Flow Assurance Guidelines

SHELL NIGERIA EXPLORATION AND PRODUCTION COMPANY Ltd.

Bonga FPSO Plant Operating Procedures Manual Volume 2D FLOW ASSURANCE GUIDELINES

OPRMOPRM-20032003-0302D 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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PURPOSE 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 Volume 2A Volume 2B Volume 2C Volume 2D Volume 3 Volume 4 Volume 5 Volume 6 Volume 7 Volume 8 Volume 9 Volume 10 Volume 11 Volume 12 Volume 13 Volume 14 Volume 15 Volume 16 Volume 17 Volume 18 Volume 19 Volume 20 Volume 21 Volume 22 Volume 23 Volume 24 Volume 25 Volume 26 Volume 27 Volume 28 Volume 29 Volume 30 Volume 31 Volume 32 Volume 33 Volume 34 Volume 35

OPRM-2003-0302D

Field and Facilities Overview Subsea Production System Subsea Waterflood System Subsea Control System Flow Assurance Guidelines Oil Separation and Treatment Oil Storage, Handling and Ballast Systems Oil Metering and Export System Vapour Recovery Compression System Field Gas Compression System Gas Dehydration/Glycol Regeneration Systems Gas Export/Import/Lift Systems Flare and Vent Systems Produced Water Treatment Systems Waterflood System Chemical Injection and Methanol Injection System Fuel Gas System Heating Medium System Drainage Systems Sewage Treatment Systems Bilge and Oily Water Separation Systems Inert Gas System Nitrogen Generation System Seawater System Fresh and Potable Water Systems Diesel Fuel System and Incinerator Aviation Fuel System Instrument and Utility Air System Deck Hydraulic Systems Fire Protection Systems and Equipment Safety and Lifesaving Equipment PSCS and ESS Power Generation and Distribution Systems Black Start Procedures HVAC Systems Deck Machinery and Mechanical Handling Systems (Cranes, etc) Telecommunications Ancillary Living Quarters (ALQ)

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

4.0

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

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SPECIAL NOTE Not applicable.

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

7.0

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

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Definitions and Abbreviations Definitions Arrival Temperature

Flowing temperature of the fluids at the FPSO boarding valve.

Backpressure

Pressure on back of valve against which equalising pressure is applied to reduce differential

Blowdown

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

Bubble Point

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

Cloud Point

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

Cold Earth Start

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

Equalising Pressure

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

Forward Pressure

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

Gas Void Fraction

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

Hot Oiling

Precirculating heated dry hydrocarbons or diesel around a flowline loop to warm the flowlines and manifold prior to a cold well startup.

Hydrate Dissociation/ Formation Temperature

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

No-touch Time

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

Pour Point

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

Safe Condition

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

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Safe Condition Temperature

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

Safe Condition Time

The time taken to reach safe condition temperature.

Warm-up Time

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

Abbreviations API ASTM

American Petroleum Institute American Society for Testing and Materials

Ba BaSO4 BIST BLPD BoD BOOR BS&W BSET

Barium Baryte Bonga Integrated Studies Team Barrels Liquid Per Day Basis of Design Bonga Oil Offloading Riser Base Sediment and Water Bonga Systems Engineering Team

CaCO3 CIV CPM CWDT

Calcite Chemical Injection Valve Cross-polar Microscopy Critical Wax Deposition Temperature

DTI

Department of Trade and Industry

EPIC ESDV

Engineer, Procure, Install and Construct Emergency Shutdown Valve

FAST FDP FEAST FPSO FPT FWHP FWHT

Flow Assurance Sub-team, Houston Field Development Plan Fluids Evaluation and Stability Testing Floating Production, Storage and Offloading Field Planning Tool Flowing Wellhead Pressure Flowing Wellhead Temperature

GLIV GLR GoM GOR

Gas Lift Injection Valve Gas Lift Riser Gulf of Mexico Gas/Oil Ratio

HDP HDT HRGC HS&E HSE HTGC

Hydrate Dissociation Pressure Hydrate Dissociation Temperature High Resolution Gas Chromatography Health, Safety and Environment Health and Safety Executive High Temperature Gas Chromatography

ID ITT

Inside Diameter Invitation to Tender

KHI

Kinetic Hydrate Inhibitor

LDHI LP

Low Dosage Hydrate Inhibitor Low Pressure

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MBLPD MBOPD MBWPD MEG MeOH MIV MMBO MoC MPT

Thousand Barrels Liquid Per Day Thousand Barrels Oil Per Day Thousand Barrels Water Per Day Monoethylene Glycol Methanol Methanol Injection Valve Million Barrels Oil Management of Change Model Pipeline Test

NORM NLNG

Naturally Occurring Radioactive Material Nigerian Liquefied Natural Gas

OD OGGS OPEX

Outside Diameter Offshore Gas Gathering Plant Operating Expenditure

PFL PID PIP PIV PM PMV POPM POV PP PPD PSDV psia PU PVT PWV

Production Flowline Proportional Integral Derivative Pipe-in-pipe Pigging Isolation Valve Production Manifold Production Master Valve Plant Operating Procedures Manual Ported Orifice Valve Pour Point Pour Point Depressant Pipeline Shutdown Valve Pounds Per Square Inch Absolute Polyurethane Pressure/Volume/Temperature Production Wing Valve

SBHP SC SCF SCSSV SIEP SITP SOI SPM SRTCA SSSV STB SWV

Shut-in Bottomhole Pressure Safe Condition Standard Cubic Feet Surface Controlled Subsea Safety Valve Shell International Petroleum Maatschappij Shut-in Tubing Pressure Shell Offshore Incorporated (SEPCo) Single Point Mooring Shell Research and Technology Center, Amsterdam Subsurface Safety Valve Stock Tank Barrels Sacrificial Wing Valve

TEG THF

Triethylene Glycol Tetrahydrofuran

UTH

Umbilical Termination Header

VIT

Vacuum Insulated Tubing

WHP

Wellhead Pressure

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WSV WTC

Well Switching Valve Westhollow Technology Center

XOV

Crossover Valve

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Reference Information/Supporting Documentation (1)

Bendiksen, KH, Malnes, D, Moe, R and Nuland, S (1991), ‘ The Dynamic Twofluid 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 (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 2627.

(9)

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

Major:

Technical

Note

–

Flow

Assurance

(10) Zabaras, GJ (1987) A New Vertical Two-phase Gas-liquid Flow Model for Predicting Pressure Profiles in Gas-lift Wells. Shell TPR (WRC 223-87). (11) Westrich, JT, Predicting Wax-related Fluid Properties Away from Well Control at Bonga, Report number SIEP.99.6096, August 1999. (12) Ratulowski, J, G Broze, J Hudson, N Utech, P O’ Neal, J Couch and J Nimmons. Asphaltene Stability, Waxy Fluid Properties and Wax Deposition Potential of Crude Oils from the Bonga Prospect, Nigeria. SEPTCo, Houston, March 1999. (13) Broze, G, N Utech, P O’ Neal and J Nimmons, Summary Report: Waxy Fluid Properties of Crude Oil from the B1 well, 803 Sand of the Bonga Prospect, Nigeria. SEPTAR, Houston, July 1999. (14) Bonga Integrated Studies Team. SDS-SNEPCo Bonga Joint Venture, Integrated Development Plan, Field Development Plan, Rev 5, December 2001. (15) Schoppa, W, Flow Assurance Constraints for Bonga Production Forecasting: Wrap-up. SGSUS, May 2002. (16) Schoppa, W and A Kaczmarski, Bonga Dynamic Flow Assurance Analysis – Evaluation of Conceptual Design. SGSUS, Technical Progress Report, February 2001. (17) Stankiewicz, Artur, Matt Flannery, Pat O’ Neal, Nancy Utech and George Broze, Asphaltene Stability and Wax Properties of the Crude Oil from the OPL 212 Prospect, Well W6, Bonga, Nigeria, SGSUS, October 2001.

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(18) George Broze, Bonga Oil Offloading Riser Wax Deposition. Memo to Ram Gopalkrishnan of SDS, September 2000. (19) Steve C Tsai, George Broze and Sabi Balkanyi, Bonga Production Flowline Wax Assessment. Shell Global Solutions, Houston, Texas, March 2003. (20) Bonga Oil Offloading Risers Conceptual Designs Summary (SD 991080). Revision R1, September 1999. (21) Pigging of Pipelines, State-of-the-Art, EP 95-2580, SIEP, The Hague, 1995. (22) SOI Deepwater Flowline Pigging Guidelines (similar to the guidelines for pigging section in the DEP 31.40.00.10 report). (23) Bonga System-wide Functionality Review in Amsterdam (Nov 2001) and email communications from H Duhon and A Kaczmarski. (24) Tsai, A, Broze, G and S Balkanyi, Bonga Production Flowline Wax Assessment. Shell Global Solutions, April 2003. (25) Westrich, JT, Predicting Wax-related Fluid Properties Away from Well Control at Bonga, Report No SIEP.99.6096, August 1999.

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Main Table of Contents

Document Status Information Definitions and Abbreviations Reference Information/Supporting Information/Supporting Documentation Section 1

Dynamic Flow Assurance Analysis

Section 2

Flow Assurance Production Constraints

Section 3

Hydrate Remediation Guidelines

Section 4

Production Flowline Wax Assessment

Section 5

Offloading Riser Wax Assessment

Section 6

Pour Point Depressant Risk Assessment

Section 7

Scale Review

Section 8

RiskRisk-based Evaluation of Scaling Tendencies for the Subsea System

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Section 1 Dynamic Flow Assurance Analysis

Table of Contents 1.0

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EXECUTIVE SUMMARY...............................................................................................5 1.1

Hardware Design ...............................................................................................5

1.2

Operational Procedures .....................................................................................5

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

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

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

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

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

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Table of Contents (cont’d) TABLES Table 1.1 – Riser Gas Lift Requirements for Terrain Slug Suppression ................................29 Table 1.2 – Cooldown Time as a Function of PU Foam Thickness Within ‘Pipe-in-pipe’ Flowlines ...........................................................................43 FIGURES Figure 1.1 – Production Forecast for Bonga Phase I Development (refer to Bonga Basis of Design).........................................................................................................13 Figure 1.2 – Bonga Subsea Field Layout..............................................................................14 Figure 1.3 – Bonga Production Well Design, Used for All Thermal-hydraulic Analysis..........15 Figure 1.4 – Production Flowline Topography for (a) 10in West-side Flowlines, and (b) 12in East-side Flowlines....................................................................................16 Figure 1.5 – Insulation Systems for 10in and 12in Pipe-in-pipe Flowlines (Left Panel), and Steel Catenary Risers (Right Panel) ...........................................................17 Figure 1.6 – Definition of Well Start-up Terminology.............................................................22 Figure 1.7 – Wellhead Warm-up Time to HDT, for Cold Earth Start-up of the Field’s Coldest Well (702p7) at 0% Watercut................................................................22 Figure 1.8 – Treatable Liquid Rate for 18gpm MeOH Injection (Mehta, 1999) ......................23 Figure 1.9 – Well Warm-up Time of 702p7: Dependence on Water Cut ...............................23 Figure 1.10 – Safe Condition Time for 8-hour Wellbore Cooldown .......................................24 Figure 1.11 – Influence of Watercut on Well Safe Condition Time for 702p7 ........................24 Figure 1.12 – Safe Condition Time for 12-hour Cooldown of Tree/Jumper/Manifold, Based on Time for Wellhead Temperature to Reach 120°F............................25 Figure 1.13 – Hot-oiling Performance: Return Temperature for 50MBOPD Circulation of 150°F Source Oil ........................................................................................25 Figure 1.14 – Flowing Wellhead Temperatures Calculated for Initial-life Wells and the Field’s Coldest Well (702p7) with 0% Water Cut.......................................33 Figure 1.15 – Arrival Temperatures Calculated for All Initial-life Wells with 0% Water Cut....33 Figure 1.16 – Cumulative Arrival Temperature for Initial-life Well Production, Relative to the 98°F Arrival Temperature Constraint for Waste Heat Capacity .............34 Figure 1.17 – Influence of Riser Gas Lift on Riser Froude Number, as a Means to Eliminate Riser Instability and Terrain Slugging Shown for the 12in East-side Risers .............................................................................................34 Figure 1.18 – Riser Base Gas Lift Required for Complete Suppression of Terrain Slugging for 10in West-side Flowlines ............................................................35 Figure 1.19 – Riser Base Gas Lift Required for Complete Suppression of Terrain Slugging for 10in East-side Flowlines .............................................................35

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Table of Contents (cont’d) FIGURES Figure 1.20 – Riser Base Gas Lift Required to Limit Terrain Slugging to Within 50bbl Slugs for 12in East-side Flowlines ..................................................................36 Figure 1.21 – Slug Volumes Calculated for 12in East-side Flowlines and 50% Water Cut as a Function of Gas Lift Rate ........................................................................36 Figure 1.22 – Separator Level Fluctuation Calculated for 12in East-side Flowlines and 50% Water Cut as a Function of Gas Lift Rate.........................................37 Figure 1.23 – Effect of Cold (40°F) Gas Lift Injection on Arrival Temperature for 10MBOPD Production and 25MMscfd Gas Lift for Slug Suppression .............37 Figure 1.24 – Gas Injection Temperatures at Mudline for Prior Umbilical-based Gas Lift Design...............................................................................................38 Figure 1.25 – Dependence of Gas Injection Temperature on Gas Lift Riser Diameter for an Insulating Value of U = 4W/m2-C ...............................................................38 Figure 1.26 – Dependence of Gas Injection Temperature on Gas Lift Riser Insulating Value for a 3.5in Tube Diameter .....................................................................39 Figure 1.27 – System Temperature Summary for Base-case Flexible Riser-based Gas Lift Design...............................................................................................40 Figure 1.28 – Definition of Contributions to Cooldown Time .................................................46 Figure 1.29 – Downtime Duration Statistics for Unplanned Shutdowns in GoM ....................47 Figure 1.30 – Wellbore Cooldown at Wellhead for Hottest and Coldest 702 Wells ...............47 Figure 1.31 – East-side 12in Riser Cooldown Performance for (a) 2in Carazite and (b) 4in Carazite ....................................................................................................48 Figure 1.32 – West-side 10in Riser Cooldown Performance for (a) 2in Carazite and (b) 4in Carazite ....................................................................................................49 Figure 1.33 – Pipe-in-pipe Cooldown for East-side 12in Flowlines .......................................50 Figure 1.34 – Pipe-in-pipe Cooldown for East-side 10in Flowlines .......................................50 Figure 1.35 – Pipe-in-pipe Cooldown for 10in West-side Flowlines ......................................51 Figure 1.36 – Illustration of Non-unique Relationship Between U Value and Cooldown........51 Figure 1.37 – Blowdown Performance: 10in West-side and Full Line-pack...........................52 Figure 1.38 – Blowdown Performance: 10in West-side and Immediate Choke Closure........53 Figure 1.39 – Blowdown Performance: 12in East-side and Full Line-pack............................54 Figure 1.40 – Blowdown Performance: 12in East-side and Immediate Choke Closure.........55 Figure 1.41 – Blowdown Performance for 50% Watercut, Illustrating Unsuccessful Blowdown for All Scenarios ............................................................................56 Figure 1.42 – Blowdown Performance with Riser Gas Lift Assist, for 12in East-side Flowlines.........................................................................................57 Figure 1.43 – Blowdown Performance with Riser Gas Lift Assist, for 10in East-side Flowlines.........................................................................................58

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Table of Contents (cont’d) FIGURES Figure 1.44 – Pressure and Temperature Evolution During Cold Gas Lift-assisted Blowdown ...................................................................................59 Figure 1.45 – Benefit of Depressurisation for Unsuccessful Blowdown in Providing 24 Hours of Additional Cooldown Time...........................................................60 Figure 1.46 – Cold Start-up ..................................................................................................61 Figure 1.47 – Additional Well Start-up ..................................................................................62 Figure 1.48 – Interrupted Start-up ........................................................................................63 Figure 1.49 – Planned or Unplanned Shutdown from Steady-state ......................................64 Figure 1.50 – Blowdown .......................................................................................................65 APPENDICES Appendix 1A – Reservoir Fluid Properties ............................................................................66 Appendix 1B – Wellbore Modelling Summary and Production Forecast ...............................71 Appendix 1C – Production Flowlines: Topography and Ambient Temperature Data .............79

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

1.1

1.2

Hardware Design •

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

•

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

•

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

•

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

•

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

•

Added capability to isolate individual flowlines for dry-oil circulation

•

Added riser base pressure/temperature sensors (MoC 64)

Operational Procedures •

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

•

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

•

Revealed that slug control not required for west-side flowlines, above 10MBLPD

•

Identified that well MeOH bullheading to Subsurface Safety Valve (SSSV) required only for long shut-ins (> 2 days)

•

Revealed that blowdown unsuccessful for watercuts 50% and higher

•

Illustrated that success of gas lift assist blowdown is not guaranteed

•

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

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2.0

ITEM OVERVIEW AND SPECIFICATIONS

2.1

Introduction Bonga is a deepwater Nigerian oil prospect in Block OPL 212 in 1000m water depth, operated by Shell Nigeria Exploration and Production Company Limited in a joint venture with Esso (20%), Elf (12.5%) and Agip (12.5%). Bonga will be developed as a subsea network, with 1.9 to 9.2km tiebacks to a permanently moored Floating Production, Storage and Offloading vessel (FPSO). Anticipated peak production rates are 225MBOPD oil, 170MMscfd gas (including recycled riser gas lift) and 100MBWPD produced water (refer to production function in Figure 1.1). Reservoir pressure will be maintained via 16 subsea waterflood wells with a 300MBWPD total water injection capacity. Produced oil will be stored on the FPSO (2MMBO storage capacity) for tanker offloading, while Bonga gas will be exported 90km via a 16in pipeline to Riser Platform A of the Offshore Gas Gathering System (OGGS), which feeds the Bonny Nigerian Liquefied Natural Gas Plant (NLNG) plant. The initial phase Bonga Field layout (refer to Figure 1.2) consists of four reservoirs (690, 702, 710/740, 803; roughly one half of reserves within 702) and 20 subsea production wells. Production wells contain a subsea tree (enabling surface controlled isolation valves, production choke and chemical injection valves) connected via short well jumpers to five subsea production manifolds. The subsea wells are produced through four pairs of piggable dual flowlines (three 10in pairs and one 12in pair), with pipe-in-pipe flowlines and externally insulated steel catenary risers. Each flowline is connected to a dedicated gas lift riser delivering up to 25MMscfd riser base gas lift. Riser base gas lift is critical for several Bonga operations, enabling: •

Riser unloading during start-up and blowdown

•

Severe slug suppression

•

Production enhancement

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

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

Bubble point at reservoir temperature (145 to 190°F) = 3335 to 5015psia

•

Stock tank oil gravity = 29 to 33° API

•

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

Unless otherwise noted, simulations here are based on compositional Pressure/Volume/Temperature (PVT) models tuned to match the properties of the dominant 702 reservoir. All transient simulations in OLGA are based on the phase diagram shown in Figure 1.46, calculated for the 702 reservoir fluid. For purposes of analysis, the oil gravity and gas: oil ratio (not to be confused with the gas:liquid ratio) are relatively constant over the field life at 600SCF/STB. Based on the production forecast (refer to Figure 1.1), watercuts of 0%, 50%, and 80% are assumed for early, mid and late-life scenarios, respectively. Hydrate dissociation curves (pressure (HDP) vs temperature (HDT)) for the 702 and 803 fluids are presented in Appendix A, calculated using MULTIFLASH (Mehta, 1998). The expected salinity is that of the seawater (due to significant waterflood), ie approximately 3wt % salt. As a result of this low salinity, compared to the typical 15% salinity of subsea GoM fields, hydrate management for Bonga is particularly challenging (ie HDT approximately 10°F higher). For conservatism, the hydrate dissociation conditions of the 803 fluid with 0% salinity (refer to Figure 1.48) are used as a worst-case for all flowline analysis in this report. At the minimum seabed temperature (40°F), this translates to a blowdown target pressure of HDP = 150psia. For subsea facilities (tree, well jumper and manifold) a target hydrate temperature of HDT = 74°F is used for the 702 wells considered here, corresponding to the maximum design shut-in pressure (4600psia).

2.3

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

702 Wells –

Water depth = 990 to 1105m

–

Measured depth = 1770 to 2315m below mud line

–

True vertical depth = 1360 to 1730m below mud line

–

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

–

Reservoir pressure (average) = 2520 to 4200psia

–

Reservoir temperature = 128 to 162°F

–

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

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•

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690 Wells –

Water depth = 990 to 1105m

–

Measured depth = 2010 to 2875m below mud line

–

True vertical depth = 1500 to 1770m below mud line

–

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

–

Reservoir pressure (average) = 3140 to 4585psia

–

Reservoir temperature = 138 to 164°F

–

Productivity index (average) = 7 to 14 BLPD/psia

710 Wells –

Water depth = 1000 to 1030m

–

Measured depth = 1770 to 1965m below mud line

–

True vertical depth = 1485 to 1760m below mud line

–

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

–

Reservoir pressure (average) = 4240 to 4650psia

–

Reservoir temperature = 134 to 158°F

–

Productivity index (average) = 6 to 27BLPD/psia

803 Wells –

Water depth = 990 to 1030m

–

Measured depth = 2140 to 2570m below mud line

–

True vertical depth = 2030 to 2165m below mud line

–

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

–

Reservoir pressure (average) = 5210 to 5300psia

–

Reservoir temperature = 178 to 186°F

–

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

For conceptual design evaluation, we focus here on wells 702p7 (coldest) and 702p4 (hottest), which represent the flowing wellhead temperature extremes for the dominant 702 reservoir. Note: Results here effectively bracket the thermal-hydraulic performance of all producing wells, which will be analysed individually as part of future detailed design and operability analysis.

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

•

2.4

702p7 (coldest) –

Measured depth = 1870m below mud line

–

True vertical depth = 1380m below mud line

–

Tubing = 4.89in ID x 5.5in OD: bare tubing

–

Reservoir pressure = 3200psia (early life) to 2200psia (late life)

–

Reservoir temperature = 128°F

–

Productivity index (average) = 30BLPD/psia

–

Watercut = 0% (early life) to 80% (late life)

702p4 (hottest) –

Measured depth = 2280m below mudline

–

True vertical depth = 1760m below mud line

–

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

–

Reservoir pressure = 4800psia (early life) to 3600psia (late life)

–

Reservoir temperature = 162°F

–

Productivity index (average) = 80BLPD/psia

–

Watercut = 0% (early life) to 80% (late life)

Subsea Flowline Details The conceptual design evaluation presented here is based on the 10in west side and 12in east side flowline topographies (refer to Figure 1.4), which capture the essential terrain features on either side of the FPSO. Note: The significant difference in offset distance between the East (3.9 and 5.8 miles) and West (1.2 and 1.5 miles) flowlines (refer to Appendix 1C). The riser gas lift injection is located 1150m horizontal distance upstream from the FPSO, at the flowline/riser connection (refer to Figure 1.4). In Appendix 1C, further flowline details are summarised, including individual flowline topographies, the catenary riser profile and profiles of (ambient) sea temperature and current. With reference to the field layout in Figure 1.2, all production flowlines are of 10in nominal diameter, with the exception of the 12in east side flowlines PFL 3/4/5/6 (the ‘East-East’ flowline). As illustrated in Figure 1.5, pipe-in-pipe insulation is used for all production flowlines, with an insulating value of UOD=2.0 W/m2-C (0.352 Btu/hr-ft2-F) or better. Note: In Figure 1.5, U values as low as 1.4W/m2-C can be attained by filling the entire annulus space with foam (as recommended here based on cooldown considerations). Based on both steady-state and cooldown performance, a 4in carazite (or equivalent) insulation has been specified for all production risers (refer to Figure 1.5).

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Operating Conditions and Constraints As a tieback comprised of numerous subsea wells and flowlines, Bonga entails several key flow assurance constraints on system design and operation, including: •

12-hour minimum cooldown time for flowline and riser

•

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

•

Target minimum turndown rate of 10MBLPD per well and per flowline

•

Target blowdown pressure of 145psia

•

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

•

Maximum boarding temperature of 153°F

•

Separator pressure = (300, 150, 150) psia for (early, mid, late) field life

In addition to general Shell subsea operating guidelines:

2.6

•

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

•

No wax deposition in the wellbore

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

Well cold start-up

•

Well safe condition time

•

Steady-state flowing wellhead temperature

•

Well cooldown

•

Steady-state arrival temperature

•

Flowline cooldown

•

Flowline blowdown

Riser gas lift requirements: •

Slug suppression

•

Riser unloading

•

Injection temperature

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

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2.7

Computational Approach

2.7.1

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

2.7.2

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

2.7.3

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

2.7.4

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

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

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

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Figure 1.2 – Bonga Subsea Field Layout

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0.50 psi/ft water-based

0.54 psi/ft oil-based

0.52 brine

psi/ft

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

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0

-200

Elevation (m)

-400

-600

-800 Gas Lift

-1000 -1100 0

500

1500

1000

2000

2500

Length (m)

0 -100 -200 -300

Elevation (m)

-400 -500 -600 -700 -800 Gas Lift -900 -1000 -1100 0

1000

2000

3000

4000

5000

6000

7000

8000

Length (m) OPRM20030302D_001.ai

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

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10in Production Flowline

10in Production Riser 10.75in OD x 1.0in Steel

Flowline 10.75in OD x 0.937in Steel PU Foam

4in Carazite (or equivalent)

Air Gap 14in OD x 0.563in Steel

12in Production Flowline

12in Production Riser 12.75in OD x 1.063in Steel

12.75in OD x 1.126in Steel

PU Foam

Air Gap

4in Carazite (or equivalent)

16in OD x 0.625in Steel OPRM20030302A_011.ai

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

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COLD WELL START-UP: HYDRATE PREVENTION STRATEGIES For flow assurance in the subsea wells, the hottest (702p4 – horizontal) and coldest (702p7 – conventional) 702 wells (described in Paragraph 2.3 and Appendix 1B) are evaluated with regard to: (i) cold-earth start-up, (ii) safe condition requirements and cooldown performance, and (iii) steady-state flowing wellhead temperature. All wellbore thermal analysis is performed using WELLTEMP, for the casing designs in Figure 1.3 and a linear geothermal temperature profile, from the reservoir temperature to 40°F at the wellhead. Production rates over the range 2.5 to 40MBLPD are considered for early, mid, and late-life conditions (0%, 50%, 80% watercut). A sample WELLTEMP input file, summaries of simulation cases and results appear in Appendix 1B Tables 1B.1 to 1B.5. For wellbore transients, the relevant terminology illustrated in Figure 1.6 is defined as follows:

3.1

•

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

•

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

•

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

•

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

Cold Earth Well Start-up A critical aspect of well flow assurance for Bonga is cold earth well start-up, in which the wellbore and surrounding formation are at ambient (geothermal) temperature, either at initial start-up or after an extended shut-in (ie longer than 1 week). In contrast to the common use of Vacuum Insulated Tubing (VIT) to provide fast warm-up of deeper subsea wells in the GoM, bare tubing is used for all Bonga wells. Although the relatively shallow depth of the Bonga wells makes bare tubing viable, careful evaluation is required of the relative hydrate risk at start-up. As a worst case, the start-up of the coldest well (702p7) is considered first for early life conditions. As shown in Figure 1.7, the well warm-up time to HDT = 74°F is moderately lengthy, particularly at low start-up rates. Note: Although rapid well ramp-ups are anticipated for Bonga (eg 10MBLPD within 1/2 hour), a more moderate start-up rate (eg 5MBPLD average) is analysed as a design case. At a start-up rate of 5MBLPD, the wellhead region is temporarily in the hydrate region for 80 minutes (refer to Figure 1.7). Note: As a general guideline, based on operating experience and preliminary hydrate kinetics research (which must be used carefully), a hydrate exposure longer than 60 minutes with greater than 10°F, subcooling is considered an unacceptable risk for subsea wells (with significant cost of intervention/ remediation).

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As a possible operational solution, bullheading of MeOH into the entire wellbore prior to start-up significantly reduces the hydrate risk, as reflected by the MeOH residence time (time required for one well pass) in Figure 1.7 (eg hydrate exposure time reduced from 80 minutes to 40 minutes at 5MBLPD). Notes: (1)

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

(2)

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

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

0% watercut: Bullheading Option

•

Hydrate Exposure (5MBLPD)

No MeOH in well

80 minutes

MeOH to SSSV (50 to 75bbl)

65 minutes

MeOH to perfs (150 to 250bbl)

40 minutes

50% watercut: Bullheading Option

Hydrate Exposure (5MBLPD)

No MeOH in well

50 minutes

MeOH to SSSV (50 to 75bbl)

35 minutes

MeOH to perfs (150 to 250bbl)

10 minutes

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

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At 50 to 80% watercut, an MeOH injection rate of 54 to 90gpm would be required, which is infeasible from an umbilical delivery viewpoint (leading also to significant MeOH production contamination). Thus, an additional factor to be considered during future operability analysis is whether or not to constrain start-up rates at high watercut, to protect the tree and jumper at the expense of the wellbore. Preliminary operability analysis suggests a possible dual start-up strategy: (1) Low watercut (below 20%): constrained start-up rate to yield MeOH-treatable (at 18gpm) water rates, with full hydrate protection of the tree and jumper. (2) High watercut (above 20%): unconstrained (fast) start-up rate (ie limited only to prevent well/reservoir impairment) to ‘outrun’ the finite time hydrate kinetics in the wellbore, tree and jumper. Note: For the fortunate result in Figure 1.9, the well warm-up time to HDT is much faster at higher watercut (due to higher heat capacity of water), which reduces the relative hydrate risk of the high watercut strategy. Further development and testing of low dosage hydrate inhibitors will also be undertaken to further reduce the hydrate risk in the tree and jumper, for watercuts up to 80% and subcoolings up to 30°F (Mehta, 2001).

3.2

Well Safe Condition Analysis The concept of a well safe condition is motivated by the risk of hydrate formation in the wellbore in the event of an aborted start-up. In this way, operations staff can determine whether immediate MeOH treatment is required in the event of an aborted start-up. Before well safe condition has been reached during a well start-up, immediate operator action (eg well bullheading) is required before safe condition (without any no-touch time), in contrast to the full 8-hour cooldown period available after safe condition. Note: The SC definitions are based on 8 hours of required cooldown time for the wellbore, tree and well jumper (eg 3 hours no-touch time + 5 hours MeOH treatment time). During well start-up, hydrate inhibition via MeOH injection at the tree is generally recommended until the SC time is reached (Ellison and Kushner, 1998). Note: If MeOH usage/storage is a concern, special operating guidelines may be developed to treat until 5 hours of cooldown are available (the MeOH treatment time), or even only to the (shorter) warm-up time to HDT. These less conservative procedures are based on the idea that in an aborted start-up of a single well, no-touch time is unnecessary and only the well being started must be treated immediately. For Bonga, the condition for termination of MeOH injection at the tree will be determined as part of future operability analysis. For the coldest (702p7) and hottest (702p4) 702 wells, and early-life conditions, the wellbore SC times are shown in Figure 1.10 as a function of the average rate during start-up. For a moderate start-up rate of 5MBOPD, these results bracket the SC times for all 702 wells to between 5 to 10 hours, translating to 130 to 260bbls MeOH volume per well, for an 18gpm injection rate. At higher watercuts (eg greater than 50%), the SC time is significantly reduced (ie faster warm-up due to higher heat capacity of water), as illustrated in Figure 1.11 for the 702p7 well.

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The corresponding SC analysis for the tree and well jumper is based on the specification (for the subsea contractor) that these components must provide at least 12 hours of cooldown from 120°F to 73°F. Note: This tree/jumper cooldown period is longer than the 8-hour cooldown allotted to the well tubing, to allow an additional operational margin for the field complexity of Bonga. The SC temperature for the tree and well jumper is 120°F, for which the corresponding SC time is shown in Figure 1.12. Note: The steady-state FWHT for well 702p7 does not reach 120°F, so its SC temperature in Figure 1.12 is modified to 110°F for purposes of comparison (an exception for 702p7 to be accounted for in operability analysis). Owing to the rather lengthy tree/jumper SC times (eg greater than 10 hours at 5MBOPD), operating procedures for less than 12 hours of cooldown (ie more immediate action upon aborted start-up) may be necessary in lieu of MeOH injection until the tree/jumper SC time is reached. Note: For treatment until a 12-hour SC, production at higher watercuts would have to be constrained for several hours to maintain a MeOH-treatable water rate, with the additional cost of deferred production.

3.3

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

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Wellhead Temperature (ºF)

120 SC Temperature 100

80 HDT Warm-up Time

60

SC Time

40 0

2

4

8

6

10

12

14

Time (hours) OPRM20030302D_002.ai

Figure 1.6 – Definition of Well Start-up Terminology

300 Time for one well pass Time to HDT Time After Start-up (minutes)

250

200

Hydrate Exposure Time

150

Wellbore Outside Hydrate Region

100

50

0 0

2000

4000

6000

8000

10,000

Average Start-up Rate (BLPD) OPRM20030302D_003.ai

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

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Treatable Liquid Rate (oil + water) (BLPD)

10,000

8000

6000

4000

2000

0 0

20

40

60

80

100

Watercut (%) OPRM20030302D_004.ai

Figure 1.8 – Treatable Liquid Rate for 18gpm MeOH Injection (Mehta, 1999) 240

Time to Reach HDT (minutes)

Time for one well pass 50% wc 0%wc 180

120 Wellbore Outside Hydrate Region 60

0 0

2000

4000

6000

8000

10,000

Average Start-up Rate (BLPD) OPRM20030302D_005.ai

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

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12 702p4 horiz 702p7

SC Time (hours): Guarantee 8-hour Cooldown

10

8

6

4

2

0 4

6

8

10

12

14

16

Average Start-up Rate (MBOPD) OPRM20030302D_006.ai

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

25 50% wc 0% wc Well SC Time (hours): Guarantee 8-hour Cooldown

20

15

10

5

0 0

5000

10,000

15,000

20,000

Average Start-up Rate (BLPD) OPRM20030302D_007.ai

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

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20

SC Time (hours): Guarantee 8-hour Cooldown

702p7 702p4 horiz 15

10

5

0 0

5

10

15

20

25

30

Average Start-up Rate (MBOPD) OPRM20030302D_008.ai

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

160 West Arrival Temperature (ºF)

140 East 120

100

80

60

40 0

2

4

6

8

10

Time (hours) OPRM20030302D_009.ai

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

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

4.1

•

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

Steady-state Thermal Performance: Wellbore and Flowline Since prior wellbore analysis (Granherne, 1998) has been based on the approximation of constant U value for the wellbore (ie U=2.0Btu/hr-ft2-F), the more rigorous thermal modelling in WELLTEMP is used here to obtain refined FWHT predictions. The range of FHWT predicted for the six initial-life production wells is shown in Figure 1.14, along with 702p7, the field’s coldest well (which fortunately produces through the short-offset West flowline PFL11). At the minimum well production rate of 10MBLPD specified in the Basis of Design (BoD), the FWHT lies in the range 115 to 165°F. The lower end of this FWHT range is noticeably colder than that typical of (deeper) GoM subsea oil wells, which should be accounted for in building upon GoM subsea operating experience. Note: Production rates lower than 10MBLPD (eg as low as 5MBLPD) are also operable from a thermal point of view, although well stability must also be accounted for in specifying the minimum turndown rate. Later in field life, the FWHT increases slightly for all flowrates (eg by 5°F for 80% watercut), due to the enhanced thermal heat capacity of water (which may be offset to some degree by reservoir cooling due to waterflood). With regard to the thermal performance of the coupled well/flowline system, there are three key constraints which govern the minimum operable arrival temperature for steady-state production: •

Flowline operation outside of hydrate regime: arrival T > 60°F

•

Minimum 12-hour cooldown of riser/flowline: arrival T > 90°F

•

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

In Figure 1.15, the arrival temperatures for the six initial-life wells/flowlines are shown as a function of production rate. Note: Each initial-life well produces through a dedicated flowline, with an initially inactive West flowline pair PFL8/9. For all pipe-in-pipe flowlines, an overall heat transfer co-efficient of Uod = 2W/m2-C is used, corresponding to a polyurethane foam thickness of ~0.6in (leaving ~0.4in of air gap, refer to Figure 1.4).

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Note: Cooldown requirements will likely require an entirely foam-filled gap (ie MoC 59, discussed in Paragraph 5.1), for which the arrival temperatures will be slightly higher than those reported here (particularly at low production rates). The 12-hour cooldown constraint (detailed analysis presented in Paragraph 5.1) translates to a minimum turndown production rate of approximately 10MBOPD for the four east-side flowlines. Although slightly lower production rates may be possible for special operations which are manageable with less than 12 hours of cooldown, production rates less than 5MBOPD are inoperable due to onset of flowing conditions in the hydrate regime. With regard to the topsides heat requirement at high production rates, the cumulative oil temperature for all six initial-life wells/flowlines (with equal production from each; refer to Figure 1.16) indicates that the 98°F constraint is met even at turndown conditions (ie >50MBOPD), with a 20°F margin in arrival temperature at flowrates greater than 150MBOPD. Thus, the available topsides waste heat for oil heating is not of concern at initial field life, which serves as the worst case since oil production will subsequently decrease (accompanied by increasing water production).

4.2

Terrain-induced (Severe) Slugging The phenomenon of severe slugging induced by undulations in flowline terrain is predicted to be significant at Bonga in the absence of mitigating control, due to: •

Significant downhill flow near the riser base for (~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)

east-side flowlines

Note: The distinction between shorter hydrodynamic slugs (up to ~50 diameters in length) in locally horizontal or uphill flow and longer terrain slugs (proportional to the length of downhill flow), which are more problematic for topsides facilities and process control. That terrain slugging is outside the scope of steady-state simulations, which cannot capture at all the adverse effects of higher well backpressure and order-of-magnitude fluctuations in liquid production rate. In the following, Olga2000 is used to define the terrain slugging operability envelope, including detailed assessment of slug suppression via riser gas lift. For terrain slugging to occur in a flowline/riser system, three necessary conditions must be satisfied simultaneously (Vreenegoor, 1999): (1) The Pots slugging number less than order unity in the flowline:

π ss =

zRT m& g < O(1) αLg m& l

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

Fr = U sg

ρg (ρ l − ρ g ) gD

< O(1)

(3) Stratified flow pattern in the riser base region of the flowline. Section 1 Dynamic Flow Assurance Analysis

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Physically, the slugging number condition: •

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

•

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

•

Enables growth of the liquid slug

For representative Bonga conditions at 10MBLPD and 50% watercut, the slugging numbers for each flowline are: • East 12in: πss = 0.3 • East 10in: πss = 0.2 • West 10in: πss = 0.7 Furthermore, the Froude number (without gas lift) is on the order of 0.05 and stratified flow is predominant in the downhill flow regions near the riser base. Thus, based on this simple conceptual analysis, severe terrain slugging is predicted at Bonga without riser gas lift, particularly for the east-side flowlines. Although it has not yet been field-proven for large-diameter deepwater risers, a potentially effective slug control technique involves gas injection at or near the riser base. With reference to the necessary conditions for terrain slugging, gas lift can eliminate the riser instability required for slug initiation (ie Froude number greater than order unity). For the 12in east Bonga flowline, riser gas lift increases the Froude number from order 0.05 to order 1 (refer to Figure 1.17), and hence is expected to be effective in slug suppression. In the following, Olga2000 computations are used to investigate in detail the effectiveness of riser gas lift in suppressing terrain slugging. In Figures 1.18 to 1.20, the gas lift required to suppress terrain slugging is shown as a function of liquid production rate. In Olga2000, terrain slugging can be isolated from smaller, less problematic hydrodynamic slugs (ie by switching Slugtracking off), to yield a sharp transition from terrain to hydrodynamic slugging. For all west-side 10in flowlines (refer to Figure 1.18), no riser gas lift is required at the minimum turndown rate of 10MBLPD, even at 80% watercut. This result is in contrast to prior studies (Granherne, 1998), which indicated that 5MMscfd gas lift was required, apparently due to inaccurate modelling of the riser-base topography. Note: Slugging may be suppressed at turndown rates as low as 5MBLPD, by gas lift rates up to 10MMscfd (refer to Figure 1.18). For the 10in east-side flowlines, 5 to 10MMscfd gas lift is required to eliminate slugging for the minimum rate of 10MBLPD at 0 to 80% watercut (refer to Figure 1.19). Due to the more adverse east-side topography, the gas lift requirement for flowrates lower than 10MBLPD is much more significant for the 10in east flowlines, compared to the 10in west results. Thus, even at the gas lift capacity of 25MMscfd per flowline, signficant slugging will occur for the east-side flowlines for turndown rates lower than approximately 8MBLPD (refer to Figure 1.19).

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For the 12in east flowlines, terrain slugging cannot be totally eliminated by feasible riser gas lift rates. Hence, for these 12in flowlines, the gas lift required to reduce the terrain slug size to 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 strongly influences the gas injection temperature, as a 3.5in riser produces a 15°F higher injection temperature compared to a 3in riser. This is due to the fact that for smaller diameters, less topsides choking is required (more pressure drop in riser) and the gas heater temperature must be reduced to satisfy the 160°F riser inlet temperature constraint. At the minimum gas lift rate of 5MMscfd, the riser insulation dominates the thermal performance, for which an insulating value of approximately U = 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 be optimised during detailed design, are a 3.5in ID central gas lift pipe with an effective U value of 4W/m2-C. As illustrated in Figure 1.27, this large-bore riser design satisfies all requirements for gas lift, providing a gas injection temperature of at least 90°F over the entire range of gas rates. In this design, topsides heating of the gas lift stream is an effective approach to prevent a significant gas lift cooling penalty on arrival temperature and riser cooldown. This analysis culminated in the preparation and acceptance of MoC 16, which specified the gas lift heating requirements and large-bore riser design described above.

Section 1 Dynamic Flow Assurance Analysis

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702p15/PF11

180 Flowing Wellhead Temperature (ºF)

803p1/PF12 170

702p4/PF1 690p1/PF2

160

702p9/PF3 702p10/PF6

150

702p7/PF11 140 130 120 110 0

5

10

15

20

25

30

35

40

Rate (MBOPD) OPRM20030302D_010.ai

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

Arrival Temperature per Flowline (ºF)

160 702p15/PF11 803p1/PF12

140

702p4/PF1 690p1/PF2 120

702p9/PF3 702p10/PF6

100

80

60 0

10

20

30

40

50

60

Rate (MBOPD) OPRM20030302D_011.ai

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

Section 1 Dynamic Flow Assurance Analysis

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130

Bulk Arrival Temperature (ºF)

120

110

100

90

80

70 0

50

100

150

200

250

Cumulative Rate (MBOPD) OPRM20030302D_012.ai

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

1

Froude#

FR < 0(1): Riser instability and possible slugging

0.1

0.01 0

5

10

15

20

25

30

35

Riser Gas Lift (MMSCFD) OPRM20030302D_013.ai

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

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20

Required Gas Lift (MMSCFD)

0%wc 50%wc 15

80%wc

10

5

0 0

10

20

30

40

Liquid Production Rate (MBLPD) OPRM20030302D_014.ai

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

40

Required Gas Lift (MMSCFD)

0%wc 50%wc 30

80%wc

20

10

0 0

10

20

30

40

Liquid Production Rate (MBLPD) OPRM20030302D_015.ai

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

Section 1 Dynamic Flow Assurance Analysis

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30 0%wc Required Gas Lift (MMSCFD)

50%wc 80%wc 20

10

0 0

10

20

30

40

Liquid Production Rate (MBLPD) OPRM20030302D_016.ai

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

800

Maximum Slug Volume (bbl)

10MBLPD 20MBLPD

600

40MBLPD

400

200

0 0

5

10

15

20

25

Gas Lift Rate (MMSCFD) OPRM20030302D_017.ai

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

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Maximum Separator Level Fluctuation (%)

20

10MBLPD 20MBLPD

15

40MBLPD

10

5

0 0

5

15

10

20

25

Gas Lift Rate (MMSCFD) OPRM20030302D_018.ai

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

130

120

110

ºF

100

90

80

70

60 0

1000

2000

3000

4000

5000

6000

7000

Horizontal Length (m) OPRM20030302D_019.ai

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

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80 Tin = 120ºF

Gas Injection Temperature (ºF)

70

Tin = 140ºF

60

50

40

30

20 0

5

10

15

20

25

Effective U of Each Umbilical Tube (W/m^2-C) OPRM20030302D_020.ai

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

Gas Injection Temperature (ºF)

120

115

110

105

100 2

2.5

3

3.5

4

4.5

5

Gas Lift Tube ID (in) OPRM20030302D_021.ai

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

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Gas Injection Temperature (ºF)

100

95

90

85

80

75

70 2

3

4

5

6

7

8

Effective U (W/m^2-C) OPRM20030302D_022.ai

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

Section 1 Dynamic Flow Assurance Analysis

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From Gas Heater Heater T

Production Riser Riser Inlet T

Topsides Subsea

Gas Lift Riser 3.5in ID UID = 4W/m2-C Injection T

Heater T (ºF) Riser Inlet T (ºF) Injection T (ºF) 220

Gas Injection Temperature (ºF)

200 180 160 140 120 100

Spec = 90ºF

80 0

5

10

15

20

25

30

Gas Rate (MMSCFD) OPRM20030302D_023.ai

Figure 1.27 – System Temperature Summary for Base-case Flexible Riser-based Gas Lift Design Section 1 Dynamic Flow Assurance Analysis

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SUBSEA SYSTEM SHUTDOWN: HYDRATE PREVENTION STRATEGIES A critical aspect of hydrate management for deepwater subsea systems is prevention of hydrate formation by system cooling during shut-ins of widely varying duration. Operationally, subsea shut-ins are inherently complex with multiple decision 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 shutdown and to protect the subsea system from hydrates, subsea facilities must be designed with sufficient cooldown time. In general terms, cooldown is defined as the time required for the inner wall of the flowpath to reach the hydrate formation temperature, somewhere in the system. The contributions to the cooldown time anticipated 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 to rectify the shutdown cause, without having to undertake operations to protect the subsea system from hydrates. The 3-hour no-touch time specified for Bonga is based on GoM platform statistics for unplanned shutdowns (refer to Figure 1.29), which indicate that 80% of typical process and instrumentation interrupts were analysed and corrected within 3 hours. Figure 1.29 indicates a rapidly diminishing benefit 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 least 8 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 provided by 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 100ft depth and below). Thus, MeOH bullheading of the well to the SSSV will be required only 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 be much more frequent (refer to Figure 1.29). The required MeOH treatment time will generally be less than the 5 hours allotted. As an added benefit, this surplus time due to quicker MeOH treatment may be used to increase the no-touch time and/or the flowline blowdown time.

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Subsea Tree/Jumper/Manifold As for the well tubing, the subsea tree, well jumper and manifold must provide at least 8 hours of cooldown, accounting for 5 hours allotted for MeOH displacement of these components. Although the chemical injection system is sized to treat all wells within 5 hours, 12 hours of cooldown time are specified for the wellhead facilities in the Subsea ITT as an added margin to assist Operations. In particular, the following gas 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) –

120°F (49°C) to 63°F (17°C) in no less than 12 hours

The starting wellhead temperature of 120°F is satisfied for all initial-life wells at rates greater 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-specific operating procedures. The final temperatures reflect the HDT at the well shut-in pressure (4600psia) upstream of the choke and the anticipated flowline shut-in pressure 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 is specified in the flowline/riser ITT, for gas-filled (methane) components at 28bara: •

West-side 10in flowlines –

•

97°F (36°C) to 66°F (19°C) in no less than 12 hours

East-side 10in and 12in flowlines –

86°F (30°C) to 61°F (16°C) in no less than 12 hours

The work presented herein culminated in approval of MoC 59, which specifies that both this cooldown requirement and a U value requirement of Uod ≤ 2.0W/m2-C must be met for the cylindrical cross-sections of the flowline and riser. Note: The more conservative specification of gas cooldown is based on restart considerations, ie the hydrate risk of wet fluid passing through cold, originally gas-filled sections upon restart. The starting temperatures for cooldown are based on the minimum anticipated riser base temperatures for 10MBOPD production, including margins for cooling by riser gas lift and possible reservoir cooling by waterflood. With these conservative margins, the starting riser base temperatures are comparable to the arrival temperatures at 10MBOPD (refer to Figure 1.15). The west-side starting temperature is 11°F than the east-side flowlines due to the significantly shorter offsets (hence lesser heat losses) of the west-side flowlines. The final temperatures are based on the HDT at the flowline shut-in pressure, using the 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-in pressure is explicitly accounted for. Due to their longer offsets, the east-side flowlines experience less partial packing and hence a lower shut-in pressure, which is why the final temperature for east-side cooldown is lower (61°F for east-side versus 66°F for west-side).

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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-filled cooldown 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) riser insulation is required to attain 12 hours of cooldown at the minimum turndown rate of 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-in pressures and hence longer cooldown times (ie results closer to the immediate choke closure curves in Figures 1.31 and 1.32). At anticipated production rates of 30 to 40MBOPD (according to the production function), 18 to 20 hours of gas cooldown are available, providing Operations staff additional time to react and/or secure the system against hydrates. For the base-case pipe-in-pipe flowline design (refer to Figure 1.5), the U = 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 indicates that the annular gap must be filled with foam (at marginal additional cost) to meet the 12-hour gas cooldown requirement. In Figures 1.33 to 1.35, the cooldown performance 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 to meet 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 cooldown requirement. The U value requirement is based only on steady-state thermal performance, which does not uniquely determine the cooldown performance. That is, significantly different cooldown performance can occur for the same U 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 the 12-hour cooldown target, while a 0.75in wall provides only 10 hours of cooldown, although the corresponding U values are identical. The situation is complicated further for alternative pipe diameters and wall thicknesses, which may be explored in the detailed design process. Thus, to ensure adequate flowline/riser cooldown performance, MoC 59 specifies that both the U value and cooldown specifications shall 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 Thickness Within ‘Pipe-in-pipe’ Flowlines

Section 1 Dynamic Flow Assurance Analysis

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Flowline Blowdown With reference to Figure 1.28, for subsea shutdowns lasting longer than 8 hours, depressurisation of producing flowlines (blowdown) must commence to secure the continuously cooling flowline against hydrate formation. To remain within the 12-hour cooldown window (the minimum cooldown at turndown rates), all flowlines must be blown down within approximately 4 hours (ie 12-hour cooldown ≥ 3-hour no-touch + 5-hour well MeOH treatment + 4-hour blowdown). Due to the lengthy well tubing cooldown, the well treatment may take only 3 to 4 hours, which will allow 5 to 6 hours of blowdown time. The precise breakdown of the available cooldown time 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 the ambient seafloor temperature of 40°F, the flowline will be secured against hydrate formation for an indefinite shut-in. For conservatism, a blowdown target of HDP = 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 target is ~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 summarised as 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 12in east-side flowlines is summarised in terms of pressure, gas outlet rate and liquid carryover, for initial-life conditions at 0% watercut. Results are shown for the following scenario, with both immediate choke closure and full line-packing considered 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 2in blowdown valve) Note: The line-packing cases capture the maximum design gas and liquid rates during blowdown, while the immediate choke closure cases reflect the typical operating scenario. With respect to the topsides facility constraints, none of the blowdown cases in Figures 1.37 to 1.40 exceed the 200MMscfd gas flare capacity or the 75MBOPD oil scrubber capacity. For the west-side flowlines, the maximum gas and liquid rates for the worst-case line-packing scenario are 27MMscfd and 45MBOPD (refer to Figure 1.37). For the 12in east-side flowlines, the peak rates are 40MMscfd and 70MBOPD (refer to Figure 1.39). Due to the short duration of these peak rates, simultaneous blowdowns of multiple flowlines may be pursued, provided that each blowdown is staggered by at least 30 minutes.

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For the flow assurance targets, blowdown is successful for the 10in west-side flowlines 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 west flowlines, the blowdown is completed within 1 hour. In contrast, blowdown for the 12in east-side flowline is unsuccessful for immediate choke closure (refer to Figure 1.40(a), with a final pressure of 600psia which is well above the 145psia target. The counterintuitive result that blowdown is successful for a line-packed east flowline is due to the additional liquid carryover driven by the higher shut-in pressure. Significantly, for a 50% watercut (which will be attained early in field life), blowdown is unsuccessful for all scenarios, as indicated in Figure 1.41. Thus, to secure flowlines for indefinite shut-ins, alternatives to a traditional, totally passive blowdown must 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 and the 10in west-side flowlines at higher watercuts, the possibility of riser gas lifting to remove riser liquid during blowdown is now considered. The specific worst-case scenario analysed below consists of: 30MBLPD production (50% watercut) → Immediate shut-in at time of maximum riser liquid during severe slugging → 3-hour cooldown → Open 2in to 10in blowdown valve (@ t = 4 hours) → Inject riser gas lift pulse of 10MMscfd 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 blowdown success (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, which instead falls back to the riser base resulting in churn-like flow. To attain pressures below 145psia, a very rapid blowdown with a 10in valve is required, with an associated peak liquid outlet rate of 200MBLPD (refer to Figure 1.42b). Although this 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 within the instantaneous flare capacity (200MMscfd). Note: After gas lift ceases (@ t = 5 hours in Figure 1.42), the flowline pressure slowly increases to approximately 170psia as liquid in the flowline and riser settles out. Similar results are obtained for the 10in east-side flowlines (refer to 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 injecting 40°F lift gas into the flowline, which contains wet fluids which have cooled several hours (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-hour cooldown → Open blowdown valve → Inject 10MMscfd gas lift @ 40°F for 2 hours → Stop gas lift

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As shown in Figure 1.44(a), the cold gas lift injection causes a local pressure/temperature within 1°F of hydrate conditions. The fact that hydrate condition subcooling does not occur is due to the rapid riser-base depressurisation by 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 to Figure 1.44(b), preventing a local hydrate condition. In light of this depressurisation effect, it is critical that the topsides blowdown valve is fully open before the gas lifting operation commences, as a significant (~20°F) subcooling of wet fluids at the 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 enable hydrate-free indefinite-length shut-ins. In particular, the requirement of a large blowdown valve orifice for effective gas lift assisted depressurisation resulted in replacement of the prior fixed 2in blowdown valve with a two-stage blowdown valve train containing a smaller variable choke and a large fixed orifice. Furthermore, it was revealed that gas lift-assisted blowdown does not guarantee successful blowdown below 145bara, due to pressure recovery resulting from liquid settle-out in the flowline and riser. Hence, a backup strategy was formulated for more lengthy shut-ins, consisting of flowline displacement by dry oil circulation at 3 to 5mph. Associated topsides modifications were also made to improve the timing and control of the dry-oil circulation operation. Additionally, a pressure/temperature sensor was added to each riser base (at the gas-injection tee) to enable Operations to accurately 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 to question whether a primary dry-oil circulation strategy should be used in place of gas lift-assisted blowdown. There are two key advantages of blowdown as a primary shut-in strategy. First, it is an essentially passive operation which can be performed under unexpected or emergency topsides shutdowns. Secondly, even an unsuccessful blowdown provides significant extra reaction time for trouble-shooting and a secondary dry-oiling operation if necessary (eg blowdown to 250psia provides 24 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

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Unrestricted

120

Percentages (%)

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 21 22 23 24 Hours OPRM20030302D_024.ai

Figure 1.29 – Downtime Duration Statistics for Unplanned Shutdowns in GoM

Minimum Wellbore Temperature (ºF)

150 702p4 702p7

140 130 120 110 100 90 80

HDT

70 0

10

20

30

40

50

Time After Shut-in (hours) OPRM20030302D_025.ai

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

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Production Rate (MBOPD) 10

20

40

14

Gas Cooldown Time (hours)

12 Target 10 8 6 4 Immediate Choke Closure 10-minute Closure

2

Full Line-pack 0 60

70

80

90

100

110

120

130

140

Initial Riser Base Temperature (ºF)

Production Rate (MBOPD) 10

20

40

30

Gas Cooldown Time (hours)

25

20

15 Target 10 Immediate Choke Closure 5

10-minute Closure Full Line-pack

0 60

70

80

90

100

110

120

130

140

Initial Riser Base Temperature (ºF) OPRM20030302D_026.ai

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

Section 1 Dynamic Flow Assurance Analysis

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Production Rate (MBOPD) 5

10

20

40

16

Gas Cooldown Time (hours)

14 Target 12 10 8 6 4

Immediate Choke Closure 10-minute Closure

2

Full Line-pack 0 80

90

100

110

120

130

Initial Riser Base Temperature (ºF)

Production Rate (MBOPD) 5

10

20

40

Gas Cooldown Time (hours)

25

20

15 Target 10

Immediate Choke Closure 5

10-minute Closure Full Line-pack

0 80

90

100

110

120

130

Initial Riser Base Temperature (ºF)

OPRM20030302D_027.ai

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

Section 1 Dynamic Flow Assurance Analysis

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35 U=2

30 Gas Temperature (ºC)

Foam-filled 25 20 15 10 5 0 0

2

4

6

8

10

12

Time (hours) OPRM20030302D_028.ai

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

35 U=2

30 Gas Temperature (ºC)

Foam-filled 25 20 15 10 5 0 0

2

4

6

8

10

12

Time (hours) OPRM20030302D_029.ai

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

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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40 U=2

35

Gas Temperature (ºC)

Foam-filled 30 25 20 15 10 5 0 0

2

4

6

8

10

12

Time (hours) OPRM20030302D_030.ai

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

40 Initial T = 36ºC

0.94in wt and U = 1.4W/m^2-K 0.75in wt and U = 1.4W/m^2-K

Gas Temperature (ºC)

35

30

Minimum CDT = 12 hours

25

20

15 0

2

4

6

8

10

12

Time (hours) OPRM20030302D_031.ai

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

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Maximum Flowline Pressure (psia)

Line-pack

Unrestricted

Blowdown

5150

4150

3150 1in valve 2150 0.5in valve 1150 2in valve

Target: HDP = 145psia

0

2

4

6

8

10

Time (hours) 50

Outlet Oil Rate (MBOPD)

2in valve: 480bbl 40

30

20 1in valve: 360bbl 10 0.5in valve: 160bbl 0 0

2

4

6

8

10

Time (hours) 30

Outlet Gas Rate (MMSCF)

2in valve 25 20 15 1in valve 10 0.5in valve

5 0 0

2

4

6

8

10

12

Time (hours) OPRM20030302D_033.ai

Figure 1.37 – Blowdown Performance: 10in West-side and Full Line-pack Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Maximum Flow Pressure (psia)

Shut-in

Unrestricted

Blowdown

950

750

550 0.5in valve 350

1in valve

Target: HDP = 145psia

2in valve 0 0

2

4

6

8

10

8

10

Time (hours)

Outlet Oil Rate (MBOPD)

50

40

30

20 2in valve: 45bbl 10

0 0

2

4

6

Time (hours)

Outlet Gas Rate (MMSCF/D)

20

15

10 2in valve

5 1in valve 0.5in valve 0 0

2

4

6

8

10

12

Time (hours) OPRM20030302D_032.ai

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

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Line-pack Blowdown 5150

Maximum Flowline Pressure (psia)

4150

3150 1in valve 2150 0.5in valve 1150 2in valve

Target: HDP = 145psia

0

2

4

6

8

10

12

14

16

Time (hours) 70 2in valve 1360bbl Outlet Oil Rate (MBOPD)

60 50 40 30 1in valve: 910bbl 20 0.5in valve 620bbl

10 0 0

2

4

6

8

10

Time (hours) 40 Outlet Gas Rate (MMSCF/D)

35 2in valve 30 25 20 15

1in valve

10 0.5in valve 5 0 0

5

10 Time (hours)

15

20

OPRM20030302D_035.ai

Figure 1.39 – Blowdown Performance: 12in East-side and Full Line-pack Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Shut-in

Blowdown

Maximum Flowline Pressure (psia)

950

750

550

350

Target: HDP = 145psia 0

2

4

6

8

10

8

10

Time (hours)

Outlet Oil Rate (MBOPD)

50

40

30

20

10

0 0

2

4

6

Time (hours)

Outlet Gas Rate (MMSCF/D)

25

20

15

10 2in valve 5

1in valve 0.5in valve

0 0

5

10

15

20

Time (hours) OPRM20030302D_034.ai

Figure 1.40 – Blowdown Performance: 12in East-side and Immediate Choke Closure Section 1 Dynamic Flow Assurance Analysis

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1150

950

Maximum Flowline Pressure (pisa)

West – Immediate closure West – Full line-pack

750

East – Full line-pack East – Immediate closure

550

350

Target: 145pisa

0

5

10

15

20

Time (hours) OPRM20030302D_036.ai

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

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Maximum Flowline Pressure (psia)

500 450 400

2in valve 4in valve

350

10in valve

300 250 200 150

Target HDP = 145psia 100 4

5

6

7

8

9

10

11

12

Time (hours) 250

Outlet Oil Rate (MBLPD)

2in valve 4in valve

200

10in valve 150

100

50

0 4

4.5

5

5.5

6

Time (hours)

Outlet Gas Rate (MMSCF/D)

70 2in valve

60

4in valve 50

10in valve

40 30 20 10 0 -10 4

4.5

5

5.5

6

Time (hours) OPRM20030302D_037.ai

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

Section 1 Dynamic Flow Assurance Analysis

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Maximum Flowline Pressure (psia)

500

2in valve 4in valve

450

8in valve

400 350 300 250 200 150

Target HDP = 145psia 100 4

5

6

7

8

9

10

11

12

Time (hours) 100

Outlet Oil Rate (MBLPD)

4in valve 2in valve

80

8in valve 60

40

20

0 4

4.5

5

5.5

6

Time (hours) 50

Outlet Gas Rate (MMSCF/D)

4in valve 40

2in valve 8in valve

30 20 10 0 -10 4

4.5

5

5.5

6

Time (hours) OPRM20030302D_039.ai

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

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Hydrate

Proximity to Hydrate Condition: Flowline Maximum (HDT-T) (ºF)

0 No Hydrate

50% Water Cut

-10

0% Water Cut

-20 -30 -40 -50 Shut-in

Gas Lift On

Gas Lift Off

-60 0

5

10

15

20

Time After Shut-in (hours)

Temperature at Gas Lift Location (ºF)

120 50% Water Cut

110

0% Water Cut

100 90 80 70 60 50 40 0

5

10

15

20

Temperature at Gas Lift Location (psia)

Time After Shut-in (hours) 1400 50% Water Cut 1200

0% Water Cut

1000 800 600 400 200 0 0

5

10

15

20

Time After Shut-in (hours) OPRM20030302D_038.ai

Figure 1.44 – Pressure and Temperature Evolution During Cold Gas Lift-assisted Blowdown

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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90

Riser Gas Temperature (ºF)

85 80 75 70 65

Shut-in HDT

60 55 HDT after Blowdown to 250pisa

50 45 40 0

5

10

15

20

25

30

35

40

45

50

55

Time (hours) OPRM20030302D_040.ai

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

6.0

CONCLUDING REMARKS AND PRELIMINARY OPERATING LOGIC In summary, detailed thermal-hydraulic analysis validates the Bonga conceptual design with respect to hydrate management, for the most extreme anticipated operating conditions. The modifications to hardware design and operating procedures identified have been addressed and fully implemented within the appropriate Bonga teams. As the first step toward development of detailed subsea operating procedures, preliminary operating logic charts, consistent with the flow assurance analysis documented here, are shown in Figures 1.46 to 1.50 for the following: •

Cold start-up

•

Additional well start-up

•

Interrupted start-up

•

Planned or unplanned shutdown

•

Blowdown

As flow assurance efforts progress into detailed design and the development of subsea operating procedures, further dynamic thermal-hydraulic studies are recommended for the following areas: •

Gas buy back at OGGS-RPA and Bonga for initial start-up and shutdown

•

Minimum operating temperature analysis for the subsea system and topsides interfaces

•

Development and check-out of operating procedures via coupled well/flowline/ topsides dynamic modelling

•

Definition of subsea transient operability envelope for on-demand operational decisions

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Hot oil circulate 150ºF hot oil at 3 to 5mph

Cold Start-up Start-up of cold well into blown down flowine

System Conditions

Is arrival temperature at FPSO > 95ºF?

Wells bullheaded with MeOH Trees, jumpers and manifolds flushed w/MeOH

No

Yes

Flowlines stabilised (blown down or dry-oiled) Stop hot oil circulation. Close pigging iso valve at manifold

Sufficient MeOH available on FPSO

Start riser base gas lift as appropriate: 10MMSCFD – 10in flowlines 20MMSCFD – 20in flowlines

Start-up lowest wc well, as per Start-up Guidelines: Start MeOH injection upstream choke Open subsea choke and start specified ramp-up

Is the FWHT >95ºF?

No

Continue MeOH injection

Yes

Stop MeOH injection and continue well ramp-up

Full system cooldown not available. No Shutdown requires immediate action: Go to 'Interrupted Start-up'

FWHT >120ºF and Arrival Temperature > 85ºF?

5-hour wellbore cooldown available

Steady-state operation. Yes For additional wells: Go to 'Additional Well Start-up'

OPRM20030302D_041.ai

Figure 1.46 – Cold Start-up

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Additional Start-up

Unrestricted

Line up subsea equipment for new well start-up

Start-up of new (cold) well into producing flowline

System Conditions

Adjust riser base gas lift as appropriate for new well

Cold well bullheaded with MeOH Cold tree and jumper flushed w/MeOH Start-up new well, as per Start-up Guidelines:

Flowline producing at steady-state: Arrival T > 85ºF Producing wells FWHT > 120ºF

Start MeOH injection upstream of choke

Sufficient MeOH available on FPSO

Open subsea choke and start specified ramp-up

Is the FWHT > 95ºF?

No

Continue MeOH injection

Yes

Stop MeOH injection and continue well ramp-up

5-hour wellbore cooldown available

Full system cooldown not available.

Steady-state operation. No

Shutdown requires immediate action: Go to 'Interrupted Start-up'

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

Yes For additional wells: Go to Top

OPRM20030302D_042.ai

Figure 1.47 – Additional Well Start-up

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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System Conditions Flowlines hot-oiled prior to well start-up: Untreated water present: Wellbore, jumper, manifold and/or flowline Interrupted Start-up Full cooldown not available System shutdown prior to steady-state

Immediate action required

5-hour wellbore cooldown available Tree temperature > 95ºF?

No

Continuous MeOH injection at tree Flowline inhibited: treated water and dry oil

Yes

Optional: Blow down flowlines (contain dry oil and inhibited fluid only)

Tree temperature > 120ºF?

Displace tree and bullhead well with MeOH ASAP (refer to MeOH table)

No

Wellbore and flowline uninhibited Wellbore, tree, jumper, manifold, flowline cooldown not secured

Optional: Displace jumpers and manifold with MeOH (already treated)

Displace tree, jumpers and manifold with MeOH ASAP

Yes

Blow down Flowlines ASAP Go to 'Blowdown'

Bullhead well with MeOH Complete within 5 hours

MeOH Table Arrival temperature > 85ºF?

No

Blow down Flowlines ASAP Go to 'Blowdown'

Jumper, Tree and Manifold MeOH

GPM

9

18

Duration

hours

2

1

Vol jumper

bbls

2

2

Vol manifold

bbls

20

20

24

24

Yes

Steady-state condition: Go to 'Shutdown from steady-state'

Bullhead wells and displace tree, jumper, manifold with MeOH. Complete within 8 hours

Total bbls used Well Treatment MeOH

GPM

9

18

Duration/well

hours

3.88

1.94

bbls

50

50

Two Wells – Total bbls Used

100

100

Total System bbls Used

124

124

Vol/well

OPRM20030302D_043.ai

Figure 1.48 – Interrupted Start-up

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

Page 63 of 89

30-April-2006

Minimum available cooldown times: • Wellbore: 48 hours • Tree, jumper, manifold: 8 hours • Flowline: 16 hours • Riser: 12 hours

Planned Shutdown

Unplanned Shutdown

Close tree chokes and PSDVs

Auto-close boarding valves

Allow flowlines to evacuate to LP separator

Stop riser gas lift Close POVs and subsea chokes (each tree)

Stop riser gas lift MeOH Table Jumper, Tree and Manifold MeOH

GPM

9

18

Duration

hours

2

1

Vol jumper

bbls

2

2

Vol manifold

bbls

20

20

24

24

Total bbls used

Can production be resumed within 3 hours? (5 hours of treatment time alotted for wells, jumpers and manifold)

Yes

Shell Nigeria E & P Company Ltd.

Planned or Unplanned Shutdown for Steady-state

FWHT (all wells) > 120ºF Arrival T > 85ºF Topsides facilities and export available

Go to 'Restart' (start up without utilising methanol)

No Well Treatment MeOH

GPM

9

18

Duration/well

hours

3.88

1.94

bbls

50

50

Two Wells – Total bbls Used

100

100

Total System bbls Used

124

124

Vol/well

Displace tree, jumpers and manifold with MeOH. Complete within 8 hours of shutdown (refer to MeOH table)

Bullhead wells with MeOH (refer to MeOH table)

Can production be resumed within 8 hours?

Yes

Go to 'Warm Start' (start up utilising methanol as necessary)

No No

Go to 'Cold Start'

Yes

Can production be resumed within 48 hours?

Blow down all flowlines within 12 hours of shutdown Go to 'Blowdown' OPRM20030302D_044.ai

Unrestricted

30-April-2006

Figure 1.49 – Planned or Unplanned Shutdown from Steady-state

Page 64 of 89

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

System Conditions (Steady-state)

Shell Nigeria E & P Company Ltd.

Unrestricted

Blowdown

System Conditions

Secure flowlines for indefinite shut-in

Flowlines isolated at platform and tree Manifold pigging iso valve closed Untreated water present in flowline Flowline at/near 8-hour cooldown

Line up topsides for blowdown to flare system

Open appropriate blowdown valves Depressure until gas/ liquid rates diminish

Manifold pressure > 10bara? (or gas-assist known to be necessary?

No

Yes

Initiate gas lift at each riser base: 15MMSCFD for 1 hour

Initiate dry-oil circulation at 3 to 5mph Option: Launch pig

Yes

Manifold pressure > 10bara? (or gas-assist known to be insufficient? No

Close boarding valve Flowline secure for indefinite shut-in OPRM20030302D_045.ai

Figure 1.50 – Blowdown

Section 1 Dynamic Flow Assurance Analysis

OPRM-2003-0302D

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Appendix 1A Reservoir 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

FIGURES Figure 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

Section 1 Appendix 1A Reservoir Fluid Properties

OPRM-2003-0302D

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

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

Section 1 Appendix 1A Reservoir Fluid Properties

OPRM-2003-0302D

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Unrestricted

Wate r Fres h

8000

3 wt %S

10 w

9000

alt

t% S alt

10000

Pressure, psia

7000 6000

Hydrate Stability Region

5000 4000 3000 2000 Non-Hydrate Region

1000 0 40

45

50

55

60

65

70

75

80

85

Temperature, F

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

OPRM-2003-0302D

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Fresh Water P (p s 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

3 wt% Salt 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

10 wt% Salt 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

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

Section 1 Appendix 1A Reservoir Fluid Properties

OPRM-2003-0302D

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a lt

10000

ter h Wa

8000

Fres

10 w

3 wt %S

alt

t% S

9000

Pressure, psia

7000 6000 Hydrate Stability Region

5000 4000 3000 2000

Non-Hydrate Region

1000 0 40

45

50

55

60

65

70

75

80

85

90

Temperature, F

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

OPRM-2003-0302D

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Fresh Water 159.5

40.0

500

55.2

750

60.3

1000

63.7

2000

71.0

3000

75.0

4000

77.9

5000

80.5

6000

82.7

7000

84.5

8000

86.2

9000

87.8

10000

89.4

3 wt% Salt 184.1

40.0

500

53.3

750

58.4

1000

61.8

2000

69.0

3000

72.9

4000

75.8

5000

78.4

6000

80.6

7000

82.4

8000

84.1

9000

85.7

10000

87.3

10 wt% Salt 301.7

40.0

500

46.6

750

51.6

1000

54.9

2000

62.0

3000

65.8

4000

68.7

5000

71.2

6000

73.4

7000

75.2

8000

76.9

9000

78.6

10000

80.2

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

Section 1 Appendix 1A Reservoir Fluid Properties

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Appendix 1B Wellbore 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

4.0

DESIGN BASIS AND PRODUCTION FORECAST: 690 RESERVOIR ......................78

5.0

DESIGN BASIS AND PRODUCTION FORECAST: 710 RESERVOIR ......................78

6.0

DESIGN BASIS AND PRODUCTION FORECAST: 803 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

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TITLE: Bonga Well 1000 BOPD CSE Bare Tubing 6.625in VERSION 3.4 TUBING 1 2 5.9 6.625 2000 2000 5.9 6.625 7477 7477 CASING 4 1 8.670 9.625 7477 6477 1 12.330 13.375 3637 2637 1 18.710 20.000 2000 0 1 27.000 30.000 200 0 WELLBORE 3 6 0 0 2000 2000 2200 2212 2400 2438 2700 2828 5780 7477 INITIAL TEMP 2 40 0 162 5780 PVYP FLUIDS 3 1 1 10.0 1 2 2 10.4 10 3 1 9.63 14 ASOLID 3 7 488 0.113 8 180 0.5 0.5 9 0.001 0.25 0.005 NATURAL GAS 1 10 0.7885 0.0663 0.0671 PRINT OPTIONS 1 0 1 1 1000. PF 0 25 0 OPTIONS 3 3 0.0006 1 0 1 0 0 END CHANGE 0.5 'HR' SINGLE FLOW 2 2 10 162

0 BWPD

Unrestricted

15000 BOPD

0 BWPD

1 1 2 3 8 8

0 7 7

60 60 60

24.8

0.0391 0.0

0.0158

0

1

1

-8.83+08

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)

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Unrestricted

INPUT---------------------------------------------------------------------------------------------------------------------common filename

MBPD

2.5 5 7.5 10 15 25 40 2.5 5 7.5 10 15 25 40

-----> 702p4

WC (%)

0 0 0 0 0 0 0 70 70 70 70 70 70 70

P-res (PSI)

4800 4800 4800 4800 4800 4800 4800 3600 3600 3600 3600 3600 3600 3600

GOR PI (SCF/STB) (BLPD/PSI)

°API

29 29 29 29 29 29 29 29 29 29 29 29 29 29

600 600 600 600 600 600 600 600 600 600 600 600 600 600

80 80 80 80 80 80 80 80 80 80 80 80 80 80

BHT (°F)

162 162 162 162 162 162 162 162 162 162 162 162 162 162

bare tubing insulated file number file number

1 2 3 4 5 6 7 8 9 10 11 12 13 14

15 16 17 18 19 20 21 22 23 24 25 26 27 28

BOPD

2500 5000 7500 10000 15000 25000 40000 750 1500 2250 3000 4500 7500 12000

BWPD

0 0 0 0 0 0 0 1750 3500 5250 7000 10500 17500 28000

MMSCFD

1.500 3.000 4.500 6.000 9.000 15.000 24.000 0.450 0.900 1.350 1.800 2.700 4.500 7.200

FBHP (PSI)

4769 4738 4706 4675 4613 4488 4300 3569 3538 3506 3475 3413 3288 3100

Table 1B.2 – WELLTEMP Input Data for 702p4, Representing the Hottest 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) T(°F) (hr) 702p41 702p42 702p43 702p44 702p45 702p46 702p47 702p48 702p49 702p410 702p411 702p412 702p413 702p414 2.5 MBPD 5 MBPD 7.5 MBPD 10 MBPD 15 MBPD 25 MBPD 40 MBPD 2.5 MBPD 5 MBPD 7.5 MBPD 10 MBPD 15 MBPD 25 MBPD 40 MBPD 0.5 56.53 64.42 71.52 78.06 90.04 110.15 130.59 55.69 66.75 76.70 85.73 101.93 126.55 143.12 1 61.33 73.25 84.02 93.81 110.58 132.58 146.36 63.45 80.70 95.49 108.66 128.47 144.83 151.31 2 68.54 86.39 101.68 114.27 131.00 144.83 151.86 75.30 100.33 119.99 132.45 143.64 150.39 153.55 3 74.08 95.87 112.99 125.00 137.92 147.64 153.21 84.04 113.64 131.30 139.65 146.67 151.61 154.20 6 85.27 111.99 127.14 135.15 143.38 150.24 154.65 100.95 129.74 139.74 144.54 149.26 152.96 155.00 12 97.36 123.02 134.10 140.03 146.35 151.95 155.71 116.03 136.38 143.51 147.20 150.94 153.92 155.59 24 107.66 129.25 138.22 143.13 148.39 153.17 156.49 124.34 140.06 145.92 149.00 152.12 154.63 156.04 48 114.10 132.99 140.78 145.07 149.75 154.01 157.02 128.74 142.34 147.50 150.15 152.90 155.11 156.34 96 118.62 135.87 142.83 146.76 150.91 154.71 157.49 131.91 144.19 148.82 151.19 153.60 155.54 156.61 120 119.95 136.68 143.54 147.22 151.23 154.93 157.62 132.91 144.77 149.21 151.49 153.81 155.67 156.69 1440 129.83 142.97 148.07 150.78 153.69 156.44 158.59 139.98 148.82 152.01 153.63 155.28 156.56 157.25 1441 127.92 141.11 146.26 148.99 151.91 154.68 156.83 138.40 147.17 150.33 151.93 153.56 154.81 155.46 1443 122.90 135.67 140.66 143.31 146.14 148.82 150.88 133.32 141.67 144.68 146.19 147.72 148.88 149.43 1446 115.88 127.79 132.45 134.94 137.56 140.06 141.97 125.78 133.47 136.24 137.63 139.04 140.08 140.53 1448 112.07 123.47 127.93 130.31 132.82 135.23 137.04 121.59 128.94 131.58 132.91 134.26 135.25 135.68 1451 107.49 118.26 122.47 124.72 127.10 129.38 131.08 116.52 123.45 125.95 127.21 128.49 129.44 129.85 1452 106.20 116.78 120.92 123.14 125.48 127.72 129.40 115.09 121.90 124.36 125.60 126.85 127.79 128.20 1464 95.58 104.59 108.13 110.03 112.03 113.94 115.39 103.18 109.00 111.11 112.18 113.26 114.08 114.47 1488 84.49 91.58 94.45 95.99 97.63 99.17 100.35 90.46 95.18 96.89 97.77 98.65 99.33 99.67

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)

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Unrestricted

INPUT---------------------------------------------------------------------------------------------------------------------common filename

MBPD

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

-----> 702p7

WC (%)

0 0 0 0 0 50 50 50 50 50 80 80 80 80 80

P-res (PSI)

3200 3200 3200 3200 3200 3200 3200 3200 3200 3200 2200 2200 2200 2200 2200

GOR PI (SCF/STB) (BLPD/PSI)

°API

29 29 29 29 29 29 29 29 29 29 29 29 29 29 29

600 600 600 600 600 600 600 600 600 600 600 600 600 600 600

30 30 30 30 30 30 30 30 30 30 30 30 30 30 30

BHT (°F)

128 128 128 128 128 128 128 128 128 128 128 128 128 128 128

bare tubing insulated file number file number

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

BOPD

2500 5000 10000 15000 20000 1250 2500 5000 7500 10000 500 1000 2000 3000 4000

BWPD

0 0 0 0 0 1250 2500 5000 7500 10000 2000 4000 8000 12000 16000

MMSCFD

1.500 3.000 6.000 9.000 12.000 0.750 1.500 3.000 4.500 6.000 0.300 0.600 1.200 1.800 2.400

FBHP (PSI)

3117 3033 2867 2700 2533 3117 3033 2867 2700 2533 2117 2033 1867 1700 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 96.90 107.74 113.83 115.45 115.74 105.99 114.40 119.00 120.40 120.93 108.33 115.69 119.57 96 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)

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1.0

Unrestricted

RESERVOIR PRESSURE AND TEMPERATURE SUMMARY S Van Gisbergen, A Hartwijk and S Lindsey (1999). Medium Skin P50 702 T@midperfs Initial Pavg 702p2 142 3421 702p3 132 2518 702p4 162 4503 702p5 153 3366 702p6 136 2830 702p7 128 2648 702p9 148 4317 702p10 148 4312 702p15 139 4183

690 T@midperfs Initial Pavg b690p1 164 4586 b690p2 147 3826 b690p3 156 3722 b690p4 138 4201 b690p5 139 3138

803 T@midperfs Initial Pavg 803p1 179 5211 803p2 186 5299

710 T@midperfs Initial Pavg 710p1 146 4455 710p2 134 4238 710p3 144 4464 710p4 158 4649

High Skin P50 702 T@midperfs Initial Pavg 702p2 142 3679 702p3 132 2690 702p4 162 4503 702p5 153 3252 702p6 136 2987 702p7 128 2862 702p9 148 4317 702p10 148 4312 702p15 139 4183

690 T@midperfs Initial Pavg 690p1 164 4586 690p2 147 4042 690p3 156 3739 690p4 138 4201 690p5 139 3118

803 T@midperfs Initial Pavg 803p1 179 5211 803p2 186 5315

710 T@midperfs Initial Pavg 710p1 146 4455 710p2 134 3964 710p3 144 4197 710p4 158 4468

Low Skin P50 702 T@midperfs Initial Pavg 702p2 142 702p3 132 702p4 162 4503 702p5 153 702p6 136 702p7 128 702p9 148 4317 702p10 148 4312 702p15 139 4183

690 T@midperfs Initial Pavg 690p1 164 4586 690p2 147 690p3 156 690p4 138 690p5 139

803 T@midperfs Initial Pavg 803p1 179 5211 803p2 186

710 T@midperfs Initial Pavg 710p1 146 710p2 134 710p3 144 710p4 158

Section 1 Appendix 1B Wellbore Modelling Summary and Production Forecast

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2.0

Unrestricted

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

Phase 1 Wells well 702p4 702p9 702p10 702p15 690p1 803p1

year Q1 2003 Q1 2003 Q1 2003 Q1 2003 Q1 2003 Q1 2003

flowline PF1 PF3 PF6 PF11 PF2 PF12

months 0 0 0 0 0 0

Phase 2 Wells well 710p1 702p2 690p2 803p2 710p4 710p3 702p5 710p2 690p3 702p6 702p7 690p4 702p3 690p5

year Q1 2004 Q1 2004 Q2 2004 Q2 2005 Q4 2005 Q1 2006 Q4 2006 Q1 2007 Q2 2007 Q1 2008 Q1 2008 Q1 2008 Q3 2008 Q1 2009

flowline PF8 PF12 PF4/PF3 PF6/PF5 PF12 PF8/PF9 PF3 PF9 PF2 PF11 PF11 PF11 PF8 PF5

months 8 11 14 26 29 32 44 47 48 59 60 62 65 71

Well 702p2 702p3 702p4 702p5 702p6 702p7 702p9 702p10 702p15

Year Q1 2004 Q3 2008 Q1 2003 Q4 2006 Q1 2008 Q1 2008 Q1 2003 Q1 2003 Q1 2003

Max. rate 22000 20000 54000 24000 20000 20000 50000 50000 50000

b690p1 b690p2 b690p3 b690p4 b690p5

Q1 2003 Q2 2004 Q2 2007 Q1 2008 Q1 2009

20000 20000 17000 16000 18000

803p1 803p2

Q1 2003 Q2 2005

24000 27000

710p1 710p2 710p3 710p4

Q1 2004 Q1 2007 Q1 2006 Q4 2005

30000 30000 28000 30000

Section 1 Appendix 1B Wellbore Modelling Summary and Production Forecast

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3.0

Unrestricted

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

5.0

DESIGN BASIS AND PRODUCTION FORECAST: 710 RESERVOIR Refer to the Field Development Plan Rev 5 for production profiles.

6.0

DESIGN BASIS AND PRODUCTION FORECAST: 803 RESERVOIR Refer to the Field Development Plan Rev 5 for production profiles.

Section 1 Appendix 1B Wellbore Modelling Summary and Production Forecast

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Appendix 1C Production Flowlines: Topography and Ambient Temperature Data Table of Contents 1.0

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

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

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Unrestricted

Flowline Topography PFL - 11/12 (West South)-10" - 960 - 980

Water Depth, m

-1 000 -1 020 -1 040

Rev. D

-1 060 -1 080 -1 100 -1 120 0

500

1 000

Riser Base

1 500

2 000

2 500

Distance, m

Flowline Topography PFL - 08/09 (West North)-10" - 960 - 980

Water Depth, m

-1 000 -1 020 -1 040

Rev. D

-1 060 -1 080 -1 100 -1 120 0 Riser Base

500

1 000

1 500

2 000

2 500

3 000

Distance, m

Figure 1C.1 – Flowline Topography for West-side Flowlines (Rev D Layout) Section 1 Appendix 1C Production Flowlines: Topography and Ambient Temperature Data

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Flowline Topography PFL - 01/02 (East West)-10" - 960 - 980

Water Depth, m

-1 000 -1 020 Rev. D

-1 040 -1 060 -1 080 -1 100 -1 120 0

1 000

2 000

3 000

Riser Base

4 000

5 000

6 000

7 000

8 000

9 000

10 000

Distance, m

Flowline Topography PFL - 03/04/05/06 (East East)-12" - 960 - 980

Water Depth, m

-1 000 -1 020 Rev. D

-1 040 -1 060 -1 080 -1 100 -1 120 0

1 000

Riser Base

2 000

3 000

4 000

5 000

6 000

7 000

Distance, m

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

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

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0 105.2632 184.2105 263.1579 315.7895 394.7368 447.3684 500 578.9474 631.5789 657.8947 710.5263 736.8421 763.1579 789.4737 815.7895 868.4211 1105.263 1263.158 1421.053 1447.368 1473.684 1500 1552.632 1578.947 1894.737 2000

West South, PFL - 11/12 Rev. D -1028 manifold -1026 -1024 -1022 -1020 -1018 -1016 -1014 -1012 -1011 -1012 -1012 -1010 -1008 -1006 -1004 -1002 -1000 -998 -998 -1000 -1002 -1000 -998 -996 -994 -994 riser base

Unrestricted

0 131.5789 473.6842 1052.632 1184.211 1236.842 1315.789 1342.105 1368.421 1421.053 1447.368 1500 1526.316 1578.947 1657.895 1710.526 1763.158 1789.474 1815.789 1842.105 1868.421 1921.053 1947.368 1973.684 1973.684 2000 2026.316 2078.947 2263.158 2289.474 2342.105 2368.421 2394.737

West North, PFL - 08/09 Rev. D -1000 manifold -998 -996 -998 -997 -998 -1000 -1002 -1004 -1004 -1002 -1002 -1000 -998 -996 -996 -998 -1000 -1002 -1004 -1006 -1006 -1004 -1002 -1000 -998 -996 -994 -995 -994 -992 -990 -988 riser base

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

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

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X, m 0 131.5789 263.1579 368.4211 447.3684 578.9474 657.8947 815.7895 894.7368 1000 1052.632 1131.579 1236.842 1342.105 1447.368 1526.316 1605.263 1684.211 1763.158 1868.421 1921.053 2000 2105.263 2210.526 2342.105 2447.368 2473.684 2500 2526.316 2578.947 2631.579 2684.211 2710.526 2736.842 2815.789 2894.737 2921.053 2947.368 2973.684 3000 3052.632 3105.263 3157.895 3210.526 3315.789 3394.737 3473.684 3552.632 3684.211 3789.474 3973.684 4052.632 4131.579 4210.526 4289.474 4368.421 4447.368 4552.632 4684.211 4815.789 4868.421 4947.368 5131.579 5184.211 5289.474 5394.737 5526.316 5710.526 5815.789 5973.684 6052.632 6157.895 6236.842

East West, PFL - 01/02 Rev. D -1106 manifold -1104 -1102 -1100 -1098 -1096 -1094 -1092 -1090 -1088 -1086 -1084 -1082 -1080 -1078 -1076 -1074 -1072 -1070 -1068 -1066 -1064 -1062 -1060 -1058 -1060 -1062 -1062 -1060 -1058 -1056 -1054 -1052 -1050 -1052 -1048 -1046 -1044 -1042 -1040 -1038 -1036 -1034 -1032 -1030 -1028 -1026 -1024 -1022 -1020 -1018 -1016 -1014 -1012 -1010 -1008 -1006 -1004 -1002 -1000 -998 -996 -994 -992 -990 -988 -986 -985 -986 -984 -982 -981 -982

Unrestricted

0 78.94737 236.8421 342.1053 447.3684 552.6316 631.5789 684.2105 710.5263 763.1579 789.4737 842.1053 947.3684 1078.947 1184.211 1289.474 1421.053 1526.316 1657.895 1789.474 1842.105 1868.421 1921.053 2000 2026.316 2052.632 2131.579 2184.211 2210.526 2236.842 2263.158 2289.474 2315.789 2342.105 2368.421 2421.053 2552.632 2605.263 2657.895 2684.211 2710.526 2736.842 2789.474 2868.421 3000 3289.474 3578.947 3684.211 3736.842 3789.474 3815.789 3842.105 3868.421 3894.737 3921.053 3973.684 4026.316 4131.579 4236.842 4315.789 4342.105 4394.737 4447.368 4631.579 4763.158 4868.421 4947.368 5000 5026.316 5078.947 5131.579 5210.526 5368.421

East East, PFL - 05/06 Rev. D -1038 manifold -1036 -1034 -1032 -1030 -1028 -1027 -1028 -1029 -1028 -1026 -1024 -1022 -1020 -1018 -1016 -1014 -1012 -1010 -1012 -1010 -1008 -1006 -1004 -1006 -1008 -1009 -1008 -1006 -1004 -1002 -1000 -998 -996 -994 -992 -990 -992 -990 -988 -986 -984 -982 -980 -978 -976 -978 -980 -982 -984 -986 -988 -990 -992 -994 -996 -998 -996 -994 -996 -998 -999 -998 -1000 -1002 -1004 -1006 -1008 -1010 -1008 -1009 -1008 -1010

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

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

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6289.474 6342.105 6421.053 6473.684 6526.316 6578.947 6631.579 6684.211 6763.158 6947.368 7078.947 7131.579 7210.526 7342.105 7578.947 7736.842 7815.789 7868.421 7947.368 8131.579 8394.737 8657.895 8842.105 8921.053 9052.632 9105.263 9131.579 9157.895 9184.211 9210.526 9236.842 9263.158 9289.474

Unrestricted

-984 -986 -988 -990 -992 -994 -996 -998 -1000 -1002 -1002 -1003 -1002 -1001 -1002 -1004 -1006 -1008 -1009 -1010 -1012 -1010 -1008 -1006 -1004 -1002 -1000 -998 -996 -994 -992 -990 -988 riser base

5421.053 5447.368 5473.684 5552.632 5578.947 5605.263 5631.579 5657.895 5684.211 5736.842 5789.474 5894.737 5947.368 6105.263 6157.895 6184.211 6210.526 6236.842 6263.158 6289.474 6315.789 6342.105

-1012 -1014 -1014 -1016 -1018 -1016 -1014 -1012 -1010 -1008 -1006 -1004 -1002 -1000 -998 -996 -994 -992 -990 -988 -986 -984 riser base 0

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

3,500.00

3,000.00

2,500.00

Elevation, Feet

2,000.00

1,500.00

1,000.00

500.00

0.00 0

1000

2000

3000

4000

-500.00 Horizontal Distance, Feet

Figure 1C.2 – Steel Catenary Riser Profile (Phifer 1998) Section 1 Appendix 1C Production Flowlines: Topography and Ambient Temperature Data

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Unrestricted

Riser top angle = 9.5 degrees from vertical Riser top elevation = 3230 feet

X (ft) 0 3.16 6.32 9.5 12.69 15.9 19.13 22.37 25.62 28.9 32.19 38.82 45.52 52.29 59.13 66.04 73.03 80.1 87.25 94.47 101.78 109.17 116.64 128.02 139.6 151.4 163.41 175.65 188.12 200.84 213.81 227.04 240.55 254.34 268.43 282.83 297.56 312.62 328.03 343.82 359.99 370.99 382.18 393.57 405.15 416.93 428.93 441.15 453.59 466.27 479.19 492.36 505.8 519.51 533.5 547.78 562.36 577.27 592.5 608.07 624

Y (ft) 3,230.00 3,211.14 3,192.28 3,173.43 3,154.58 3,135.73 3,116.89 3,098.05 3,079.21 3,060.37 3,041.54 3,003.88 2,966.23 2,928.60 2,890.98 2,853.37 2,815.77 2,778.19 2,740.63 2,703.08 2,665.55 2,628.03 2,590.53 2,534.31 2,478.14 2,422.01 2,365.92 2,309.88 2,253.90 2,197.97 2,142.10 2,086.29 2,030.55 1,974.87 1,919.27 1,863.75 1,808.32 1,752.97 1,697.73 1,642.58 1,587.55 1,550.93 1,514.37 1,477.87 1,441.42 1,405.05 1,368.74 1,332.51 1,296.35 1,260.27 1,224.28 1,188.39 1,152.59 1,116.89 1,081.30 1,045.83 1,010.49 975.27 940.2 905.28 870.52

X (ft) 640.3 656.99 674.08 691.6 709.55 727.96 746.85 766.24 786.15 806.61 827.64 849.26 871.51 894.4 917.97 942.24 967.24 993.01 1,019.56 1,046.92 1,075.12 1,104.17 1,134.10 1,164.91 1,196.60 1,229.16 1,262.58 1,296.82 1,331.79 1,367.40 1,385.39 1,403.46 1,421.57 1,439.67 1,457.68 1,475.50 1,492.99 1,509.98 1,526.20 1,541.31 1,544.16 1,546.94 1,549.65 1,552.28 1,554.82 1,557.28 1,559.64 1,561.89 1,564.04 1,566.06 1566.06 1569.94 1573.81 1577.68 1581.56 1585.43 1589.3 1593.18 1597.05 1600.93 1604.8 1953

Y (ft) 835.93 801.52 767.32 733.33 699.56 666.05 632.81 599.85 567.21 534.9 502.96 471.43 440.33 409.7 379.59 350.04 321.11 292.86 265.34 238.64 212.81 187.96 164.16 141.52 120.14 100.14 81.62 64.72 49.55 36.24 30.33 24.92 20.04 15.7 11.91 8.67 5.98 3.83 2.21 1.08 0.91 0.75 0.61 0.48 0.37 0.27 0.19 0.11 0.05 0 0 -0.09 -0.16 -0.23 -0.28 -0.33 -0.37 -0.4 -0.43 -0.45 -0.46 -0.46

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

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

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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°N and 4° to 6°E. Our experience is that deepwater temperatures do not vary much over such an area. All of the profiles were averaged over depth bins, and the standard deviation of the temperature in each bin was also found. The columns in Table 1C.3 give the mean depth in the bin, the mean temperature, the standard deviation of the temperature, the mean +/- the standard deviation and n, the number of observations in the depth bin. There are many more observations at shallow depths than deep in the water, but the standard deviations of the observations are also much higher at shallow depths. This variability is natural, largely due to seasonal effects in the temperature and river runoff in the salinity. The average temperatures and salinities are, for engineering purposes, nearly constant at great depth, and the average values in the tables can be 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 is given in units of kg/m3. Temperatures, salinities and densities at other depths can be found by interpolation in the table.

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

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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

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

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Depth

Avg

Avg +std

Avg -std

Std

n

Avg 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

1026.4

80.00

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

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

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Section 2 Flow 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

Section 2 Flow Assurance Production Constraints

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Table of Contents (cont’d) FIGURES Figure 2.6 – Arrival Temperature as a Function of Rate, for 1 Well/1 Flowline Production 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

Section 2 Flow Assurance Production Constraints

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OBJECTIVES The principal objective’ of this study is to quantify flow assurance constraints for production forecasting, particularly minimum acceptable flowrates per well and flowline. It is important to note that results herein represent the absolute edge of the flow assurance envelope, with essentially all conservatism in analysis removed. As such, this analysis is intended for Shell Bonga project staff only and should not be shared with Engineer, Procure, Install and Construct (EPIC) contractors, who could misinterpret/misuse these results as a basis for systems design. The key end-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 flow assurance

•

Bonga operations staff, to outline the operating envelope for relevant flow assurance risks

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

2.0

(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 at the minimum stable rates.

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 lower production rates (ie two possible flowrates at the same applied pressure drop). The low flowrate solution represents a liquid loaded well (usually with slugging at the wellhead), while the high flowrate solution has less liquid hold-up and a larger frictional pressure drop. Hence, rates below the instability threshold (the minimum in Figure 2.1) are generally not controllable, as the past history of the well’s liquid loading 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 instability threshold (by choking), the well will load-up with liquid and shut-in if the wellhead pressure is not reduced.

Well ∆p

Instability Production rate

Figure 2.1 – Illustration of Multiple Solution Behaviour Associated with Well Instability Section 2 Flow Assurance Production Constraints

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Well

Tubing Size

Minimum Rate for Stability

690p1 (horizontal)

5 1/2in

2.5MBLPD

690p2

5 1/2in

3.0

690p3

5 1/2in

2.0

690p4

5 1/2in

2.0

702p2

5 1/2in

5.0

702p4 (horizontal)

6 5/8in

7.0

702p3

5 1/2in

4.5

702p5

5 1/2in

4.5

702p6

5 1/2in

4.5

702p7

5 1/2in

5.0

702p9 (horizontal)

6 5/8in

6.5

702p10 (horizontal)

6 5/8in

7.0

702p14

5 1/2in

2.0

702p15 (horizontal)

6 5/8in

7.0

710p1

5 1/2in

5.0

710p2

5 1/2in

2.0

710p3

5 1/2in

3.5

710p4

5 1/2in

4.5

803p1

5 1/2in

4.5

803p2

5 1/2in

3.0

803p3

5 1/2in

5.0

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

Section 2 Flow Assurance Production Constraints

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In this report, well stability for Bonga was assessed on a well-by-well basis using Olga2000, 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 sustained production occurs. If the Flowing Wellhead Pressure (FWHP) is too high, the well will shut-in after liquid travels up the wellbore.

(3)

The minimum acceptable flowrate for a well is the smallest sustained production that can occur as calculated in Step (2). Note:

Production rates below the minimum rate for stability may simply be unattainable (even if sufficient reservoir pressure exists), as additional choking can cause the well to load-up and abruptly shut-in. That is, intermediate rates below the threshold are unstable and may not be observable in practice (much like the inherent instability of a pin balanced on its tip).

As shown in Table 2.1, the minimum well rates for stability vary between 2 to 7MBLPD. Notes: (1)

The key discriminator between the lower and higher thresholds is the well tubing, since lower gas velocities obtained for the larger 6 5/8in tubing are more 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 other horizontal well, but with 5 1/2in tubing).

Noting the complexities in modelling multiphase flow and the discrete 25psi WWellhead Pressure (WHP) steps used in analysis, the limiting rate for both tubing sizes 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 to Figure 2.1), summarised in van Gisbergen, 1999.

Section 2 Flow Assurance Production Constraints

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WELL KICK-OFF Noting the relatively low Bonga reservoir pressures and the importance of waterflood for pressure maintenance, well kick-off requirements are evaluated with respect to depletion predictions for each well. Figures 2.2 to 2.5 show the reservoir pressure required to start each well against a minimum attainable wellhead pressure of 600psi, relative to the minimum reservoir pressure (over the field life) predicted by GAP (GAP is a subsurface software used to model wells and flowline networks). The minimum reservoir pressures tend to occur in mid-life; assuming effective waterflood, the reservoir pressure rises later in field life. Note that a wellhead backpressure 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 manifold pressures 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 the return 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

Section 2 Flow Assurance Production Constraints

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5000 4500

Required reservoir P for stable flow [psia]

4000 3500 3000

0% wc 50% wc 80% wc Min Reservoir P

2500 2000 1500 1000 500 0 702p14

702p5

702p9

702p10

803p2

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)

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

Section 2 Flow Assurance Production Constraints

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Figure 2.4 – Reservoir Pressure Required for Well Start-up to Stable Flowrates: Wells in Manifold PM 1 (West-North Flowlines 8 and 9) 4000 3500

Required reservoir P for stable flow [psia]

3000 2500

0% wc 50% wc 80% wc Min Reservoir P

2000 1500 1000 500 0 690p4

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

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

Section 2 Flow Assurance Production Constraints

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As shown in Figures 2.2 to 2.5, all wells except for 803p2 are able to start up against a 600psi wellhead backpressure, for the worst-case scenario of an initially liquid-loaded well and the minimum reservoir pressures of each body over the field 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 margin for 702p2, 702p5, and the 803 wells. For 803p2, extra surveillance attention will be needed to avoid loading it with liquid, as it may not be restarted at the minimum 803 reservoir pressure. Also, the phasing of 803p2 with respect to stronger wells should be assessed to assure that its production will not be backed out. These results underscore the importance of effective waterflood for reservoir pressure maintenance, 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 backpressure requirements of individual wells, which will be necessary whenever wells in different phases 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 Wax Deposition Temperature (CWDT) in the wellbore and to pig flowlines during planned shutdown operations. Recent wax analysis (Tsai et al 2002) indicates a maximum CWDT 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 1/2in tubing; 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-term turndown production (ie below 10MBLPD) should be avoided for these wells. Noting the relatively low deposition rate characteristic of the Bonga fluids, production of these lower-T wells may be tolerable for shorter-term durations to accommodate transient operations such as well testing or well flowline switching. Note: In Table 2.3, all other wells are outside the wax deposition envelope at the minimum rates for stable flow.

Section 2 Flow Assurance Production Constraints

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Well

Minimum 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

112

710p4

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) at minimum stable production rates of 5MBLPD (5 1/2in tubing wells), and 7MBLPD (6 5/8in tubing wells). Temperatures below CWDT = 109°F are highlighted.

Section 2 Flow Assurance Production Constraints

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Flowline Wax Management Regarding flowline/riser wax management, the basic operating strategy is to pig flowlines for wax during scheduled or planned shut-ins, during hot or dry-oiling operations. Based on the updated wax analysis in Tsai et al, 2002, pigging frequency requirements at turndown conditions are shown in Table 2.4. The Flowing Wellhead Temperature (FWHT) values of 100°F and 120°F are based on the minimum FWHT observed at rates of 5MBLPD and 7MBLPD, respectively (refer to Table 2.3, with slight exception of 116°F for 702p15 at 7MBLPD). Recall that the Bonga Basis of Design (BoD) specifies a minimum turndown rate of 10MBLPD per flowline, 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 at 5MBLPD (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 planned shutdowns are less frequent than once per month (as is expected in availability analysis). 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 and the higher wellhead temperature (120°F, refer to Table 2.4). The feasibility of such pigging frequencies will have to be determined based on operating experience and shutdown statistics (ie number of pigging opportunities). During surveillance, wax analysis 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 model benchmarking) to further refine the 690 specific pigging requirements.

4.3

West Flowlines Due to their much shorter offset, the West flowlines’ wax requirements are less severe, with four piggings per year required for 5MBLPD production (one well into 1 flowline). Note: In Table 2.3, the wellhead temperature for most wells exceeds 100°F at 5MBLPD, so that this pigging frequency represents the upper limit. As discussed above, post-start-up wax analysis should be included in the surveillance programme, especially if such turndown production is anticipated for some wells. Rate (MBLPD)

FWHT (°F)

Pigging Frequency (No per Year)

East 10in (PFL 1, 2)

5

100

10

7

120

6

East 12in (PFL 3, 4, 5, 6)

5

100

8

7

120

4

West 10in (PFL 8, 9, 11, 12)

5

100

4

7

120

1

Flowline

Table 2.4 – Wax Pigging Frequencies for Turndown 1 Well/1 Flowline Production (Tsai et al, 2002) Section 2 Flow Assurance Production Constraints

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WELLHEAD COOLDOWN Wellhead area equipment (tree, jumper, manifold) is to be insulated to meet a cooldown specification: 120°F to 73°F in 12 hours (upstream of choke) and 120°F to 63°F in 12 hours (downstream of choke). As shown in Table 2.3, roughly half of the wells will meet the 120°F start temperature, even at turndown conditions (5 to 7MBLPD), and hence provide 12+ hours of wellhead area cooldown. Based on analogy with cooldown performance of cylindrical components (eg well jumpers), a start temperature of 100°F will provide roughly 8 hours of cooldown. Since the colder wells produce at 100°F or higher at turndown, these wells will provide at least 8 hours of cooldown. Noting that the cooldown criteria is designed to provide time for wellhead Methanol (MeOH) flushing of up to 16 wells, it is expected that 8 hours of cooldown is sufficient for a limited number of producing wells, with the exact number based on actual MeOH treatment times determined via surveillance.

6.0

FLOWLINE/RISER COOLDOWN The production flowlines and riser are governed by the following cooldown specifications: •

West-side 10in flowlines: –

•

97°F (36°C) to 66°F (19°C) in no less than 12 hours

East-side 10in and 12in flowlines: –

86°F (30°C) to 61°F (16°C) in no less than 12 hours

Arrival Temperature per Flowline (ºF)

160 702p15/PF11 803p1/PF12

140

702p4/PF1 690p1/PF2 120

702p9/PF3 702p10/PF6

100

80

60 0

10

20

30

40

50

60

Rate (MBOPD) OPRM20030302D_046.ai

Figure 2.6 – Arrival Temperature as a Function of Rate for 1 Well/1 Flowline Production Scenarios

Section 2 Flow Assurance Production Constraints

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Note: The West and East start temperatures differ due to offset differences, while the end temperatures differ due to the effects of line-packing (with an assumed 10 minimum choke closing time). Arrival temperatures as a function of production rate for representative early-life one well/one flowline combinations are shown in Figure 2.6. Note: The required riser base start temperatures translate to arrival temperatures of approximately 80°F (East) and 90°F (West). In Figure 2.6, the 12-hour cooldown requirement corresponds to minimum rates of approximately 5MBLPD (West) and 7MBLPD (East). These results are also consistent with the generalised thermal modelling in Tsai et al, 2002, for a wellhead temperature 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 slug control at turndown, but it is important to note that the total gas lift compression capacity is 65MMscfd (Bonga BoD). Hence, only a limited number of flowlines may be operated simultaneously in an extended turndown condition. As illustrated in Figures 2.7 and 2.8, terrain slug control requires the 25MMscfd gas lift capacity at production rates of 5MBLPD (West) and 7MBLPD (East). Note: The minimum flowrate for the East 12in flowlines is also approximately 7MBLPD, with residual 50bbl slugs observed even at high gas lift rates (compared to complete slug suppression for the other flowlines).

20

Required Gas Lift (MMSCFD)

0% wc 50% wc 15

80% wc

10

5

0 0

10

20

30

40

Liquid Production Rate (MBLPD) OPRM20030302D_047.ai

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

Section 2 Flow Assurance Production Constraints

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40

Required Gas Lift (MMSCFD)

0% wc 50% wc 30

80% wc

20

10

0 0

10

20

30

40

Liquid Production Rate (MBLPD) OPRM20030302D_048.ai

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

8.0

CONCLUDING REMARKS To better quantify the Bonga operating envelope, key flow assurance issues have been analysed at turndown production conditions, including: well stability, well and flowline wax deposition, wellhead and flowline cooldown, and flowline slugging. Collectively, the edge of the operating envelope is defined by the following production constraints, which must be satisfied simultaneously: •

5 1/2in wells: Rates per well ≥ 5MBLPD

•

6 5/8in wells: Rates per well ≥ 7MBLPD

•

West flowlines (PFL 8, 9, 11, 12): Rates per flowline ≥ 5MBLPD

•

East flowlines (PFL 1, 2, 3, 4, 5, 6): Rates per flowline ≥ 7MBLPD

Interestingly, each of these flow assurance requirements tends to involve a similar minimum rate constraint, indicating that a variety of operational difficulties may occur if these constraints are violated. In production forecasting, lower rates may be feasible but should be risked for flow assurance. Noting the high cost of deferment/intervention, it is recommended to maintain (through operational solutions and careful well sequencing) the original minimum design rates of 10MBLPD per well and 10MBLPD per flowline. Finally, it is important to note that these results are based on complex predictive modelling – surveillance, sampling and model benchmarking will be required to precisely define the actual operating envelope.

Section 2 Flow Assurance Production Constraints

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Appendix 2A Well Design Basis – FDP Rev 5 Compiled by Kelda McFee. 690 Wells 690p1 Well Trajectory MD(ft) SS WD 3581 2 3600

TVD (ft) SS 3581 3600

Inc (deg) 0 0

3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61

3700 3800 3900 4000 4100 4200 4300 4400 4500 4600 4700 4800 4900 5000 5100 5200 5300 5400 5500 5600 5700 5800 5900 6000 6100 6200 6299.7 6399.1 6497.6 6594.2 6688.4 6780.5 6872.9 6965.2 7057.6 7150 7242.4 7334.8 7427.1 7519.5 7611.9 7704.3 7796.7 7889.1 7981.4 8073.8 8166.2 8258.6 8351 8435.6 8443.3 8533.6 8619.8 8701.3 8777.4 8847.5 8911.2 8967.9 9017.3

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2.5 5 7.5 12.5 17.5 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.51 22.93 27.93 32.93 37.93 42.93 47.93 52.93 57.93 62.93

3700 3800 3900 4000 4100 4200 4300 4400 4500 4600 4700 4800 4900 5000 5100 5200 5300 5400 5500 5600 5700 5800 5900 6000 6100 6200 6300 6400 6500 6600 6700.3 6800 6900 7000 7100 7200 7300 7400 7500 7600 7700 7800 7900 8000 8100 8200 8300 8400 8500 8591.6 8600 8700 8800 8900 9000 9100 9200 9300 9400

hz Summary Profile PI@PSSS Initial Pavg

20 4511

bbl/day psia psia

Initial GOR T@midperfs

605 160

scf/bbl °F

SSSV Depth ML (ft) ID (in) Length (ft) TVD (ft) SS

2300 4.56 9.72 9447.2

Tubing size (I) AHD ft (SS) 12931

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 Linear between reservoir and seabed 2

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

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690 Wells (cont’d) 690p1 Well Trajectory MD(ft) SS

TVD (ft) SS

Inc (deg)

62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103

9058.8 9092.3 9117.7 9138.2 9159 9180.1 9200.6 9221.4 9240.1 9242.2 9258.8 9268.3 9278.8 9289.4 9299.9 9310.4 9320.9 9323.7 9325.1 9325.4 9330.9 9340.6 9350.4 9360.1 9369.9 9379.7 9389.4 9399.2 9406.5 9408.7 9411.2 9413.2 9416.8 9420.5 9424.1 9427.8 9431.4 9435.1 9438.7 9442.4 9446 9447.2

67.93 72.93 78 78 78 78 78 78 78 78.5 83.97 83.97 83.97 83.97 83.97 83.97 83.97 83.97 84.54 84.4 84.4 84.4 84.4 84.4 84.4 84.4 84.4 84.4 84.4 85.65 87.91 87.91 87.91 87.91 87.91 87.91 87.91 87.91 87.91 87.91 87.91 87.91

Well Trajectory MD(ft) SS WD 3581.0 2 5500.0 3 6400.0 4 7789.4

TVD (ft) SS 3581.0 5500.0 6310.3 7292.7

Inc (deg) 0.00 0.00 45.00 45.00

5 1 2 3 4

7521.0 8286.2 8404.3 8678.0 8775.0

65.00 65.00 83.46 83.46 83.46

9500 9600 9701.3 9800 9900 10001.3 10100 10200 10289.9 10300 10409.6 10500 10600 10700 10800 10900 11000 11026.7 11041.4 11044.1 11100 11200 11300 11400 11500 11600 11700 11800 11874.8 11900 11945.5 12000 12100 12200 12300 12400 12500 12600 12700 12800 12900 12931.2

hz

690p2

8189.4 10000.0 10435.0 12837.6 13689.2

Summary Profile Tubing size (I) PI@PSSS Initial Pavg Initial GOR T@midperfs

25 4279 605 146

SSSV Depth ML (ft) ID (in) Length (ft) TVD (ft) SS

2300 4.56 9.72 5881.0

bbl/day psia psia scf/bbl °F

AHD ft (SS) 13689

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 linear 2

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

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690 Wells (cont’d) S690p3 Well Trajectory MD(ft) SS

TVD (ft) SS

Inc (deg)

Sidetrack of 702p4 WD 3568.0 1 7300.0 2 7686.6 3 10589.6

3568.0 7236.6 7489.2 9023.0

0.00 40.00 58.11 58.11

Summary Profile

S690p4 Well Trajectory MD(ft) SS

TVD (ft) SS

Inc (deg)

Sidetrack of 702p2 WD 3369.0 1 6150.0 2 7415.4 3 10841.9

3369.0 6147.6 7090.1 8268.0

0.00 7.50 69.89 69.89

Tubing size (I) PI@PSSS Initial Pavg Initial GOR T@midperfs

18 4365 605 155

SSSV Depth ML (ft) ID (in) Length (ft) TVD (ft) SS

2300 4.56 9.72 5868.0

bbl/day psia psia scf/bbl °F

AHD ft (SS) 10590

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 linear 2

Summary Profile Tubing size (I) PI@PSSS Initial Pavg Initial GOR T@midperfs

19 4415 605 137

SSSV Depth ML (ft) ID (in) Length (ft) Depth (ft) SS

2300 4.56 9.72 5669.0

bbl/day psia psia scf/bbl °F

AHD ft (SS) 10842

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 linear 2

702 Wells 702p2 Well Trajectory MD(ft) SS WD 3369.0 2 5850.0

TVD (ft) SS 3369.0 5850.0

Inc (deg) 0.00 0.00

3 4 5 6 7 8 9

6149.1 6838.1 8121.9 8387.4 8467.0 8544.0 8838.0

7.50 47.03 47.03 30.00 30.00 30.00 30.00

TVD (ft) SS

Inc (deg)

6150.0 6940.6 8824.1 9164.7 9256.6 9345.5 9685.0

S702p3 Well Trajectory MD(ft) SS Sidetrack of 710p1 WD 3276.0 1 5950.0 2 7095.7 3 9150.2

Summary Profile PI@PSSS Initial Pavg

100 4201

Initial GOR T@midperfs

589.57 scf/bbl 143 °F

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

2300 4.56 9.72 5669.0

bbl/day psia psia

Tubing size (I) AHD ft (SS) 9685

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 Linear between reservoir and seabed 2

Summary Profile

3276.0 5948.7 6915.0 8050.0

0.00 7.50 56.46 56.46

PI@PSSS Initial Pavg Initial GOR T@midperfs

20 4052 589.57 130

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

2300 4.56 9.72 5576.0

bbl/day psia psia scf/bbl °F

Tubing size (I) AHD ft (SS) 9150

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 Linear between reservoir and seabed 2

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

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702 Wells (cont’d) 702p5 Well Trajectory MD(ft) SS 1 3343.0 2 5500.0 3 6333.2 4 9831.1

Summary Profile TVD (ft) SS 3343.0 5500.0 6261.7 8875.0

Inc (deg) 0.00 0.00 41.66 41.66

S702p6 Well Trajectory MD(ft) SS Sidetrack of 702p15 WD 3359.0 1 5600.0 2 6790.5

3359.0 5600.0 6586.5

0.00 0.26 59.64

3

8216.0

59.64

10014.0

PI@PSSS Initial Pavg Initial GOR T@midperfs

35 4351 589.57 151

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

2300 4.56 9.72 5643.0

bbl/day psia psia scf/bbl °F

Tubing size (I) AHD ft (SS) 9831

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 Linear between reservoir and seabed 2

Summary Profile TVD (ft) SS

Inc (deg)

S702p7 Well Trajectory MD(ft) SS Sidetrack of 803p3 WD 3359.0 1 6500.0 2 7840.1 3 10528.0 4 10778.5 5 11349.1

3359.0 6494.6 7357.1 7850.0 7869.1 7851.0

0.00 17.50 79.43 79.43 91.82 91.82

702p14 Well Trajectory MD(ft) SS WD 3327 1 5500 2 6500 3 6909.6 4 7409.6 5 13957.9 6 14267

TVD (ft) SS 3327 5500 6377.8 6641.1 6870.2 8565 8645

Inc (deg) 0 0 50 50 75 75 75

PI@PSSS Initial Pavg Initial GOR T@midperfs

15 4129 589.57 136

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

2300 4.56 9.72 5659.0

bbl/day psia psia scf/bbl °F

Tubing size (I) AHD ft (SS) 10014

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 Linear between reservoir and seabed 2

Summary Profile TVD (ft) SS

Inc (deg) PI@PSSS Initial Pavg Initial GOR T@midperfs

14 4032 589.57 120

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

2300 4.56 9.72 5659.0

bbl/day psia psia scf/bbl °F

Tubing size (I) AHD ft (SS) 11349

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 linear 2

Summary Profile Tubing size (I) AHD ft (SS) 14267

PI@PSSS Initial Pavg Initial GOR T@midperfs

13 4247 589.57 144

SSSV Depth ML (ft)

2300

Roughness

0.0018

ID (in) Length (ft) TVD SS (ft)

4.56 9.72 5627.0

Geothermal profile Heat transfer coefficient

linear 2

bbl/day psia psia scf/bbl °F

ID (in) 4.892

OD (in) 5 1/2

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

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702 Wells (cont’d) 702p9 Well Trajectory MD(ft) SS WD 3331.0 2 3721.4 3 4003.9 4 4286.0 5 4568.8 6 4851.4 7 5133.7 8 5416.1 9 5599.8 10 5678.0 11 5764.0 12 5866.0 13 5960.0 14 6051.0 15 6143.0

TVD (ft) SS 3331.0 3721.4 4003.9 4286.0 4568.8 4851.4 5133.7 5416.1 5599.8 5678.0 5764.0 5866.0 5959.9 6050.4 6141.3

Inc (deg) 0.00 0.09 0.35 0.31 0.18 0.18 0.18 0.22 0.13 0.45 0.30 1.33 3.94 7.13 10.65

Roughness Geothermal profile Heat transfer coefficient

16 17 18

6240.0 6333.0 6426.0

6235.9 6324.2 6408.6

15.04 21.29 28.27

Well Design/ Tubing Size

19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70

6520.0 6615.0 6709.0 6804.0 6896.0 6989.0 7151.0 7244.0 7341.0 7434.0 7526.0 7620.0 7713.0 7807.0 7901.0 7995.0 8089.0 8184.0 8278.0 8374.0 8468.0 8561.0 8656.0 8666.2 8750.0 8820.0 8846.0 8920.0 9020.0 9120.0 9220.0 9320.0 9420.0 9520.0 9620.0 9720.0 9820.0 9853.7 9920.0 10020.0 10120.0 10195.5 10216.0 10220.0 10266.0 10320.0 10392.2 10420.0 10520.0 10620.0 10720.0 10820.0

6487.6 6560.2 6629.5 6700.0 6767.0 6831.4 6935.9 6991.1 7044.7 7095.2 7146.9 7201.9 7259.1 7320.1 7383.7 7448.9 7516.0 7585.1 7655.0 7729.5 7804.2 7878.5 7955.3 7963.4 8029.3 8085.1 8106.3 8165.8 8241.8 8312.2 8376.7 8434.8 8486.1 8530.2 8567.0 8596.1 8617.3 8622.7 8632.4 8647.0 8661.7 8672.7 8675.7 8676.3 8683.0 8689.7 8694.7 8695.8 8699.7 8703.6 8707.5 8711.4

37.12 43.15 41.96 42.11 44.43 47.94 51.95 55.29 57.73 56.47 55.16 53.17 51.00 48.10 46.70 45.47 43.32 43.37 40.65 37.46 37.36 36.49 35.73 37.92 38.51 35.78 34.77 38.21 42.86 47.51 52.16 56.81 61.46 66.11 70.76 75.41 80.05 81.59 81.59 81.59 81.59 81.59 81.59 81.59 81.59 84.23 87.77 87.77 87.77 87.77 87.77 87.77

Summary Profile PI@PSSS Initial Pavg Initial GOR T@midperfs

100 4292 589.57 147

SSSV Depth ML (ft) ID (in) Length (ft)* TVD SS (ft)

2300 4.56 9.72 5631.0

AHD ft (SS) 3545 5545 5576.72 10576.72 12084.7

ID (in) 4.892 5.921 4.562 5.921 4.892

bbl/day psia psia scf/bbl °F

0.0018 Linear between reservoir and seabed 2

OD (in) 6 7.191 7.99 7.191 6.05

Length (ft) 45 2000 31.72 5000 1508.0

Description Tubing Hanger Tubing SSSV* Tubing Excluder Screens

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

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702 Wells (cont’d) 702p9 Well Trajectory MD(ft) SS

TVD (ft) SS

Inc (deg)

71 72 73 74 75 76 77 78 79 80 81 82 83

8715.3 8719.1 8723.0 8726.9 8730.8 8734.7 8738.6 8742.5 8746.4 8750.3 8754.2 8758.1 8760.6

87.77 87.77 87.77 87.77 87.77 87.77 87.77 87.77 87.77 87.77 87.77 87.77 87.77

702p15 Well Trajectory MD(ft) SS WD 3359.0 2 3369.0 3 3420.0 4 3520.0 5 3620.0

TVD (ft) SS 3359.0 3369.0 3420.0 3520.0 3620.0

Inc (deg) 0.00 0.00 0.00 0.00 0.00

PI@PSSS Initial Pavg Initial GOR T@midperfs

135 4168 589.57 140

6 7 8 9 10 11

3720.0 3820.0 3920.0 4020.0 4120.0 4220.0

3720.0 3820.0 3920.0 4020.0 4120.0 4220.0

0.00 0.00 0.00 0.00 0.00 0.00

SSSV Depth ML (ft) ID (in) Length (ft)* TVD SS (ft)

2300 4.56 9.72 5659.0

12 13 14 15 16

4320.0 4420.0 4520.0 4620.0 4720.0

4320.0 4420.0 4520.0 4620.0 4720.0

0.00 0.00 0.00 0.00 0.00

Roughness Geothermal profile Heat transfer coefficient

17 18 19

4820.0 4920.0 5020.0

4820.0 4920.0 5020.0

0.00 0.00 0.00

Well Design/ Tubing Size

20 21

5120.0 5220.0

5120.0 5220.0

0.00 0.00

AHD ft (SS)

ID (in)

OD (in)

Length (ft)

Description

22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53

5320.0 5420.0 5520.0 5620.0 5720.0 5820.0 5920.0 6020.0 6120.0 6220.0 6320.0 6420.0 6520.0 6620.0 6720.0 6820.0 6920.0 7020.0 7120.0 7170.8 7220.0 7320.0 7420.0 7520.0 7620.0 7720.0 7820.0 7920.0 8020.0 8120.0 8220.0 8320.0

5320.0 5420.0 5520.0 5620.0 5720.0 5820.0 5920.0 6020.0 6120.0 6220.0 6320.0 6420.0 6520.0 6620.0 6720.0 6820.0 6920.0 7020.0 7120.0 7170.8 7220.0 7319.6 7418.0 7514.6 7608.6 7699.2 7785.8 7867.8 7944.4 8015.1 8079.4 8136.8

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2.46 7.46 12.46 17.46 22.46 27.46 32.46 37.46 42.46 47.46 52.46 57.46

3545 5545 5576.72 10576.72 11264.1

4.892 5.921 4.562 5.921 4.892

6 7.191 7.99 7.191 6.05

45 2000 31.72 5000 687.4

Tubing Hanger Tubing SSSV* Tubing Excluder Screens

10920.0 11020.0 11120.0 11220.0 11320.0 11420.0 11520.0 11620.0 11720.0 11820.0 11920.0 12020.0 12084.7

Summary Profile

Summary Profile

bbl/day psia psia scf/bbl °F

0.0018 Linear between reservoir and seabed 2 Btu/hr ft2/°F

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

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702 Wells (cont’d) 702p15 Well Trajectory MD(ft) SS

TVD (ft) SS

Inc (deg)

54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89

8186.9 8229.2 8263.5 8289.4 8299.4 8307.9 8325.3 8342.6 8347.0 8352.0 8360.7 8373.7 8378.2 8379.7 8384.1 8388.4 8392.7 8397.1 8401.4 8405.8 8410.1 8414.4 8418.8 8421.0 8424.1 8429.5 8436.0 8448.9 8461.8 8474.7 8487.6 8500.5 8513.5 8526.4 8539.3 8545.0

62.46 67.46 72.46 77.46 80.00 80.00 80.00 80.00 80.00 80.00 80.00 84.46 87.51 87.51 87.51 87.51 87.51 87.51 87.51 87.51 87.51 87.51 87.51 87.51 85.09 82.58 82.58 82.58 82.58 82.58 82.58 82.58 82.58 82.58 82.58 82.58

702p10 Well Trajectory MD(ft) SS WD 3178.0 2 3558.0 3 3808.0 4 4094.0 5 4379.0 6 4641.0 7 4946.0 8 5217.0 9 5450.0

TVD (ft) SS 3178.0 3558.0 3808.0 4094.0 4379.0 4641.0 4946.0 5217.0 5450.0

Inc (deg) 0.00 0.62 0.40 0.18 0.22 0.13 0.40 0.75 0.40

10 11 12 13 14 15 16 17

5517.0 5611.0 5706.0 5800.0 5895.0 5990.0 6083.0 6177.0

5517.0 5610.8 5704.5 5795.5 5884.4 5968.6 6046.2 6121.4

0.27 5.99 12.10 17.17 23.73 31.36 35.52 38.23

Roughness Geothermal profile Heat transfer coefficient

18 19 20

6271.0 6366.0 6458.0

6193.6 6263.9 6331.3

41.38 43.11 42.77

Well Design/Tubing Size

21 22 23 24 25 26 27 28 29 30

6555.0 6650.0 6744.0 6838.0 6932.0 7026.0 7121.0 7215.0 7307.0 7324.0

6402.7 6472.1 6539.7 6607.4 6676.6 6747.3 6818.9 6888.4 6954.5 6966.5

42.43 43.71 44.23 43.68 41.46 40.98 41.33 43.20 44.93 45.52

8420.0 8520.0 8620.0 8720.0 8770.8 8820.0 8920.0 9020.0 9045.2 9074.0 9124.4 9220.0 9285.3 9320.0 9420.0 9520.0 9620.0 9720.0 9820.0 9920.0 10020.0 10120.0 10220.0 10271.4 10320.0 10370.4 10420.0 10520.0 10620.0 10720.0 10820.0 10920.0 11020.0 11120.0 11220.0 11264.1

Summary Profile

PI@PSSS Initial Pavg Initial GOR T@midperfs

60 4262 589.57 146

SSSV Depth ML (ft)

2300

ID (in) Length (ft)* TVD SS (ft)

4.56 9.72 5478.0

AHD ft (SS) 3545 5545 5576.72 10576.72 14019.3

ID (in) 4.892 5.921 4.562 5.921 4.892

bbl/day psia psia scf/bbl °F

0.0018 Linear between reservoir and seabed 2 Btu/hr ft2/°F

OD (in) 6 7.191 7.99 7.191 6.05

Length (ft) 45 2000 31.72 5000 3442.6

Description Tubing Hanger Tubing SSSV* Tubing Excluder Screens

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702 Wells (cont’d) 702p10 Well Trajectory MD(ft) SS

TVD (ft) SS

Inc (deg)

31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100

6982.0 7047.0 7112.1 7176.1 7237.5 7294.5 7348.2 7396.9 7440.7 7479.2 7514.6 7549.1 7582.9 7615.5 7647.0 7678.2 7709.3 7741.5 7773.8 7805.3 7826.3 7834.8 7863.7 7894.7 7925.7 7956.6 7987.6 8018.6 8049.5 8080.5 8111.5 8142.4 8173.4 8204.4 8235.3 8266.3 8297.3 8328.2 8359.2 8390.2 8421.1 8452.1 8483.1 8514.0 8545.0 8576.0 8607.0 8624.9 8634.3 8637.9 8649.8 8667.3 8688.9 8701.9 8706.3 8706.3 8706.6 8707.0 8707.3 8707.6 8707.9 8708.2 8708.5 8708.8 8709.2 8709.5 8709.8 8710.1 8710.4 8710.7

45.05 46.23 46.23 48.14 51.23 54.13 57.04 60.57 64.54 67.03 68.73 68.29 69.52 70.31 70.60 71.01 70.31 69.68 70.56 70.34 70.68 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 71.96 75.03 80.01 85.00 89.82 89.82 89.82 89.82 89.82 89.82 89.82 89.82 89.82 89.82 89.82 89.82 89.82 89.82 89.82 89.82

7346.0 7439.0 7533.0 7627.0 7722.0 7816.0 7911.0 8005.0 8100.0 8194.0 8288.0 8382.0 8476.0 8571.0 8665.0 8760.0 8854.0 8948.0 9043.0 9137.0 9200.0 9226.5 9320.0 9420.0 9520.0 9620.0 9720.0 9820.0 9920.0 10020.0 10120.0 10220.0 10320.0 10420.0 10520.0 10620.0 10720.0 10820.0 10920.0 11020.0 11120.0 11220.0 11320.0 11420.0 11520.0 11620.0 11720.0 11778.1 11808.3 11820.0 11858.3 11920.0 12020.0 12120.0 12216.9 12220.0 12320.0 12420.0 12520.0 12620.0 12720.0 12820.0 12920.0 13020.0 13120.0 13220.0 13320.0 13420.0 13520.0 13620.0

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702 Wells (cont’d) 702p10 Well Trajectory MD(ft) SS

TVD (ft) SS

Inc (deg)

101 102 103 104

8711.0 8711.4 8711.7 8712.0

89.82 89.82 89.82 89.82

702p4 Well Trajectory MD(ft) SS WD 3568.0 2 3915.0 3 4189.0

TVD (ft) SS 3568.0 3915.0 4189.0

Inc (deg) 0.00 0.22 0.18

4 5 6 7 8 9 10

4470.0 4748.0 5027.0 5317.0 5599.0 5791.0 5905.0

4470.0 4748.0 5027.0 5317.0 5599.0 5791.0 5905.0

0.18 0.97 0.13 0.22 0.22 0.26 0.99

11 12 13 14 15

6002.0 6097.0 6191.0 6289.0 6383.0

6001.9 6096.9 6190.8 6288.8 6382.8

1.41 1.92 1.62 1.73 1.85

16 17 18 19 20

6477.0 6571.0 6659.0 6758.0 6848.0

6476.7 6570.5 6658.0 6756.1 6844.6

2.41 5.03 6.54 8.85 12.39

21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62

6945.0 7039.0 7132.0 7225.0 7299.0 7320.0 7349.0 7420.0 7520.0 7620.0 7647.8 7720.0 7820.0 7920.0 8020.0 8120.0 8220.0 8320.0 8420.0 8520.0 8620.0 8647.8 8720.0 8820.0 8858.8 8920.0 9020.0 9120.0 9138.7 9220.0 9320.0 9420.0 9520.0 9620.0 9720.0 9820.0 9920.0 9932.8 10020.0 10120.0 10132.8 10220.0

6938.1 7025.9 7109.2 7186.2 7242.8 7258.4 7279.9 7333.7 7413.4 7497.2 7521.1 7583.6 7670.2 7756.8 7843.4 7930.0 8016.6 8103.2 8189.9 8276.5 8363.1 8387.1 8448.5 8529.4 8559.4 8606.1 8682.4 8758.7 8772.9 8833.0 8901.3 8963.1 9017.7 9064.9 9104.2 9135.3 9158.0 9160.3 9175.4 9192.8 9195.0 9207.9

18.48 23.07 29.79 38.13 42.16 42.16 42.16 39.20 35.10 31.09 30.00 30.00 30.00 30.00 30.00 30.00 30.00 30.00 30.00 30.00 30.00 30.00 33.51 38.40 40.30 40.30 40.30 40.30 40.30 44.37 49.37 54.36 59.36 64.36 69.36 74.36 79.36 80.00 80.00 80.00 80.00 83.05

13720.0 13820.0 13920.0 14019.3

Summary Profile PI@PSSS Initial Pavg Initial GOR

70 bbl/day psia 4465 psia 589.57 scf/bbl

T@midperfs

161

SSSV Depth ML (ft) ID (in) Length (ft)* TVD SS (ft)

2300 4.56 9.72 5868.0

Roughness Geothermal profile Heat transfer coefficient

°F

0.0018 Linear between reservoir and seabed 2 Btu//hr ft2/°F

Well Design/ Tubing Size AHD ft (SS)

ID (in)

OD (in)

Length (ft)

Description

3545 5545 5576.72 10576.72 11958.0

4.892 5.921 4.562 5.921 4.892

6 7.191 7.99 7.191 6.05

45 2000 31.72 5000 1381.3

Tubing Hanger Tubing SSSV* Tubing Excluder Screens

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702 Wells (cont’d) 702p4 Well Trajectory MD(ft) SS

TVD (ft) SS

Inc (deg)

63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83

9216.9 9219.9 9220.0 9220.7 9221.5 9222.2 9223.0 9223.7 9224.5 9225.2 9226.0 9226.3 9227.6 9234.7 9247.8 9267.0 9268.2 9289.5 9312.0 9334.5 9343.0

86.55 89.57 89.57 89.57 89.57 89.57 89.57 89.57 89.57 89.57 89.57 89.57 87.69 84.19 80.69 77.19 77.00 77.00 77.00 77.00 77.00

Well Trajectory MD(ft) SS WD 3276.0 2 5650.0 3 5950.0 4 6695.1 5 9544.7 6 9706.6

TVD (ft) SS 3276.0 5650.0 5949.1 6606.4 8630.0 8745.0

Inc (deg) 0.00 0.00 7.50 44.75 44.75 44.75

7

9038.6

44.75

Well Trajectory MD(ft) SS WD 3278.0 2 5200.0 3 6291.6 4 9332.2

TVD (ft) SS 3278.0 5200.0 6133.9 7896.0

Inc (deg) 0.00 0.00 54.58 54.58

5

8165.0

54.58

10320.0 10406.2 10420.0 10520.0 10620.0 10720.0 10820.0 10920.0 11020.0 11120.0 11220.0 11266.4 11320.0 11420.0 11520.0 11620.0 11625.5 11720.0 11820.0 11920.0 11958.0

710 Wells

10120.0

Summary Profile PI@PSSS Initial Pavg Initial GOR T@midperfs

150 4306 1139.2 147

bbl/day psia psia scf/bbl °F

Tubing size (I) AHD ft (SS) 10120

ID (in) 4.892

OD (in) 5 1/2

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

Roughness Geothermal profile Heat transfer coefficient

2300 4.56 9.72 5576.0

0.0018 Linear between reservoir and seabed 2

710p2

9796.3

Summary Profile

710p3 Well Trajectory MD(ft) SS WD 3278.0 2 5200.0

TVD (ft) SS 3278.0 5200.0

Inc (deg) 0.00 0.00

3 4 5

5874.9 8364.0 8605.0

36.08 36.08 36.08

5921.7 9001.6 9299.8

PI@PSSS Initial Pavg Initial GOR T@midperfs

14 4152 1139.2 128

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

2300 4.56 9.72 5578.0

bbl/day psia psia scf/bbl F

Tubing size (I) AHD ft (SS) 9796

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 Linear between reservoir and seabed 2

Summary Profile Tubing size (I) AHD ft (SS) 9300

PI@PSSS Initial Pavg

20 4308

Initial GOR T@midperfs

1139.2 scf/bbl 139 °F

SSSV Depth ML (ft) ID (in)

2300 4.56

Roughness Geothermal profile

0.0018 Linear between reservoir and seabed

Length (ft) TVD SS (ft)

9.72 5578.0

Heat transfer coefficient

2

bbl/day psia psia

ID (in) 4.892

OD (in) 5 1/2

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702 Wells (cont’d) 710p4 Well Trajectory MD(ft) SS TVD (ft) SS Inc (deg) Combined with 803p1 in a single wellbore WD 3362.0 3362.0 0.00 2 6150.0 6150.0 0.00 3 6730.0 6705.5 29.00 4 9387.6 9030.0 29.00

Summary Profile PI@PSSS Initial Pavg Initial GOR T@midperfs

18 4527 1139.2 158

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

2300 4.56 9.72 5662.0

bbl/day psia psia scf/bbl °F

Tubing size (I) AHD ft (SS) 9388

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 Linear between reservoir and seabed 2

803 Wells 803p1 Well Trajectory MD(ft) SS WD 3362.0 2 6150.0 3 6730.0 4 9387.6 5 10770.0 6 10873.3 7 10988.5 8 12379.0

TVD (ft) SS 3362.0 6150.0 6705.5 9030.0 9910.9 9930.0 9949.6 10165.0

Inc (deg) 0.00 0.00 29.00 29.00 79.31 79.31 81.09 81.09

803p2 Well Trajectory MD(ft) SS WD 3195.0 2 5500.0 3 6400.0 4 15607.7 5 16007.7 6 16465.8

TVD (ft) SS 3195.0 5500.0 6310.3 12821.1 13049.4 13243.0

Inc (deg) 0.00 0.00 45.00 45.00 65.00 65.00

Summary Profile PI@PSSS Initial Pavg Initial GOR T@midperfs

18 5142 1447 176

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

2300 4.56 9.72 5662.0

Tubing size (I) AHD ft (SS) 12379

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 Linear 2

Summary Profile PI@PSSS Initial Pavg Initial GOR T@midperfs

803p3 Well Trajectory MD(ft) SS WD 3359.0 2 5700.0 3 6684.6 4 7584.6

TVD (ft) SS 3359.0 5700.0 6684.6 7494.9

Inc (deg) 0.00 0.00 0.00 45.00

5 6 7 8 9

10437.8 10675.1 10805.0 10955.0 11401.0

45.00 30.00 30.00 30.00 30.00

4 5176 1447 179

bbl/day psia psia scf/bbl °F

Tubing size (I) AHD ft (SS) 16466

ID (in) 4.892

OD (in) 5 1/2

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

11746.5 12046.5 12196.5 12369.7 12884.7

bbl/day psia psia scf/bbl °F

Roughness Geothermal profile Heat transfer coefficient

2300 4.56 9.72 5495.0

0.0018 Linear 2

Summary Profile PI@PSSS Initial Pavg Initial GOR T@midperfs

70 5381 956 198

SSSV Depth ML (ft) ID (in) Length (ft) TVD SS (ft)

2300 4.56 9.72 5659.0

bbl/day psia psia scf/bbl °F

Tubing size (I) AHD ft (SS) 12885

Roughness Geothermal profile Heat transfer coefficient

ID (in) 4.892

OD (in) 5 1/2

0.0018 Linear 2

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Section 3 Hydrate Remediation Guidelines

Table of Contents 1.0

2.0

3.0

4.0

INTRODUCTION...........................................................................................................3 1.1

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

1.2

Shutdown...........................................................................................................3

1.3

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

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

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

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 a Methanol Rate of 14gpm ..................................................................................10 Figure 3.3 – Methanol Volume Requirement for 702 Fluid....................................................10

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Table of Contents (cont’d) FIGURES Figure 3.4 – Maximum Treatable Flowrate for the 710 Oil with a Methanol Rate of 14gpm ..................................................................................11 Figure 3.5 – Methanol Volume Requirements for the 710/740 Fluid .....................................11 Figure 3.6 – Hydrate Remediation Times for the 702 Reservoir Fluid, Dashed Curves 12in PIP Flowline, Solid Curves 10in PIP Flowline ..................12 Figure 3.7 – Hydrate Remediation Times for the 710 Reservoir Fluid, Dashed Curves 12in PIP Flowline, Solid Curves 10in PIP Flowline ..................13 Figure 3.8 – Risk Identification for Hydrate Plugging in Different Parts of the Subsea System for Bonga................................................................................15 Figure 3.9 – Schematic of Hydrate Plug in Flowline (Except PFL 03/04) ..............................22 Figure 3.10 – Schematic of Hydrate Plug in Flowline (PFL 03/04) ........................................23 Figure 3.11 – Schematic of Hydrate Plug in Riser ................................................................23 Figure 3.12 – Remediation Procedure for Hydrate Plug in Flowline ......................................27 Figure 3.13 – Remediation Procedure for Hydrate Plug in Riser...........................................28 Figure 3.14 – Schematic of Hydrate Plate in Jumper............................................................29 Figure 3.15 – Remediation Procedure for Hydrate Plug in Jumper/Manifold.........................32 Figure 3.16 – Schematic of Hydrate Plug in Wellbore...........................................................33 Figure 3.17 – Remediation Procedure for a Hydrate Plug in the Wellbore ............................35 Figure 3.18 – Schematic of Hydrate Plug in Umbilical Line...................................................36 Figure 3.19 – Remediation Procedure for a Hydrate Plug in an Umbilical.............................37 Figure 3.20 – Schematic of Hydrate Plug in Riser Gas Lift System (Between Methanol Line and Flowline) ............................................................38 Figure 3.21 – Schematic of Hydrate Plug in Riser Gas Lift System (Between Methanol Line and GLR Topsides) ..................................................39 Figure 3.22 – Remediation Procedure for a Hydrate Plug in the Gas Lift Riser (Between Methanol Line and the Flowline) ......................................................41 Figure 3.23 – Remediation Procedure for a Hydrate Plug in the Gas Lift Riser (Between Methanol Line and Topsides)...........................................................42 Figure 3.24 – Schematic of Hydrate Plug in Water Injection Line .........................................44 APPENDICES Appendix 3A – Pressure Tags ..............................................................................................45 Appendix 3B – Case Studies ................................................................................................49 Appendix 3C – Nomenclature...............................................................................................63

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INTRODUCTION Bonga is a deepwater development offshore Nigeria in Block OML 118, in approximately 1000m water depth. Shell Nigeria E&P (SNEPCO) will operate Bonga in a joint venture with Esso (20%), Elf (12.5%) and Agip (12.5%). Bonga is being developed as a subsea network with 1.9 to 9.2km tiebacks to a permanently moored Floating Production, Storage, and Offloading vessel (FPSO). Peak production rates are anticipated at 225,000 barrels of oil per day, 170MMSCF of gas per day (including recycled riser lift gas) and 100,000 barrels of produced water per day. Reservoir pressures will be maintained via subsea waterflood wells with up to 300,000 barrels water per day injection capacity. Bonga consists of four reservoirs (690, 702, 710/740 and 803) with roughly half of the total reserves in the 702 reservoir. The production system contains subsea trees – enabling Surface Controlled Subsurface Safety Valves (SCSSVs), production chokes, and chemical injection valves – connected via short well jumpers to five subsea production manifolds. The subsea wells are produced through four pairs of piggable dual pipe-in-pipe flowlines, with externally insulated steel catenary risers. Each flowline is connected to a dedicated gas lift riser delivering up to 25MMSCF per day. One of the biggest flow assurance challenges at Bonga is hydrate control. Bonga is expected to operate under the philosophy of hydrate avoidance during all phases of operation – start-up, shutdown and steady state. This is achieved by the following operational strategies:

1.1

Start-up The strategy is to hot oil the flowlines to protect them from hydrates. The strategy for the trees, well jumpers and manifolds is to inject methanol/Low Dosage Hydrate Inhibitor (LDHI). In the absence of any methanol injection downhole, the well is ramped up as quickly as practicable (notionally 5000 to 7000bpd, depending on water-cut and pressure) such that the flowing wellhead temperature is greater than the hydrate dissociation temperature (approximately 24°C (75°F), but exact temperature 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 hydrate dissociation pressure at 4.4°C (40°F) before the cooldown period has expired (notionally 12 hours following production at minimum flowline flowrates of 10,000bpd). The well jumpers and manifolds are displaced with methanol, before the cooldown time has expired, to remove hydrateable fluids and replace them with methanol. The wellbore is also bullheaded with methanol to the SCSSV in order to protect 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 at steady 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 immediately upon shut-in, since the cooldown time in this section is limited.

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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 a temperature that guarantees at least 12 hours to cool down to the hydrate temperature during a shut-in. However, in spite of the above philosophies, there are four major reasons which makes hydrate control at Bonga particularly challenging. These are: Low Water Salinity

•

The expected produced water salinity at Bonga is ~3wt% while typical Gulf of Mexico (GoM) produced water is between 6 to 22wt%. Assuming an average of 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 to 4°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 has important implications for Bonga since current blowdown calculations with and without riser base gas lift indicate that the low blowdown pressure requirement challenges the limits of the blowdown system (transient report on blowdown has 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 data for black oil systems is limited. There are a number of different factors that determine 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 Bonga crude, plugging times were all very rapid. In all tests, the fluids were cooled from higher temperatures down into the hydrate region, and within a few degrees 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/oil emulsion) actually froze in place. This rapid hydrate formation has not been observed previously. While there are no other experiments done at the same conditions as these for Bonga, tests with other crude oil systems in the flow loop 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 hydrate formation at such high water rates, methanol injection rates of nearly 60 to 90gpm 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). When operating at such high water rates, Bonga depends on a unique never-before-used methanol/LDHI cocktail to prevent hydrate formation in the trees, jumpers and manifolds during start-up. Although, laboratory tests have indicated that this combination will work at Bonga, it must be understood that this strategy has not been field tested.

2

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

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Lack of Operating Experience at Bonga Experience has indicated that new facilities are prone to a lot of aborted start-ups and extended shutdowns during their first few years of operation (eg Auger had nearly 253 unplanned shutdowns and 79 planned shutdowns during its first 22 months of operation, while Mars had nearly 112 unplanned shutdowns and 29 planned shutdowns during its first 8 months of operations)3. The subsea system is most vulnerable to hydrates during start-up and shutdown (especially before steady-state is attained), and the probability of operational errors is greatest during these transient events.

In view of the above reasons, hydrate formation/plugging is a credible risk at Bonga and hence, maximum precautions must be taken to ensure hydrate free operations at Bonga. The main purposes of this document are to: •

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

•

Provide the first steps of blockage remediation to operators/surveillance staff in case a hydrate blockage forms so that operators/surveillance staff can safely secure the system and/or prevent the problem from getting worse

•

Define safe procedures to start remediation of the subsea hydrate blockage before expert help can be summoned

•

Provide examples from other fields (within and outside Shell) on how hydrates blockages 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 should be 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 of the subsea system. (We view hydrate plugging as an abnormal event requiring expert help. Each event is somewhat different and hence routine procedures cannot be written. Although some initial procedures can be initiated from the FPSO, we strongly recommend summoning expert help to complete remediation of 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 cover some of the critical operations. In fact, this document assumes that the reader is intimately familiar with Bonga’s operating strategies especially with respect to hydrate management

•

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

3

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

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This document is structured as follows:

2.0

•

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 the subsea system

•

Paragraph 4.0 describes remediation methodologies for each section of the subsea system and contains guidelines for remediating hydrates once a plug is formed

•

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

•

Appendix 3B describes several different case studies involving hydrate plug formation 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

HYDRATE CHARACTERISTICS OF THE BONGA FLUIDS This paragraph is intended as a summary of the information used in determining the hydrate curves and methanol requirements4. The hydrate curves are presented for all fluids to give some indication of the relative hydrate risk of each of the different oil systems. Methanol rates are only included for the 702 oil (best-case) and the 710 oil (worst-case) to bracket the potential methanol requirements at Bonga.

2.1

Hydrate Curves The hydrate curves define the stability of hydrates in the Bonga system. The hydrate curves are dependent on the salinity of the produced water. Hydrate curves are included 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 and Table 3.1 should be used in determining if the system is operating in the hydrate 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 is decreased to 150bar (2175psi), the 690 and 702 fluids are no longer in the hydrate stability region, but the 803 and 710 fluids are still in the hydrate region. If the pressure is further reduced to 100bar (1450psi), the conditions are such that all fluids are now out of the hydrate region. Alternatively, if the temperature is increased from 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 Management Strategy’, report OG.03.80057, 2003.

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Temperature (ºF) 42

32

52

62

72

82 5000

690 300

4500

720 4000 803 3500

710/740 Hydrate Stability Region

200

3000 2500

150

2000

Pressure (psi)

Pressure (bar)

250

1500

100 Non-hydrate Region

50

1000 500 0

0 0

5

10

15

20

25

30

Temperature (ºC)

OPRM20030302D_063.ai

Figure 3.1 – Hydrate Curves for the Bonga Fluids

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Pressure (bar)

690 HDT (°C)

702 HDT (°C)

710/740 HDT (°C)

803 HDT (°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)

690 HDT (°F)

702 HDT (°F)

710/740 HDT (°F)

803 HDT (°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

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Blowdown and Plug Remediation Pressures An important aspect of the hydrate equilibriums curve is the Hydrate Dissociation Pressure (HDP) at the ambient seafloor temperature of 4.4°C (40°F). This is the pressure that will determine the blowdown requirement and the hydrate plug remediation pressure. One of the key components to hydrate control at Bonga is the ability to blow down the flowlines and move the flowline conditions outside of the hydrate region. Table 3.2 shows 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 of hydrate plug remediation. The flowline pressure must be reduced below the HDP of the 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 at which 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 with the 702 and the 710 fluids. Figures 3.3 and 3.5 give the methanol requirements in a more general format that can be applied to any flowrate. The minimum flowrate during start-up is either 5000blpd or 7000blpd, depending on the well. At a given pressure and flowrate, these figures can be used to determine how much water can be treated. This is important in determining when to switch from the methanol-only strategy to the methanol/Kinetic Hydrate Inhibitor (KHI) strategy. For example, if the 702 fluid is being produced at a rate of 5000blpd, the flowline pressure is 150bar (2175psi) and the water cut is greater than 20%, then methanol alone (at 14gpm) is not enough to protect against hydrate formation and it is time to switch to the methanol/KHI strategy. Similarly, if the flowline is producing the 710 fluid at a rate of 5000blpd and a pressure 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 hydrate formation.

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Pressure (psi)

Maximum Treatable % Water Cut

70

0

500

1000

1500

2000

2500

3000

3500

4000

4500

60 50

Fluids cannot be treated with methanol alone

40 30 5000blpd

20 Fluids can be treated with methanol

10

7000blpd

0 0

50

100

150

200

250

300

Pressure (bar) OPRM20030302D_049.ai

Figure 3.2 – Maximum Treatable Flowrate for the 702 Oil with a Methanol Rate of 14gpm 0.80

m3 Methanol/m3 Water

0.70 0.60 0.50 0.40 0.30 0.20 0.10 0

5

10

15

20

25

30

35

40

% Water Cut 34.5bar (500psia)

68.9bar (1000psia)

241.3bar (3500psia)

317.2bar (4600psia)

103.4bar (1500psia)

OPRM20030302D_050.ai

Figure 3.3 – Methanol Volume Requirement for 702 Fluid

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500

Unrestricted

1000

1500

2000

2500

3000

3500

4000

4500

45

Maximum Treatable % Water Cut

40 35 Fluids Cannot be Treated with Methanol Alone

30 25 20

5000blpd 15 10 7000blpd

Fluids Can be Treated with Methanol

5 0

5

0

100

150

200

250

300

Pressure (bar) OPRM20030302D_071.ai

Figure 3.4 – Maximum Treatable Flowrate for the 710 Oil with a Methanol Rate of 14gpm 0.80

m3 Methanol/m3 Water

0.70

0.60

0.50

0.40

0.30

0.20

0.10 0

5

10

15

20

25

30

35

40

% Water Cut 34.5bar (500psia)

68.9bar (1000psia)

241.3bar (3500psia)

317.2bar (4600psia)

103.4bar (1500psia)

OPRM20030302D_064.ai

Figure 3.5 – Methanol Volume Requirements for the 710/740 Fluid

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Hydrate Plug Dissociation Times Figures 3.6 and 3.7 are intended to give approximate hydrate plug remediation times as a function of the pressure. In this case, approximate means an order of magnitude estimate. The intent of these predictions is to indicate if the plug melting time is days, weeks or months. This model has been compared with available information on hydrate plug removal and was found to give reasonable estimates of the plug melting time6. If the predicted dissociation time is a week, then the plug can be expected to take 1 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 pressure communication 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 were generated for the Bonga flowlines (10in and 12in), but similar results were obtained for 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 are used in the prediction of the hydrate remediation times. These two fluids bracket the possible remediation times that are expected for Bonga.

Downstream Pressure (psia) 30

87

100

6

7

113

126

139

152

165

178

191

204

Hydrate Dissociation Pressure

Remediation Time (Days)

25

217

20

15

10

5

0 8

9

10

11

12

13

14

15

Downstream Pressure (bar) 1-sided dissociation 2-sided dissociation OPRM20030302D_051.ai

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.

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Downstream Pressure (psia) 44

54

64

74

84

94

104

114

124

134

30

Hydrate Dissociation Pressure

Remedlation Time (Days)

25

20

15

10

5

0 3

4

5

6

7

8

9

Downstream Pressure (bar) 1-sided dissociation

2-sided dissociation OPRM20030302D_065.ai

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 SYSTEMS When assessing the hydrate risk in the subsea system, there is an important distinction to be made between hydrate formation and the formation of a hydrate plug. In an uninhibited system, if the subsea temperature and pressure are in the hydrate formation region, hydrates will form. The formation of a solid hydrate plug is not predictable but, from laboratory and field experience, it is most likely to occur during a restart. If a plug is not formed immediately upon restart, continued operation inside the hydrate region greatly increases the risk that sufficient hydrates will accumulate and lead to the formation of a plug. How long the system can operate in the hydrate region before a plug is formed depends on a number of factors, including the kinetics of hydrate formation and the ‘stickiness’ of the hydrate particles that are formed. Unfortunately there is no accurate means of predicting when the hydrate particles will accumulate into a plug, but laboratory testing with the Bonga fluids showed the rapid formation of hydrate plugs once the system was inside the hydrate region. There are several examples of GoM systems that operate in the hydrate region without forming hydrate plugs even though hydrates are formed. However, these examples 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 the flowline. Once the pressure drop increases sufficiently, the production rate is curtailed while the methanol pumps continue to run at full flowrates to flush the hydrates out of the flowline. This strategy can be used at South-east Tahoe since production is at the end of the field life and the consequences of forming a plug are not severe (limited loss of production).

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The same is not true of oil systems. Currently, the steady-state operating strategy for oil systems is to operate outside of the hydrate region, thus there are no similar cases to compare. Most plugs in oil systems occur during restart after the system remained in the hydrate region for some amount of time. Also, based on flowloop tests, the plugs that are formed in an oil system usually occur much more catastrophically and the typical warning signs observed in gas condensate systems (such as gradual increase in pressure drop) are not observed. The Bonga fluids have shown rapid failure times in testing and hence it is assumed that the formation of hydrates will quite quickly lead to the formation of a plug. Therefore, the philosophy at Bonga is for hydrate avoidance during all phases of operation by keeping the operating conditions outside of the hydrate formation region (or by delaying the formation of hydrates for at least 12 hours by using LDHI in mid-life to late-life). For the special case of the wellbore during start-up (without downhole inhibitor injection capability at Bonga), the risk of hydrate plug formation is minimised by ‘bullheading’ the upper wellbore with methanol (or methanol/LDHI) after shut-in. There is some evidence from a North Sea oil field that signals are provided during plug formation and prior to complete blockage in an oil system. As was the case with South-east Tahoe, in the North Sea oil field after significant build-up in the line pressure drop, the methanol rate was increased and the hydrate restrictions cleared from the flowline. The methanol rate was reduced to initial levels and the cycle repeated. However, several key differences exist between this example and Bonga, in particular, the water cut (~10%) was much lower than is expected at Bonga. So, while it may be possible to observe early signs of hydrate plug formation, this will not be the operating strategy used at Bonga. With Bonga production, it is assumed that any hydrate formation will rapidly lead to the formation of a plug. It will be crucial to monitor the temperatures and pressures along the subsea system in order to determine where hydrates are forming. This will allow the location of a hydrate plug to be isolated to the riser, flowline, jumper or wellbore. These temperature and pressure measurements can be monitored using the various sensors on the subsea system. Appendix 3A shows the tag numbers for the various pressure sensors in different parts of the subsea system for different flowline loops, trees, manifolds and gas lift risers. The tags for the temperature sensors are not included since they have only a limited usefulness in detecting hydrate plugs. Before writing any paragraph on remediation, it is important to assess the risk of hydrate formation on various parts of the Bonga subsea system during all stages of operation. Figure 3.8 shows the risk associated with each part of the subsea system. However, the temperature readings are vitally important in determining if the system is in the hydrate formation region.

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Event Subsea System

Start-up

Steady State

Shutdown

Aborted Start-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 hydrate control is achieved by a combination of design and active strategies. Examples include the tree and jumper where the addition of methanol/LDHI is used to prevent hydrates during start-up. If a methanol pump fails, it could lead to the formation of hydrates. Another example is that for the wellbore, there is not the ability to treat with methanol/LDHI to prevent hydrates during start-up and instead a strategy of minimising 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 eroded by operational decisions. An example of this is deciding to start up into a warm flowline (without hot-oiling) that has partially cooled down. An aborted start-up at this stage would leave the flowline in a state with an unknown cooldown time and possibly allow the liquids in the system to cool inside the hydrate region prior to following the procedure for a ‘normal’ aborted start-up.

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Low Risk The system design protects itself from hydrates for normal operating conditions. For example, the Bonga subsea system is designed such that during steady state operation, all sections are outside of the hydrate region and that upon a shut-in, there is sufficient cooldown time provided by the insulation to give at least 3 hours during which no hydrate inhibition actions are required.

3.1

Start-up High Risk As shown in Figure 3.8, the highest risk during start-up is in the wellbore, tree, wellbore jumper, manifold and umbilicals. During start-up, these sections are typically at the coolest temperature and highest pressure in the subsea system. The highest risk among these sections is the wellbore since the system design does not include wellbore hydrate inhibitor injection, whereas the tree, manifold and jumper will be susceptible to hydrate formation if the injection of methanol or methanol/LDHI fails. The hydrate risk in the wellbore is difficult to quantify. Prior to the start-up, the wellbore should have been bullheaded with methanol to prevent any hydrate from forming during shut-in. Once the system is restarted, there is a fairly lengthy warm-up time and the wellbore may be operating in the hydrate region for up to 90 minutes1. There is a good chance hydrates will form and be pushed out of the wellbore to areas of the subsea system that have already been warmed and/or treated with methanol/LDHI without forming a hydrate plug in the wellbore. The risk of hydrate formation is high. The risk of forming a hydrate plug is less and is difficult to quantify. Based on GoM experience, the formation of a hydrate plug in the wellbore is low if the warm-up times are quick (ie less than 1 hour). However, there are several key differences between the GoM wells and the Bonga wells that make the Bonga wells a higher risk. GoM wells typically have Vacuum Insulated Tubing (VIT), which decreases the warm-up time considerably. An unknown in this process is the effect of watercut. All testing indicates that the higher the watercut, the higher the hydrate risk, but there are very few subsea flowlines producing oil at high watercut, which makes this risk difficult to quantify, hence, the overall risk is marked as high. There are cases when an oil system (eg Auger and Tahoe) has plugged with hydrates during start-up. However, both examples are a bit unusual in that very little produced water was present. At Auger, there may have been some additional unloading fluids present that increased the total watercut. In both cases, the systems were shut-in without any hydrate inhibition (since it was assumed the watercut was too low to form a hydrate plug). Likely hydrates were formed from the small amounts of water present in the oil stretched throughout the flowline but also in larger amounts from water settled and accumulated in low spots in the flowline. Upon restart, these hydrate particles grew to form a plug. This illustrates the need to protect the system against hydrates even when the watercut is low. As the watercut is increased, the likelihood of forming hydrates is only increased.7 1

Due to the bare tubing in the wellbore, cooldown times are much larger when the well has been operating at steady 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 immediately upon shut-in, since the cooldown time in this section is limited. 7

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 extended shut-in) and the properties of the reservoir are different than at Bonga.

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The hydrate risk in the tree, well jumper and manifold is largely mitigated by the use of chemicals. During early life, methanol can be injected in sufficient quantities to prevent 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 areas where water can accumulate and this greatly increases the risk of hydrate plug formation. If adequate measures are taken to ensure pump reliability, then this risk is decreased. However, based on the definition of risk, this is considered a high risk since the insulation alone does not provide protection from hydrates during restart and transition to steady-state, but instead hydrate mitigation relies upon chemical treatment. Similarly, the chemical umbilical lines (especially flying leads) are susceptible to hydrates 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 their own pressure), gas can migrate past the SCSSV (towards the tree) during an extended shut-in and can form hydrates with the water in the well. This risk is greatest when waterflood has just started for the first time and the well is shut in within a few days of initial start-up. This is because the gas front in the reservoir would not have been pushed away from the wellbore and hence the gas will tend to migrate back into the wellbore. As more and more water is injected into the reservoir, the risk continues to decrease as the gas front in the reservoir is pushed away from the water injection wellbore (hence, the gas takes much longer to migrate back into the wellbore). This risk is difficult to quantify since the probability of gas migration into the wellbore is unknown. Any hydrates that are formed will be a result of these gas bubbles migrating up the wellbore. In the absence of any agitation, a column of hydrate bubbles will be established. With time, these hydrate bubbles will be 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 the shut-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 upon restart, it may or may not be enough to stop flow and prevent the water from pushing this hydrate to below the SCSSV, where they will melt. Even excluding this scenario of gas leaking past the SCSSV, gas and oil migration will pose a risk at start-up as the valve is opened with oil or gas trapped beneath it unless 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 case will likely not be quickly melted even if flow is established since the incoming water temperature is expected to be no higher than about 60°F and at pressures still within the hydrate region. Because of the uncertain nature of gas migration in the water injection system and the inability to inject any chemicals into the wellbore to prevent or remediate hydrates, then the risk is considered high for the water injection trees and upper wellbore. Since this is a problem that occurs during shut-in and can prevent start-up, this risk is included in both the ‘start-up’ and ‘shutdown’ categories for the sake of completeness.

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Medium Risk None. Low Risk Flowlines and risers have a low risk of hydrate formation during start-up since they will always be started up with hot-oiling (or will be started up before their cooldown time has expired). Hot-oiling ensures that the flowlines are always above the Hydrate Dissociation Temperature (HDT) and have a guaranteed 12-hour cooldown to HDT. Water injection flowlines and water injection tees have low risk of hydrate formation due to the low probability of any gas migration to these parts. Any oil or gas that migrates 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 of hydrocarbons into the gas lift system (achieved by means of an orifice plate which ensures 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 due to the design of the Bonga system. By design, every part of the subsea production system is insulated to operate above hydrate dissociation temperatures and also to provide 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 not expect any kind of backflow of hydrocarbons into umbilicals, water injection system or the gas lift system during steady-state.

3.3

Shutdown Shutdown risks are tricky to capture since any problem that occurs during shutdown will be manifested only when we try to restart the system. However, this paragraph attempts to capture possible hydrate problems that are solely the result of a shut-in and 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.

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In Bonga, the control system is designed such that the chemical valves at the trees are instructed to close as soon as the wells shut in. Similarly, the gas lift valves on the gas lift sled are also designed to be shut in as soon as the FPSO flowline boarding valves shut in. However, there has been past experience wherein hydrate formation has occurred due to backflow. An example of this is the Malampaya Project wherein methanol lines were plugged with hydrates due to backflow from the production system into the umbilical. Gas migration from the water injection reservoirs can also result in hydrate formation in the water injection trees. Gas migration can occur either during shut-in after a short period of operation (say within the first few days of start-up when the hydrocarbon front has not been pushed far enough into the reservoir) or during a long extended shut in (when gas eventually migrates back, as in the case of the Terra Nova Field in Canada)8. The gas from the reservoir can migrate past the SCSSV towards the trees and can result in plug formation. Medium Risk None. Low Risk All other parts of the subsea system have a low risk with respect to hydrate formation due to the fact that the Bonga production system is designed with a minimum 12-hour cooldown time after shut-in. Failure to protect the subsea sections against hydrate formation greatly increases the risk of forming a hydrate plug upon restart.

3.4

Aborted Start-up High Risk The aborted start-up has the highest risk of hydrate formation of any of the operations at Bonga. The wellbore, well jumper, production manifolds, gas lift sled, umbilicals and water injection trees are all particularly susceptible to hydrates during an aborted start-up. The risk is similar to that of the start-up case (ie wellbore, well-jumper, production manifold, 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 to hydrate formation. This is due to the fact that the water-heated portion of the Gas Lift 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 migrated near the wellbore and/or accumulated beneath the SCSSV during the shut-in would not be moved very far during the initial start-up. This means that less time is required for the gas to migrate back to the wellbore or past the safety valve. Cold fluids have been moved further down into the wellbore where the pressure is higher and 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 extended shut-in) and the properties of the reservoir are different than at Bonga.

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Medium Risk The flowlines are designed in such a way that they have a minimum of 12 hours cooldown after a shut-in from steady state. However, if a well has a warm start into a flowline during the cooldown period and this well has an aborted start-up, it is not very easy to estimate the resulting cooldown time. This uncertainty in the cooldown time necessitates identifying hydrate formation as a medium risk. The second scenario is starting up a cold well into a flowline, which has just been hot-oiled. The hot-oiling ensures that the flowline has a 12-hour cooldown prior to starting up the well and also that the cold fluids from the well do not reduce the flowline temperature to below the HDT. However, an aborted start-up on this well will result in not knowing the exact temperature of the flowline and thus result in an uncertain 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 waterflood flowlines 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 of hydrates with respect to Bonga, it is unlikely that hydrate formation will be detected in the system before a hydrate plug is formed. Therefore, this paragraph assumes that a hydrate plug has formed and provides guidance for determining approximately where the plug is in the subsea system and for remediating hydrate plugs. Lastly, there are examples for hydrate detection and remediation drawn from different fields from various parts of the world (Shell and non-Shell). In this document the pressure measurement is the crucial parameter in determining the location of the hydrate plug. However, it should be noted that the temperature measurement is important in determining if the system is in the hydrate formation region. The temperature and pressure must be in the hydrate region before hydrates can form. Figure 3.1 or the Bonga tool can be used to determine if the system temperature and pressure are in the hydrate region. If the system is operating outside of the hydrate region and a blockage is formed, then the cause is something other 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 can be determined to be between a particular pair of pressure sensors. Although not discussed in this document, there are other methods to determine a more exact plug location (eg ultrasonic sensors). The pressure sensors at Bonga can localise the plug to specific sections of the subsea system, including the flowline, riser, jumper/manifold or the wellbore. For the hydrate remediation guidelines presented in this document, this gross determination of plug location is sufficient. If the plug location needs to be determined more exactly, expert guidance is suggested. Information is also presented for hydrate plugs that form in umbilical lines and the waterflood lines. These lines are not equipped with instruments that help to locate and remediate a hydrate plug, as are the other portions of the subsea system. In these cases, more general information will be given.

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Flowlines/Risers Although the risk for hydrate formation in the flowline has been determined to be low, it is important to have guidelines in place to remediate a hydrate plug in the flowline. The loss of a flowline can affect production from multiple wells (all wells from that manifold), which has a significant impact on deferred production and 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 the flowline/riser section is during a restart following an aborted start-up. Plugs may occur during the shutdown period, but they will not be detected until the flowline is restarted. A hydrate plug during steady-state operation is considered unlikely since the 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 along with the affected subsea components. For simplicity, this figure can be used for any flowline 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 in Flowline 1 results in a pressure increase at the manifold (and at the tree of the wells flowing into Flowline 1) to the Shut-in Tubing Pressure (SITP). The pressure at the downstream 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 too slow 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 (wells flowing to Flowline 1) to SITP –

[Pm-1])

and at the tree

Manifold pressure and tree pressure upstream and downstream of the choke 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 readily observed

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Flowline PFL 03/04 The case of a hydrate plug in either PFL 03 or 04 is similar to the general case of hydrate plug in one of the flowlines except that the pressure downstream of the plug is determined at manifold PM3 instead of at the riser base (or topsides). There is an additional difficulty in this case since the downstream pressure will still see contributions from other wells flowing into PM3, but there should be a significant decrease in pressure (and temperature). However, the upstream pressure (PM4 manifold pressure in Flowline 1 and in all wells flowing to Flowline 1 at PM4) will increase to the SITP pressure. Plug Formation Between PM3 and PM4 (PFL 03/04) Refer to the schematic in Figure 3.10 for relevant locations of pressure gauges: •

Increase in pressure drop in Flowline 1 between PM3 and PM4 –

•

Pressure increase at PM4 (Flowline 1 side), pressure decrease at PM3 (Flowline 1 side)

Pressures at the tree of the wells flowing to Flowline 1 (through PM4) increase to SITP

Riser 2

Subsea Manifold

Pm-2

Topsides Pressure

Flowline 2 Prb-2 Riser Base Pressure

PIV Pm-1

Hydrate Plug

Riser 1

Prb-1

Flowline 1 Manifold Pressure OPRM20030302D_058.ai

Figure 3.9 – Schematic of Hydrate Plug in Flowline (Except PFL 03/04)

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Manifold (PM4)

Manifold (PM3)

Flowline 2

Flowlines to FPSO PFL 05/06

Manifold (PM3) Pressure

PIV Pm-1

Hydrate Plug Flowline 1

Manifold (PM4) Pressure OPRM20030302D_059.ai

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 in the flowline except for the pressure reading at the base of Riser 1. In this case, both the 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 downstream end of the plug (measured at Riser 1 topsides). The hydrate plug in Riser 1 will not affect 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

Riser 2 Topsides Pressure

Subsea Manifold

Pm-2

Flowline 2 Prb-2 Riser Base Pressure

PIV

Hydrate Plug

Prb-1

Pm-1

Riser 1

Flowline 1 Manifold Pressure OPRM20030302D_060.ai

Fig 3.11 Schematic of Hydrate Plug in Riser

Figure 3.11 – Schematic of Hydrate Plug in Riser

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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 of safely performing a remediation and hence are not discussed in this document. In these cases additional support is recommended before any plug remediation procedures are attempted. Flowlines (Except PFL 03/04) The following discussion is based on Figure 3.9 and the convention that the hydrate blockage is in Flowline 1 (not necessarily PFL 01), and that Flowline 2 (not necessarily PFL 02) does not have a hydrate blockage. Refer to Figure 3.12 for a flowchart 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 pressures are 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 steps should 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 allow blow 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 drop the better. The pressure gradient across the manifold should be small in the event that 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, the wells feeding Flowline 2.

Pm-2,

to rise to close to

Pm-1,

and then shut in

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) is the pressure across the blockage, Pab. Pab times the pipeline internal diameter is the driving force on the blockage.

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Blow down Flowline 2 topsides to the flare until the target safe pressure at is reached.

Pm-2

Target safe pressure at Pm-2 is within ±14bar (200psi) of Pm-1. (4)

Close the topsides Flowline 2 valve.

Step 4 – Reduce Pressure in Flowlines Open PIV to equalise pressures between the two flowlines. Blow down Flowline 2 until Prb-2 reaches a pressure of 7bar to 14bar (100psi to 200psi) below Prb-1. When this occurs, begin simultaneous blowdown of both flowlines, making sure that Prb-2 remains 7bar to 14bar (100psi to 200psi) below Pm-1. Near the end of the pressure lowering, gas lift may be required to further lower the pressure. Step 5 – Reduce Pressure Outside of Hydrate Region Blow down the flowlines to pressures outside of the hydrate region so that the blockage will melt (dissociate). The lower the pressure, the faster the blockage will melt10. Blow down Flowline 1 and Flowline 2 to as low pressures as possible while maintaining Prb-1 7bar to 14bar above Pm-1. The pressure at the blockage must be less than the hydrate equilibrium pressure at ambient seafloor temperature11 in order for hydrates to melt (dissociate). If the pressure cannot be lowered enough to melt the hydrates in a reasonable amount of time (refer to Figures 3.6 and 3.7), then alternative means of hydrate remediation are necessary and will be recommended by the blockage response team. Step 6 – Hydrate Removal As soon as pressure communication is observed across the plug, methanol should be injected into the flowline (via one or more of the wells feeding that flowline). This will help ensure that residual hydrate in the flowline does not form another plug during displacement and will aid in melting the remaining hydrate. A total volume of about 50 barrels of methanol should be injected into the flowline prior to start-up. Step 7 – Dead-oiling Circulate dead-oil from Flowline 2 into Flowline 1. This moves residual hydrates closer to topsides, where blockages are easier to remediate if they form. Hot-oiling is preferred to dead-oiling, if it is available. Flowline PFL 03/04 This situation is similar to the general flowline plug case, except that there is an additional manifold (PM3) that needs to be taken into account. The flowlines should be configured as illustrated in Figure 3.10, in that Flowline 1 flows into either PFL 05 or 06 and Flowline 2 flows only into the other flowline (PFL 06 or 05). The Crossover Valve (XOV) at manifold PM3 is to remain closed during the remediation process. This will create a single large dual-flow loop that can be remediated using the procedures given for the other flowlines.

10

For instance, if the pressure is reduced to 7bar (100psi), it will take a hydrate plug (with the 702 fluid) about a day to melt; and if the pressure is only decreased to 14bar (200psi), it will take a hydrate plug about a month to melt. 11

15bar (215psi) for 702 or 9bar (130psi) for 710 Refer to Table 3.2 Figure 3.1.

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The case studies given in Appendix 3B Paragraph 2.0 give several examples where plugs have been safely remediated by depressurising the flowline at both ends. These examples are meant to illustrate the wide range of conditions that lead to hydrate 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 HDP and the plug melted. Particular note should be paid to the very well-documented case study of the ARCO hydrate plug. This plug formed in an insulated line and took 23 days to remediate once the pressure was reduced, and further reinforces that the removal 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 way as in the case of a hydrate plug in one of the flowlines. However, extra caution needs to be taken to ensure that the pressure at the base of Riser 1 is less than the pressure 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-sided depressurisation by aggressively blowing down Flowline 2. This will ensure that any plug movement is away from the FPSO. Figure 3.13 presents a flowchart for plug removal 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 depressurisation is used.

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Close in all wells flowing to affected manifold Treat jumper and wellbore by displacing 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).

Open PIV to equalise pressure in Flowlines 1 and 2

Begin blowdown of Flowline 2 (flowline without hydrate plug) to flare. Blow down Flowline 1 (flowline without hydrate plug) to LP separator

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)

Is the manifold pressure below HDP?

Use riser gas lift to further reduce the pressure in the flowline

Yes

Maintain pressure drop of 7 to 14bar (100 to 200psig) across the plug

No

Monitor pressure at the base of riser 1 (Prb-1) for signs of pressure communication (eg sudden pressure decrease)

Is there pressure communication across plug?

Yes

No

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 OPRM20030302D_052.ai

Figure 3.12 – Remediation Procedure for Hydrate Plug in Flowline

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Close in all wells flowing to affected manifold Treat jumper and wellbore by displacing with methanol Open PIV to equalise pressure in Flowlines 1 and 2

Begin blowdown of Flowline 2 (flowline without hydrate plug) to flare. Blow down Flowline 1 (flowline without hydrate plug) to LP separator

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

Use riser gas lift to further reduce the pressure. Note that this only applies to riser 2

Is the pressure at the base of riser 1 (Prb-1) below HDP?

Yes

Maintain pressure drop of 7 to 14bar (100 to 200psig) across the plug

No

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) Is there pressure communication across plug?

Yes

No

Inject 50 barrels of methanol into the flowline (via the gas lift riser). Start dead-oiling the flowline from Flowline 2 to Flowline 1 OPRM20030302D_053.ai

Figure 3.13 – Remediation Procedure for Hydrate Plug in Riser

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4.2

Wellbore Jumper and Manifold

4.2.1

Hydrate Plug Formation A hydrate plug in the jumper or manifold prevents flow from a particular well into the flowline. 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-in Bottomhole 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 be noticeable (since it will occur slowly). Note: The temperature must be in the hydrate formation region in order to form hydrates. 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 the pressure does not decrease as low as it would with only one well flowing to the manifold, 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 flowing into the flowline MIV 1

Methanol Line

XOV

MIV 2

ASV

PSV

Production Pressure Choke

AWV

Annulus

PWV PWV

SWV

Manifold

Outlet Pressure

PIV Hydrate Plug

WSV

WSV

SCSSV

Manifold Pressure

Downhole Pressure

Flowlines to FPSO

OPRM20030302D_066.ai

Figure 3.14 – Schematic of Hydrate Plate in Jumper

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Hydrate Plug Remediation 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 safety considerations, it should not be attempted unless the methanol remediation strategy 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 to the hydrate surface. In order to have a reasonable chance of getting methanol to the hydrate surface, the methanol should be ‘rocked’ into the jumper. This strategy has proved successful in the wellbore (refer to the Popeye case study), but has not been tried in a jumper. The flowchart shown in Figure 3.15 gives the steps to follow in order to use this methanol ‘rocking’ procedure. The first step is to isolate the affected jumper from the manifold 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 against hydrates. Once the well is protected, all valves should then be closed except for the SCSSV, Production Master Valve (PMV) and Sacrificial Wing Valve (SWV) and the choke. Use MIV2 to inject methanol into the jumper. Once the pressure (production and 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 to the discussion below).

(2)

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

(3)

For 60 to 90 minutes, monitor for blockage breach. Blockage breach may be indicated in several ways (refer to the discussion below). If the blockage is not breached, then open PWV (and drop the outlet pressure to the downhole pressure).

‘Rocking’ the methanol into the jumper is achieved by repeating these three steps many 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.

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Blockage breach may be indicated by a rapid pressure reduction during methanol injection or during the monitoring period; by a slow but significant pressure reduction during the monitoring period; or by a significant increase in the amount of methanol that 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 blockage breach, a blockage-breach test should be conducted in Step 1 of a ‘rock’. The blockage-breach test is: (1)

After completion of Step 3 of a ‘rock’ and closing of PWV, open WSV and observe 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 manifold pressure then blockage breach is indicated. Proceed to blockage-breach confirmation (Step 5).

(4)

If the well outlet pressure is about equal to the manifold pressure prior to opening WSV in Step 1, then it may not be clear whether the system behaves as described in Step 2 or Step 3. If this is the case, or it is not clear as to whether or not the blockage is breached for whatever reason, then MIV2 should be 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. Continue until 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 remaining hydrate debris into the manifold with (additional methanol and) well production. If production from the other wells was never stopped, the manifold should be warm and 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 an alternative remediation method. The alternative methods include: •

One-sided pressure reduction

•

Replacement of the jumper section

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

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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

Close MIV2

Monitor pressure at tree (outlet pressure) for any change for 60 to 90 minutes

Conduct a blockage-breach test every fourth cycle by opening the WSV

Did pressure decrease at tree?

Close PWV

Yes

Inject 20bbls of methanol into wellbore and jumper, then proceed to start-up procedures

No

Open PWV and relieve pressure in the jumper into wellbore OPRM20030302D_054.ai

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

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4.3

Wellbore/Tree (Upstream of Inhibitor Injection Point)

4.3.1

Hydrate Plug Formation 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 gauge increases to the SBHP, and the production and outlet pressures approach the manifold 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 being not fully open)

•

No change in production pressure as the choke opening is changed MIV 1

Methanol Line

MIV 2

XOV

ASV

PSV

Production Pressure Choke

AWV

Annulus

PWV

SWV Outlet Pressure

PWV

Jumper to Subsea Manifold Hydrate Plug

SCSSV Downhole Pressure

OPRM20030302D_067.ai

Figure 3.16 – Schematic of Hydrate Plug in Wellbore

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4.3.2

Unrestricted

Hydrate Plug Remediation If a plug is formed in the wellbore, two-sided depressurisation is not possible. Generally, one-sided pressure reduction is not recommended for wellbore blockages due to the difficulty of safe execution in the wellbore environment. ‘Rocking’ methanol into the well is recommended as the first means of removing the hydrate blockage. 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 the manifold. Production from the other wells does not need to be stopped immediately, but preparations should be made in case the hydrate plug cannot be easily removed. Open the SCSSV, PMV and the choke, and close all other valves (refer to Figure 3.16 for relevant valves). Use MIV2 to inject methanol into the well by opening PWV. Increase the production pressure until the maximum pressure is achieved (~345bar (5000psi) the rating of the tree) and then close MIV2 and monitor for blockage breach for approximately 60 to 90 minutes. Then slowly open the SWV to 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 established between the downhole pressure and the production pressure. Initially, the top of the wellbore may be filled with gas. The methanol can be used to remove the gas and fill the top section of the wellbore with liquid. This will prevent the plug from breaking free and having enough momentum to cause any damage at the tree. Therefore, during the first few pressure cycles, the pressure should only be decreased to 7bar (100psig) less than the last known SITP. When the wellbore is liquid filled, the pressure should begin to increase very quickly with the addition of only a small amount of methanol. Pressure communication can be detected by a sudden change in the production pressure, which may be either a sudden increase or decrease depending on when in the pressure cycle communication is established. The downhole pressure sensor should 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 increase once the hydrate blockage is breached. Once the blockage is breached and pressure communication is established between the 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) noted on 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 the Popeye case study). At Popeye, the plug took roughly a day to remove once the methanol ‘rocking’ procedure commenced. In other cases, such as at Auger, a coiled tubing unit had to be brought in to melt a hydrate blockage which was much larger than the one experienced at Popeye.

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Select affected well and close the WSV to isolate well from manifold

All valves should be closed, except the SCSSV, PMV and the choke

Open PWV and use MIV2 to inject methanol into the well

Inject methanol into the well until maximum flowline pressure is achieved

Close MIV2

Close SWV

Monitor wellbore pressure and watch for pressure communication for 60 to 90 minutes

Pressure communication?

Yes

Inject 50bbls of methanol into wellbore and proceed to well start-up procedures

No

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)

OPRM20030302D_055.ai

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

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4.4

Umbilicals

4.4.1

Hydrate Plug Formation

Unrestricted

The risk of hydrate formation in the umbilical lines is highest during times when there are large pressure fluctuations in the flowline. Many control system interlocks are put in place to prevent pressure fluctuation-induced hydrate formation in the umbilical lines. Examples of this include: Chemical Injection Valves (CIVs) have to be closed before reducing the choke and shutting in a well; CIVs automatically close when a well gets shut in etc). It should be noted that hydrate plugs in the umbilical might occur during steady-state operation due to pressure fluctuations created by slugging. These pressure fluctuations have the potential to push production fluids into the umbilical. Once production fluids are in the umbilical, it is relatively easy to form a hydrate plug due to the small diameter of the umbilical lines. Based on GoM experience, the formation of hydrate plugs in umbilical lines is fairly common. It should 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 followed and valves were opened/closed in the wrong order). A plug in one of the umbilical lines will be detected as an increase in the injection pressure 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 the umbilical lines. Hydrate Plug

MIV 1

Methanol Line

MIV 2

Production Pressure Choke

Annulus

PWV

SWV Outlet Pressure

PWV

Jumper to Subsea Manifold

SCSSV Downhole Pressure

OPRM20030302D_068.ai

Figure 3.18 – Schematic of Hydrate Plug in Umbilical Line

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4.4.2

Unrestricted

Hydrate Plug Remediation Since hydrate plugs formed in umbilicals are typically much smaller hydrate plugs, it may be possible to push them out by increasing the pressure on the upstream end of the plug. Similar to the procedure of methanol rocking to remove a hydrate plug in the jumper or wellbore, the chemical in the umbilical can be used to cycle the pressure up and down in an effort to remove the plug. Note: This strategy attempts to mechanically remove the hydrate plug and not to physically melt it as in all the other remediation strategies. The flowchart in Figure 3.19 shows the blockage clearing procedure steps. The pressure in the umbilical should be increased to 70bar (~1000psig) above the normal hydrostatic pressure in the umbilical. Then the pressure can be released from the chemical line but still kept above the flowline pressure. Since the chemical in the line is not likely to actually melt the hydrate, the time between cycles can be short (about 15 to 30 minutes). This process may be repeated several times. The likelihood of success using this method is small, but is much easier than other remediation options. If this strategy does not work, then the system must be depressurised. This will involve stopping production from all wells flowing to the affected manifold and blowing down the entire flowline. The first step is to assess how critical this particular chemical is to maintain the current production. If clearing the blockage can wait until the next planned shut-in, then that would be recommended. Once this is done, the plug in the umbilical can be melted using one-sided depressurisation. In this case there is much less of a safety concern associated with one-sided depressurisation due to the small size of the hydrate plug.

Relieve pressure in umbilical to hydrostatic pressure

Increase pressure in umbilical to maximum pressure and leave for 15 to 30 minutes

Did this clear blockage?

Yes

Inject chemical through the affected chemical line to fully clear blockage

No

If chemical line is critical to operating system, begin preparations to shut in and blow down flowlines

OPRM20030302D_056.ai

Figure 3.19 – Remediation Procedure for a Hydrate Plug in an Umbilical

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4.5

Gas Lift Riser

4.5.1

Hydrate Plug Formation

Unrestricted

The risk of forming a hydrate plug in the gas lift riser is highest during a shutdown and an aborted start-up. A plug in this section is detected by lack of gas flow in the riser and an increase in the gas lift riser topside pressure. Determining which pressure sensors are in communication with one another can help to localise the 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 base pressure sensor in the flowline. The hydrate plug is located between the two adjacent pressure sensors not in pressure communication. If the gas lift riser pressure and the gas lift riser topside pressure are equal, then the plug is between the gas lift riser pressure sensor and the flowline (refer to Figure 3.20). If the riser base pressure and the gas lift riser pressure are equal, then the plug is between the gas 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 the methanol injection point. There is a small risk that the plug is between the methanol injection point and the pressure sensor, but due to the small volume between these sections, this is highly 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 to remediate should it form12. Methanol Line

Gas Lift Riser

GLR Topside Pressure

To Production Riser

GLIV1 Gas Lift Riser Pressure GLIV2

Hydrate Plug

To Subsea Manifold

Flowline Riser Base Pressure

OPRM20030302D_069.ai

Figure 3.20 – Schematic of Hydrate Plug in Riser Gas Lift System (Between Methanol Line and Flowline) 12

Email from Sada Iyer, March 2003.

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Methanol Line

Gas Lift Riser

GLR Topside Pressure

GLIV1 Hydrate Plug

To Production Riser

Gas Lift Riser Pressure

GLIV2

To Subsea Manifold

Flowline Riser Base Pressure

OPRM20030302D_070.ai

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 be delivered to the riser, the flowline does not need to be blown down to remove a hydrate plug in the gas lift riser. Flow in the flowline will actually help to remove the plug 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 lift riser. It is assumed that the plug does not form between the gas lift riser pressure sensor and Gas Lift Injection Valve (GLIV) 1 or between the gas lift riser pressure sensor and the methanol injection point. If either of these cases occur, the following remediation methods will still work, but the pressure 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 these sections, there is not enough energy to move the plug any significant distance. If the plug is located downstream of the gas lift riser pressure sensor in the gas lift riser, 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 GLIV1 and then use the methanol line to pressurise the gas lift riser to the maximum pressure (pressure measured at the gas lift riser pressure). Maintain this pressure on the upstream end of the plug and monitor the rate at which methanol is being injected into the gas lift riser. If the hydrate plug is solid, then the methanol volume will be very near zero. If the plug is moving or is porous enough to allow methanol to flow through, then some finite volume of methanol is needed to maintain the pressure in the gas lift riser. If after 6 hours, the pressure in the riser section has not changed and the volume of methanol injected is zero, then this method is not likely to work. Conversely, if methanol continually needs to be injected into the gas lift riser, then eventually the plug will either be melted or pushed into the flowline.

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If increasing the pressure with methanol does not remove the hydrate plug, then the gas 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 is injected to pressurise the section between GLIV1 and GLIV2. The valve between the hydrate plug and the methanol-filled section (GLIV1) is then opened. Methanol can then be used to pressurise the section of the gas lift riser between the hydrate plug and GLIV2. At this point, the pressure on the methanol side of the plug should be greater than the flowline so that when the plug releases, it will move towards the flowline. If the plug does not release within 60 to 90 minutes, then the above process should be repeated. The time expected to remove a plug in the gas lift riser using 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 to Figure 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 riser should be increased (or decreased) to a pressure that is 14bar (200psig) greater than 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 pressure until it is slightly less than the gas lift riser topsides pressure. Repeat this process every 60 to 90 minutes until plug releases. The time required to remove a plug using this method should be in the order of a day. However, this case is less likely to succeed than the other gas lift riser scenario (refer to Figure 3.20) and other remediation techniques may be necessary.

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Close GLIV2 and open GLIV1

Close GLIV1 and GLIV2

Use methanol to maintain the maximum pressure in the gas lift riser

Open GLIV2 and depressurise 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

Close GLIV2

Inject methanol into gas lift riser to maximum pressure

Open GLIV1

Use methanol to increase gas lift riser pressure to maximum

Is the injected volume of methanol greater than zero?

No

Monitor the gas lift pressure for any sudden pressure decrease and/or communication with riser base pressure

Yes

Pressure equalisation within 60 to 90 minutes?

Yes

Start methanol injection and begin gas lift

No

Close GLIV1

Continue injecting methanol until plug releases

Open GLIV2 and depressurise the gas lift riser

OPRM20030302D_057.ai

Figure 3.22 – Remediation Procedure for a Hydrate Plug in the Gas Lift Riser (Between Methanol Line and the Flowline)

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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

Open GLIV1 to reduce pressure at gas lift riser to riser base pressure

Open GLIV2

Monitor gas lift pressure for any sudden pressure increase and/or communication with gas lift riser topside pressure

Pressure equalisation?

Yes

Start methanol injection and begin gas lift

No

Close GLIV1 and GLIV2

OPRM20030302D_061.ai

Figure 3.23 – Remediation Procedure for a Hydrate Plug in the Gas Lift Riser (Between Methanol Line and Topsides)

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4.6

Water Injection Wells

4.6.1

Hydrate Plug Formation

Unrestricted

The most likely scenario in which a plug may form in one of the water injector wells is during a shut-in, which is performed within a few days of initial start-up. Since the Bonga water injection wells are completed into the oil zone, it is possible for gas to migrate back into the well and accumulate where the temperature and pressure are in the hydrate stable region. This involves the occurrence of two situations, gas migration into the well (from the reservoir) and a leaking SCSSV that allows gas to migrate up to the tree. Although hydrates would form during shut-in, they would not be noticed until start-up. During water injection, there is no hydrate risk. The risk also decreases with time as more water is injected into the reservoir and the gas front is pushed further away from the wellbore, which will make migration less likely within the duration of shut-in. Based on experience at Petro-Canada, this problem of gas 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 the well (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 of the wellbore. 4.6.2

Hydrate Plug Remediation Due to the lack of remediation options for the water injection wells, every attempt should be made to minimise hydrates from forming. The best means for this is to ensure that the SCSSV is closed during shut-in. Unfortunately, the SCSSV is not gastight 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 reason to suspect gas migration into the well, the water injection should be started up as quickly 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 pressure can be increased in an attempt to move the plug below the SCSSV. In order to make sure that the plug is pushed back below the SCSSV, make sure that at least 50 to 150 barrels of water are flowed into the well. However, this is unlikely to be effective and may only create a more solid hydrate plug. If a plug is detected during start-up, then every attempt should be made to localise the plug and shut in the appropriate valves to prevent any further gas or hydrate from 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 Hydrate Remediation Guidelines

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Figure 3.24 – Schematic of Hydrate Plug in Water Injection Line

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Appendix 3A Pressure 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

Section 3 Appendix 3A Pressure Tags OPRM-2003-0302D

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Well No

Downhole Pressure

Production Pressure (Upstream of Choke)

Outlet Pressure (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 Section 3 Appendix 3A Pressure Tags OPRM-2003-0302D

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Production Flowlines

Manifold Pressure

Riser Base Pressure

Topside Pressure

Gas Lift Riser Pressure (between GLIV1 and GLIV2)

PFL 08

03-PT-800

04-PT-812

04-PIT-304

04-PT-804

31-PIT-013

PFL 09

03-PT-801

04-PT-813

04-PIT-324

04-PT-805

31-PIT-023

PFL 11

03-PT-802

04-PT-814

04-PIT-344

04-PT-806

31-PIT-033

PFL 12

03-PT-803

04-PT-815

04-PIT-364

04-PT-807

31-PIT-043

PFL 05

03-PT-804

04-PT-810

04-PIT-404

04-PT-802

31-PIT-063

PFL 06

03-PT-805

04-PT-811

04-PIT-384

04-PT-803

31-PIT-053

PFL 03

03-PT-806

N/A

N/A

N/A

N/A

702p9

PFL 04

03-PT-807

N/A

N/A

N/A

N/A

690p1

PFL 01

03-PT-808

04-PT-808

04-PIT-444

04-PT-800

31-PIT-083

PFL 02

03-PT-809

04-PT-809

04-PIT-424

04-PT-801

31-PIT-073

Well No

Production Manifold

710p1 710p2

PM1

Gas Lift Riser Topside Pressure

710p3 702p2 702p15 PM2 710p4 803p3 702p10 PM3 702p14 702p5 PM4

690p2

PM5

702p4

Table 3A.2 – Pressure Tags for Production Flowlines Section 3 Appendix 3A Pressure Tags OPRM-2003-0302D

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Well No

Injection Pressure

Inlet Pressure

690w1

01-PT-900

01-PT-901

690w4

01-PT-903

01-PT-904

702w1

01-PT-906

01-PT-907

702w2

01-PT-909

01-PT-910

702w4

01-PT-912

01-PT-913

702w5

01-PT-915

01-PT-916

702w6

01-PT-918

01-PT-919

702w9

01-PT-921

01-PT-922

710w1

01-PT-924

01-PT-925

702w8

01-PT-927

01-PT-928

710w3

01-PT-930

01-PT-931

803w2

01-PT-933

01-PT-934

803w4

01-PT-936

01-PT-937

R690w2

01-PT-939

01-PT-940

690w3

01-PT-942

01-PT-943

702w10

01-PT-945

01-PT-946

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

Section 3 Appendix 3A Pressure Tags OPRM-2003-0302D

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Appendix 3B Case Studies Table of Contents 1.0

HYDRATE FORMATION IN FLOWLINE ....................................................................50 1.1

2.0

3.0

4.0

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

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

HYDRATE REMOVAL IN WELL.................................................................................58 3.1

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

3.2

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

HYDRATE REMOVAL IN A CHEMICAL INJECTION LINE........................................60 4.1

Oregano...........................................................................................................60

Section 3 Appendix 3B Case Studies

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1.0

HYDRATE FORMATION IN FLOWLINE

1.1

Case Study: Popeye Taken from: AP Mehta et al, ‘Fulfilling the Promise of Low-dosage Hydrate Inhibitors: 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 the methanol and hence the flowline was operating in the hydrate region. What was observed during steady-state operation was that there was a slow gradual increase in the pressure drop along the flowline, which is attributed to the formation and accumulation of hydrates in the flowline. The figure below indicates variables that would typically be measured and that show an observable indication of hydrate formation. The pressure drop in the flowline shows a steady increase with the gas rate showing a steady decline. Since the formation of hydrates in this system was observable, actions could be taken to remove the hydrates before they accumulated sufficiently to form a hydrate plug.

Section 3 Appendix 3B Case Studies

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2.0

HYDRATE REMOVAL IN FLOWLINE

2.1

Case Study: Tahoe Taken from: AP Mehta, ‘Hydrate Plug Blockage and Remediation: Case Studies from Operations in the Gulf of Mexico’, EP 2001-3019. Where Tahoe Well #A4 experienced hydrate plugs in a 6in uninsulated flowline connecting the well to the Bud Platform at Main Pass 252 over a distance of 12 miles. This was part of the Tahoe Phase I development; in Tahoe Phase II, three additional gas wells and one oil well were added as subsea tiebacks to newly built facilities at Bud Lite, also at MP252. These new wells were also 6in, 12-mile, dual-uninsulated flowlines and were Shell’s first foray into deepwater subsea tieback development. The oil well Tahoe A3 has its own dedicated 4in x 8in pipe-in-pipe insulated flowlines. Hydrates have formed in all Tahoe gas lines at one point or the other, but each has been remediated quickly due to the ability of carrying out a two-sided depressurisation. A hydrate plug was also reported in March 1999 in the Tahoe oil line. How Methanol is injected on a continuous basis in the Tahoe gas lines to prevent hydrates. The expected sea-bottom temperature is 46°F (at a water depth of 1500ft), with pipeline pressures varying from 2500 to 3300psig. The subcoolings at Tahoe are on the order of 25 to 30°F, under normal flowing conditions. Hydrates are believed to have formed in Tahoe A4 due to failure of the methanol pump. Gradual pressure build-ups were observed in the gas line, but went unnoticed until a plug had formed. Alarms on the pressure monitors and pump were also not geared to pick up on the pump failure. In the case of the Tahoe A3 oil well, hydrate formation was more unexpected. Tahoe A3 was operating with a water cut of less than 1%. This was based upon a Base Sediment and Water (BS&W) of 10MBPD/flowline

–

Manifold temperature Tman – controlled by well flowrate; expected Tman > 49°C (120°F) in most cases

–

Flowline insulation – fixed in system selection

–

Line size – fixed in system selection

Base Case Based on this information, the base case was chosen to be: •

Qfl = 10MBPD

•

Tman = 49°C

•

Worst wax-related properties (B1 Well 803 sand deposition rates and B2ST3 well 702 sand Critical Wax Deposition Temperatures (CWDTs)

•

All flowlines studied

Sensitivity Studies •

Qfl = 5 and 20MBPD

•

Tman = 38 and 60°C

•

Low wax-related properties found in the partially biodegraded crudes (B1 Well 803 sand and B2ST3 Well 803 sand CWDTs as well as B2ST3 Well 803 sand deposition rates)

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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 and surveillance. The wax risks in the long flowlines (east of the FPSO) are minimal if the conditions are base case or better. Using Qfl > 10MBPD, Tman > 49°C, and worst-case wax properties, 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 pour point 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 strength under shut-in pipeline conditions. We expect that no pour point depressant will be required. These findings will be compared with those of chemical vendors when the chemical tender results become available.

1.3

Recommendations The wax deposition study has used Tman as a variable rather than connecting specific well production functions to manifold temperatures. For this reason, we recommend that a comparison be made of critical wax deposition temperatures to case-specific manifold and arrival temperatures based on production functions and wellbore thermal/hydraulic simulations. Frequent surveillance is recommended for the produced fluid wax properties to ensure that: •

The fluid is arriving above the critical wax deposition temperatures in each flowline

•

The produced fluid pour points have not increased

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BACKGROUND The wax-related properties of Bonga fluids have been assessed in several previous studies (Refs 12, 13 and 25). The testing was not comprehensive across all wells/sands, and some of the measurements were deemed to have high uncertainties (Ref 25). Table 4.1 lists the fluids that had some wax properties measured. Additional information is provided in Paragraph 4.0. Well

Sand

Comments

B1

670

Low wax content and pour point

B1

702

Low pour point; cloud point similar to B1 803; CWDT higher

B1

710

Pour point, wax content slightly below B1 803

B1

803

Highest wax properties (except CWDT) from B1, B2ST3 and B3ST samples

B2 ST3

702

Termed ‘kinetically inhibited’ but highest CWDT

B2 ST3

803

Termed ‘kinetically inhibited’ but high CWDT

B3 ST

690

Low wax content and pour point; cloud points lower than B2ST3 702 and 803

B3 ST

702

Limited data; low wax content and pour point

702 W6

709

Highest wax properties, based on limited volume of questionable sample

Table 4.1 – List of Bonga Fluids Whose Wax Properties Were Measured

2.1

Sample Selection for the Present Study Wax-related properties show a wide variation for Bonga fluids (Ref 25) and we therefore recommended that an expected worst-case fluid be identified and tested for wax deposition and pour point problems. As a general statement, the Bonga crude oils appear to be from the same oil family (private communications from Erik Tegelaar (SIEP-EPT-DE) and Nancy Utech (OGUS-OGUA)), and fluid property variations are largely caused by secondary alteration processes (eg biodegradation, water washing or gas stripping). Biodegradation has had a noticeable impact on the Bonga wax-related fluid properties (lowering wax content, pour points and cloud points). Therefore, the goal of the sample selection was to find a substantial volume of a non-biodegraded Bonga oil. At the time of the initial reports (Refs 12 and 25), the preferred fluid was expected to be B1 Well 803 oil, classified as ‘W0 – no biodegradation’. Subsequent to those reports, sample was obtained from 702W6 Well 709 sand (Ref 17). Tests on this showed low pour points (7 to 10°C) and higher cloud points (29 to 33°C) than the B1 Well 803 oil (21 to 24°C). However, the 709 oil was received as an emulsion with a rag layer; emulsion breaking and decanting left solids in the container that had to be removed with solvent rinses. Both the sample and the High Temperature Gas Chromatography (HTGC) analyses were reconstructed from the various sub-samples. In addition, only limited sample was available (blowdown of one 600cc SSB downhole sampling chamber). Owing to limited sample and questionable quality, no additional analyses of 702W6 Well 709 oil are currently possible.

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A sample of B1-Well 803 oil was found in storage in Nigeria and provided to Shell 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 properties at 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 point fluid (B1 803): HTGC, pour point, cloud point, kinetic wax deposition rate

–

Verify wax deposition strategy by comparing range of CWDTs to expected arrival temperatures of production flowlines; run HYSYS Wax Deposition for selected 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; also do pipeline restart tests if/when sample volumes become available (possibly get samples during unloading)

–

Model restart of high pour point fluid if required

–

Investigate effect of mixing oils at manifolds and topsides; determine if export oil should be treated for high pour point

Surveillance/Analysis –

Specify requirements for sample analysis during development drilling and as a part of surveillance after first oil

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PRODUCTION FLOWLINE LAYOUT AND PIPE CHARACTERISTICS The Bonga production concept brings all produced fluids from five Production Manifolds (PMs) to an FPSO located in the middle of the field. Each PM combines multiple wells with fluids from various pay sands. The West Field (ie west of the FPSO) consists of two Production Flowline Loops (PFLs), namely, PFL 8/9 and PFL 11/12 and the East Field consists of three PFLs, namely, PFL 1/2, PFL 3/4 and PFL 5/6. Since PFLs 3/4 and 5/6 are connected together, they are considered as one PFL for realistic wax deposition simulation. According to contractual specifications in the basis of design (Bonga Field Development Plan, 2001), all PFLs are 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.

West

East PFL 3/4

PFL 8/9

PFL 5/6

FPSO PFL 11/12 PFL 1/2

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 of 8.876in (22.6cm). The East PFLs range from 3.6 to 5.5 miles (5.8 to 8.8km) and the pipe 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 Lifted

PIP U Factor 2 (W/m -C)

Flowline Length (km)

21

0

22.6

No

1.063

8.8

Parr (bar)

WC (%)

PIP ID (cm)

Gas Lifted

PIP U Factor 2 (W/m -C)

Flowline Length (km)

21

0

22.6

No

1.063

1.8

Parr (bar)

WC (%)

PIP ID (cm)

Gas Lifted

PIP U Factor 2 (W/m -C)

Flowline Length (km)

21

0

27

No

1.101

5.8

West 10in PFL

East 12in PFL

Table 4.2 – Production Flowline Data Section 4 Production Flowline Wax Assessment

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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 cloud point and HTGC measurements, after which kinetic wax deposition rates were measured as input for the deposition studies. Appendix 4C contains all wax properties 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 noted previously, the 709 sand in well 702W6 looks as bad or slightly worse than B1 803 oil, but the 709 sample is questionable.) These data show that B1 803 oil is expected 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 and transport 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 in Refs 11 to 13 and 17. Major conclusions in those studies are that wax-related properties vary both between and within reservoirs. The primary cause of this variation is biodegradation, which metabolises paraffins and reduces cloud and pour points. 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 highest known 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/minimum pour points were measured according to the ASTM D5853-95 protocol. Cloud Point (°C) Well

B1

Sand

803

SAM ID

NIG-O-129A

WTC ID

6140

Gravity (API)

33.9

Cold Finger

HTGC

35.6

37.0

Pour Points (°C)

4/-7

Table 4.3 – Basic Properties of B1 803 Oil Table 4.4 compares cloud points for Bonga Main fluids measured or derived by Shell Global Solutions (and, previously, SEPTAR Flow Assurance) using consistent cold-finger and HTGC methods. B1 803 oil has the highest pour and cloud point values 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 812 oils. However, these values (29 to 32°C including both cold-finger and HTGC techniques) are lower than Bonga Main B1 803 oils. ASTM D97 pour points were 2 to 4°C, similar to B1 803 oil. HTGC data were uniformly lower for the Bonga SW 803 and 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.

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Pour Point (°C) Well

Pay Sand

SAM ID

B-3ST

690

NIG-O-88A

B-2ST3

702

NIG-O-85H

B-2ST3

803

NIG-O-84H

702W6

709

NIG-O-93X

B1

702

B1

803

ASTM D97

ASTM D5853

Cloud Point (°C) Cold Finger

HTGC

Thermo Model

15

24

18