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HSEHealth & Safety

Executive

Completion component reliability

Failure mode identification

Prepared by IDM Engineeringfor the Health and Safety Executive

OFFSHORE TECHNOLOGY REPORT

2001/061

HSEHealth & Safety

Executive

Completion component reliability

Failure mode identification

IDM EngineeringTorridon House

73-75 Regent QuayAberdeenAB11 5AR

United Kingdom

HSE BOOKS

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© Crown copyright 2002Applications for reproduction should be made in writing to:Copyright Unit, Her Majesty’s Stationery Office,St Clements House, 2-16 Colegate, Norwich NR3 1BQ

First published 2002

ISBN 0 7176 2244 4

All rights reserved. No part of this publication may bereproduced, stored in a retrieval system, or transmittedin any form or by any means (electronic, mechanical,photocopying, recording or otherwise) without the priorwritten permission of the copyright owner.

This report is made available by the Health and SafetyExecutive as part of a series of reports of work which hasbeen supported by funds provided by the Executive.Neither the Executive, nor the contractors concernedassume any liability for the reports nor do theynecessarily reflect the views or policy of the Executive.

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EXECUTIVE SUMMARY A study has been undertaken on behalf of the HSE by IDM Engineering Ltd, to determine the credible failure modes and their direct effects as associated with typical single and dual completion gas lift designs as utilised in the UK North Sea. The study has been undertaken with the understanding that both wellhead configurations would be analysed under normal operating conditions. No consideration was given for any installation, workover or abandonment activities in connection with the wells. To ensure that a typical wellhead and tree arrangement was modelled, vendor information in the form of general arrangement drawings and associated information was reviewed from various manufacturers. A representative single and dual completion model was generated from this information in conjunction with the expertise associated within the project team. In order to identify the key components and seal arrangements that required consideration during the FMECA, the primary gas path was charted for both representative models. Each model was then broken up into zones to help facilitate the FMECA. Primary, secondary and tertiary barriers (where appropriate) were then identified. With the aid of zone specific drawings the FMECA was carried out for each representative model. The FMECA was carried out up to the side pocket mandrels in the production tubing for completeness, however, the main focus of the study was above the dual bore upper packer separating the upper and lower A annulus. The results of the FMECA for the single and dual completion model are detailed in Appendix F & E respectively. Both FMECA’s highlighted failure modes with the potential to leak injection gas to the atmosphere. Further leak sources were identified arising from component/sealing arrangement failures. These failures could in turn, cause injection gas to leak into the B annulus and C annulus (single completion only).

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CONTENTS

1. OBJECTIVE .............................................................................................................. 1 2. INTRODUCTION...................................................................................................... 2

2.1. BACKGROUND ................................................................................................2 2.2. GAS LIFT ..........................................................................................................2 2.3. SINGLE AND DUAL COMPLETION GAS LIFT MODELS..............................3

3. REPRESENTATIVE MODELS................................................................................. 5

3.1. MODEL DESCRIPTION...................................................................................5 3.2. OPERATING PARAMETERS ..........................................................................6 3.3. MODEL BOUNDARIES....................................................................................6

3.3.1. Dual Completion Model Boundaries ...................................................6 3.3.2. Single Completion Model Boundaries.................................................7 3.3.3. General Model Boundaries...................................................................7

4. METHODOLOGY ..................................................................................................... 8

4.1. ASSUMPTIONS................................................................................................8 4.2. APPROACH......................................................................................................8

4.2.1. Representative Model Identification....................................................8 4.2.2. FMECA....................................................................................................9

5. RESULTS ............................................................................................................... 12

5.1. DUAL COMPLETION FMECA.......................................................................12 5.2. SINGLE COMPLETION FMECA....................................................................12

6. ACKNOWLEDGEMENTS....................................................................................... 13 7. REFERENCE LIST................................................................................................. 14 8. BIBLIOGRAPHY..................................................................................................... 16 9. GLOSSARY OF TERMS ........................................................................................ 18 10. FIGURES................................................................................................................ 19 APPENDIX A - PRIMARY GAS PATHS, WETTED CONTAINMENT ZONES, PRIMARY AND SECONDARY BARRIERS DUAL COMPLETION. .............................. 23 APPENDIX B - PRIMARY GAS PATHS, WETTED CONTAINMENT ZONES, PRIMARY AND SECONDARY BARRIERS SINGLE COMPLETION. .......................... 30 APPENDIX C - SEAL DESCRIPTIONS DUAL COMPLETION..................................... 35 APPENDIX D - SEAL DESCRIPTIONS SINGLE COMPLETION................................. 48 APPENDIX E - DUAL COMPLETION FMECA RESULTS ............................................ 58

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APPENDIX F - SINGLE COMPLETION FMECA RESULTS....................................... 146 APPENDIX G - DUAL COMPLETION MODEL DRAWINGS ...................................... 217 APPENDIX H - SINGLE COMPLETION MODEL DRAWINGS ................................... 239

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1. OBJECTIVE The objective of this study is to identify the failure modes that can lead to leakage of gas from representative single and dual completion gas lift wells.

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2. INTRODUCTION 2.1. BACKGROUND As part of normal offshore oil and gas operations gas can be injected into the production tubing of a well to assist in the recovery of the hydrocarbon fluids. A normal feature of this process is the mass of pressurised hydrocarbon gas that resides in the well annulus. The well annulus differs from typical topside process plant in that it does not have a means to vent or blowdown its inventory of gas in an emergency, only to contain the gas within the annulus its self. The mass of pressurised gas is typically in the range of 0.5 to 12 metric tonnes. The gas represents a considerable hazard to platform personnel through fire and explosion. Of ultimate interest is the magnitude of this risk. It must be noted that the hazard is created as a function of injecting gas into the well annulus. The hazard does not originate directly from the reservoir. Many continuous gas lift wells, will cease to flow if the supply of compressed gas from topside compression is lost. This study has been commissioned to identify typical failure modes associated with typical gas lift configurations. Ultimately a representative frequency of gas leakage from a typical gas lift well can be established. The purpose of this study is to develop a representative single and dual completion gas lift well and to identify typical failure modes associated with the equipment that is used in the well configuration. Results from this report will be used in future studies to identify failure and/or leakage rates for equipment used in these types of wells. 2.2. GAS LIFT Artificial lift is a commonly used methodology for enhancing reservoir recovery rates, gas lift being by far the most utilised technique. The principle of gas lift is to simply supplement the natural flow process of hydrocarbon fluids by adding additional gas into the produced fluid to reduce the hydrostatic head component and hence, the back pressure on the formation. There are essentially two different methods of gas lift, which are utilised offshore to enhance or stimulate wells to ensure recover well fluids:

• Continuous Gas Lift • Intermittent Gas Lift

Continuous gas lift is essential for wells, which under normal operating conditions would not flow. This is due to an ageing well which is off plateau, as a result the reservoir pressure having dropped considerably and/or increased viscosity of the hydrocarbon fluids. The injection gas is normally supplied in a closed loop system, the gas is fed from the gas separation, compression and drying (if necessary) process facilities to the well as required.

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The lift gas is normally injected down the annulus and into the production tubing through the side pocket mandrels. In certain circumstances, the gas is supplied via annulus tubing into the lower well annulus and injected into the production tubing string as before. The other less common concept is the intermittent gas lift system. This is used to produce low volumes of liquid (<350 stb/d) from wells with low Bottom Hole Flow Pressure (BHFP) (<0.1 psi/ft). In this case, the liquid is produced in slugs by periodically opening a motorized flowline valve and allowing the gas accumulated in the annulus to suddenly expand through the side pocket mandrels to surface, bringing the accumulated liquids with it. A standing valve is often used to prevent the gas from flowing into the formation. 2.3. SINGLE AND DUAL COMPLETION GAS LIFT MODELS The models used in this study will assume that continuous gas lift is required to maintain the flow of hydrocarbons under normal operating conditions. There are four basic configurations of gas lift well used in the UK sector of the North Sea, principally:

• Single Completion • Dual Completion • Single Tree Dual-String Completion • Concentric Completion

In the first, and simpler configuration (Figure 1), gas is routed through a wellhead annular valve and into the ‘A’ annulus. The gas passes through the annulus downhole safety valve (DHSV) located in the dual bore upper packer. The lower packer prevents gas from flowing further down the annulus. Gas is injected into the production tubing at various depths between upper and lower packers via the side packer mandrels. In this configuration the ‘A’ annulus is completely filled with gas from the tubing hanger to the lower side pocket mandrel. There is a facility for isolating the upper and lower ‘A’ annulus by closing the annulus DHSV. The more complex dual completion (Figure 2) routes the gas through an annulus wing valve mounted on the Christmas tree, down through the upper and lower master valves, and into the annulus pipe work via an in line DHSV, to a point directly below the dual bore upper packer. Gas is injected into the production tubing at various depths between upper and lower packers via the side pocket mandrels. In this configuration and, under normal operation only the lower ‘A’ annulus space between the upper and lower packers is filled with gas. The upper ‘A’ annulus contains completion fluid. (1)The single tree dual-string completion is essentially a hybrid between the single and dual completion designs. Similarly to the dual completion, annulus tubing is utilised to inject the gas into the lower well annulus below the dual bore upper packer. This removes the inventory of gas that would normally reside under the tubing hanger in a typical single completion design. The gas itself would still be injected via the A annulus. (1)(2)The concentric design, which also uses a single tress essentially, is a modified single completion design. Lift gas is injected through the tubing spool and down the annulus created by the addit ional casing string within the production casing.

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In order to represent the most onerous circumstances offshore, the single and dual completions models are considered further in this study.

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3. REPRESENTATIVE MODELS 3.1. MODEL DESCRIPTION (7)It is recognised that there are no standard representations of single or dual completion gas lift wells. As a consequence there are many configurations in terms of well layout and equipment design. Despite this, the general function of using gas to reduce the hydrostatic head on the production tubing and promote a flow of well fluids remains the same. The variations in configuration and design originate from three key areas.

1. Variability in basic design between the equipment manufacturers. 2. Variability of manufacturers design due to specification by operators. 3. Variability due to combining manufacturers equipment for the completion.

(4)It is not the intent of this study to represent all permutations of well equipment and layout. It is the intent to establish the associated failure modes with typical equipment configurations, layouts and operating conditions. To establish a representative model an industry-recognised standard has been applied to provide a common guideline. We consider that the same standard would be applied to the majority of completions found offshore. This results in a consistent link between a specific North Sea gas lift well and the representative model of one. The representative models for the single and dual completion models were developed from the review of a variety of general arrangement drawings, taking into account the various considerations discussed above. Figure 1 represents a schematic of the single completion considered for this study, the following features were considered:

• Gas is injected through the connection to one of the A annulus valves. • The annular valve adjacent to the gas injection point is automated (fail closed), and

linked accordingly to the ESD system. • A none active-wing valve on the tree have been included for the annulus. • A compact wellhead design was considered as opposed to separate tubing spools. • 9 5/8” casing is utilised for the production casing with a 7” liner downhole. • The production wing valve and upper master valve are automated (fail closed), and

linked accordingly to the ESD system. • Tie down bolts have been utilised for the tubing hanger to tubing spool. • A dual bore upper packer is utlised to separate the upper and lower annulus, with the

annulus DHSV installed within the packer body. Figure 2 represents a schematic of the dual completion considered for this study, the following features were considered:

• None active-wing valves on the tree have been included for both annulus and production.

• A compact wellhead design was considered as opposed to separate tubing spools. • 9 5/8” casing is utilised for the production casing with a 7” liner downhole. • A VR plug was modelled in the A annulus to model a particular case where there is

maintenance of an annular valve.

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• Both the annulus and production wing valves and upper master valves are automated (fail closed), and linked accordingly to the ESD system.

• Tie down bolts have been utilised for the tubing hanger to tubing spool. • A dual bore upper packer is utlised to separate the upper and lower annulus.

API standard 6A (seventeenth edition) has been used as the basis in the development of the representative models. The primary gas paths for the dual completion and single completion were then determined, key items providing boundaries for each zone were described using consistent terminology. (8) to (13)In order to facilitate the FMECA, the schematic drawings were split down into general area zones (see glossary) were described by linking these items in pairs (Appendix A & B). Drawings were then generated for each zone for the dual completion detailing all major components identified in Appendix A to facilitate the FMECA (Appendix G). Only the drawings of the major differences between the dual and single models were generated for the single completion arrangement as a result of duplication of similar components (Appendix H). In order to distinguish between the different types of polymeric/elastomeric sealing arrangements, for each zone the seals were colour coded according to the following regime.

• Red – Primary Active Seal • Blue – Secondary Active Seal • Black – Passive Seal

It should be noted that all metal to metal, threaded connections and components were considered but not highlighted on the drawings in the same way as the sealing arrangements above. 3.2. OPERATING PAR AMETERS The model considers dry gas composed of 95% Methane and the balance being a combination of Ethane and Propane. Gas well entry temperature is assumed circa 82°C with an entry pressure of 1500 psi. The model represents the normal continuous producing condition. Well intervention, work-over, inspection, test, maintenance operations, and any non-normal well conditions, including initiating events that do not originate from the well model, do not form part of this study. 3.3. MODEL BOUNDARIES 3.3.1. Dual Completion Model Boundaries The boundaries of the dual completion model are defined by:

• The gas line check valve. • Tree assembly including all major valves up to secondary (and where applicable

tertiary) seal barriers. • Well head up to the secondary seal barriers.

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• Annulus assembly up to the side pocket mandrels. • Secondary seal barriers. • Production tubing up to the production wing valve.

3.3.2. Single Completion Model Boundaries The boundaries of the single completion model are defined by:

• The gas line check valve. • Well head up to the secondary seal barriers. • Annulus assembly up to the side pocket mandrels. • Secondary seal barriers. • Production tubing up to the production wing valve.

3.3.3. General Model Boundaries The boundaries include some downhole components. This was because all secondary and tertiary barriers were considered. Failure of some primary barriers downhole, result in annulus spaces around the wellhead becoming wetted by gas. Subsequent barrier failure can then result in loss of containment topsides.

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4. METHODOLOGY 4.1. ASSUMPTIONS The model assumes the following points: -

• The production/operations group is responsible for well integrity under normal operating conditions.

• The individuals working on or around wellhead equipment are competent to do so. • The operator ensures suitable training and supervision (as appropriate) to all individuals

operating on or around the wellhead.

• A permit to work system is in place, applied and operating satisfactorily.

• The inspection function is effective in identifying non-normal events or situations.

• Maintenance brings the equipment into the As Good As New (AGAN) condition.

• The requirements of DCR – Well examination Legislation are being effectively applied.

• The initial suitability of the equipment is correct in terms of its design limits, and capability to withstand any reasonably foreseeable non-normal events.

• The well is performing within its specified operational parameters.

• All seals and containment components are suitable for typical gas lift tree ratings ie

(3,000, 5,000, 6000 psi etc).

• Lockdown bolts are used rather than a lockdown ring for the tubing hanger on both models.

• Gas lift is utilised to maintain continuous production.

• Equipment is compatible with the well fluids.

• Major accident events, misuse or negligence are not considered.

• (6)The downhole safety valves utilised in the single and dual completions are considered

to be tubing retrievable and not wireline retrievable. 4.2. APPROACH 4.2.1. Representative Model Identification Initially the primary gas routing was established, from the point at which the gas enters the tree, to a point where the gas and the well fluids leaves the tree.

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The primary gas paths for the dual completion and single completion were then determined, key items was described using a consistent terminology (Section 3). General area zones were described by linking these items into pairs. In order to ensure that the FMECA remains focused consideration has to be given to all sources of leakage; therefore there was a degree of overlap when looking at each zone in turn. This is highlighted in the FMECA results (Appendix E & F) in italics and ensures that there are no working joints (see glossary). (14) to (18Further examination of drawings was then undertaken to describe the primary, secondary and tertiary barriers (see glossary) as described in Appendix A & B. Once the location of the key mechanical joints and seals was complete, a description of each joint configuration and type was made. (3)(5)Seal descriptions and details of the following segments are described in Appendix C & D inclusive.

• Primary gas paths. • Components. • Wetted containment zones. • Primary, Secondary and where applicable tertiary barriers. • Mechanical joints. • Seal configurations.

All elastomeric/polymeric seals were categorised into the following types as a result of sealing arrangements being very different between manufacturers, even though the type of seal is similar.

• Compression • Parallel • Face

The preparation work was complete and the FMECA could commence. 4.2.2. FMECA (19)The FMECA was conducted in general accordance with BS 5760 part 5 (1991). Taking each zone in turn, the mechanical joints forming the barriers between the well fluids and atmosphere, (primary, secondary and tertiary) were examined in terms of their configuration, components and function. Using engineering knowledge and experience, the credible failure modes, their causes and their effect where discussed and recorded as appropriate. 4.2.2.1. Description Of FMECA Structure A sample FMECA worksheet is detailed in Figure 3. The worksheet is made up of several columns holding all the pertinent information discussed during the FMECA, a description of each column is detailed below. System – This is a defined set of components or an assembly that forms part of the overall gas lift well. The systems have been broken down and referenced as zones.

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Sub system - The sub systems are the major component assemblies associated with each zone. It is the sub systems that are subjected to the FMECA. Function – The function of each sub system is described in terms of its primary or foremost role. There can be more than one function for each sub system. Failure – This provides an outline as to where the credible failures are likely to occur within the sub system. This FMECA has focused on the mechanical joints and seal assemblies of the sub systems. For example ‘bonnet seal failure’ leads to one consideration as to the ways in which the seal can fail. Cause – This outlines the most likely reasons leading to failure. There can be several effects originating from a single cause. In the example of the ‘bonnet seal’ then as one example, the bolts may be incorrectly installed. Effect – Provides a description as to what is likely to occur to the mechanical joints and seal assemblies if the cause manifests itself. In the example of bolts being incorrectly installed, there may be several effects, depending upon either over tightening or under tightening the bolts. Symptoms – What evidence of the effect will exist? Would the symptom reveal the failure immediately or over a period of time? Would it be visible or audible to an operator? Or would the failure remain unrevealed perhaps for many years? For example where a joint has been incorrectly made perhaps using wrong materia ls or techniques, then it may remain undetected. The integrity of the joint is not to the design intent and it may remain as a weak point that we are not aware of until failure occurs (if it occurs at all). Mitigation – Prior to ranking the probability of occurrence, the normal or usual practices of design, construction, installation, commissioning and operations need to be considered. Only the primary mitigating factors are recorded. For example the use of ISO 9001 as a quality assurance standard requires that many aspects of design, manufacture, inspection and test are considered and formally managed. This does not guarantee that failures will not occur, but does provide confidence that the probability of occurrence should be reduced. The integrity and effectiveness of such standards, systems and procedures has not been considered. 4.2.2.2. Criticality Analysis Using a qualitative approach, each failure consequence was ranked in terms of its local effect. A single barrier primary seal failure that would result in a direct loss of containment is ranked as a high criticality. Conversely, failure of a primary barrier that results in a secondary barrier becoming wetted is considered to be less critical. The consequence is ranked at one of five levels. 5 – Full cross sectional area failure of a major barrier (seals or components) leading directly to loss of containment. 4 – Full cross sectional area failure of a minor barrier (seals or components) leading directly to loss of containment. 3 – Major seal failure, leading to loss of primary containment that should be detectable by an operator or the F&G systems if a subsequent seal fails and containment is lost.

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2 – Part seal failure, leading to a loss of primary containment that is unlikely to be detectable by an operator or the F&G systems if subsequent seals fail. 1 – Minor Seal failure, (perished, weeping) leading to a loss of primary containment that would wet the secondary barriers or cause a fugitive emission to atmosphere. Using a qualitative approach, each failure was ranked in terms of its probability of occurrence, when considering all assumptions of the model. The probability is ranked at one of five levels. 1 – Highly improbable, not considered to be realistic. 2 – Improbable, a rare one off event. 3 – Possible, known to have occurred previously. 4 – Probable, has been experienced on more than one occasion. 5 – Frequent, is a normal or regular occurrence for the situation. The criticality of each failure mode and effect was then detailed in the criticality section of Figure 3 in the format ‘consequence.probability’. This enables the screening of the less critical events and sets the seen for any future leak frequency analysis.

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5. RESULTS 5.1. DUAL COMPLETION FMECA The results of the FMECA for the dual completion model are detailed in Appendix E. It can be noted that even though the dual completion zone drawings (Appendix G) cover zones 1 to 20, the FMECA only covered down to the side pocket mandrels in the production tubing. This was carried out for completeness, the study was only concerned with any leakage in above the dual bore upper packer. The results dictated that even though the original focus was purely on the leakage of injection gas below the tubing hanger in the upper A annulus. There were some expected failure modes leading to potential leaks to atmosphere from the xmas tree and the wellhead configuration. Certain failure modes dictated leakage of injection gas into the B annulus providing additional potential leak sources to atmosphere. 5.2. SINGLE COMPLETION FMECA The results of the FMECA for the single completion model are detailed in Appendix F. It was noted that even though the equipment was simpler in construction than that of the dual completion, there were obvious similarities in the designs. As a result of this only the zones, which were significantly different between the two completion designs, were completed (Appendix H). Similarly to the dual completion the FMECA only covered down to the side pocket mandrels in the production tubing, again for completeness. The single completion pressurises both the upper and lower annulus as a result of injecting directly into the A annulus under normal operating conditions. The results highlighted that certain components/sealing arrangements in the dual completion model were secondary barriers, in the single completion model the same items became primary barriers. The same as the dual completion, there were some expected failure modes leading to potential leaks to atmosphere from the xmas tree and the wellhead configuration. Certain failure modes dictated that injection gas could not only leak into the B annulus but also the C annulus providing additional potential leak sources to atmosphere.

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6. ACKNOWLEDGEMENTS The authors would like to acknowledge the individuals who contributed to this study: Dr M Croft of The Robert Gordon University, Mr. J Da Costa of Hancoss Ltd. and Mr H Hopper of Subsea Well Technology Ltd.

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7. REFERENCE LIST

1. BLOWOUT RISK ANALYSIS OF GAS-LIFT COMPLETIONS Society of Petroleum Engineers Paper Report no.: SPE 20916, D D Grassick, P S Kallos, S Dean and S D J King, May 1992

2. DOWN HOLE SAFETY VALVE FOR CONCENTRIC COMPLETION

Society of Petroleum Engineers Paper Report No,: SPE 16536/1, J L Geyelin., 1987

3. THE IMPORTANCE OF CORRECT RUNNING AND HANDLING PROCEDURES FOR

PREMIUM TUBULAR GOODS Society of Petroleum Engineers Paper Report No,: SPE 16107, D E Walstad and D W Crawford, March 1987

4. PROCEDURES AND PRACTICES OF DUAL-COMPLETION DESIGN IN ABU DHABI Society of Petroleum Engineers Paper Report No,: SPE 17983, R F Gabort & G J Ghnelm, February 1997

5. EVALUATION OF PREMIUM TAPERED THREADED CONNECTIONS USING

FINITE ELEMENT ANALYSIS AND FULL-SCALE TESTING Society of Petroleum Engineers Paper Report No,: SPE 23904, A Hilbert & I A Kalli, February 1992

6. RADICAL SOLUTIONS REQUIRED: COMPLETIONS WITHOUT PACKERS AND

DOWNHOLE SAFETY VALVES CAN BE SAFE Society of Petroleum Engineers Paper Report No,: SPE 56934, C J Durham & C A Oaveley, September 1999

7. RISK ANALYSIS OF SINGLE AND DUAL-STRING GAS-LIFT COMPLETIONS

Society of Petroleum Engineers Paper Report No,: SPE 19281, D Grassick, P S Kallos, I J A Jardine & F J Doogan, 1990

8. Y BLOCK XMAS TREE & WELLHEAD LAYOUT, GAS LIFT SYSTEM

FMC Drawing No.: SD-4333-65

9. XMAS TREE & WELLHEAD LAYOUT, GAS LIFT SYSTEM FMC Drawing No.: SD-4333-70

10. SECTIONAL LAYOUT PLATFORM, WELLHEAD AND TREE ASSEMBLY FMC Drawing No.: DL-0931

11. WELLHEAD DUAL COMPLETION FMC Drawing No.: SK-1587

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12. WELLHEAD AND XMAS TREE, STANDARD COMPLETION Cooper Cameron Drawing No.: SK-177568-01

13. PLATFORM DRILLED PRODUCTION WELLHEAD ASSEMBLY DRAWING Cooper Cameron Drawing No.: LO-021811-01

14. CAMERON API GATE VALVES Cooper Cameron 1997

15. 1999-2000 CAMERON CATELOG Cooper Cameron 1999

16. CAMERON MBO ULTIBOWL WELLHEAD SYSTEM Cooper Cameron 1998

17. SSMC WELLHEAD SYSTEM Cooper Cameron 1998

18. CAMERON CONVENTIONAL SURFACE WELLHEADS Cooper Cameron 1998

19. RELIABILITY OF SYSTEMS, EQUIPMENT AND COMPONENTS. GUIDE TO FAILURE MODES, EFFECTS AND CRITICALITY ANALYSIS (FMEA AND FMECA) British Standards Institue Document No.: BS 5760 part 5, 1991.

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8. BIBLIOGRAPHY 1. COMPLETION DESIGN MANUAL

BP Exploration Vol 1, & 2

2. BP Exploration, Forties Artificial Lift Project, Shallow Gas Lift Course, 1989. 3. IN SITU MACHINING AND REPAIR OF CAMERON FC STYLE XMAS TREES

Society of Petroleum Engineers Drawing No.: SPE 19274/1, Bryne D, Terry Dr P

4. SHORT COURSE ON GAS LIFT PRINCIPLES AND EQUIPMENT.

Camco Training Department Study Guide, 1991

5. COMPLETION PRODUCTS Halliburton Second Edition.

6. MSC DRILLING ENGINEERING, MODULE 9, COMPLETION TECHNOLOGY.

The Robert Gordon University

7. WELL ENGINEERING DISTANCE LEARNING PACKAGE – WELLHEADS Shell Expro Version 1.00

8. WELL ENGINEERING DISTANCE LEARNING PACKAGE – COMPLETIONS Shell Expro Version 1.00

9. WELL SERVICES CO-ORDINATOR COMPETENCE COURSE, MODULE 1 Shell Expro Version 3, Jan 1996

10. PRODUCTION OPERATIONS WELL SERVICES GUIDE, ASPECTS OF WELL COMPLETION DESIGN, Shell International Exploration and Production B.V Document No.: EP 95-1811, Vol 2, Nov 1995.

11. SPECIFICATION FOR WELLHEAD AND CHRISTMAS TREE EQUIPMENT

American Petroleum Institute Document No.: API 6A 17th Ed , Nov 1999.

12. VAM CATALOG

Sumitomo Metals No. 940

13. SUMITOMO PRODUCTS FOR THE OIL AND GAS INDUSTRIES.

Sumitomo Metals

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14. HIGH ALLOY OCTG, NEW SM – SERIES Sumitomo Metals

15. TUBULAR CONNECTION DATA BOOK

Weatherford 1992

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9. GLOSSARY OF TERMS Term Description Primary Barrier Equipment or sealing arrangement providing

containment, which is in direct contact with either gas or hydrocarbon fluids, under normal operating conditions.

Secondary Barrier Equipment or sealing arrangement providing containment, in the event of a primary barrier failure under normal operating conditions.

Tertiary Barrier Equipment or sealing arrangement providing containment, in the event of a primary and secondary barrier failure under normal operating conditions.

Zone Each model is broken down into discrete manageable areas (zones) so that a detailed FMECA can be carried out.

Working Joint A joint or section, which defines the boundary of a zone. If the joint or section is not included within the adjacent zone, the FMECA would have not considered all permutations.

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10. FIGURES

CONTENTS

Page

Figure 1 Single Completion Gas Lift Well Schematic .......................................................... 20 Figure 2 Dual Completion Gas Lift Well Schematic ............................................................ 21 Figure 3 Sample FMECA Worksheet.................................................................................. 22

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Figure 1 Single Completion Gas Lift Well Schematic

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Figure 2 Dual Completion Gas Lift Well Schematic

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SYSTEM SUB-SYSTEM FUNCTION FAILURE CAUSE EFFECT SYMPTOMS MITIGATION CRITICALITY

Figure 3 Sample FMECA Worksheet

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APPENDIX A

PRIMARY GAS PATHS, WETTED CONTAINMENT ZONES, PRIMARY AND SECONDARY BARRIERS DUAL COMPLETION

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MAJOR COMPONENTS OF THE DUAL COMPLETION MODEL USING A DUAL BLOCK TREE ARRANGEMENT. Primary gas path 1.1 Gas line check valve 1.2 Annulus wing valve 1.3 Annulus upper master valve 1.4 Annulus lower master valve 1.5 Annulus bore tubing hanger 1.6 Annulus tubing & annulus tubing nipples 1.7 Annulus downhole safety valve 1.8 Annulus tubing 1.9 Annulus bore dual bore upper packer 1.10 Lower well annulus 1.11 Side Pocket Mandrels 1.12 Production tubing 1.13 Production bore dual bore upper packer 1.14 Production tubing 1.15 Production downhole safety valve 1.16 Production tubing and nipples 1.17 Production bore tubing hanger 1.18 Production lower master valve 1.19 Production upper master valve 1.20 Production wing valve HYDROCARBON (WETTED) CONTAINMENT ZONES (WELL IN PRODUCTION) Zone 1.1 – 1.2 Primary barrier components:

• Gas check valve • Connecting pipework • Annulus wing valve

Secondary barrier components – None Zone 1.2 – 1.3 Primary barrier components:

• Annulus wing valve • Annulus non-active wing valve, • Annulus bore, • Annulus upper master valve, • Annulus swab valve, • Chemical injection valve.

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Secondary barrier components:

• Tree cap

Zone 1.3 – 1.4 Primary barrier components:

• Annulus upper master valve • Annulus bore • Annulus lower master valve

Secondary barrier components – None Zone 1.4 –1.5 Primary barrier components:

• Annulus lower master valve, • Annulus bore, • Annulus bore tubing hanger


• Tubing spool to tree outer flange seal, • Tubing spool downhole chemical injection line, • Tubing spool downhole chemical injection point packing gland & tertiary outer block

assembly, • Tubing hanger tie down bolts and seals, • Tubing spool downhole safety valve control packing gland & tertiary outlet block

assembly, • Tubing spool to tubing hanger seal, • Tubing hanger downhole safety valve control upper packing gland, • Tubing hanger downhole chemical injection point upper packing gland. • Tubing spool downhole safety valve control line.


• Annulus bore Tubing hanger, • Annulus tubing & annulus tubing nipples

Secondary barrier components –

• Production casing, • Production casing hanger seal to tubing spool, • Upper annulus tubing spool inner valve, • Upper annulus tubing spool outer valve, • Upper annulus tubing spool monitor and vent assembly,

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• VR plug & tertiary valve(s), • Tubing hanger seal to tubing spool, • Tubing spool downhole chemical injection line, • Tubing spool downhole safety valve control line, • Tubing hanger downhole safety valve control line lower packing gland, • Tubing hanger downhole chemical injection line lower packing gland, • (Possible connection between tubing spool and casing spool.)

‘B’ and ‘C’ casing spool valves and associated equipment form tertiary barriers, and require primary and secondary failures before being subjected to gas. This would require a triple jeopardy event to realise a leak to the wellhead areas. These barriers are not considered further. Zone 1.6 –1.7 Primary barrier components:

• Annulus tubing & annulus tubing nipples • Annulus downhole safety valve.

Secondary Barrier Components - As per details for zone 1.5 – 1.6 Zone 1.7 – 1.8 Primary barrier components:

• Annulus downhole safety valve • Annulus tubing.


• Annulus tubing • Annulus bore dual bore upper packer.


• Annulus bore dual bore upper packer • Lower well annulus - 9 5/8” Casing • Side Pocket Mandrels • Chemical Injection line

Secondary barrier components-

• ‘B’ annulus (bore of intermediate casing) • Intermediate casing hanger to casing spool seal

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• Production casing hanger seal to the casing spool • ‘B’ annulus valve & upper annulus spool monitor and vent assembly • VR plug

Tertiary Barrier Components:

• ‘C’ annulus • Tertiary valve(s)


• Side Pocket Mandrels • Production tubing

Secondary barrier components – Not applicable – gas already in annulus as function of gas lift. Zone 1.12 – 1.13 Primary barrier components:

• Production tubing, • Production bore dual bore upper packer

Secondary barrier components – Not applicable – gas already in annulus as function of gas lift. Zone 1.13 – 1.14 Primary barrier components:

• Production bore dual bore upper packer, • Production tubing.

Secondary barrier components – As per details for zone 1.5 – 1.6 Zone 1.14 – 1.15

• Production tubing, • Production downhole safety valve

Secondary barrier components – As per details for zone 1.5 – 1.6 Zone 1.15 – 1.16 Primary barrier components:

• Production downhole safety valve, • Production tubing and nipples.

Secondary barrier components – As per details for zone 1.5 – 1.6

28

Zone 1.16 – 1.17

Primary barrier components:

• Production tubing and nipples, • Production bore tubing hanger.

Secondary barrier components – As per details for zone 1.5 – 1.6 Zone 1.17 – 1.18 Primary barrier components:

• Production bore tubing hanger, • Production bore, • Production lower master valve.


• Tubing spool to tree outer flange seal, • Tubing spool downhole chemical injection line, • Tubing spool downhole chemical injection line packing gland & tertiary outer block


assembly, • Tubing spool to tubing hanger seal, • Tubing hanger downhole safety valve control packing gland, • Tubing hanger downhole chemical injection point packing gland, • Tubing spool downhole safety valve control line.


• Production lower master valve, • Production bore, • Production upper master valve.

Secondary barrier components – None Zone 1.19 – 1.20


• Production upper master valve, • Production bore, • SWAB valve, • Chemical injection valve, • Production wing valve, • Production non-active wing valve.

29


• Tree cap

30

APPENDIX B

PRIMARY GAS PATHS, WETTED CONTAINMENT ZONES, PRIMARY AND SECONDARY BARRIERS SINGLE

COMPLETION

31

MAJOR COMPONENTS OF THE SINGLE COMPLETION MODEL USING A SINGLE BLOCK TREE ARRANGEMENT Primary gas path 2.1 Gas line check valve 2.2 Tubing spool side valve 2.3 Upper well annulus 2.4 Annulus downhole safety valve in the dual bore packer 2.5 Lower well annulus 2.6 Side Pocket Mandrels 2.7 Lower production tubing 2.8 Production bore dual bore upper packer 2.9 Upper production tubing 2.10 Production downhole safety valve 2.11 Production tubing and nipples 2.12 Production bore tubing hanger 2.13 Production lower master valve 2.14 Production upper master valve 2.15 Production wing valve

HYDROCARBON (WETTED) CONTAINMENT ZONES (WELL IN PRODUCTION) Zone 2.1 – 2.2 Primary barrier components:

• Gas check valve, • Connecting pipework, • Tubing spool side valve.

Secondary barrier components – None Zone 2.2 – 2.3 Primary barrier components:

• Tubing spool side valve, • Tubing spool to tubing hanger seal, • Tubing spool to casing hanger seal, • Production tubing to tubing hanger seal, • Upper well annulus, • Tubing hanger body, • Tubing hanger downhole safety valve control line lower packing gland, • Tubing hanger downhole chemical injection line lower packing gland, • Tubing spool downhole chemical injection line, • Tubing spool downhole safety valve control line, • Production tubing, • Tubing spool side valve, • Upper annulus tubing spool and monitoring assembly.

32


• Tubing hanger tie down bolts, • Tubing hanger down hole safety valve control line upper packing gland, • Tubing hanger down hole chemical injection line upper packing gland, • Tubing spool to tree outer flange seal, • Tubing hanger downhole safety valve control packing gland & tertiary block assembly, • Tubing hanger downhole chemical injection packing gland & tertiary block assembly, • Tubing spool downhole chemical injection line, • Tubing spool downhole safety valve control line.


• Upper well annulus, • Annulus downhole safety valve, • Production tubing,

Secondary barrier components -

• B Annulus Casing, • B Annulus Tubing Spool Valves, • Upper annulus tubing spool monitor and vent assembly, • B annulus tubing spool to casing hanger seal.

Zone 2.4 – 2.6


• Annulus downhole safety valve, • Dual bore upper packer, • Lower well annulus (9 5/8"), • Side Pocket Mandrels (SPM), • Chemical Injection Line.

Secondary barrier components – • ‘B’ annulus (bore of intermediate casing), • Intermediate casing hanger to casing spool seal, • Tertiary seal is the ‘C’ annulus, • Production casing hanger seal to the casing spool, • ‘B’ annulus valve & upper annulus spool monitor and vent assembly.

Zone 2.6 – 2.8


• Side packer mandrels, • Lower production tubing, • Production bore dual bore upper packer

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• Not Applicable (gas already in annulus as a function of gas lift)

Zone 2.8 – 2.9

Primary barrier components: • Production bore dual bore upper packer, • Upper production tubing.



Zone 2.9 – 2.10


• Upper production tubing, • Production downhole safety valve.

Secondary barrier components – • Not Applicable (gas already in annulus as a function of gas lift)

Zone 2.10 – 2.11





Zone 2.11 – 2.12

Primary barrier components: • Production tubing and nipples, • Tubing hanger.

Secondary barrier components – • Not Applicable (gas already in annulus as a function of gas lift)

34

Zone 2.12 – 2.13

Primary barrier components: • Tubing hanger, • Production bore, • Production lower master valve.

Secondary barrier components – • Tubing spool to tree outer flange seal, • Tubing spool downhole chemical injection line, • Tubing spool downhole chemical injection point packing gland & tertiary outer block


assembly, • Tubing spool to tubing hanger seal, • Tubing hanger downhole safety valve control packing gland, • Tubing hanger downhole chemical injection point packing gland. • Tubing spool downhole safety valve control line.

Zone 2.13 – 2.14

Primary barrier components: • Production lower master valve • Production bore, • Production upper master valve

Secondary barrier components – None

Zone 2.14 – 2.15


• Production upper master valve • Production bore, • SWAB valve, • Chemical injection valve • Production wing valve • Production non-active wing valve.

Secondary barrier components – • Tree Cap

35

APPENDIX C

SEAL DESCRIPTIONS DUAL COMPLETION

36

SEAL DESCRIPTIONS FOR EACH ZONE - DUAL COMPLETION Zone 1.1 – 1.2 Primary barrier components: -

• Gas check valve, • Connecting pipework, • Annulus wing valve.

1.0 Gas Check Valve (Fail Closed) - (open) 1.1 Bonnet Seal (compression, bolts) 1.2 Ring gasket (compression, bolts) 2.0 Connecting Pipework 2.1 Ring Gasket (compression, bolts) 3.0 Annulus Wing Valve (Fail Closed) – Floating Gate (open) 3.1 Bonnet Seal (compression, bolts) 3.2 Stem Seal (parallel, screw cap) 3.3 Grease fitting (compression screw thread) Secondary barrier components: – None Zone 1.2 – 1.3 Primary barrier components: -

• Annulus wing valve, • Annulus non-active wing valve, • Annulus bore, • Annulus upper master valve, • Annulus swab valve, • Chemical injection valve.

1.0 Annulus Wing Valve (Fail Closed) – Floating Gate (open) 1.1 Bonnet Seal (compression, bolts) 1.2 Stem Seal (parallel, screw cap) 1.3 Grease fitting (compression screw thread) 1.4 Ring Gasket (compression, bolts) 2.0 Annulus Bore 2.1 Tree Block 3.0 Annulus Upper Master Valve (Fail Closed) – Floating Gate (open) 3.1 Bonnet Seal (compression, bolts) 3.2 Stem Seal (parallel, screw cap) 3.3 Grease fitting (compression screw thread) 4.0 Annulus SWAB Valve (Manual) – Floating Gate (closed) 4.1 Gate Seal (face, pressure) 4.2 Seat Seal (face, pressure) 4.3 Bonnet Seal (compression, bolts)

37

4.4 Back Seat (face, pressure) - ineffective 4.5 Stem seal (grease fitting secondary barrier) 5.0 Chemical Injection Valve (open) 5.1 Single Cartridge Dual Check Valve (metal to metal nose joint, threaded) 5.2 CI Valve - Bonnet Assembly (screw cap, threaded) 5.3 CI Valve - Stem packing 5.4 CI Valve - Ring Gasket (compression, bolts) 6.0 Annulus non-active wing va lve (Manual) – Floating Gate (closed) 6.1 Gate Seal (face, pressure) 6.2 Seat Seal (face, pressure) 6.3 Bonnet Seal (compression, bolts) 6.4 Back Seat (face, pressure) - ineffective 6.5 Stem seal (grease fitting secondary barrier) Secondary barrier components: – Tree cap 7.0 Tree Cap 7.1 Tree Cap (parallel, screw cap) 7.2 Test Port (compression, screw threads) Zone 1.3 – 1.4 Primary barrier components: -

• Annulus upper master valve, • Annulus bore, • Annulus lower master valve.

1.0 Annulus Upper Master Valve (Fail Closed) – Floating Gate (open) 1.1 Bonnet Seal (compression, bolts) 1.2 Stem Seal (parallel, screw cap) 1.3 Grease fitting (compression screw thread) 2.1 Annulus Bore 2.1 Tree Body 3.0 Annulus Lower Master Valve (Manual) – Floating Gate (open) 3.1 Bonnet Seal (compression, bolts) 3.2 Stem Seal (parallel, screw cap) 3.3 Grease fitting (compression screw thread) Secondary barrier components – None Zone 1.4 –1.5 Primary barrier components: -

• Annulus lower master valve, • Annulus bore, • Annulus bore tubing hanger.

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1.0 Annulus Lower Master Valve (Manual) – Floating Gate (open) 1.1 Bonnet Seal (compression, bolts) 1.2 Stem Seal (parallel, screw cap) 1.3 Grease fitting (compression screw thread) 2.0 Annulus Bore 2.1 Tree Body 2.2 Bore Sleeve (parallel, main fixing bolts for tree) 3.0 Annulus bore tubing hanger 3.1 Hanger Body Secondary barrier components: –



assembly, • Tubing spool to tubing hanger seal, • Tubing hanger downhole safety valve control upper packing gland, • Tubing hanger downhole chemical injection point upper packing gland, • Tubing spool downhole safety valve control line.

4.0 Tubing spool to tree outer flange seal 4.1 Ring Gasket (compression, main fixing bolts for tree) 5.0 Tubing spool downhole chemical injection line 5.1 Chemical Injection Line Integrity 6.0 Tubing spool downhole chemical injection point packing gland & tertiary outer block

assembly 6.1 Packing Gland (tertiary seal - outer block assembly seal (compression, bolts), Gland to

Line Seal) 6.2 Gland to Tubing Spool Seal 7.0 Tubing hanger tie down bolts and seals 7.1 Bolt Seals (Compression, screw) 8.0 Tubing spool downhole safety valve control packing gland & tertiary outlet block


Line Seal) 8.2 Gland to Tubing Spool Seal 9.0 Tubing spool to tubing hanger seal 9.1 Tubing spool annulus Seal (parallel, lockdown) 10.0 Tubing hanger downhole safety valve control line upper packing gland 10.1 Tubing hanger downhole safety valve control line upper packing gland (compression,

screw)

39

11.0 Tubing hanger downhole chemical injection line upper packing gland 11.1 Tubing hanger downhole chemical injection point upper packing gland (compression,

screw) 12.0 Tubing spool downhole safety valve control line 12.1 Downhole safety valve control line Integrity Zone 1.5 – 1.6 Primary barrier components: -

• Annulus bore - tubing hanger, • Annulus tubing & annulus tubing nipples.

1.0 Annulus bore tubing hanger 1.1 Tubing Hanger Body 1.2 Premium Tapered Tubing Connection 2.0 Annulus tubing & annulus tubing nipples 2.1 Tubing 2.2 Annulus Tubing Nipples 2.3 Premium Tapered Tubing Connection Secondary barrier components –

• Production casing, • Production casing hanger seal to tubing spool, • Upper annulus tubing spool inner valve, • Upper annulus tubing spool outer valve, • Upper annulus tubing spool monitor and vent assembly, • VR plug & tertiary valve(s), • Tubing hanger seal to tubing spool, • Tubing spool downhole chemical injection line, • Tubing spool downhole safety valve control line, • Tubing hanger downhole safety valve control line lower packing gland, • Tubing hanger downhole chemical injection line lower packing gland, • (Possible connection between tubing spool and casing spool).

‘B’ and ‘C’ casing spool valves and associated equipment form tertiary barriers, and require primary and secondary failures before being subjected to gas. This would require a triple jeopardy event to realise a leak to the wellhead areas. These barriers are not considered further. 3.0 Production casing 3.1 Production Pipe 3.2 Premium Casing Threads 4.0 Production casing hanger seal to tubing spool 4.1 Production casing hanger seal to casing spool (parallel, lockdown) 5.0 Upper annulus tubing spool inner valve (Manual) (open) – well producing, open

valves to take a sample 5.1 Ring Gasket (compression, bolts)

40

5.2 Bonnet Seal (compression, bolts) 5.3 Stem Seal (parallel, screw cap) 5.4 Grease fitting (compression, screw thread) 6.0 Upper annulus tubing spool monitor and vent assembly 6.1 Ring Gasket (compression, bolts) 6.2 Needle Valve (compression, screw) 7.0 VR plug & tertiary valve(s) 7.1 VR Plug (parallel, screw) (tertiary seal – manual gate valves) 8.0 Tubing hanger seal to tubing spool 8.1 Tubing spool annulus Seal (parallel, lockdown) 9.0 Tubing spool downhole chemical injection line 9.1 Chemical Injection Line Integrity 10.0 Tubing spool downhole safety valve control line 10.1 Downhole safety valve control line Integrity 11.0 Tubing hanger downhole safety valve control line lower packing gland 11.1 Tubing hanger downhole safety valve control line lower packing gland (compression,

screw) 12.0 Tubing hanger downhole chemical injection line lower packing gland 12.1 Tubing hanger downhole chemical injection point lower packing gland (compression,

screw) Zone 1.6 –1.7 Primary barrier components: -

• Annulus tubing & annulus tubing nipples, • Annulus downhole safety valve.

1.0 Annulus tubing & annulus tubing nipples 1.1 Annulus Tubing 1.2 Annulus Tubing Nipples 1.3 Premium Tapered Tubing Connection 2.0 Annulus downhole safety valve (ADHSV Fail Closed) - (open) 2.1 Premium tapered tubing connection 2.2 Valve body 2.3 Valve piston/control line seal Secondary barrier components:- As per details for zone 1.5 – 1.6 Zone 1.7 – 1.8 Primary barrier components: -

• Annulus downhole safety valve, • Annulus tubing.

41

1.0 Annulus downhole safety valve (ADHSV Fail Closed) - (open) 1.1 Premium tapered tubing connection 1.2 Valve body 1.3 Valve piston/control line seal 2.0 Annulus Tubing 2.1 Annulus Tubing 2.2 Premium Tapered Tubing Connection Secondary barrier components: - As per details for zone 1.5 – 1.6 Zone 1.8 – 1.9 Primary barrier components: -

• Annulus tubing, • Annulus bore dual bore upper packer, • Tubing spool downhole chemical injection line, • Dual bore upper packer chemical injection line upper packing gland.

1.0 Annulus Tubing 1.1 Annulus Tubing 1.2 Premium Tapered Tubing Connection 2.0 Annulus bore dual bore upper packer 2.1 Packer body 2.2 Premium Tapered Tubing Connection Secondary barrier components: - As per details for zone 1.5 – 1.6 3.0 Tubing spool downhole chemical injection line 3.1 Chemical Injection Line Integrity 4.0 Dual bore upper packer chemical injection line upper packing gland 4.1 Dual bore upper packer chemical injection point upper packing gland (compression,

screw) Zone 1.9 – 1.11 Primary barrier components: -

• Annulus bore dual bore upper packer, • Chemical injection line, • Lower well annulus, • Side Pocket Mandrels.

1.0 Annulus bore dual bore upper packer 1.1 Packer body 1.2 Premium Tapered Tubing Connection 2.0 Lower well annulus – 9 5/8” Casing 2.1 Annulus Tubing

42

2.2 Premium Tapered Tubing Connection 2.3 Production casing 3.0 Side Pocket Mandrels (SPM) 3.1 SPM body 3.2 Orifice Valve (parallel) 4.0 Chemical Injection Line 4.1 Chemical Injection Line pipe 4.2 Chemical injection line connection at bottom of dual bore upper packer Secondary barrier components: -

• ‘B’ annulus (bore of intermediate casing) • Intermediate casing hanger to casing spool seal • Tertiary seal is the ‘C’ annulus • Production casing hanger seal to the casing spool • ‘B’ annulus valve & upper annulus spool monitor and vent assembly • VR plug & tertiary valve(s)

Zone 1.11 – 1.12 Primary barrier components: -

• Side Pocket Mandrels, • Production tubing..

1.0 Side Pocket Mandrels (SPM) 1.1 SPM body 1.2 Orifice Valve (parallel) 2.0 Production tubing 2.1 Production Tubing 2.2 Premium Tapered Tubing Connection Secondary barrier components – Not applicable – gas already in annulus as function of gas lift. Zone 1.12 – 1.13 Primary barrier components: -

• Production tubing, • Production bore dual bore upper packer.

1.0 Production tubing 1.1 Tubing 1.2 Premium Tapered Tubing Connection 2.0 Production bore dual bore upper packer 2.1 Packer body

43

2.2 Premium Tapered Tubing Connection Secondary barrier components – Not applicable – gas already in annulus as function of gas lift. Zone 1.13 – 1.14 Primary barrier components: -

• Production bore dual bore upper packer, • Production tubing.

1.0 Production bore dual bore upper packer 1.1 Packer body 1.2 Premium Tapered Tubing Connection 2.0 Production tubing 2.1 Tubing 2.2 Premium Tapered Tubing Connection Secondary barrier components – As per details for zone 1.5 – 1.6 Zone 1.14 – 1.15 Primary barrier components: -

• Production tubing, • Production downhole safety valve.

1.0 Production tubing 1.1 Tubing 1.2 Premium Tapered Tubing Connection 2.0 Production downhole safety valve (Fail Closed) - (open) 2.1 Premium tapered tubing connection 2.2 Valve body 2.3 Valve piston/control line seal Secondary barrier components – As per details for zone 1.5 – 1.6 Zone 1.15 – 1.16 Primary barrier components: -


1.0 Production downhole safety valve (Fail Closed) - (open) 1.1 Premium tapered tubing connection 1.2 Valve body 1.3 Valve piston/control line seal

44

2.0 Production tubing and nipples 2.1 Production Tubing 2.2 Production Tubing Nipples 2.3 Premium Tapered Tubing Connection Secondary barrier components – As per details for zone 1.5 – 1.6 Zone 1.16 – 1.17 Primary barrier components: -

• Production tubing and nipples, • Production bore tubing hanger.

1.0 Production tubing and nipples 1.1 Production Tubing 1.2 Production Tubing Nipples 1.3 Premium Tapered Tubing Connection 2.0 Production bore tubing hanger 2.1 Tubing Hanger Body 2.2 Premium Tapered Tubing Connection Secondary barrier components – As per details for zone 1.5 – 1.6 Zone 1.17 – 1.18 Primary barrier components: -

• Production bore tubing hanger, • Production bore, • Production lower master valve.

1.0 Production bore tubing hanger 1.1 Tubing Hanger Body 1.2 Premium Tapered Tubing Connection 2.0 Production bore 2.1 Bore Sleeve (parallel, main fixing bolts for tree) 2.2 Tree Body 3.0 Production Lower Master Valve (Manual) – Floating Gate (open) 3.1 Grease fitting (compression screw thread) 3.2 Stem Seal (parallel, screw cap) 3.3 Bonnet Seal (compression, bolts) Secondary barrier components –

• Tubing spool to tree outer flange seal, • Tubing spool downhole chemical injection line, • Tubing spool downhole chemical injection line packing gland & tertiary outer block

assembly, • Tubing hanger tie down bolts and seals,

45

• Tubing spool downhole safety valve control packing gland & tertiary outlet block assembly,

• Tubing spool to tubing hanger seal, • Tubing hanger downhole safety valve control line upper packing gland, • Tubing hanger downhole chemical injection point upper packing gland, • Tubing spool downhole safety valve control line.

4.0 Tubing spool to tree outer flange seal 4.1 Ring Gasket (compression, main fixing bolts for tree) 5.0 Tubing spool downhole chemical injection line 5.1 Chemical Injection Line Integrity 6.0 Tubing spool downhole chemical injection line packing gland & tertiary outer block


Line Seal) 6.2 Gland to Tubing Spool Seal 7.0 Tubing hanger tie down bolts and seals 7.1 Bolt Seals (Compression, screw) 8.0 Tubing spool downhole safety valve control packing gland & tertiary outlet block


Line Seal) 8.2 Gland to Tubing Spool Seal 9.0 Tubing spool to tubing hanger seal 9.1 Tubing spool production Seal (parallel, lockdown) 10.0 Tubing hanger downhole safety valve control line upper packing gland 10.1 Tubing hanger downhole safety valve control upper packing gland (compression,

screw) 11.0 Tubing hanger downhole chemical injection line upper packing gland 11.1 Tubing hanger downhole chemical injection point upper packing gland (compression,

screw) 12.0 Tubing spool downhole safety valve control line 12.1 Downhole safety valve control line Integrity Zone 1.18 – 1.19 Primary barrier components: -

• Production lower master valve, • Production bore, • Production upper master valve.

1.0 Production lower master valve (Manual) – Floating Gate (open) 1.1 Bonnet Seal (compression, bolts) 1.2 Stem Seal (parallel, screw cap)

46

1.3 Grease fitting (compression screw thread) 2.0 Production bore 2.1 Tree Body 3.0 Production upper master valve (Fail Closed) – Floating Gate (open) 3.1 Bonnet Seal (compression, bolts) 3.2 Stem Seal (parallel, screw cap) 3.3 Grease fitting (compression screw thread) Secondary barrier components – None Zone 1.19 – 1.20 Primary barrier components: -

• Production upper master valve, • Production bore, • Swab valve, • Chemical injection point, • Production wing valve, • Production non-active wing valve.

1.0 Production Wing Valve (Fail Closed) – Floating Gate (open) 1.1 Bonnet Seal (compression, bolts) 1.2 Stem Seal (parallel, screw cap) 1.3 Grease fitting (compression screw thread) 1.4 Ring Gasket (compression, bolts) 2.0 Production Bore 2.1 Tree Block 3.0 Production Upper Master Valve (Fail Closed) – Floating Gate (open) 3.1 Bonnet Seal (compression, bolts) 3.2 Stem Seal (parallel, screw cap) 3.3 Grease fitting (compression screw thread) 4.0 Production SWAB Valve (Manual) – Floating Gate (closed) 4.1 Gate Seal (face, pressure) 4.2 Seat Seal (face, pressure) 4.3 Bonnet Seal (compression, bolts) 4.4 Back Seat (face, pressure) - ineffective 4.5 Stem seal (grease fitting secondary barrier) 5.0 Chemical Injection Valve (open) 5.1 Single Cartridge Dual Check Valve (metal to metal nose joint, threaded) 5.2 CI Valve - Bonnet Assembly (screw cap, threaded) 5.3 CI Valve - Stem packing 5.4 CI Valve - Ring Gasket (compression, bolts) 6.0 Production non-active wing valve (Manual) – Floating Gate (closed) 6.1 Gate Seal (face, pressure) 6.2 Seat Seal (face, pressure)

47

6.3 Bonnet Seal (compression, bolts) 6.4 Back Seat (face, pressure) - ineffective 6.5 Stem seal (grease fitting secondary barrier) Secondary barrier components –

• Tree cap. 7.0 Tree Cap 7.1 Tree Cap (parallel, screw cap) 7.2 Test Port (compression, screw threads)

48

APPENDIX D

SEAL DESCRIPTIONS SINGLE COMPLETION

49

SEAL DESCRIPTIONS FOR EACH ZONE - SINGLE COMPLETION Zone 2.1 – 2.2 Primary barrier components:

• Gas check valve, • Connecting pipework, • Tubing spool side valve,

1.0 Gas Check Valve (Fail Closed) - (open) 1.1 Bonnet Seal (compression, bolts) 1.2 Ring gasket (compression, bolts) 2.0 Connecting Pipework 2.1 Ring Gasket (compression, bolts) 3.0 Tubing Spool Side Valve (Fail Closed) – Floating Gate (open) 3.1 Bonnet Seal (compression, bolts) 3.2 Stem Seal (parallel, screw cap) 3.3 Grease fitting (compression screw thread) Secondary barrier components – None Zone 2.2 – 2.3 Primary barrier components:

• Tubing spool side valve, • Tubing spool to tubing hanger seal, • Tubing spool to casing hanger seal, • Production tubing to tubing hanger seal, • Upper well annulus, • Tubing hanger body, • Tubing hanger downhole safety valve control line lower packing gland, • Tubing hanger downhole chemical injection line lower packing gland, • Tubing spool downhole chemical injection line, • Tubing spool downhole safety valve control line, • Production tubing, • Tubing spool side valve, • Upper annulus tubing spool and monitoring assembly.

1.0 Tubing Spool Side Valve (Fail Closed) – Floating Gate (open) 1.1 Bonnet Seal (compression, bolts) 1.2 Stem Seal (parallel, screw cap) 1.3 Grease fitting (compression screw thread) 2.0 Tubing spool to tubing hanger seal 2.1 Tubing spool annulus Seal (parallel, lockdown) 3.0 Tubing spool to casing hanger seal 3.1 Tubing spool to casing hanger seal (parallel, lockdown)

50

4.0 Production tubing to tubing hanger seal 4.1 Premium Threaded Connection 5.0 Upper well annulus 5.1 Tubing 5.2 Premium Tapered Tubing Connection 6.0 Tubing hanger body 6.1 Hanger body 7.0 Tubing hanger downhole safety valve control line lower packing gland (x2) 7.1 Tubing hanger downhole safety valve control line lower packing gland (compression,

screw) 8.0 Tubing hanger downhole chemical injection line lower packing gland 8.1 Tubing hanger downhole chemical injection line lower packing gland (compression,

screw) 9.0 Tubing spool downhole chemical injection line 9.1 Chemical Injection Line Integrity 10.0 Tubing spool downhole safety valve control line 10.1 Downhole safety valve control line Integrity 11.0 Production tubing 11.1 Production tubing 11.2 Premium tapered tubing connection 12.0 Tubing spool side valve (Manual) (open) – well producing, open valves to take a

sample 12.1 Ring Gasket (compression, bolts) 12.2 Bonnet Seal (compression, bolts) 12.3 Stem Seal (parallel, screw cap) 12.4 Grease fitting (compression, screw thread) 13.0 Upper annulus tubing spool and monitoring assembly 13.1 Ring Gasket (compression, bolts) 13.2 Needle Valve (compression, screw) Secondary barrier components:

• Tubing hanger tie down bolts, • Tubing hanger downhole safety valve control line upper packing gland, • Tubing hanger downhole chemical injection line upper packing gland, • Tubing spool to tree outer flange seal, • Tubing hanger downhole safety valve control packing gland & tertiary block assembly, • Tubing hanger downhole chemical injection packing gland & tertiary block assembly, • Tubing spool downhole chemical injection line, • Tubing spool downhole safety valve control line.

14.0 Tubing hanger tie down bolts 14.1 Bolt Seals (Compression, screw)

51

15.0 Tubing hanger downhole safety valve control line upper packing gland 15.1 Tubing hanger downhole safety valve control line upper packing gland (compression,

screw) 16.0 Tubing hanger downhole chemical injection line upper packing gland 16.1 Tubing hanger downhole chemical injection point upper packing gland (compression,

screw) 17.0 Tubing spool to tree outer flange seal 17.1 Ring Gasket (compression, main fixing bolts for tree) 18.0 Tubing hanger downhole safety valve control packing gland & tertiary block assembly 18.1 Packing Gland (tertiary seal - outer block assembly seal (compression, bolts), Gland to

Line Seal) 18.2 Gland to Tubing Spool Seal 19.0 Tubing hanger downhole chemical injection packing gland & tertiary block assembly 19.1 Packing Gland (tertiary seal - outer block assembly seal (compression, bolts), Gland to

Line Seal) 19.2 Gland to Tubing Spool Seal 20.0 Tubing spool downhole chemical injection line 20.1 Chemical Injection Line Integrity 21.0 Tubing spool downhole safety valve control line 21.1 Downhole safety valve control line Integrity Zone 2.3 – 2.4 Primary barrier components:

• Upper well annulus, • Annulus downhole safety valve, • Production tubing,

1.0 Upper well annulus production casing 1.1 Production casing 1.2 Premium Tapered Tubing Connection 2.0 Annulus downhole safety valve (Fail Closed) - (open) 2.1 Valve Body 2.2 Valve piston / control line seal (parallel) 2.3 Premium Tapered Tubing Connection 3.0 Production tubing 3.1 Production Tubing 3.2 Premium Tapered Tubing Connection Secondary barrier components -

• B Annulus Casing, • B Annulus Tubing Spool Valves, • Upper annulus tubing spool monitor and vent assembly, • B annulus tubing spool to casing hanger seal.

52

4.0 Intermediate Casing ‘B’ Annulus 4.1 Intermediate Casing 4.2 Premium Tapered Tubing Connection 5.0 B Annulus Tubing Spool Valves (Manual) (open) – well producing, open valves to take

a sample 5.1 Ring Gasket (compression, bolts) 5.2 Bonnet Seal (compression, bolts) 5.3 Stem Seal (parallel, screw cap) 5.4 Grease fitting (compression, screw thread) 6.0 Upper annulus tubing spool monitor and vent assembly 6.1 Ring Gasket (compression, bolts) 6.2 Needle Valve (compression, screw) 7.0 B annulus tubing spool to casing hanger seal 7.1 Tubing spool to casing hanger seal (parallel, lockdown) Zone 2.4 – 2.6 Primary barrier components:

• Annulus downhole safety valve, • Dual bore upper packer, • Lower well annulus (9 5/8"), • Side Pocket Mandrels (SPM), • Chemical Injection Line.

1.0 Annulus downhole safety valve in the dual bore packer (Fail Closed) - (open) 1.1 Valve Body 1.2 Valve piston / control line seal (parallel) 1.3 Premium Tapered Tubing Connection 2.0 Dual bore upper packer 2.1 Packer body 2.2 Premium Tapered Tubing Connection 3.0 Lower well annulus (9 5/8") 3.1 Production casing 3.2 Premium Tapered Tubing Connection 4.0 Side Pocket Mandrels (SPM) 4.1 SPM body 4.2 Orifice Valve (parallel) 5.0 Chemical Injection Line 5.1 Chemical Injection Line pipe 5.2 Chemical injection line connection at bottom of dual bore upper packer

53

Secondary barrier components – • ‘B’ annulus (bore of intermediate casing), • Intermediate casing hanger to casing spool seal, • Tertiary seal is the ‘C’ annulus, • Production casing hanger seal to the casing spool, • ‘B’ annulus valve & upper annulus spool monitor and vent assembly.


• Side packer mandrels, • Lower production tubing, • Dual bore upper packer

1.0 Side Pocket Mandrels (SPM) 1.1 SPM body 1.2 Orifice Valve (parallel) 2.0 Lower production tubing 2.1 Tubing 2.2 Premium Tapered Tubing Connection 3.0 Dual bore upper packer 3.1 Packer body 3.2 Premium Tapered Tubing Connection Secondary barrier components –



• Dual bore upper packer, • Upper production tubing.

1.0 Production bore dual bore upper packer 1.1 Packer body 1.2 Premium Tapered Tubing Connection 2.0 Upper production tubing 2.1 Tubing 2.2 Premium Tapered Tubing Connection Secondary barrier components –


54


• Upper production tubing, • Production downhole safety valve.

1.0 Upper production tubing 1.1 Tubing 1.2 Premium Tapered Tubing Connection 2.0 Production downhole safety valve (Fail Closed) - (open) 2.1 Valve Body 2.2 Valve piston / control line seal (parallel) 2.3 Premium Tapered Tubing Connection Secondary barrier components –




1.0 Production downhole safety valve (Fail Closed) - (open) 1.1 Valve Body 1.2 Valve piston / control line seal (parallel) 1.3 Premium Tapered Tubing Connection 2.0 Production tubing and nipples 2.1 Tubing 2.2 Annulus Tubing Nipples 2.3 Premium Tapered Tubing Connection Secondary barrier components –

• Not Applicable (gas already in annulus as a function of gas lift) Zone 2.11 – 2.12 Primary barrier components:

• Production tubing and nipples, • Tubing hanger.

1.0 Production tubing and nipples 1.1 Tubing 1.2 Annulus Tubing Nipples 1.3 Premium Tapered Tubing Connection

55

2.0 Tubing hanger 2.1 Tubing Hanger Body 2.2 Premium Tapered Tubing Connection Secondary barrier components –



• Tubing hanger, • Production bore, • Production lower master valve.

1.0 Tubing hanger 1.1 Tubing Hanger Body 1.2 Premium Tapered Tubing Connection 2.0 Production bore 2.1 Bore Sleeve (parallel, main fixing bolts for tree) 2.2 Tree Body 3.0 Production Lower Master Valve (Manual) – Floating Gate (open) 3.1 Grease fitting (compression screw thread) 3.2 Stem Seal (parallel, screw cap) 3.3 Bonnet Seal (compression, bolts) Secondary barrier components –


assembly, • Tubing hanger tie down bolts and seals, • Tubing spool downhole safety valve control line packing gland & tertiary outlet block

assembly, • Tubing spool to tubing hanger seal, • Tubing hanger downhole safety valve control line packing gland, • Tubing hanger downhole chemical injection point packing gland. • Tubing spool downhole safety valve control line.

4.0 Tubing spool to tree outer flange seal 4.1 Bore Sleeve (parallel, main fixing bolts for tree) 5.0 Tubing spool downhole chemical injection line 5.1 Chemical Injection Line Integrity 6.0 Tubing spool downhole chemical injection point packing gland & tertiary outer block


Line Seal) 6.2 Gland to Tubing Spool Seal

56

7.0 Tubing hanger tie down bolts and seals 7.1 Bolt Seals (Compression, screw) 8.0 Tubing spool downhole safety valve control packing gland & tertiary outlet block

assembly 8.1 Packing Gland (tertia ry seal - outer block assembly seal (compression, bolts), Gland to

Line Seal) 8.2 Gland to Tubing Spool Seal 9.0 Tubing spool to tubing hanger seal 9.1 Tubing spool annulus Seal (parallel, lockdown) 10.0 Tubing hanger downhole safety valve control line upper packing gland 10.1 Tubing hanger downhole safety valve control line upper packing gland (compression,

screw) 11.0 Tubing hanger downhole chemical injection point upper packing gland 11.1 Tubing hanger downhole chemical injection point upper packing gland (compression,

screw) 12.0 Tubing spool downhole safety valve control line 12.1 Downhole safety valve control line Integrity Zone 2.13 – 2.14 Primary barrier components:

• Production lower master valve • Production bore, • Production upper master valve

1.0 Production lower master valve (Manual) – Floating Gate (open) 1.1 Bonnet Seal (compression, bolts) 1.2 Stem Seal (parallel, screw cap) 1.3 Grease fitting (compression screw thread) 2.0 Production bore 2.1 Tree Body 3.0 Production upper master valve (Fail Closed) – Floating Gate (open) 3.1 Bonnet Seal (compression, bolts) 3.2 Stem Seal (parallel, screw cap) 3.3 Grease fitting (compression screw thread) Secondary barrier components – None Zone 2.14 – 2.15 Primary barrier components:

• Production upper master valve • Production bore,

57

• SWAB valve, • Chemical injection valve • Production wing valve • Production non-active wing valve.

1.0 Production Wing Valve (Fail Closed) – Floating Gate (open) 1.1 Bonnet Seal (compression, bolts) 1.2 Stem Seal (parallel, screw cap) 1.3 Grease fitting (compression screw thread) 1.4 Ring Gasket (compression, bolts) 2.0 Production Bore 2.1 Tree Block 3.0 Production Upper Master Valve (Fail Closed) – Floating Gate (open) 3.1 Bonnet Seal (compression, bolts) 3.2 Stem Seal (parallel, screw cap) 3.3 Grease fitting (compression screw thread) 4.0 Production SWAB Valve (Manual) – Floating Gate (closed) 4.1 Gate Seal (face, pressure) 4.2 Seat Seal (face, pressure) 4.3 Bonnet Seal (compression, bolts) 4.4 Back Seat (face, pressure) - ineffective 4.5 Stem seal (grease fitting secondary barrier) 5.0 Chemical Injection Valve (open) 5.1 Single Cartridge Dual Check Valve (metal to metal nose joint, threaded) 5.2 CI Valve - Bonnet Assembly (screw cap, threaded) 5.3 CI Valve - Stem packing 5.4 CI Valve - Ring Gasket (compression, bolts) Secondary barrier components –

• Tree cap 7.0 Tree Cap 7.1 Tree Cap (parallel, screw cap) 7.2 Test Port (compression, screw threads)

58

APPENDIX E

59


Zone 1.1 to 1.2 1. Gas Check Valve - Primary Barrier

To contain the gas within the tree on loss of pressurisation in the upstream pipework.

Bonnet seal leakage (metal to metal joint)

Seal incorrectly specified

Material specification of seal incompatible with body causing differential cell to be setup.

Gradually leaking over time

Designers and manufacturers to have ISO quality systems in place. Offshore supervisors checks and balances i.e. permit to work system etc.

2.2




Wrong seal taken from stores

Dimensions, chemical and mechanical properties similar to actual specification, therefore no immediate effect.

None


2.2





Seal incorrectly specified in design None.

Tree has been operating in excess of 6 months, initial teething problems have been ironed out.

2.2




Seal incorrectly installed Effective seal not made Gas leak around seal

Employ competent individuals and appropriate supervision is available. Pressure tested after envelope broken.

2.1




Bolts installed incorrectly - bolts unevenly tensioned

Joint integrity reduced Sealing arrangement unevenly energised

Employ competent individuals and appropriate supervision is available.

3.3




Bolts installed incorrectly - incorrect grade of bolt fitted

Joint integrity reduced None.


3.2

60





Bolts installed incorrectly - bonnet over tensioned

Joint integrity reduced Seal distortion leading to progressive leakage.


2.3




Bolts installed incorrectly - bonnet under tensioned

Joint integrity reduced Instantaneous leak from bonnet


2.3



Failure of Ring Gasket Seal

Bolts loosen off in service Partial leakage of gas Gas release

Possible detection by plant operators and/or F&G system

2.3



Failure of Ring Gasket Seal Fatigue failure of bolts

Catastrophic failure of one or more bolts after a period of time.

Excessive vibration on pipework

Appropriate support for piping as per pipe stress analysis.

3.3




Thermal/mechanical gradients induce fatigue on bolts


Displacement from normal relative position

Appropriate piping design as per pipe stress analysis.

3.3






None


2.2






Gradually increasing leak over time.


2.2

61






Seal incorrectly specified in design None


2.2




Seal incorrectly installed Effective seal not made Gas leakage around seal


2.1







3.3





Joint integrity reduced None


3.2







2.3







2.3

Zone 1.1 to 1.2 2. Connecting Pipework - Primary Barrier





2.3

62








3.3








3.3






None


2.2








2.2







2.2






2.1







3.3

63








3.2







2.3







2.3

Zone 1.1 to 1.2 3. Annulus Wing Valve - Primary Barrier

To contain the gas within the tree on loss of pressurisation in the upstream pipework and or on activation of platform ESD






2.2






None


2.2







2.2

64







2.1







3.3







3.2







2.3







2.3



Stem Seal Leak Wear and Tear Loss of full seal Gas leaks from actuator housing

Perform maintenance and inspection in accordance with manufacturers requirements.

2.4

65




Stem Seal Leak Packing not set correctlyLoss of full seal Gas leaks from actuator housing


2.4



Stem Seal Leak Wrong packing fitted Loss of full seal Gas leaks from actuator housing


2.4



Grease fitting Leakage Fitter backs off assembly rather than just the cap

Partial leak Audible evidence of gas release Using competent fitters 3.3



Grease fitting Leakage

Removal or backing off of plug during routine greasing/lubricating removes inner check valve




Bonnet Seal Leakage Seal incorrectly specified




2.2



Bonnet Seal Leakage Wrong seal taken from stores


None


2.2

66







2.2



Bonnet Seal Leakage Seal incorrectly installed Effective seal not made Gas leak around seal


2.1



Bonnet Seal Leakage Bolts installed incorrectly - bolts unevenly tensioned



3.3



Bonnet Seal Leakage Bolts installed incorrectly - incorrect grade of bolt fitted



3.2



Bonnet Seal Leakage Bolts installed incorrectly - bonnet over tensioned



2.3



Bonnet Seal Leakage Bolts installed incorrectly - bonnet under tensioned



2.3

67




Stem Seal Leakage Wear and Tear Loss of full seal Gas leaks from actuator housing


2.4



Stem Seal Leakage Packing not set correctly Loss of full seal Gas leaks from actuator

housing


2.4



Stem Seal Leakage Wrong packing fitted Loss of full seal Gas leaks from actuator housing


2.4



Grease fitting leakage Fitter backs off assembly rather than just the cap




Grease fitting leakage



Zone 1.2 to 1.3 2. Annulus Bore - Primary Barrier

To maintain annulus pressure integrity Tree block failure Manufacturing defect Stress raisers and crack

initiators

Slag inclusion/laminations, cold laps and other geometric imperfections in the forged block.

Designers and manufacturers to have ISO quality systems in place.

1.2

68


Zone 1.2 to 1.3 3. Annulus Upper Master Valve - Primary Barrier






2.2





None


2.2






2.2





2.1






3.3

69







3.2






2.3






2.3





2.4



Stem Seal Leak Packing not set correctlyLoss of full seal Gas leaks from actuator housing


2.4





2.4

70











Zone 1.2 to 1.3 4. Annulus SWAB Valve - Primary Barrier

Provides isolation of annulus from tree cap other than under any well intervention conditions

Poor seal between gate and seat

Gate/seat scored or damaged

Gas passing into upper bore under tree cap

Pressurised gas under tree cap

Pressure testing at manufactures to ensure integrity of gate/seat. Maintenance and inspection by manufacturer including periodic testing offshore. Tree cap is a secondary barrier

1.5



Poor seal between seat seal and valve body





1.1








1.2

71








1.2






1.1








2.2






None


2.2







2.2






2.1

72








3.3







3.2







2.3







2.3



Stem seal leakage Wear and Tear Loss of full seal Gas leaks from handle assembly


2.4



Stem seal leakage Packing not set correctlyLoss of full seal Gas leaks from handle assembly


2.4



Stem seal leakage Wrong packing fitted Loss of full seal Gas leaks from handle assembly


2.4

73


Zone 1.2 to 1.3 5. Chemical Injection Valve - Primary Barrier

To provide a controlled entry point for chemical injection

Cartridge nose seal failure, annulus gas leakage past cartridge wall

Cartridge not fully tightened

Gas leakage around cartridge walls None.


1.1



Failure of bonnet seal Seal incorrectly specified




2.2



Failure of bonnet seal Wrong seal taken from stores


None


2.2






2.2



Failure of bonnet seal Seal incorrectly installed Effective seal not made Gas leak around seal


2.1



Failure of bonnet seal Bolts installed incorrectly - bolts unevenly tensioned



3.3

74




Failure of bonnet seal Bolts installed incorrectly - incorrect grade of bolt fitted



3.2



Failure of bonnet seal Bolts installed incorrectly - bonnet over tensioned



2.3



Failure of bonnet seal Bolts installed incorrectly - bonnet under tensioned



2.3






2.3







3.3








3.3






None


2.2

75









2.2







2.2






2.1







3.3







3.2







2.3

76








2.3





2.4





2.4





2.4

Zone 1.2 to 1.3 6. Annulus non-active wing valve - Primary Barrier

To provide a facility for injecting kill fluid into the annulus.

Poor seal between gate and seat

Gate/seat scored or damaged

Gas passing into upper bore under tree cap

Pressurised gas under tree cap

Pressure testing at manufactures to ensure integrity of gate/seat. Maintenance and inspection by manufacturer including periodic testing offshore. Tree cap is a secondary barrier

1.5

77









1.1








1.2







1.2






1.1








2.2






None


2.2

78








2.2






2.1







3.3







3.2







2.3







2.3





2.4

79






2.4





2.4






2.3







3.3








3.3






None


2.2








2.2







2.2

80







2.1







3.3







3.2







2.3







2.3

Zone 1.2 to 1.3 7. Tree Cap - Secondary Barrier

To provide a removable secondary barrier to allow well intervention activities

On failure of primary barrier (gate on SWAB) all tree cap seals are primary barriers. Tree Cap Annulus Bore Seal passing.



2.3




Fatigue of bolts Catastrophic failure of one or more bolts after a period of time.



3.3

81









3.3






None


2.2








2.2







2.2






2.1







3.3

82








3.2







2.3







2.3



On failure of primary barrier (gate on SWAB) all tree cap seals are primary barriers. Tree Cap Bonnet Seal passing.



2.3




Fatigue of bolts Catastrophic failure of one or more bolts after a period of time.



3.3








3.3

83







None


2.2








2.2







2.2






2.1







3.3







3.2

84








2.3







2.3



On failure of primary barrier (gate on SWAB) all tree cap seals are primary barriers. Tree Cap Plug Seal passing.

Damage of o-ring on installation of cap

Scoring and/or nipping of o-ring breaking down seal integrity

Gas leakage from the tree cap retainer ring.

Careful installation of tree cap. Pressure test of tree cap on tree assembly.

2.4




Damage to polished bore on installation of tree cap

Scoring of polished boreGas leakage from the tree cap retainer ring.

Inspect and dress polished bore prior to installation. Pressure test of tree cap on tree assembly.

2.3




Incorrect o-ring used Inadequate seal Gas leakage from the tree cap retainer ring.

Designers and manufacturers to have ISO quality systems in place. Offshore supervisors checks and balances. Pressure test of tree cap on tree assembly.

2.2

85





Ageing of o-ring prior to installation

Gradual deteriation of seal, causing increasing leakage over a period of time

Gas leakage from the tree cap retainer ring.

Designers and manufacturers to have ISO quality systems in place. Offshore supervisors checks and balances. Pressure test of tree cap on tree assembly.

2.2



On failure of primary barrier (gate on SWAB) all tree cap seals are primary barriers. Test Valve-Tree Cap crewed seal interface passing.

Thread cut out of tolerance

Reduced thread to thread contact surface (seal maintained by excessive PTFE for example)

No visible symptoms. Degraded mechanical joint, since joint relies more on excessive sealant than intimate thread contact.

Use of go/no go gauges during manufacture. Designers and manufacturers to have ISO quality systems in place. Offshore supervisors checks and balances. Use of competent fitters

3.3





Either male or female threads are cut oversize

Component will only mate for a proportion of the threads (rather than full length engagement)


3.3




Cross threads Ineffective seal

Excessive torque required to install. Fitting improperly aligned. Leaking joint.

Use of competent fitters and effective supervision. Suitable pressure testing.

1.3

86





Damaged threads Improperly mated threads

Joint difficult to make up. Excessive torque required to install. Fitting improperly aligned. Leaking joint


1.3



On failure of primary barrier (gate on SWAB) all tree cap seals are primary barriers. Valve Stem packing passing.

Wear and Tear Loss of full seal Gas leaks from actuator housing


2.4




Packing not set correctly Loss of full seal Gas leaks from actuator housing


2.4




Wrong packing fitted Loss of full seal Gas leaks from actuator housing


2.4

87








2.2





None


2.2






2.2





2.1






3.3

88







3.2






2.3






2.3





2.4



Stem Seal Leak Packing not set correctly Loss of full seal Gas leaks from actuator

housing


2.4





2.4

89




Leakage from grease fitting

Individual back off assembly rather than just the cap







Zone 1.3 to 1.4 2. Annulus Bore - Primary Barrier


initiators



1.2

Zone 1.3 to 1.4 3. Annulus Lower Master Valve - Primary Barrier

To contain the gas within the tree on loss of pressurisation in the upstream pipework





2.2





None


2.2






2.2

90






2.1






3.3






3.2






2.3






2.3



Stem Seal Leak Wear and Tear Loss of full seal Gas leaks from handle assembly


2.4



Stem Seal Leak Packing not set correctlyLoss of full seal Gas leaks from handle assembly


2.4

91




Stem Seal Leak Wrong packing fitted Loss of full seal Gas leaks from handle assembly


2.4

















2.2





None


2.2






2.2





2.1

92







3.3






3.2






2.3






2.3





2.4



Stem Seal Leak Packing not set correctly Loss of full seal Gas leaks from handle

assembly


2.4





2.4

93












Zone 1.4 to 1.5 2. Annulus Bore -Primary Barrier


initiators



1.2


To maintain annulus pressure integrity

Annulus bore sleeve seal failure

During installation of tree the seals become damaged

Leakage into xmas tree/upper tubing hanger cavity

Potential leakage from tied own bolts or tree body gasket.

Confirmed by pressure testing and established installation procedures. Competent individuals and appropriate supervision

2.3


To maintain annulus pressure integrity

Annulus bore sleeve seal failure

Due to incorrect installation seals fail to energise

Leakage into xmas tree/upper tubing hanger cavity

Potential leakage from tied own bolts or tree body gasket.

Confirmed by pressure testing and established installation procedures. Competent individuals and appropriate supervision

2.3

Zone 1.4 to 1.5 3. Annulus bore tubing hanger - Primary Barrier

To provide a continuous bore between the tree and the annulus tubing

Annulus bore failure Manufacturing defect Stress raisers and crack initiators



1.1

94



To provide a sealed mechanical joint between components

Failure of seal (metal to metal)

Failure due to threads being out with manufacturing tolerances

Ineffective seal

Leakage of gas past threaded connection consequently pressurising the upper A annulus. Additional loading on the dual bore upper packer (hydrostatic head, weight of tubing and gas lift pressure)

Instrument monitor facility on upper A annulus. Pressure in upper A annulus monitored by plant operators.

2.2



Failure of seal (metal to metal) Galling on seal face Ineffective seal



2.2




Insufficient make up torque Ineffective seal



2.2

95





Excessive loading on seal arrangement

Seal integrity reduced or failed



2.2



Failure of threaded connection

Jumping out or 'unzipping' of the thread Joint opens



2.2



Failure of threaded connection Shearing of threads Joint integrity reduced

or failed



2.2

Zone 1.4 to 1.5 4. Tubing spool to tree outer flange seal - Secondary Barrier

Provide seal between the tree and the spool interface

Leakage of gas around seal





2.3

96







None


1.2








1.2







1.2






1.1

Zone 1.4 to 1.5

5. Tubing spool downhole chemical injection line - Secondary Barrier

Provide a conduit for chemical injection into production bore

Rupture of chemical injection line - between tubing spool and tree cavity

Pipework damaged during installation

Pressurisation of void between tree and tubing spool with chemicals.

Pump Labouring (audible) Significant reduction or cessation of dosing rate of chemicals. Potential leakage from ring gasket and tie down bolts.

Regular checks of pump pressure injection rates by plant operators. Competent fitters and appropriate installation procedures.

1.2

97


Zone 1.4 to 1.5

6. Tubing spool downhole chemical injection line packing gland - Secondary Barrier Outer block assembly - Tertiary Barrier

To provide a seal between the chemical injection line and the gland bore

Leakage around seal Ageing of seal


Leakage around seal increasing over time.

Designers and manufacturers to have ISO quality systems in place. Offshore supervisors checks and balances. Pressure test of complete assembly.

2.2

Zone 1.4 to 1.5



Leakage around seal Seal incorrectly installed Effective seal not made Gas leakage around seal


1.1

Zone 1.4 to 1.5



Leakage around seal Wrong seal taken from stores


None


1.2

Zone 1.4 to 1.5



Leakage around seal Seal incorrectly specified




1.2

Zone 1.4 to 1.5






1.2

98


Zone 1.4 to 1.5


To provide a seal between the gland body and the tubing spool



1.1

Zone 1.4 to 1.5





None


1.2

Zone 1.4 to 1.5







1.2

Zone 1.4 to 1.5






1.2

Zone 1.4 to 1.5







2.2

99


Zone 1.4 to 1.5 7. Tubing hanger tie down bolts and seals - Secondary Barrier

To provide a secondary barrier between the casing spool and the tie down bolts



Leakage around seal increasing over time. Casing hanger may drop as a result of seal deteriation.


2.2

Zone 1.4 to 1.5

8. Tubing spool downhole safety valve control packing gland - Secondary Barrier Outlet block assembly - Tertiary Barrier

To provide a seal between the DHSV control line and the gland bore





2.2

Zone 1.4 to 1.5





None


1.2

Zone 1.4 to 1.5







1.2

Zone 1.4 to 1.5






1.2

100


Zone 1.4 to 1.5





1.1

Zone 1.4 to 1.5







2.2

Zone 1.4 to 1.5





None


1.2

Zone 1.4 to 1.5







1.2

Zone 1.4 to 1.5






1.2

101


Zone 1.4 to 1.5





1.1

Zone 1.4 to 1.5 9. Tubing spool to tubing hanger seal - Secondary Barrier

To provide a seal between the tubing hanger and tubing spool

Leakage around seal Seal loses energisation Over a period of time seal has compressed

Pressure build up in the upper A annulus. Tertiary barriers provided by annular valves, VR plug and instrumentation fittings


1.3





1.1





None


1.2







1.2






1.2

102








2.2

Zone 1.4 to 1.5

10. Tubing hanger downhole safety valve control line upper packing gland - Secondary Barrier

Provide a seal between the DHSV control line and the tubing hanger body

Loss of integrity of packing gland body thread causing trapped pressure to leak into upper annulus





3.3

Zone 1.4 to 1.5








3.3

Zone 1.4 to 1.5







1.3

103


Zone 1.4 to 1.5







1.3

Zone 1.4 to 1.5



Loss of integrity of packing gland compression fitting causing trapped pressure to leak into upper annulus

Incorrect joint make-up Leakage of gas into upper A annulus



1.3

Zone 1.4 to 1.5

11. Tubing hanger downhole chemical injection line upper packing gland - Secondary Barrier

Provide a seal between the Chemical Injection line and the tubing hanger body






3.3

104


Zone 1.4 to 1.5








3.3

Zone 1.4 to 1.5







1.3

Zone 1.4 to 1.5







1.3

Zone 1.4 to 1.5



Loss of integrity of packing gland compression fitting causing trapped pressure to leak into upper annulus




1.3

105


Zone 1.4 to 1.5

12. Tubing spool downhole safety valve control line - Secondary Barrier

Provide a conduit for the hydraulic fluid for control of the down hole safety valves

Rupture of down hole safety valve control line - between tubing spool and tree cavity


Pressurisation of void between tree and tubing spool with hydraulic fluid.



1.2


To provide a continuous bore between the tubing hanger and the annulus tubing

Annulus bore failure Manufacturing defect Stress raisers and crack initiators



1.1





Ineffective seal



2.2






2.2

106








2.2








2.2







2.2

107





or failed



2.2

Zone 1.5 to 1.6 2. Annulus tubing & annulus tubing nipples - Primary Barrier

Provide location and hang-off for well intervention equipment

Nipple body integrity failure Manufacturing defect Stress raisers and crack

initiators

Leakage of gas into the upper A annulus. Additional loading on the dual bore upper packer (hydrostatic head, weight of tubing and gas lift pressure)


2.2


Annulus tubing will provide a conduit for the gas to be injected into the production bore.

Annulus tubing ruptures Manufacturing defect Stress raisers and crack initiators



2.2





Ineffective seal



2.2

108







2.2







2.2








2.2

109








2.2




or failed



2.2

Zone 1.5 to 1.6 3. Production casing - Secondary Barrier

To protect the formation to the top of the pay zone and the 9 5/8" casing

Production casing split or parted

Corrosion (where water is present)

Produce corrosion products which are a source of debris and can under certain situations apply a pressure to mating surfaces

Degradation of components over time. This less applicable to 13% Cr Alloys.

Optimisation of material design and selection Injection of inhibitors

1.3




Corrosion (where water is present) Localised corrosion

Deep pits and cavities. If equipment is left for an extended period of time full wall perforation can occur.

Optimisation of material design and selection Good corrosion management strategy and execution.

4.3

110




Production casing split or parted Incorrect casing design Casing could part

Gas lift pressure leakage into the B annulus, consequently annular valves on B annulus become primary barrier. B annulus is rated to a lower pressure than the A annulus.

Correct casing design 3.3




Embrittlement during manufacturing process (high alloy steels)

13% Cr steels vulnerable to temper Embrittlement under incorrect welding and heat treatment regimes.

Gas lift pressure leakage into the B annulus, consequently annular valves on B annulus become primary barrier. B annulus is rated to a lower pressure than the A annulus. Loss of ductility resulting in a greater sensitivity to cracking under normal well conditions (thermal loading).

Design and manufacturers quality assurance in accordance with ISO and equivalent. Plant operators would monitor annulus pressure.

2.3





Ineffective seal



2.2

111







2.2







2.2








2.2

112








2.2




or failed



2.2

Zone 1.5 to 1.6

4. Production casing hanger seal to tubing spool - Secondary Barrier

To provide a seal between the casing hanger and casing spool


Pressure build up in the B annulus. Secondary barriers provided by annular valves and instrumentation fittings

Instrument monitor facility on B annulus. Pressure in B annulus monitored by plant operators.

3.3

Zone 1.5 to 1.6





1.1

113


Zone 1.5 to 1.6





None


1.2

Zone 1.5 to 1.6







1.2

Zone 1.5 to 1.6






1.2

Zone 1.5 to 1.6





Leakage around seal increasing over time Casing hanger may drop as a result of seal deteriation.


2.2

Zone 1.5 to 1.6

5. Upper annulus tubing spool inner and outer valves - Secondary Barrier

To provide a facility to isolate the A,B or C annulus and with instrumentation monitor annular pressures

Bonnet seal leakage (metal to metal joint) - 2 valves





2.2

114


Zone 1.5 to 1.6






None


2.2

Zone 1.5 to 1.6







2.2

Zone 1.5 to 1.6






2.1

Zone 1.5 to 1.6







3.3

Zone 1.5 to 1.6







3.2

Zone 1.5 to 1.6







2.3

115


Zone 1.5 to 1.6







2.3

Zone 1.5 to 1.6



Stem Seal Leak - 2 valves Wear and Tear Loss of full seal Gas leaks from handle

assembly


2.4

Zone 1.5 to 1.6



Stem Seal Leak - 2 valves Packing not set correctlyLoss of full seal Gas leaks from handle

assembly


2.4

Zone 1.5 to 1.6



Stem Seal Leak - 2 valves Wrong packing fitted Loss of full seal Gas leaks from handle

assembly


2.4

Zone 1.5 to 1.6





Zone 1.5 to 1.6






Zone 1.5 to 1.6

6. Upper annulus tubing spool monitor and vent assembly - Secondary Barrier

To provide a facility for pressure monitoring equipment to be linked to the A annulus





1.1

116


Zone 1.5 to 1.6







2.2

Zone 1.5 to 1.6





None


2.2

Zone 1.5 to 1.6






2.2

Zone 1.5 to 1.6





2.1

Zone 1.5 to 1.6






3.3

Zone 1.5 to 1.6






3.2

117


Zone 1.5 to 1.6






2.3

Zone 1.5 to 1.6






2.3

Zone 1.5 to 1.6






2.3

Zone 1.5 to 1.6







3.3

Zone 1.5 to 1.6








3.3

Zone 1.5 to 1.6






None


2.2

Zone 1.5 to 1.6








2.2

118


Zone 1.5 to 1.6







2.2

Zone 1.5 to 1.6






2.1

Zone 1.5 to 1.6







3.3

Zone 1.5 to 1.6







3.2

Zone 1.5 to 1.6







2.3

Zone 1.5 to 1.6







2.3

Zone 1.5 to 1.6





2.4

119


Zone 1.5 to 1.6





2.4

Zone 1.5 to 1.6





2.4

Zone 1.5 to 1.6

7. VR plug - Secondary Barrier Tertiary valve(s)

Provides isolation in A,B or C annulus to carry out maintenance on annular valves and fittings.

Nose seal failure Debris on seal face Seal not seated correctly

Leakage of gas into the inner annular valve. VR plugs are generally used for maintenance when one of the annular valves requires to be removed and an additional isolation is required.

Correct torque applied to VR plug in accordance with the manufacturers specification. Use of competent fitters

1.1

Zone 1.5 to 1.6




Misalignment during installation

Threads crossed causing loss of integrity of joint

Leakage from upper A annulus into inner annular valve. VR plugs are generally used for maintenance when one of the annular valves requires to be removed and an additional isolation is required.

Use of competent fitters.1.3

Zone 1.5 to 1.6




Galling of threads due to debris on threaded connections

Loss of integrity of joint

Leakage from upper A annulus into inner annular valve. VR plugs are generally used for maintenance when one of the annular valves requires to be removed and an additional isolation is required.

Use of competent fitters.1.3

120


Zone 1.5 to 1.6 8. Tubing hanger seal to tubing spool - Secondary Barrier






2.2





None


1.2




Material specification ofseal incompatible with body causing differential cell to be setup.



1.2






1.2





1.1

121





Pressure build up in the B annulus. Secondary barriers provided by annular valves and instrumentation fittings


3.3

Zone 1.5 to 1.6



Rupture of chemical injection line - below tubing hanger


Pressurisation of void between tubing hanger and the dual bore upper packer with chemicals.

Pump Labouring (audible) - increased injection rate Significant increase of dosing rate of chemicals.

Regular checks of pump pressure and injection rates by plant operators. Competent fitters and appropriate installation procedures.

1.2

Zone 1.5 to 1.6


Provide a conduit for the hydraulic fluid for control of the down hole safety valves

Rupture of down hole safety valve control line - below tubing hanger


Pressurisation of void between tubing hanger and the dual bore upper packer with hydraulic fluid.

Pump Labouring (audible) - increased injection rate


1.2

Zone 1.5 to 1.6

11. Tubing hanger downhole safety valve control line lower packing gland - Secondary Barrier


Loss of integrity of packing gland body thread causing trapped pressure to leak into cavity between tree and tubing hanger. On coincident failure of upper packing gland.





3.3

122


Zone 1.5 to 1.6








3.3

Zone 1.5 to 1.6







1.3

Zone 1.5 to 1.6







1.3

123


Zone 1.5 to 1.6





Leakage of gas past threaded connection consequently pressurising the cavity between tree and tubing hanger Tertiary barriers provided by tie down bolt arrangement, chemical injection point, down hole safety valve point, tubing hanger to casing spool seal.


1.3

Zone 1.5 to 1.6

12. Tubing hanger downhole chemical injection line lower packing gland - Secondary Barrier


Loss of integrity of packing gland body thread causing trapped pressure to leak into cavity between tubing hanger and tree. On coincident failure of upper packing gland.





3.3

Zone 1.5 to 1.6








3.3

124


Zone 1.5 to 1.6







1.3

Zone 1.5 to 1.6







1.3

Zone 1.5 to 1.6




Incorrect joint make-up Leakage of gas into cavity between tubing hanger and tree.

Leakage of gas past threaded connection consequently pressurising the cavity between tree and tubing hanger. Tertiary barriers provided by tie down bolt arrangement, chemical injection point, down hole safety valve point, tubing hanger to casing spool seal.

None. 1.3

125



Provide location and hang-off for well intervention equipment

Nipple body integrity failure Manufacturing defect Stress raisers and crack

initiators



2.2






2.2





Ineffective seal



2.2






2.2

126








2.2








2.2







2.2

127





or failed



2.2

Zone 1.6 to 1.7 2. Annulus downhole safety valve - Primary Barrier

To provide addition barrier between lower annulus and tree/wellhead



Ineffective seal



2.2






2.2

128








2.2








2.2







2.2

129





or failed



2.2



Failure of housing sealing arrangement

Failure of two radially successive seals of the component interface

DHSV housing loses integrity

Gas leakage into upper A annulus. A Annular valves become tertiary barriers.

Correct specification of seals. Manufacturers and designers have a suitable quality assurance system in accordance with ISO or equivalent.

1.1



Failure of control line housing


Leakage into the A annulus

Gas leakage into upper A annulus. Flapper closes if control line ruptures A Annular valves become tertiary barriers.

Correct specification of seals. Periodic testing

2.1





Ineffective seal



2.2

130







2.2







2.2








2.2

131








2.2



Failure of seal (metal to metal) Shearing of threads Joint integrity reduced

or failed



2.2






Gas leakage into upper A annulus. A Annular valves become tertiary barriers.

Correct specification of seals. Manufacturers and designers have a suitable quality assurance system in accordance with ISO or equivalent.

1.1






Gas leakage into upper A annulus. Flapper closes if control line ruptures A Annular valves become tertiary barriers.


2.1

132


Zone 1.7 to 1.8 2. Annulus Tubing - Primary Barrier





2.2





Ineffective seal



2.2






2.2

133








2.2








2.2







2.2

134





or failed



2.2






2.2





Ineffective seal



2.2

135







2.2







2.2








2.2

136








2.2




or failed



2.2

Zone 1.8 to 1.9 2. Annulus bore dual bore upper packer - Primary Barrier

Dual upper bore packer provides isolation between the upper and lower annulus

Failure of the packer sealing element Incorrectly set

Gas passing from lower annulus to upper annulus

Upper A annulus pressurise with gas.

Periodic checks of upper A annulus pressure. Pressure testing when packer was originally installed.

2.2



Failure of the packer sealing element

Deteriation of the packer sealing element




2.2




Design working loads are exceeded

Additional tensile loads imposed on packer

Expansion and contraction of annulus tubing in the absence of a slip joint.

Packer to be designed for all reasonably foreseeable events.

2.3

137




Failure of the tubing annulus to packer seal

Deteriation of the annulus upper bore tubing stab seal




2.2







Tubing stab to be designed for all reasonably foreseeable events.

2.3

Zone 1.8 to 1.9 3. Downhole chemical injection line - Secondary Barrier


Rupture of chemical injection line - between tubing hanger and dual bore upper packer


Pressurisation of upper aannulus with chemicals

Pump Labouring (audible) Significant reduction or cessation of dosing rate of chemicals. A annulus pressure increase.


1.2

Zone 1.8 to 1.9

4. Dual bore packer downhole chemical injection line upper packing gland - Secondary Barrier

Provide a seal between the Chemical Injection line and the dual bore upper packer body

Loss of integrity of packing gland body thread causing trapped pressure to leak up against the lower chemical injection line packing gland. Coincident failure of lower chemical injection line packing gland in order to leak into lower annulus.





3.3

138


Zone 1.8 to 1.9








3.3

Zone 1.8 to 1.9







1.3

Zone 1.8 to 1.9







1.3

139


Zone 1.8 to 1.9





Chemical injection line subject to back pressure from injection gas under normal chemical injection activities. Chemical injection pressure will increase. Chemical injection line pressurised with injection gas when not injecting chemicals. Tertiary barriers provided by annular valves, VR plug and instrumentation fittings


1.3



Failure of the packer sealing element Incorrectly set




2.2




Deteriation of the packer sealing element




2.2







Packer to be designed for all reasonably foreseeable events.

2.3




Deteriation of the annulus upper bore tubing stab seal




2.2

140









2.3

Zone 1.9 to 1.11 2. Lower well annulus (9 5/8") - Primary Barrier

To provide a conduit for the gas to be injected into the production string

Lower annulus casing split or parted





1.3







4.3



Lower annulus casing split or parted Incorrect casing design Casing could part







13% Cr steels vulnerable to temper Embrittlement under incorrect welding and heat treatment regimes.



2.3

141






Ineffective seal



2.2






2.2







2.2

142









2.2







2.2




or failed



2.2

Zone 1.9 to 1.11 3. Side Pocket Mandrels (SPM) - Primary Barrier

To provide a means of injecting gas into the bore string

Orifice valve fails to open on demand Incorrect set pressure

Gas is not injected at the right level in the production string

Gas lift is not effective, if well is reliant on gas lift well may not flow.

Manufacturers and designers quality assurance scheme in accordance with ISO or equivalent. Orifice valves checked before installation in well.

1.2

143




Orifice valve fails to open on demand

Orifice valve seized - closed

Gas is not injected into the production string

Gas lift is not effective, if well is reliant on gas lift well may not flow. Lower A annulus is pressurised beyond normal operating conditions.


1.2

Zone 1.9 to 1.11 4. Chemical Injection Line

Provide a conduit to inject chemicals into the production tubing

Chemical injection line rupture

Operational loads exceeded Line could split

Chemical injection line subject to back pressure from injection gas under normal chemical injection activities. Chemical injection pressure will increase. Chemical injection line pressurised with injection gas when not injecting chemicals.

Chemical injection pipework and fittings should be designed and constructed for all reasonably foreseeable events. Chemical injection pressure should be monitored by competent individuals.

2.3




Operational loads exceeded Fatigue

Combination of vibration and tension in line due to slippage of supports. Pressure cyclic effects from injecting.

Correct supporting arrangement. 2.3

144





Operational loads exceeded Incorrect installation

Joint leakage at either dual bore upper packer or connection to production tubing. Chemical injection line subject to back pressure from injection gas under normal chemical injection activities. Chemical injection pressure will increase. Chemical injection line pressurised with injection gas when not injecting chemicals.


2.3




Operational loads exceeded Corrosion of fittings

Due to residual liquids from previous operations. Chemical injection line subject to back pressure from injection gas under normal chemical injection activities. Chemical injection pressure will increase. Chemical injection line pressurised with injection gas when not injecting chemicals.

Corrosion/materials engineer to ensure compatibility of materials with environment.

2.3

145




Lower seal between chemical injection line and dual bore upper packer

Deteriation of the lower chemical injection line seal


Upper chemical injection line seal to dual bore upper packer takes lower A annulus pressure. Coincidental failure of upper chemical injection line seal to dual bore upper packer to upper A annulus pressurise with gas.


2.2








2.3



Upper seal between chemical injection line and dual bore upper packer

Deteriation of the upper chemical injection line seal


Failure of upper chemical injection line seal to dual bore upper packer to upper A annulus pressurise with gas. Failure of lower chemical injection line seal to dual bore upper packer to upper A annulus pressurise with gas.


2.2








2.3

146

APPENDIX F

SINGLE COMPLETION FMECA RESULTS

147



To contain the gas within the A annulus of the wellhead on loss of pressurisation in the upstream pipework.






2.2






None


2.2







2.2






2.1







3.3

148








3.2







2.3







2.3






2.3







3.3

149









3.3






None


2.2







Designers and manufacturers to have ISO quality systems in place. Offshore supervisors checks and balances i.e. permit to work syst em etc.

2.2







2.2




Seal incorrectly installed Effective seal not made Gas leakage around

seal


2.1

150








3.3







3.2







2.3







2.3






2.3

151








3.3








3.3






None


2.2







Designers and manufact urers to have ISO quality systems in place. Offshore supervisors checks and balances i.e. permit to work system etc.

2.2







2.2

152


Zone 2.1 to 2.2 2. Connect ing Pipework - Primary Barrier



Seal incorrectly installed

Effective seal not made Gas leakage around seal


2.1







3.3







3.2







2.3







2.3

153


Zone 2.1 to 2.2 3. Tubing Spool Side Valve - Primary Barrier

To contain the gas within the A annulus of the wellhead on loss of pressurisation in the upstream pipework and or on activation of platform ESD






2.2






None


2.2







2.2






2.1

154








3.3







3.2







2.3







2.3

155






2.4



Stem Seal Leak Packing not set correctly Loss of full seal Gas leaks from actuator

housing


2.4





2.4





156






Partial leak Audible evidence of gas release

Using competent fitters 3.3







2.2





None


2.2






2.2

157




Bonnet Seal Leakage Seal incorrectly installed

Effective seal not made Gas leak around seal


2.1






3.3






3.2






2.3

158







2.3



Stem Seal Leakage Wear and Tear Loss of full seal Gas leaks from actuator housing


2.4



Stem Seal Leakage Packing not set correctly Loss of full seal Gas leaks from

actuator housing


2.4



Stem Seal Leakage Wrong packing fitted Loss of full seal Gas leaks from actuator housing


2.4

159




Grease fitting leakage Fitter backs off assembly rather than just the cap

Partial leak Audible evidence of gas release

Using competent fitters 3.3



Grease fitting leakage



Zone 2.2 to 2.3 2. Tubing spool to tubing hanger seal - Primary Barrier


Leakage around seal Seal fails to remain energised

Over a period of time seal is permanent deformed

Pressure build up in the cavity between tree and tubing hanger. Secondary barriers provided by tie down bolt arrangement, chemical injection point, downhole safety valve point, tubing hanger to casing spool seal.

None. 1.3



Leakage around seal Seal incorrectly installed Effective seal not made Gas leakage around

seal


1.1

160






None


1.2







1.2






1.2




Gradual determination of seal, causing increasing leakage over a period of time



2.2

161


Zone 2.2 to 2.3 3. Tubing spool to Casing Hanger Seal - Primary Barrier



Over a period of time seal is permanently deformed

Pressure build up in the B annulus. Secondary barriers provided by tie down bolt arrangement, chemical injection point, downhole safety valve point, tubing hanger to casing spool seal.


3.3




seal


1.1





None


1.2







1.2

162







1.2





Leakage around seal increasing over time. Casing hanger may drop as a result of seal determination.


2.2

Zone 2.2 to 2.3 4. Production Tubing to Tubing Hanger Seal - Primary Barrier




Ineffective seal

Leakage of gas past threaded connection consequently pressurising the cavity between tree and tubing hanger. Secondary barriers provided by tie down bolt arrangement, chemical injection point, downhole safety valve point, tubing hanger to casing spool seal.

None. 2.2

163






None. 2.2






None. 2.2

164








None. 2.2




Jumping out or 'unzipping' of the threadJoint opens


None. 2.2

165




Failure of threaded connection Shearing of threads

Joint integrity reduced or failed


None. 2.2

Zone 2.2 to 2.3 5. Upper Well annulus -Primary Barrier

To provide containment for hydrocarbon gas to be injected into production bore

Casing Spool failure Manufacturing defect Stress raisers and crack initiators



1.2





Ineffective seal


None. 2.2

166






None. 2.2






None. 2.2

167








None. 2.2






None. 2.2

168







None. 2.2

Zone 2.2 to 2.3 6. Tubing hanger body - Primary Barrier

To provide a continuous bore between the tree and the production tubing

Production bore failure Manufacturing defect Stress raisers and crack initiators



1.1

Zone 2.2 to 2.3

7. Tubing hanger downhole safety valve control line lower packing gland (x2) - Primary Barrier


Loss of integrity of packing gland body thread causing trapped pressure to leak up to upper packing gland. Coincident failure of upper packing gland would lead to trapped pressure leaking into cavity between tubing hanger and tree.





3.3

169


Zone 2.2 to 2.3








3.3

Zone 2.2 to 2.3







1.3

Zone 2.2 to 2.3







1.3

170


Zone 2.2 to 2.3






None. 1.3

Zone 2.2 to 2.3

8. Tubing hanger downhole chemical injection line lower packing gland - Primary Barrier







3.3

171


Zone 2.2 to 2.3








3.3

Zone 2.2 to 2.3







1.3

Zone 2.2 to 2.3







1.3

172


Zone 2.2 to 2.3






None. 1.3

Zone 2.2 to 2.3

9. Tubing spool downhole chemical injection line - Primary Barrier


Rupture of chemical injection line - below tubing hanger


Pressurisation of void between the tubing hanger and the dual bore upper packer with chemicals.

Pump Labouring (audible) - increased injection rate Significant increase of dosing rate of chemicals.


1.2

Zone 2.2 to 2.3

10. Tubing spool downhole safety valve control line - Primary Barrier

Provide a conduit for hydraulic fluid for control of the down hole safety valves

Rupture of down hole safety valve control line - below tubing hanger


Pressurisation of void between the tubing hanger and the dual bore upper packer with hydraulic fluid



1.2

173


Zone 2.2 to 2.3 11. Production tubing - primary barrier

Production tubing will provide a conduit for the hydrocarbon fluid to the topsides process plant.

Production tubing ruptures

Manufacturing defect Stress raisers and crack initiators

Leakage of gas into the production tubing No credible effect, since gas pressure should be higher than hydrocarbon fluids.


1.2





Ineffective seal



1.2






1.2







1.2

174









1.2







1.2




or failed



1.2

Zone 2.2 to 2.3 12. Annulus Tubing Spool Valves - Primary Barrier






Designers and manufact urers to have ISO quality systems in place. Offshore supervisors checks and balances i.e. permit to work system etc.

2.2

175







None


2.2







2.2






2.1







3.3







3.2

176








2.3







2.3


To provide a facility to isolate the A,B or C annulus and with instrumentat ion monitor annular pressures



2.4



Stem Seal Leak Packing not set correctly Loss of full seal

Gas leaks from handle assembly


2.4





2.4

177











Zone 2.2 to 2.3

13. Upper annulus tubing spool monitor and vent assembly - Primary Barrier






1.1

Zone 2.2 to 2.3







2.2

Zone 2.2 to 2.3





None


2.2

178


Zone 2.2 to 2.3






2.2

Zone 2.2 to 2.3



Failure of bonnet seal Seal incorrectly installed



2.1

Zone 2.2 to 2.3






3.3

Zone 2.2 to 2.3






3.2

Zone 2.2 to 2.3






2.3

179


Zone 2.2 to 2.3






2.3

Zone 2.2 to 2.3






2.3

Zone 2.2 to 2.3







3.3

Zone 2.2 to 2.3








3.3

Zone 2.2 to 2.3






None


2.2

180


Zone 2.2 to 2.3








2.2

Zone 2.2 to 2.3







2.2

Zone 2.2 to 2.3





seal


2.1

Zone 2.2 to 2.3






Emplo y competent individuals and appropriate supervision is available.

3.3

Zone 2.2 to 2.3







3.2

181


Zone 2.2 to 2.3







2.3

Zone 2.2 to 2.3







2.3

Zone 2.2 to 2.3





2.4

Zone 2.2 to 2.3



Stem seal leakage Packing not set correctly Loss of full seal



2.4

Zone 2.2 to 2.3





2.4

Zone 2.2 to 2.3 14. Tubing hanger tie down bolts and seals - Secondary Barrier

To provide a secondary barrier between the casing spool and the tie down bolts





2.2

182


Zone 2.2 to 2.3



Loss of integrity of packing gland body thread causing trapped pressure to leak into cavity between tubing hanger and tree. On coincident failure of lower packing gland.





3.3

Zone 2.2 to 2.3








3.3

Zone 2.2 to 2.3







1.3

183


Zone 2.2 to 2.3







1.3

Zone 2.2 to 2.3

15. Tubin g hanger downhole safety valve control line upper packing gland - Secondary Barrier





None. 1.3

184


Zone 2.2 to 2.3








3.3

Zone 2.2 to 2.3

16. Tubing hanger downhole chemical injection line up per packing gland - Secondary Barrier







3.3

Zone 2.2 to 2.3


Provide a seal bet ween the Chemical Injection line and the tubing hanger body





1.3

185


Zone 2.2 to 2.3







1.3

Zone 2.2 to 2.3






None. 1.3








2.3

186







None


1.2








1.2







1.2




Seal incorrectly installed Effectiv e seal not made Gas leakage around

seal


1.1

Zone 2.2 to 2.3







2.2

187


Zone 2.2 to 2.3





None


1.2

Zone 2.2 to 2.3







1.2

Zone 2.2 to 2.3






1.2

Zone 2.2 to 2.3




seal


1.1

188


Zone 2.2 to 2.3






Designers and manufacturers to have ISO quality systems in place. Offshore supervisors checks and balances. Pressure test of complete assembly .

2.2

Zone 2.2 to 2.3





None


1.2

Zone 2.2 to 2.3







1.2

Zone 2.2 to 2.3




Seal incorrectly specified in design

None


1.2

189


Zone 2.2 to 2.3



Leakage around seal Seal incorrectly installed


Employ competent individuals and appropriat e supervision is available. Pressure tested after envelope broken.

1.1

Zone 2.2 to 2.3







2.2

Zone 2.2 to 2.3




seal


1.1

Zone 2.2 to 2.3





None


1.2

190


Zone 2.2 to 2.3







1.2

Zone 2.2 to 2.3






1.2

Zone 2.2 to 2.3




seal


1.1

Zone 2.2 to 2.3





None


1.2

191


Zone 2.2 to 2.3







1.2

Zone 2.2 to 2.3






1.2

Zone 2.2 to 2.3







2.2

Zone 2.2 to 2.3



Rupture of chemical injection line - between tubing spool and tree cavity


Pressurisation of void between the tree and tubing spool with chemicals.



1.2

192


Zone 2.2 to 2.3


Provide a conduit for hydraulic fluid for control of the down hole safety valves

Rupture of down hole safety valve control line - between tubing spool and tree cavity


Pressurisation of void between the tree and tubing spool with hydraulic fluid



1.2


To provide containment for hydrocarbon gas to be injected into production bore

Casing Spool failure Manufacturing defect Stress raisers and crack initiators



1.2





Ineffective seal


None. 2.2

193





Galling on seal face Ineffective seal


None. 2.2






None. 2.2

194








None. 2.2




Jumping out or 'unzipping' of the thread

Joint opens


None. 2.2

195





Shearing of threads Joint integrity reduced or failed

Leakage of gas past threaded connection consequently pressurising the cavity between tree and tubing hanger. Secondary barriers provided by tie down bolt arra ngement, chemical injection point, downhole safety valve point, tubing hanger to casing spool seal.

None. 2.2


To provide addition barrier in A annulus



Ineffective seal

No credible effect, gas already present in both upper and lower A annulus.

Not Applicable 2.2





Not Applicable 2.2






Not Applicable 2.2







Not Applicable 2.2






Not Applicable 2.2




or failed


Not Applicable 2.2

196








Correct specification of seals. Manufacturers and designers have suitable quality assurance system in accordance with ISO or equivalent.

1.1






Upper A annulus already pressurised with gas, therefore pressure of gas potentially higher than hydrocarbon fluid inhibiting the leak into the upper A annulus.


2.1


Production tubing will provide a conduit for the hydrocarbon fluid to the topsides process plant.

Production tubing ruptures Manufacturing defect Stress raisers and crack

initiators



1.2





Ineffective seal



1.2

197





Galling on seal face Ineffective seal



1.2







1.2








1.2







1.2

198





Shearing of threads Joint integrity reduced or failed



1.2

Zone 2.3 to 2.4 4. B Annulus Casing - secondary barrier

To give additional protection to the formation to the top of the pay zone.






1.3







4.3



Production casing split or parted Incorrect casing design Casing could part

Gas lift pressure leakage into the C annulus, consequently annular valves on C annulus become primary barrier. C annulus is rated to a lower pressure than the B annulus.


199






Precipitation of Chromium Carbides under incorrect welding and heat treatment regimes.



2.3





Ineffective seal


Instrument monitor facility on B & C annulus. Pressure in B and C annulus monitored by plant operators.

2.2






2.2

200








2.2








2.2







2.2

201








2.2

Zone 2.3 to 2.4 5. B Annulus Tubing Spool Valves - Secondary Barrier

To provide a facility to isolate the B annulus and with instrumentation monitor annular pressures






2.2






None


2.2







2.2

202





Seal incorrectly installed



2.1







3.3







3.2







2.3







2.3

203






2.4



Stem Seal Leak Packing not set correctly Loss of full seal


Perform maintenance and in spection in accordance with manufacturers requirements.

2.4





2.4


To provide a facility to isolat e the B annulus and with instrumentation monitor annular pressures








Zone 2.3 to 2.4


To provide a facility for pressure monitoring equipment to be linked to the B annulus





1.1

204


Zone 2.3 to 2.4







2.2

Zone 2.3 to 2.4





None


2.2

Zone 2.3 to 2.4






2.2

Zone 2.3 to 2.4





2.1

Zone 2.3 to 2.4






3.3

205


Zone 2.3 to 2.4






3.2

Zone 2.3 to 2.4






2.3

Zone 2.3 to 2.4





Employ competent individuals and appropriat e supervision is available. Pressure tested after envelope broken.

2.3

Zone 2.3 to 2.4






2.3

Zone 2.3 to 2.4







3.3

Zone 2.3 to 2.4








3.3

206


Zone 2.3 to 2.4






None


2.2

Zone 2.3 to 2.4








2.2

Zone 2.3 to 2.4







2.2

Zone 2.3 to 2.4





seal


2.1

Zone 2.3 to 2.4







3.3

207


Zone 2.3 to 2.4







3.2

Zone 2.3 to 2.4







2.3

Zone 2.3 to 2.4







2.3

Zone 2.3 to 2.4





2.4

Zone 2.3 to 2.4 7. B annulus tubing spool to casing hanger seal - Primary Barrier



Over a period of time seal is permanently deformed

Pressure build up in the B annulus. Secondary barriers provided by tie down bolt arrangement, chemical injection point, downhole safety valve point, tubing hanger to casing spool seal.


3.3

208




Leakage around seal Seal incorrectly installed



1.1





None


1.2







1.2






1.2







2.2

209






Ineffective seal


Not Applicable 2.2





Not Applicable 2.2




Insufficient make up torque

Ineffective seal


Not Applicable 2.2







Not Applicable 2.2




Jumping out or 'unzipping' of the thread

Joint opens


Not Applicable 2.2




or failed


Not Applicable 2.2







Correct specification of seals. Manufacturers and designers have suitable quality assurance system in accordance with ISO or equivalent.

1.1

210







Upper A annulus already pressurised with gas, therefore pressure of gas potentially higher than hydrocarbon fluid inhibiting the leak into the upper A annulus.


2.1



Failure of the packer sealing element Incorrectly set None.



2.2




Determination of the packer sealing element None.



2.2




Determination of the annulus upper bore tubing stab seal

None.



2.2








1.3

211






Localised corrosion



4.3



Lower annulus casing split or parted Incorrect casing design Casing could part







Precipitation of Chromium Carbides under incorrect welding and heat treatment regimes.



2.3

212






Ineffective seal



2.2






2.2







2.2

213









2.2







2.2




or failed



2.2

214





Incorrect set pressure Gas is not injected at the right level in the production string

Gas lift is not effective, if well is reliant on gas lift well may not flow.


1.2




Orifice valve seized - closed

Gas is not injected into the production string

Gas lift is not effective, if well is reliant on gas lift well may not flow. Lower A annulus is pressurised beyond normal operating conditions.


1.2

Zone 2.4 to 2.6 5. Chemical Injection Line – primary barrier



Operational loads exceeded Line could split

Chemical injection line subject to backpressure from injection gas under normal chemical injection activities. Chemical injection pressure will increase. Chemical injection line pressurised with injection gas when not injecting chemicals.


2.3




Operational loads exceeded Fatigue

Combination of vibration and tension in line due to slippage of supports. Pressure cyclic effects from injecting.

Correct supporting arrangement. 2.3

215





Operational loads exceeded Incorrect installation

Joint leakage at either dual bore upper packer or connection to production tubing. Chemical injection line subject to backpressure from injection gas under normal chemical inject ion activities. Chemical injection pressure will increase. Chemical injection line pressurised with injection gas when not injecting chemicals.


2.3




Operational loads exceeded

Corrosion of fittings

Due to residual liquids from previous operations. Chemical injection line subject to backpressure from injection gas under normal chemical injection activities. Chemical injection pressure will increase. Chemical injection line pressurised with injection gas when not injecting chemicals.

Corrosion/materials engineer to ensure compatibility of materials with environment.

2.3

216





Determination of the lower chemical injection line seal


Upper chemical injection line seal to dual bore upper packer takes lower A annulus pressure. Coincidental failure of upper chemical injection line seal to dual bore upper packer to upper A annulus pressurise with gas.


2.2








2.3




Determination of the upper chemical injection line seal


Failure of upper chemical injection line seal to dual bore upper packer to upper A annulus pressurise with gas. Failure of lower chemical injection line seal to dual bore upper packer to upper A annulus pressurise with gas.


2.2








2.3

217

APPENDIX G

DUAL COMPLETION MODEL DRAWINGS

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APPENDIX H

SINGLE COMPLETION MODEL DRAWINGS

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Printed and published by the Health and Safety ExecutiveC0.35 01/02

OTO 2001/061

£35.00 9 780717 622443

ISBN 0-7176-2244-4

Documents

OFFSHORE TECHNOLOGY REPORT 2001/061 - Health and Safety ... · PDF filefor the Health and Safety Executive OFFSHORE TECHNOLOGY ... valve and allowing the gas accumulated ... The gas