and 49°C (120°F).No deposition is seen in the buoyancy section due to the excellent insulatingproperties assumed. Translated this result to wax deposition volume and pigging,both the cumulative deposit volume and the pigging interval are reduced only slightly(shown in Figures 5.13 and 5.14 respectively). Therefore, the recommendation

of once per year pigging frequency is not altered, taking into account of buoyinsulation effect.

Figure 5.11 – Effect of Buoy Insulation onFluid Temperature Profile – 600MBPD






Figure 5.12 – Effect of Buoy Insulation onWax Deposition Profile – 600MBPD, 49°C Inlet

Figure 5.13 – Effect of Buoy Insulation on Wax Deposit Volume






BOOR - 2.3-km Flowline (20" ID)

Figure 5.14 – Effect of Buoy Insulation on Pigging Interval

5.0 HEALTH, SAFETY AND ENVIRONMENT (HSE)

We have carried out the assessment of the potential risks associated with theinterpretation, usage and field implementation of the technical results of the present

study. It was determined that such risks are very low. Additionally, it was determinedthat the engineering predictions and recommendations of this study do not raise anysignificant HSE issues or concerns. It is further advised that the users of thistechnical report conduct their own HSE risk assessment of the usage andimplementation of the results and recommendations of the present report.




Section 5 Appendix 5A Raw Data – 720-hour Simulation


Appendix 5ARaw Data – 720-hour Simulation

Oil Tanker Arrival Temperature (°C)

Oil Rate (MBLPD)BOOR InletTemperature (°C) 600 900

16 14.4 15.3

32 26.2 28.6

49 38.4 42.1

66 50.9 55.8

Max Deposit Thickness (mm)


16 0.03744 0.02802

32 0.08012 0.05956

49 0.09653 0.05815

66 0 0

Wax Deposit Volume (bbl)


16 0.6 0.5

32 1.5 1.2

49 1.1 0.3

66 0 0

Pigging Interval (days)


600 900 600

1363 1759 1363

524 689 524

727 2752 727

Pigging Frequency (Number per Year)


16 0.3 0.2

32 0.7 0.5

49 0.5 0.1

66 0 0






Section 6 Pour Point Depressant Risk Assessment


1.0 RISK DOCUMENT TO VALIDATE NOT INJECTING POUR POINTDEPRESSANT FOR INITIAL BONGA WELLS

Pour point is viewed as a risk for Bonga 803 and 710 sands. Based on analysis

done so far, the Bonga 803 and 710 fluids can have pour points that range from3°C to 10°C. Production of pour point fluids can be a challenge due to the possibletendency of the oil to form a gel when the flowline has cooled down to atemperature, which is below the measured pour point. Scenarios under which thiscan happen for Bonga include the following:

• A planned shutdown (under low water-cut scenario) wherein the flowline isprotected against hydrates by treating it with methanol and yet the flowline couldcool below the pour point

• A situation under which the flowline is not circulated with dead oil after it hasbeen blown down

During a shutdown, the fluid could gel-up and might potentially result in restartproblems since gels typically have non-zero yield strength (ie some pressure is neededto dislodge a gel). This document summarises the analysis performed to assesspour point risk for Bonga. The Flow Assurance Sub-team (FAST) reviewed this workon 14 April 2003.

2.0 RECOMMENDATIONS

Based on the analysis done thus far:

• It is recommended not to inject a pour point depressant for the initial Bonga803 and 710 wells. However, it may be prudent to wait for testing results fromthe vendors before making a final decision

• It is also recommended to analyse samples obtained during the initial wellunload to rig and to perform active surveillance during the initial months ofproduction to verify pour point properties. This includes sampling of theappropriate sampling of the fluid (according to given procedures) andverification of fluid properties by a properly qualified laboratory

3.0 RESULTS AND DISCUSSION

As with other wax-related properties, Bonga pour points show large variabilityacross the field (Ref 24). Reported measurements of pour points from eightBonga samples ranged from less than -45°C to 15°C. The highest of the reliable

results were obtained for Bonga B1 803 samples. The results were measured bySPDC Warri and indicate an upper pour point of 10°C. This is above the ambientseafloor temperature and was therefore a major driver for this study. The B1 803sample was identified as among the worst fluids from a wax perspective due to itsprimary nature (ie no waxes lost) and hence was determined to be adequate for waxflow assurance experimental measurements and modelling.

Table 6.1 shows the results on the pour point measurement obtained from variouslabs on the B1-803 fluid. It was also determined that the presence of a small amountof gas in the samples (pour point measurement done with live fluid at 300psig) madethe pour point to be slightly lower but did not substantially alter the pour point.






Laboratory Protocol UpperPour Point (°C)

LowerPour Point (°C)

SPDC Warri ASTM D5853-95 10 N/A

Shell WTC ASTM D5853-95 4 -7

Oil-phase DBR ASTM D97(modified)

N/A -8


ASTM D5853-95 3 N/A


ASTM D97 0 N/A

Table 6.1 – Measured Pour Points for Bonga B1 803 Sample NIG-O-129A

Pour points are typically characterised by a maximum pour point and a minimumpour point. It is entirely likely (as suggested by the above Bonga data) that themaximum pour points can be above ambient conditions and minimum pour pointscan be below ambient conditions. Ref 24 indicates that a minimum pour point ismore likely for production systems due to the presence of higher temperatures andturbulence while a maximum pour point is more likely during dead-oiling and oiloffloading. The above data indicates that the minimum pour point for Bonga B1 803is about -7/-8°C while the maximum pour point ranges from 3°C to 10°C.

Although a pour point is a good indicator whether or not a gelling problem mightexist, it is ultimately the gel strength that will determine if a pipeline can be restarted.

Therefore, in addition to the pour point measurements, a gel strength measurementwas also conducted.

The gel strength measurement was done at DBR. The pour point measurementsconducted as part of DBR study showed an upper pour point for the Bonga 803sample that was 7°C lower than the value previously measured by SPDC Warri(3°C measured at DBR vs 10°C measured at Warri). The seafloor temperature is6°C below the Warri pour point (10°C to 4°C = 6°C), therefore we chose a restarttemperature 6°C below the DBR-measured pour point of 3°C (Trestart = -3°C). Bydoing this, we ensured that a gel would form and that the results would beconservative. More details can be found in Ref 24. The measured gel strength wasfound to be 3N/m2. In order to determine if this would lead to any problems during a

restart, the required restart pressure was calculated for the Bonga flowlines, refer toTable 6.2. The calculations show that the required restart pressure for all theflowlines will be significantly lower than the maximum available pump pressure. Thecalculations in Table 6.2 are also made with the conservative assumption that theentire flowline loop is filled with dead oil that has gelled.

All the initial high pour point wells flow into the west flowlines which are the shortestflowlines. Table 6.2 indicates that a maximum gel strength of 48N/m2 can berestarted with the topsides pump pressure in the West flowline loops. Also, if youassume that only leg of the flowline loop (ie one flowline instead of two) is filled withthe gelled fluid then maximum gel strength of up to 98N/m2 can be restarted.






West 10in PFL East 10in PFL 1/2 East 12in PFL 3/4 and 5/6 East 12in PFL 5/6 only

Pipe ID 0.226m Pipe ID 0.226m Pipe ID 0.27m Pipe ID 0.27m

Pipe Length 7000m Pipe Length 21000m Pipe Length 15000m Pipe Length 9800m

YieldStress

(Pa)

RestartPressure

(bar)

YieldStress

(Pa)

RestartPressure

(bar)

YieldStress

(Pa)

RestartPressure

(bar)

YieldStress

(Pa)

RestartPressure

(bar)

1 1.24 1 3.72 1 2.22 1 1.45

2 2.48 2 7.43 2 4.44 2 2.90

31

3.72

31

11.15 31 6.67

3

14.36

6 7.43 6 22.30 6 13.33 6 8.71

12 14.87 12 44.60 12 26.67 12 17.42

24 29.73 16.14 60.002 24 53.33 24 34.84

30 37.17 27.00 60.002 30 43.56

48.43 60.002

41.33 60.002

1 Yield stress measured for Bonga 803 oil.

2 Maximum Pump Pressure.

Table 6.2 – Required Restart Pressures for Bonga Production Flowlines (PFL)

Lastly, all the above discussion focuses on the pour point properties of the B1-803Bonga fluid which is one of the worst fluids in Bonga in terms of wax properties.Mixing of this fluid with other benign fluids (eg 690 fluids or 720 fluids) will cause thepour point to reduce further. The amount of reduction that can be achieved is shown

in Figure 6.1. As seen in Figure 6.2, a 70/30 mixture of 803 and 703 fluid reducesthe maximum pour point to less than 0°C.

Blend Pour Points of Bonga B1 702 and 803 Oils

-40

-30

-20

-10

0

10

0 20 40 60 80 100

803 Oil Fraction, % vol

U p p e r P o u r P

o i n t , C

Upper limit; actual value may be lower.

Figure 6.1 – Pour Points of Bonga B1 702 and B1 803 Blends








4.4 Other Considerations

The Bonga production trees are designed such that the methanol and chemicalinjection have a common port. In spite of the presence of the insert to avoid mixingof the PPD and the methanol (which are incompatible chemicals) there still existssome risk of mixing and forming a plug, thereby jeopardising the methanol system.The probability of this occurrence ranges from low to medium. However, the impactof this is quite high considering that we could lose the methanol injection system tothe tree.

Preliminary testing results from the chemical vendors also indicate that they areunable to form a stable gel and thereby select an appropriate chemical. Hence,it may be prudent to defer injection of the chemical (if needed) until morerepresentative production samples have been obtained either during well unloadingor during actual production surveillance.

All the above arguments are in favour of NOT INJECTING a PPD. However,

the impact resulting from this event is quite high in the sense that we couldpotentially lose a flow line. Hence we need to carefully involve all the relevantparties while making this decision.

5.0 CONCLUSIONS

Based on the analysis done thus far, the following conclusions are reached:

• The risks of a flowline plugging due to pour point problems ranges are low.This is based on the analysis done on one the worst fluids (from a geochemicalperspective) at Bonga – the B1-803 fluid

• The risks can be lowered further by putting operating procedures in place to

mitigate the risk (dead-oil displacement after blowdown)

• Active surveillance must be done during the initial months of productionto verify pour point properties. This includes sampling of the appropriatesampling of the fluid (according to given procedures) and verification offluid properties by a qualified laboratory

• It is also recommended to collect samples and measure pour points onthe 803 and 710 wells while the wells are being unloaded to the rig




Section 7Scale Review.

Table of Contents

1.0 INTRODUCTION.............................................................................................................3

2.0 SUMMARY OF CONCLUSIONS AND RECOMMENDATIONS.....................................3

2.1 Bonga Formation Water Composition ................................................................. 5

2.2 Bonga Produced Gas Composition..................................................................... 6

2.3 ScaleChem Predictions and Analysis..................................................................8

TABLES

Table 7.1 – Matrix of Pressure, Temperature Used for Scale Analysis(Obtained from Bonga Subsea Systems Engineering Team)..............................7

Table 7.2 – Critical Parameters for Severity of Uninhibited Scale(From SIEP Scaling Manuals) ........................................................................... 11

FIGURES

Figure 7.1 – Scale Tendency as a Function of Temperature and

Pressure for BaSO4 (0.1)...................................................................................12

Figure 7.2 – mg/L as a Function of Temperature and Pressure forBaSO4 (0.1).......................................................................................................12

Figure 7.3 – Scale Tendency as a Function of Temperature andPressure for BaSO4 (1)......................................................................................13

Figure 7.4 – mg/L as a Function of Temperature and Pressure forBaSO4 (1)..........................................................................................................13

Figure 7.5 – Scale Tendency as a Function of Temperature andPressure for BaSO4 (10) ................................................................................... 14

Figure 7.6 – mg/L as a Function of Temperature and Pressure forBaSO4 (10)........................................................................................................14

Figure 7.7 – Scale Tendency as a Function of Temperature andPressure for BaSO4 (100) ................................................................................. 15

Figure 7.8 – mg/L as a Function of Temperature and Pressure forBaSO4 (100) ...................................................................................................... 15

Figure 7.9 – Scale Tendency as a Function of Temperature andPressure for CaCO3 (0.1)..................................................................................16

Section 7 Scale Review






FIGURES

Figure 7.10 – mg/L as a Function of Temperature and Pressurefor CaCO3 (0.1) ................................................................................................ 16

Figure 7.11 – Scale Tendency as a Function of Temperature andPressure for CaCO3 (1)...................................................................................17

Figure 7.12 – mg/L as a Function of Temperature and Pressurefor CaCO3 (1) .................................................................................................. 17

Figure 7.13 – Scale Tendency as a Function of Temperature andPressure for CaCO3 (10).................................................................................18

Figure 7.14 – mg/L as a Function of Temperature and Pressurefor CaCO3 (10) ................................................................................................ 18

Figure 7.15 – Scale Tendency as a Function of Temperature andPressure for CaCO3 (100)...............................................................................19

Figure 7.16 – mg/L as a Function of Temperature and Pressurefor CaCO3 (100)...............................................................................................19






Figure 7.22 – mg/L as a Function of Temperature and Pressurefor CaCO3 (10).................................................................................................24






1.0 INTRODUCTION.

Previous Bonga scale studies done by Frigo1 (June 1997), Morgenthaler et al2 (June 2000) and Lorimer et al3 (December 2000) have been reviewed. Our workwas done primarily to evaluate scaling potential under operating conditions notconsidered in the previous studies (especially low pressure operating points) and toassess the current inhibition strategies in place for scale control at Bonga.The immediate focus was to address whether a subsea scale inhibitor is needed forBonga during the first few years of operation.

In the absence of data files used by Morgenthaler, the scaling calculations(self-scaling and mixing water) have been reworked using the latest information onproduction profiles and thermal hydraulic modelling obtained from the BongaSubsea Systems Engineering Team. Exact reproduction of Morgenthaler’s resultswas not seen and this may be due to different strategies/philosophies used in thescale modelling work (eg brine reconciliation, ratios of brine and gas used etc) usingSCALECHEM v2.2 simulation software. However, the trends of results and the

major conclusions are similar to those of Morgenthaler et al.

We have based our calculations on the brine and gas compositions as shown inTables 7.1 and 7.2, which are similar to those used in the study performedby Morgenthaler et al2 (June 2000). Table 7.3 shows the various pressuretemperature conditions evaluated in our study. The brine and gas flow rates wereobtained via simulations (unavailable to past studies) from Bonga Subsea SystemsEngineering Team (Susan Lindsey).

2.0 SUMMARY OF CONCLUSIONS AND RECOMMENDATIONS

We would like to reiterate the recommendation of Frigo1 and Morgenthaler et al2 that

we need more water samples from the Bonga region. The robustness of the watersample used in our analysis (and also that used by Morgenthaler) has beencritiqued and evaluated by Morgenthaler et al in detail. The water analysis is indeedin question and needs to be verified via analysis on a fresh water sample from aShell-certified laboratory. Whenever feasible, water samples should be obtainedduring developmental drilling in the region. The FEAST5 (Fluids Evaluation andStability Testing) networks best practices should be applied to all sampling andsubsequent analysis to ensure that the data we get are representative and understrict Shell Group guidelines. Efforts should be made to acquire or share data withother operators in the region or participate in studies aimed at understandingregional formation water chemistry. Our work is based on the water chemistryidentified in the Bonga Development Basis of Design Document (Rev 5).

The composition in Table 7.1 forms the design basis and hence has been used inour study.

Basis our calculations and analysis, for the range of flow ratios of brine to gas andoperating conditions that will exist at various stages of operation, the only twoscaling minerals that could form scale would be barium sulphate and calciumcarbonate.

1 Frigo, D: Scale review draft report sent via email to Bonga Project Team (1997).

2 Morgenthaler, L, Bell, F: ‘Water Compositions and Scaling Predictions for the Bonga Field: Sensitivity to CarbonDioxide, Organic Acid, and Barium Concentrations’ (June 2000).

3 Lorimer, S, Wallace, C, Gibson, G: ‘ Review of Bonga Corrosion, Souring and Scaling (Rev 1)’ (Dec 2000).

5 Contact at [email protected] for FEAST sampling protocols and analysis.



mailto:[email protected]






Basis information obtained through Bonga Subsea Systems Engineering Team(Susan Lindsey), the gas to water ratio (kscf per day of gas produced per bbl ofwater) over field life in Bonga would range from 0.1 to 100.

Barium sulphate self-scale formation (from formation water) is likely for lowtemperatures (~40°F) at all pressures considered (150 to 5000psia) (scalingtendency >8). However, the amount of scale (mg/L) that would form in all thesecases is minimal (~1 to 2mg/L) and below limits of those required for causingplugging/deposition problems4. The likelihood of barium sulphate scale to occur inthe field is therefore minimal. No subsea treatment for barite scale is thereforerecommended. This confirms the findings of Morgenthaler 2. Surveillance andmonitoring of produced water is strongly recommended, especially to verify theanalysis of Bonga formation brine used in this study with respect to barium scale.Scale analysis should be redone when the new production water sample is analysedto scrutinise scaling risks and operating strategies.

Calcite self-scale formation (from formations water) is likely at pressures lower than

1000psia (scaling tendency ~5, amount of scale ~300mg/L)) and at temperaturesgreater than 145°F. From the scaling manual4, the scaling risk is higher around175°F and at pressures close to ~350psia, where scaling tendency ~10 and amountof scale ~600mg/L. The severity of calcite scaling causing production problems inthese conditions will be low to moderate4. Subsea scale treatment is advised ifBonga’s operating conditions fall under these operating conditions (and producedwater is formation water only). Topsides scale treatment is however advised,as separator pressures will be around 150psia where the scaling tendencyincreases to a value of ~ >10 and amount of scale is ~500mg/L. These conclusionsare similar to those of Morgenthaler et al2. The impact of scaling calculationson specific Bonga conditions (anticipated thermal hydraulic conditions at variousnodes and produced water compositions) during field life is explained in detail inSection 8. Surveillance and monitoring of produced water is strongly recommended.Scale analysis should be redone when the new production water sample is analysedto scrutinise scaling risks and operating strategies.

Scaling risk for scenarios with production water having 25, 50 and 75% seawatercontent have been calculated. For these scenarios, calcite scaling is likely atconditions of high temperature (175°F) and low pressure (150psia). As thesescenarios are not likely subsea, hence subsea-scaling risk is minimal for theseratios. Also, self-scaling risk from seawater production alone is negligible at allconditions tested.

4 Frigo, D: Scaling Manuals. SIEP 99-5679 and SIEP 99-5780.






2.1 Bonga Formation Water Composition

We have used the design basis formation water chemistry similar to the one used byMorgenthaler et al 2. Morgenthaler et al 2 have performed extensive simulations toanalyse sensitivity of formation water to variables like carbon dioxide, organic acidsand barium concentrations. The reconciliation of the brine to balance forelectro-neutrality may be done by changing either the calcium or bicarbonatecomposition in the brine. However, we expect lesser errors during the analysis ofcalcium. Hence we chose to reconcile using the bicarbonate composition whereinthe higher alkalinity (bicarbonate 2800mg/L) is attributed to unmeasured organicacids content (acetate as shown in Paragraph 2.1.2). Morgenthaler et al2 report asimilar approach. This would need to be verified with analysis of new water samplesfrom Bonga. The analysis of the new water sample should be carried out by a Shelllab (or a Shell-certified lab) using standard Shell certified protocols5. Paragraph 2.1.1gives the original composition of water composition used by us as well asMorgenthaler et al2.

2.1.1 Original Brine Composition Before Reconciliation(Same as Reported by Morgenthaler et al2)

• Sodium (mg/L) 10440

• Potassium (mg/L) 5140

• Calcium (mg/L) 280

• Magnesium (mg/L) 14

• Barium (mg/L) 0.81

• Strontium (mg/L) 2.1

• Iron (mg/L) 15

• Chloride (mg/L) 19305

• Sulphate (mg/L) 500

• Bicarbonate (mg/L) 2830

• pH at 77°F 8.22

2 Morgenthaler, L, Bell, F: ‘Water Compositions and Scaling Predictions for the Bonga Field: Sensitivity to CarbonDioxide, Organic Acid, and Barium Concentrations’ (June 2000).

5Contact at [email protected] for FEAST sampling protocols and analysis.










7CO2 content used herein (refer to Paragraph 2.2.1) is higher than that in the BongaBasis of Design. This would provide conservative results and was chosen to matchits value used in previous studies2. Table 7.1 shows the matrix of conditions used foranalysis. They cover expected range of temperature (40 to 175°F) and pressures

(150 to 5000psia) conditions at Bonga.

T (°F) P (psia)

5000

4500

3000

1000

350

175

150

5000

4500

3000

1000

350

145

150

5000

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1000

350

100

150

5000

45003000

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40

150

Table 7.1 – Matrix of Pressure, Temperature Used for Scale Analysis(Obtained from Bonga Subsea Systems Engineering Team)

2

Morgenthaler, L, Bell, F: ‘Water Compositions and Scaling Predictions for the Bonga Field: Sensitivity to CarbonDioxide, Organic Acid, and Barium Concentrations’ (June 2000).






The main difference between this test matrix and the one used by Morgenthaleret al (2000) is the inclusion of the new separator (topsides) pressure conditions of350 and 150psia. From the production data obtained from Bonga Subsea SystemsEngineering Team, the various ratios of gas to brine that will exist in the various

Bonga flowlines at various stages of the project life are: 0.1, 1, 10, 100kscf of gasper bbl of brine.

2.3 ScaleChem Predictions and Analysis

ScaleChem has been used to evaluate scaling tendencies using the input datadiscussed earlier. Severity of the scaling and extent of problems anticipated arebased on the scaling manual and instructions therein by Frigo3 (1997).

The following cases have been run to evaluate scaling potential and associatedrisks.

Case # Seawater Formation Water

A (self-scaling) 0 100

B 25 75

C 50 50

D 75 25

E (seawater only) 100 0

2.3.1 Case A: Self-scaling Calculations (Produced Water is Formation-water Only)

The methodology used in ScaleChem for performing self-scaling calculations isas follows:

• Reconcile the formation brine attributing the excess alkalinity to unmeasuredacetate (salt of organic acid). This brine is then taken to reservoir conditions andused for scaling analysis)

• This reservoir brine is then used with the gas phase in the scaling scenariooption to calculate scaling tendency and amount of scale for the range ofprocess conditions (refer to Table 7.1) and for the various gas-to-brine ratios

• The gas composition used for simulations is in Paragraph 2.2.1

Basis our calculations and analysis, for the range of flow ratios of brine to gas thatwill exist at various stages of operation, the only two scaling minerals that could formscale would be barium sulphate and calcium carbonate

3 Lorimer, S, Wallace, C, Gibson, G: ‘ Review of Bonga Corrosion, Souring and Scaling (Rev 1)’ (Dec 2000).






BaSO 4 Scale

Figures 7.1, 7.3, 7.5 and 7.7 show the scaling tendencies for barite scale aspredicted by SCALECHEM for the four ratios 0.1, 1, 10 and 100 respectively.Figures 7.2, 7.4, 7.6 and 7.8 give the corresponding amounts of baryte scale (mg/L)for the four ratios. The trends in these graphs are very similar and consistent trendsare also observed at the higher ratios (1000, 2000kscf gas per bbl of water). BaSO 4 solubility is moderately affected by pressure, however it is strongly influenced bytemperature. BaSO4 solubility increases sharply as a function of temperature.Therefore, scaling tendency increases as temperature drops, the highest valuebeing at the lowest temperature (40°F).

For a ratio of 0.1kscf gas per bbl of brine, Figure 7.1 shows the anticipated scalingtendency for the various conditions tested. The produced fluids will becomesaturated with baryte as temperature drops with saturation levels increasing as thefluids move to topsides. Production problems have been observed only when thedegree of baryte super saturation becomes ~ 5 to 8, ie scaling tendency is ~ 5 to 8 3

(refer to Table 7.2). This threshold is reached when temperature reaches around40°F. Hence, BaSO4 scale formation is very likely at conditions of lower temperature(~40°F). However, from Figure 7.2 the amount of scale (1 to 2mg/L) that precipitatesout of solution is not significant to cause plugging or deposition problems (~ 50mg/L)based on guidelines provided in the SIEP Scaling Manual3. Increasing the ratio ofgas to brine, ie 1, 10, 100, has no significant effect on either the scaling tendenciesor the amount of scale as shown in Figures 7.3 to 7.8. Even though scalingtendencies are greater than threshold limits at lower pressures and temperatures,the amount of scale is not significant to cause plugging or deposition problems.

Conclusions for Baryte Scale in Case A

The baryte-scaling tendency reaches values above threshold for scale formation atlower temperatures (40°F). The amount of scale formed (mg/L) is not high enough tocause any concern regarding production problems (plugging/deposition). As such,the analysis shows a low risk of scale formation based on field experience.

Based on data used and analysis done herein, no subsea baryte scale treatment isrecommended. However, it is strongly recommended to obtain a good qualityproduced water sample and to perform scale analysis using the new data due toconcerns with water analysis (eg Ca, Ba content) used for the simulations.

We strongly recommend that topsides surveillance and monitoring strategies be putin place to assist operations in the management of possible scaling issues.

CaCO 3 Scale

Figures 7.9, 7.11, 7.13 and 7.15 show the scaling tendencies for calcite scale aspredicted by SCALECHEM for the ratios 0.1, 1, 10, 100 (kscf of gas per bbl of brine)respectively. Figures 7.10, 7.12, 7.14 and 7.16 give the corresponding amounts ofcalcite scale (mg/L) for these four ratios.

For ratio of 0.1kscf of gas per bbl of brine, Figures 7.9 and 7.10 give scalingtendency and amount of scale that could potentially form. As suggested in the SIEPScaling Manual3 (refer to Table 7.5), for calcite scaling to cause productionproblems, the threshold limit for scaling tendency is about 4 and correspondingamount is about 300mg/L. This threshold is reached in the system with operatingconditions of temperatures greater than 145°F and pressures less than 1000psia.

3Lorimer, S, Wallace, C, Gibson, G: ‘ Review of Bonga Corrosion, Souring and Scaling (Rev 1)’, Dec 2000.






Under these conditions, low scale formation problems could appear. However, scaleseverity is increased at pressure around 350psia and temperature around 175°F.

For higher ratios (ie 1, 10 and 100), Figures 7.11 to 7.16 show that the trend ofresults (scaling tendency and amount of scale formation). Based on our analysis, atthese ratios, moderate problems could appear in the system with operatingconditions having temperature around 175°F and pressure around 350psia.

Conclusions for Calcite Scale in Case A

Calcite self-scale formation is likely at pressures lower than 1000psia (scalingtendency ~5, amount of scale ~ 300mg/L)) and at temperatures greater than 145°F.From the scaling manual4, the scaling risk is higher around 175°F and at pressuresclose to ~350psia, where scaling tendency ~10 and amount of scale ~600mg/L.The severity of calcite scaling causing production problems in these conditions willbe low to moderate4. At Bonga’s operating conditions, in the event of significantproduction of formation water only, subsea scale treatment is recommended.

Topsides scale treatment is however advised for all scenarios.The impact of these scaling calculations on specific Bonga conditions (at anticipatedthermal hydraulic conditions and at various nodes and under different producedwater compositions) is explained in detail in Section 8.

It is strongly recommended to obtain a good-quality produced water sample andto perform scale analysis using this data due to concerns with water analysis(eg Ca, Ba content) used for the simulations. Surveillance and monitoring ofproduced water is strongly recommended, as there are concerns about wateranalysis (eg very low barium content). This is especially crucial since the majorassumption of our work and recommendations is the basis claim of reservoirengineers that produced water will be primarily seawater. Scale analysis should be

redone when the new production water sample is analysed to scrutinise operatingguidelines and strategies. We strongly recommend that topsides and subseasurveillance and monitoring strategies be put in place to assist operations in scalemanagement.

Note: Figures 7.1 to 7.16 indicate the scaling tendency and amount of scale possible at a specific water to gas ratio. The number in the brackets in thetitle for each figure, eg 0.1, indicates the specific ratio ie kscf of gas per barrelof water produced.

4 Frigo, D: Scaling Manuals. SIEP 99-5679 and SIEP 99-5780.








175145

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Figure 7.1 – Scale Tendency as a Function ofTemperature and Pressure for BaSO4 (0.1)

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Figure 7.2 – mg/L as a Function ofTemperature and Pressure for BaSO4 (0.1)






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Figure 7.3 – Scale Tendency as a Function ofTemperature and Pressure for BaSO4 (1)

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Figure 7.4 – mg/L as a Function ofTemperature and Pressure for BaSO4 (1)






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Figure 7.9 – Scale Tendency as a Function ofTemperature and Pressure for CaCO3 (0.1)

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Figure 7.10 – mg/L as a Function ofTemperature and Pressure for CaCO3 (0.1)






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Figure 7.11 – Scale Tendency as a Function ofTemperature and Pressure for CaCO3 (1)

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Figure 7.12 – mg/L as a Function ofTemperature and Pressure for CaCO3 (1)






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2.3.2 Case B-D: Mixed Water-scaling Analysis(Produced Water is a Combination of Formation Water and Seawater)

The input seawater composition (from Grant Gibson – Bonga Subsea SystemsEngineering Team – EPP) used in simulating scaling scenarios (Cases B-E) is asfollows:

• Sodium (mg/L) 1968

• Potassium (mg/L) 245

• Calcium (mg/L) 262

• Magnesium (mg/L) 1339.5

• Barium (mg/L) 0.042

• Strontium (mg/L) 5.66

• Iron (mg/L) 0.025

• Chloride (mg/L) 5075.7

• Sulphate (mg/L) 3435.5

• Bicarbonate (mg/L) 36.6

• pH at 77°F 8.3

The seawater analysis above is electro-neutrally balanced (calculation checkedusing ScaleChem). However, it is different from a typical seawater compositionavailable in literature7 (wherein eg Na+ is ~ 10400mg/L and Cl- is ~19400mg/L).The water analysis report6 mentions that the composition above is similar to otherwater samples collected in offshore Niger Delta regions. This could be true because

of a dilution effect from the Niger Delta water. The Bonga seawater may need to besampled again and re-analysed to confirm previous work. The analysis should bedone by a Shell-certified laboratory or under Shell supervision. The scalingcalculations were not affected significantly by accounting for increased salt content.We have used the above analysis as Bonga seawater. A quick simulation usingstandard seawater composition7 yields different magnitudes of scaling tendenciesand amounts of scale, however the major conclusions are similar to those obtainedfrom simulations using the above compositions.

7 Handbook of Chemistry and Physics, 83

rd edition, Pages 14 to 17.






The methodology used in SCALECHEM is as follows:

• Reconcile the seawater brine as above and saturate it with calcite at reservoirconditions (pressure 4500psia, temperature = 145°F)

• This saturated seawater is then mixed with formation water (refer to Paragraph2.1.2) in various ratios at reservoir conditions. In Case E, only seawater wasused under reservoir conditions

• The output brine resulting from this mixing calculation is then used asproduction brine for scaling calculations to assess scaling risk over the entirefacility (bottom hole to topsides). Similar to the self-scaling analysis,the simulations have been run at ratios ranging from 0.1 to 100kscf of producedgas per barrel of produced water and for a matrix of thermal-hydraulic conditions(refer to Table 7.1)

• The gas composition used for simulations is in Paragraph 2.2.1

It is worth mentioning that there is no appreciable change in the composition of thesaturated seawater, indicating that it is almost saturated at surface conditions withthis salt. We have performed simulations using two combinations:

(1) Saturated seawater + saturated formation water.

(2) Saturated seawater + supersaturated produced water.

Results in case (2) above will give conservative estimates. The trends and valuesobtained for scaling tendency and amount of scale are similar and we will show theresults in cases of simulation using 10kscf of gas in this report. In all thesesimulations, it is observed that calcium carbonate seems to be the only likely scale. At the ratios considered (refer to Paragraph 2.3.1), the mixing of the seawater andformation water yields a benign production water in terms of calcite scale problems.From these simulations, it is concluded that calcite scale will cause moderateproblems around conditions of high temperature (> 145°F) and low pressure(~150psia). No appreciable scale is seen when seawater alone is produced andtherefore self-scaling is not an issue when production water is seawater only (Case E).

The results of the simulations for Cases B-D are shown in Figures 7.17 to 7.22.For the ratio of 10kscf per day of gas produced per barrel of water; Figures 7.17 and7.18 give the scaling tendency and amount of scale respectively for Case B.The magnitude of scaling tendency and amount of scale obtained for remainingratios are very similar. Similarly, Figures 7.19 and 7.20 highlight the results for thisratio for Case C. Case D results are shown in Figures 7.21 and 7.22.

Note: The 350psia calculation node used in the self-scaling simulations (refer toTable 7.1) was replaced by 500psia to obtain a better midpoint for anyextrapolation that might be necessary.






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Figure 7.17 – Scale Tendency as aFunction of Temperature and Pressure for CaCO3 (10)

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Shell Nigeria E & P Company Ltd Unrestricted

Section 8Risk-based Evaluation of Scaling Tendenciesfor the Subsea System

Table of Contents

1.0 INTRODUCTION.............................................................................................................2

2.0 SUMMARY .....................................................................................................................3

3.0 WAY FORWARD............................................................................................................4

TABLESTable 8.1 – Scaling Risks for Wells During Early Life and Late Life ........................................ 3

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





1.0 INTRODUCTION

This section provides a risk-based evaluation of scaling tendencies for the BongaSubsea System starting from the wellbore until the topsides. The followingmethodology was used to evaluate the scaling risks:

(1) The entire Bonga production was simulated on a well-by-well basis usingPIPESIM (with the Field Planning Tool (FPT) feature).

(2) The production function of every well was examined to quantify wellbore risk.The production function was split into early and late-life scenarios.

(a) Early-life constitutes the dry phase of the well with a water cut less than2% of the entire liquid production from that particular well. During thistime, the pressure and temperature range over which the well spendsmost of its early life is evaluated for scaling tendency.

(b) Late-life constitutes the wet phase of the well with substantial water cut

(> 20%). Similarly, the pressure and temperature range over which thewell spends most of its late life is evaluated for scaling tendency. It isimportant to note that almost all of the Bonga reservoirs (except for803p2) produce a substantial amount of water and the water cut risesquite dramatically from 0% to greater than 20% within a very shortperiod of time (2 to 6 months). This dramatic rise in water production isin sharp contrast to the average production life of most Bonga wells(range from 5 to 10 years) and hence an intermediate water cut case(mid-life) blends into the late-life cases. 20% was chosen because this isalso the time at which the riser base gas lift is turned on, which causes asubstantial lowering of manifold pressure. Although a water cut between2 and 20% is not explicitly covered, it is included in the late-life scenario.

This is justified because scaling problems do not occur when the wellbegins to make substantial water (refer to Paragraph 2.0).

(c) As mentioned above, the pressure and temperature range over whichthe well spends most of its life was examined for scaling risks. This willaccount for the most likely risk for scaling. For example, well 702p5 hasa pressure range that varies from 1000psi to 650psi (early-life, prior towater cut). However, the well spends most of its life between 600psi and700psi (early-life) and hence we looked at a pressure of 700psi toevaluate scaling tendencies during early-life.

(3) A similar approach is taken to evaluate risks for flowlines and risers.Production profiles in each flowline and riser are evaluated and split into early

and late-life according to similar criteria as listed above. Scaling risks are thenevaluated by looking at the pressure and temperature regions where theflowline and riser spends most of its lift.

The following assumptions are made while evaluating scaling tendencies:

(1) Scaling tendency has been evaluated only for the Bonga Subsea Systemstarting from the wellbore up to the topsides. Scale has been identified as arisk at topsides and there is provision for the injection of scale-inhibitor atthe topsides.






(2) Current scaling evaluations have been made with a water sample that wasobtained from the original Bonga exploration wells (Bonga No 2 well, sampleanalysed in May 97). There is apparently a more credible water sample(stored in Nigeria from both Bonga-5 (702-w4) or Bonga-7 (702-p9)), but

an analysis on this has not been performed. It is important to re-examine thisentire report once analysis from the new water sample becomes available.In particular, attention must be paid to the barium content of the water sample(current sample shows that amount of Ba is less than 1ppm) since this canhave substantial implications with respect of mixing with seawater.

(3) Reservoir engineers have indicated that most of the produced water (water cuts> 20%) in Bonga will be seawater that has been injected. The percentageof seawater in the produced water is estimated to be greater than 70%. Although we have calculated scaling tendencies at a seawater percentage ofas low as 25%, this assumption needs to be validated at the FPSO when thewells begin to produce water.

(4) We have also assumed that any small amount of water that is produced duringearly life will be formation water). Moreover, we have evaluated scalingtendencies at a ratio of 10kscf/bbl and 100kscf/bbl of water produced. This ismost consistent with the production GoRs and amount of water that might beproduced. For example, a production of 20,000bbl per day of oil (GoR of 500)and 100 barrels per day of water results in an approximate ratio of100kscf/bbl.

2.0 SUMMARY

Based on the main report and the production functions, we came to the followingconclusions:

(1) Baryte scale is not a problem for Bonga, all subsequent scalingtendencies refer only to calcite scales. However, it is critical that we verifythe water composition for barium after the field starts cutting water.

(2) Calcite scaling is not a problem when the field starts to produce water. This is mainly due to the fact that a mixture of seawater and formation waterleads to highly reduced scaling tendencies.

(3) Scaling is a potential problem only during early life where formation water willbe produced. Table 8.1 describes the problem.

Early Life(< 2% WC)

Late Life Comments

Wells 5 wells out of 21 wellsare problematic

No Problem Well Nos 702p5,710p4, 803p2,803p3

Flowlines 1 out of 8 flowline loopsare problematic

No Problem PF-12

Risers All risers are problematic No Problem –

Table 8.1 – Scaling Risks for Wells During Early Life and Late Life






Although, the above regions of the subsea system have been identified asbeing problematic during early life the actual risk of scale deposition is quite