departamento de ingenieria de produccion.pdf

Master thesisWELL INTEGRITY OF SUBSEA WELLS DURING LIGHT WELL INTERVENTIONS

By Stud.techn. Sigbjrn Tornes Birkeland June 2005

Well Integrity of Subsea Wells during Light Well Interventions

PrefaceThis thesis constitutes the results of the 10th semester of my master degree program at the Norwegian University of Science and Technology, Department of Production and Quality Engineering, Trondheim. During the work, I would like to thank my teaching supervisor, Professor Marvin Rausand Department of Production and Quality Engineering, Trondheim and assisting supervisor Eivind Okstad at Sintef. I would also like to thank Professor Sigbjrn Sangesland, at Department of Petroleum Engineering and Applied Geophysics, NTNU for advising me where to gather information and comments on important issues related to Riserless Light Well Intervention (RLWI) and Big Bore Completions (BBC). Finally I would like to thank Jan Fredrik Carlsen, and Harald Hansen at FMC Kongsberg Production Services AS for providing me with valuable information regarding RLWI and a stay at Kongsberg.

Trondheim, Norway, 15.06.2005

Sigbjrn T. Birkeland Stud. techn.

Master thesis Norwegian University of Science and Technology, 2005

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SummaryAs the offshore oil and gas production continues to grow, the number of subsea wells continues to increase. Today, there are roughly 2,000 subsea wells worldwide, in water depth up to 2,000 m. About 400 of these subsea wells are located on the Norwegian Continental Shelf (NCS), and they account for almost half of the oil and gas produced in this region. Installation and maintenance of subsea wells are traditionally performed by costly, moored, semi-submersible drilling rigs. Maintenance of subsea wells improves the recovery rate. This is the principal driving force behind the development of light well intervention technology. The thesis introduces and discusses different methods for subsea well intervention. The main equipment and well intervention tasks is described. Furthermore focus is put on identification of hazards and operability problems that may interfere during light well intervention tasks. The concept of well integrity during light well intervention is discussed bases on NORSOK D-010 Well integrity in drilling and well operations. The section incorporates technical, operational and organizational solutions to reduce the risk of uncontrolled release of formation fluids throughout the entire life cycle of a well. A framework for Project Risk Analysis of a light well intervention project is carried out. The purpose of the framework is to provide a consistent and systematic approach to risk handling for light well intervention operations in order to allow project teams to proactively identify and prevent problems or reduce the impact of problems when they do occur. A hazard identification (HAZID) analysis is performed to identify potential hazards and operability problems related to subsea light well intervention operations by use of the RLWI system. The analysis is performed by combining the main operational phases and critical events during operation. Based on the analysis, important issues and risk reducing measures are discussed. Hazards and operability problems related to light well intervention in BBC are shortly described. The main factors which differentiate conventional and Big Bore completed light well interventions are discusses. Appendix B is carried out in corporation with FMC Kongsberg Subsea Production Services AS. A technical description of the current RLWI design is presented. Furthermore the evolution of the current RLWI concept is shown, based on the patent WO 01/25593 and two different alternative configurations before a simplified design are presented. A well barrier analysis of the simplified system is conducted for the phases affected of the design changes. The suggested changes are evaluated after the evaluation criterias functionality, barrier element and ability to perform testing. Finally, an evaluation of alternative designs for the Wireline Seal Shear Ram (WRRS) in the lubricator section is suggested.


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AbbreviationsBOP CT CXT DHSV DP DTC ESD EQD FMECA HAZID HAZOP HXT LIP LLP LUB NCS NPD PBR PCH PHA PLT PMV PSA PSV PWV RLWI SCSSV SJA SSR TCBV ULP WBE WL WLRSCSSV WHP PHA THCP TRSCSSV Blow Out Preventer Coiled Tubing Conventional X-mas Tree Down Hole Safety Valve Dynamic Positioned Debris Tree Cap Emergency Shut Down Emergency Quick Disconnect Failure Mode and Criticality Analysis Hazard Identification Hazard and operability Horizontal X-mas Tree Lower Intervention Package Lower Lubricator Package Lubricator Tubular Norwegian Continental Shelf Norwegian Petroleum Directorate Polish Bore Receptacle Pressure Control Head Preliminary Hazard Analysis Production Logging Tool Production Master Valve Petroleum Safety Authority Production Safety Valve Production Wing Valve Riserless Light Well Intervention Surface Controlled Subsurface Safety Valve Safe Job Analysis Shear Seal Ram Tubing hanger Crown plug Ball Valve Upper Lubricator Package Well Barrier Element Wireline Wireline Retrievable Surface Controlled Subsurface Safety Valve Well Head Pressure Preliminary Hazard Analysis Tubing Hanger Crown Plug Tubing Retrievable Surface Controlled Subsurface Safety Valve


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Table of contentsPREFACE............................................................................................................................................................. II SUMMARY .........................................................................................................................................................III ABBREVIATIONS ............................................................................................................................................. IV TABLE OF CONTENTS......................................................................................................................................V TABLE OF FIGURES...................................................................................................................................... VII LIST OF TABLES ............................................................................................................................................ VII 1 INTRODUCTION ....................................................................................................................................... 8 1.1 1.2 2 OBJECTIVES AND LIMITATIONS ............................................................................................................. 9 REPORT STRUCTURE ........................................................................................................................... 10

SUBSEA LIGHT WELL INTERVENTION METHODS ..................................................................... 11 2.1 2.2 2.3 2.4 RIG ISSUES .......................................................................................................................................... 12 WHY IS INTERVENTION NEEDED? ........................................................................................................ 11 CLASSIFICATION OF SUBSEA INTERVENTION ....................................................................................... 11 LIGHT AND HEAVY WELL INTERVENTION. ......................................................................................... 12

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TECHNICAL DESCRIPTIONS .............................................................................................................. 12 3.1 WIRELINE METHOD ............................................................................................................................. 13 3.1.1 Stuffing box.................................................................................................................................... 13 3.1.2 Lubricator ..................................................................................................................................... 14 3.1.3 Blow Out Preventer (BOP) ........................................................................................................... 14 3.1.4 Wireline unit.................................................................................................................................. 14 3.1.5 Hydraulic powerpack .................................................................................................................... 14 3.1.6 Measuring device .......................................................................................................................... 14 3.1.7 Control system............................................................................................................................... 15 3.1.8 Tool string ..................................................................................................................................... 15 3.1.9 Well tractor ................................................................................................................................... 15 3.1.10 Wireline .................................................................................................................................... 16 3.2 COILED TUBING (CT) ......................................................................................................................... 17 3.2.1 Injector head ................................................................................................................................. 17 3.2.2 Coiled tubing reel.......................................................................................................................... 18 3.2.3 Well control equipment ................................................................................................................. 18 3.2.4 3.2.4 Powerpack............................................................................................................................ 18 3.2.5 3.2.5 Gooseneck ............................................................................................................................ 19 3.2.6 Lifting frame.................................................................................................................................. 19

4 LIGHT WELL INTERVENTION AS A PROJECT. FRAMEWORK FOR PROJECT RISK ANALYSIS .......................................................................................................................................................... 20 4.1 INTRODUCTION ................................................................................................................................... 20 4.2 THE OBJECTIVES OF PROJECT RISK ANALYSIS...................................................................................... 20 4.3 STANDARDS AND GUIDELINES FOR PROJECT RISK ANALYSIS ............................................................... 20 4.4 THE PROCESS OF PROJECT RISK ANALYSIS........................................................................................... 22 4.5 EVENT AND PARAMETER UNCERTAINTIES IN PROJECTS ..................................................................... 24 4.6 CONTINGENCY PLANNING ................................................................................................................... 24 4.7 QUALITATIVE RISK ANALYSIS ............................................................................................................. 24 4.8 QUANTITATIVE RISK ANALYSIS ........................................................................................................... 24 4.9 SEMI-QUANTITATIVE ANALYSIS .......................................................................................................... 25 4.10 APPLICATION AREA FOR PROJECT RISK ANALYSIS ............................................................................... 25 4.10.1 Toolbox meeting/ Safe Job Analysis (SJA) ............................................................................... 25 4.10.2 Procedure Hazard and Operability (HAZOP) analysis............................................................ 25 4.11 DISCUSSION ........................................................................................................................................ 26


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Well Integrity of Subsea Wells during Light Well Interventions5 WELL INTEGRITY ................................................................................................................................. 27 5.1 INTRODUCTION ................................................................................................................................... 27 5.2 WELL INTEGRITY ................................................................................................................................ 27 5.2.1 Well Barriers................................................................................................................................. 27 5.2.2 Well Barrier methodology............................................................................................................. 28 5.2.3 Barriers in well operations ........................................................................................................... 29 5.2.4 Well barrier characteristics .......................................................................................................... 29 5.3 DISCUSSION ........................................................................................................................................ 30 6 6 RISERLESS LIGHT WELL INTERVENTION (RLWI) .................................................................. 32 6.1 6.2 6.3 INTRODUCTION ................................................................................................................................... 32 AREA OF APPLICATION ........................................................................................................................ 32 DESCRIPTION OF THE RISERLESS LIGHT WELL INTERVENTION (RLWI) SYSTEM ................................ 33 ..................................................................................................................................................................... 33 6.3.1 Lower Intervention Package (LIP)................................................................................................ 34 6.3.2 6.3.5 Lower Lubricator Package (LLP) ........................................................................................ 34 6.3.3 Lubricator Tubular (LUB) ............................................................................................................ 34 6.3.4 Upper Lubricator Package (ULP) ................................................................................................ 34 6.3.5 Pressure Control Head (PCH) ...................................................................................................... 34 6.3.6 Umbilical system ........................................................................................................................... 35 6.3.7 Control system............................................................................................................................... 35 6.4 RISERLESS LIGHT WELL INTERVENTION SYSTEM IN OPERATION......................................................... 35 7 HAZARD ASSESSMENT DURING WELL INTERVENTION .......................................................... 36 7.1 INTRODUCTION ................................................................................................................................... 36 7.2 STANDARDS AND REGULATIONS ......................................................................................................... 36 7.3 METHODS TO IDENTIFY HAZARDS AND OPERABILITY PROBLEMS. ....................................................... 36 7.3.1 HAZID Hazard Identification..................................................................................................... 36 7.3.2 HAZID process.............................................................................................................................. 37 7.3.3 Failure Modes, Effects and Criticality Analysis (FMECA)........................................................... 37 7.3.4 What- If analysis. .......................................................................................................................... 37 7.3.5 Hazard and Operability Analysis (HAZOP).................................................................................. 37 7.3.6 HAZOP process............................................................................................................................. 38 7.4 IDENTIFICATION OF POTENTIAL HAZARDS AND OPERABILITY PROBLEMS DURING A LIGHT WELL INTERVENTION OPERATION. .............................................................................................................................. 39 7.4.1 Description of operational phases. ............................................................................................... 39 7.4.2 Identification of operational events............................................................................................... 40 7.5 COMBINATION OF PHASES AND EVENTS IN A MATRIX.......................................................................... 42 7.6 DISCUSSION ........................................................................................................................................ 42 7.7 CONCLUSION ...................................................................................................................................... 44 8 LIGHT WELL INTERVENTION IN BIG BORE COMPLETED WELLS ....................................... 45 8.1 8.2 8.3 INTRODUCTION ................................................................................................................................... 45 BIG BORE COMPLETIONS .................................................................................................................... 45 IDENTIFICATION OF HAZARDS AND OPERABILITY PROBLEMS FOR BBC RELATED TO WELL INTEGRITY DURING LIGHT INTERVENTION ........................................................................................................................... 45 8.3.1 Evaluation of upstream forces for Big Bore Completions............................................................. 45 8.3.2 Evaluation of equipment specifications needed for Big Bore light well interventions .................. 47 8.4 HAZARDS AND OPERABILITY PROBLEMS THAT MAY OCCUR DURING LIGHT WELL INTERVENTION IN BIG BORE COMPLETIONS ......................................................................................................................................... 48 8.5 DISCUSSION ........................................................................................................................................ 48 9 10 11 CONCLUSIONS........................................................................................................................................ 49 RECOMMENDATIONS FOR FURTHER WORK............................................................................... 50 REFERENCES .......................................................................................................................................... 51


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Table of figuresFigure: 0-1:Frontpage. Riserless Light Well Intervention system in operation. Adapted from (Andersen, 2004)..I Figure 2-1: Subsea light well intervention system. Adapted from (Dick, 2004) ..................... 11 Figure 2-2: Indicate degree of intervention.............................................................................. 12 Figure 3-1: Subsea lubricator configuration located on a subsea well. Adapted from (Mller, 2004)...................................................................................................................... 13 Figure 3-2: Wireline tractor. Adapted from (Hansen, 2002).................................................... 15 Figure 4-1: The steps in a risk management process. Adapted from (BS 6079-3, 2000) ........ 22 Figure 4-2: Procedure framework for risk -and project risk analysis. Adapted from ROSS Community 23 Figure 4-3: Indication of complexity versus time for planning and handling of operations.... 25 Figure 5-1: Well barrier schematic of a CT intervention stack up. Adapted form (NORSOK D-010, 2004).......................................................................................................... 28 Figure 5-2: Methodology for breakdown of well barriers........................................................ 30 Figure 6-1: The modules of the RLWI configuration. Adapted from (Andersen, 2004) ......... 33 Figure 7-1: Show the steps in a HAZOP process chart............................................................ 39 Figure 8-1: Conventional versus big bore tubing diameters. ................................................... 46 Figure 8-2: Simplified upstream wellhead forces for three different completion sizes ........... 46 Figure 8-3: Required accumulator volumes with respect to water depth to operate a BOP shear/seal valve...................................................................................................... 47

List of tablesTable 2.3-1: Categrization of subsea well intervention. Adapted from (Andersen, 2005) ...... 11 Table 3.1-1: Typical tasks for wireline operations................................................................... 16 Table 4.9-1: Estimating scales: Adapted from (Mogstad, 2000) ............................................. 25 Table 5.2-1: Typical well barriers. Adapted from Holand et al (2003) ................................... 29 Table 7.4-1: The main operational phases during a RLWI operation ...................................... 40 Table 7.4-2: Operational events during a well intervention using subsea lubricator .............. 40 Table 7.5-1: Combination matrix of operational phases and events.42

Appendix listAppendix A: HAZID analysis of a light well intervention by use of the RLWI system Appendix B: A simplified valve configuration for the RLWI system


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1 IntroductionThe petroleum activity on the Norwegian Continental Shelf (NCS) has reached a mature stage. One of the main work areas, from a technological point of view, is to increase the recovery rates from existing oil and gas infrastructures. Subsea wells have traditionally a lower recovery rate than platform wells. The main reason for this gap is related to well intervention costs. Increasing focus will be put on well interventions in subsea wells on the (NCS), and the different tasks that are necessary to carry out such interventions. Many mature fields need to intensify well intervention to both maintain production through well stimulation, sand or scale handling, and for replacing systems and components that are worn. New technology creates more cost effective methods to carry out lighter intervention tasks, such as riserless light intervention and other subsea lubricator systems. This is contributing to close the gap between platform and subsea completed wells. NPD statistics show that reservoir recovery is 36% for subsea wells and 44% for platform wells. Today there are 17 subsea fields in operation on the NCS today. The total amount of oil recovery is 5.7 Bn Bbl of oil at 33% reservoir recovery. By increasing subsea recovery rates to 44% this will over a 10 year time period give 1 Bn Bbl of oil (Inderberg, 2005). With todays oil price this approximately 300 Billion NOK in potential extra values. Challenges for the new technological solutions such as RLWI are to perform light well intervention without compromising the well integrity during operation. This thesis identifies and evaluates hazards and operability problems related to light well intervention tasks conducted from a relatively small DP vessel as top side facility. In appendix F is linked to FMC Kongsberg Subsea Production Services AS. A Riserless Light Well Intervention (RLWI) system is here evaluated with respect to well barrier during operation. The analysis suggests a simplified design. Appendix F is classified as restricted on request from the company.


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1.1 Objectives and limitationsThe main objective of this thesis is to evaluate well integrity when performing light well intervention in subsea wells. The objectives and limitations are specified below. 1. The first task shall covers definitions and descriptions of the main tasks for typical light well interventions into subsea wells by use of the wireline and the coiled tubing method. Descriptions of the main equipment components to carry out the tasks are included. This section shall give a base for the further tasks. The primary focus is set on Wireline operations since this is of most relevance today. 2. A framework for Project Risk Analysis for light well intervention projects shall be established. This shall give an overview of how to handle risks, methods to be used and when to use the methods. 3. The concept of well integrity shall be defined and discussed based on the NORSOK standard D-010 Well integrity in drilling and well operations. The primary focus for this section shall be how well barriers affect the integrity of a well. 4. Identification and discussion of potential hazards and operability problems during light well intervention shall be performed by using a RLWI system. HAZID is chosen to be the method of analyze. The discussion shall contain suggestions of risk reducing measures for the analyzed operation. The costs of the potential hazards and operability problems are not detailed described, because available information is limited. 5. An evaluation of light well interventions in Big Bore completed wells shall be carried out. This section shall focus on potential hazards and operability problems related to well integrity during light intervention by increasing the production tubing diameter. Thereby measures to reduce Big Bore related problems shall be suggested. Point 5 and 6 are merged together because to author 6. A barrier analysis shall be performed on a RLWI system. Based on the analysis a simplified RLWI design shall be suggested. This is carried out in appendix F


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1.2 Report structureThe report structure Chapter 1 provides the necessary background information, objectives and limitations, and a presentation of the master thesis structure. Chapter 2 gives an introduction to subsea light well intervention methods. Definitions and categorization of intervention tasks are described. The background for why there is a demand for intervention in subsea wells is explained. Chapter 3 gives a technical description of the main equipment needed to carry out wireline and coiled tubing operations. Chapter 4 introduces a framework for project risk analysis in conjunction with light well interventions. Chapter 5 introduces and discusses the concept and factors which affect the integrity of subsea wells during light well interventions based on NORSOK D-010. Chapter 6 covers a describing and discussion of the main operational benefits and weaknesses by using the RLWI system. Chapter 7 describes a basis for identification and evaluation of hazards and operability problems related to light well interventions in general. Chapter 8 discusses hazard and operability problems for light well intervention in big bore completed wells. Chapters 9 conclude and summarize the results of the thesis. Chapter 10 gives a recommendation for further work. Appendix F evaluates the valve configuration of the current RLWI design before a simplified design is introduces. A barrier analysis is then performed of the suggested simplified RLWI configuration before conclusions and recommendations for further work are given.


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2 Subsea light well intervention methodsAs the deepwater development trend continues to accelerate utilizing subsea wells, the importance of reliable and cost efficient subsea well intervention techniques is a key factor. Subsea intervention tasks are costly and represent a major part of the total recovery costs. Therefore the industry put a lot of effort in developing methods to reduce the expenses of such operations. Figure 2.1 shows an example of a riserless well intervention system.

Figure 2-1: Subsea light well intervention system. Adapted from (Dick, 2004)

2.1 Why subsea intervention is neededSubsea wells are mainly intervened due to reservoir reasons. These vary from field to field due to the different reservoir conditions, the nature of the produced or injected fluids, the configuration and status on the equipment installed. Two of the main objectives are to gain information of the production condition downhole or to stimulate the well production. Wells are normally maintained so that optimal well performance is met. This also includes any modifications of the well completion to enable proper drainage of the reservoir. Data acquisition is required to diagnose the well in case of unexpected performance, verification of the composition and rates from the different zones open to production. This is important to enable the best possible reservoir production management, and in some cases preparation for heavier well intervention operations.

2.2 Classification of subsea intervention When considering a functioning subsea facility, there are three categories of intervention

Table 2.2-1: Categrization of subsea well intervention. Adapted from (Andersen, 2005)

Light interventionThe operation is carried out within the XT and production tubing. And without no use of riser from the subsea well to the topside facility.

Medium interventionSubsea well intervention without removal of XT and with use of high-pressure riser from the well to the topside facility.

Heavy interventionWell workover operations that can imply pulling of tubing and abandonment. Demands complete drilling BOP with stiff riser


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Well Integrity of Subsea Wells during Light Well Interventions . The main parameters for classifying intervention tasks are: Complexity of operation. Time perspective Necessary equipment. Top side facilities.

2.3 Light and heavy well interventionTraditionally well maintenance or workover operations have been divided into, heavy and light interventions. Heavy interventions usually mean operations requiring use of a heavy 18 drilling blowout preventer (BOP) for pressure control. Removal of X-mas tree (XT), tubing replacement and side tracking are typical examples of heavy intervention operations today. This might change over time as capabilities of lighter systems are further developed. Light interventions are commonly used to describe those operations that may be carried out inside or through the XT and completion tubing, i.e wireline and coiled tubing operations. Figure 2.2 illustrates the equipment needed and thereby the time and complexity of performing intervention tasks. The more equipment involved in the workover task the more heavy intervention. In the Ormen Lange Plan for development and operation they also include the term medium intervention which is another way to classify intervention tasks. Medium intervention is defined in table 2.3-1. In this context focus will be set on wireline (WL) and coiled tubing (CT) methods classified as light interventions. Figure 2-2 categorize the different intervention operations. The degree of intervention is a variable of operational complexity and time. Complexity indicates the equipment and accessories needed to carry out the operations.

Complexity

Conventional Drilling and Workover Snubbing and Hydraulic Workover Coiled tubing Wireline

Time

Figure 2-2: Indicate degree of intervention

2.4 Rig issuesTraditionally, drilling rigs have been used for light well intervention operations. However, the availability and flexibility of such drilling rigs have a significant impact on the timing, costs and length of time to perform subsea intervention operations. The development of more flexible, smaller and cost efficient Dynamic Position (DP) vessels now offers a viable option. Well intervention is a regular task on fixed platforms, and is one of the major contributors to increase the recovery rate. It is also accepted that well intervention is required in order to achieve increased recovery rates in present and future subsea wells. Master thesis Norwegian University of Science and Technology, 2005

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3 Technical descriptionsThis chapter gives a general description and overview of conventional methods for subsea light well intervention by use of Wireline (WL) and Coiled Tubing (CT). The main equipment needed to carry out operational demands are briefly introduced and discussed. The literature is based on Subsea Well Intervention (Sangesland, 2004) and Production technique 1 (Jrgensen, 1998)

3.1 Wireline methodThe most frequent technique for intervention is use of WL. In simple steps this is carried out by a tool string attached to a wire that is run by the force of gravity into the well, to perform a maintenance or service operation. The main components of a WL intervention system consists in general of WL, stuffing box, lubricator, blow out preventer (BOP), WL unit, hydraulic powerpack, measuring devices, and a control system. Figure 3-1 shows an subsea lubricator system placed on a XT.

Figure 3-1: Subsea lubricator configuration located on a subsea well. Adapted from (Mller, 2004)

3.1.1 Stuffing box The stuffing box is used as a means of running the WL into a lubricator that is subjected to well pressure. The WL is passed over the sheave wheel and fed down through a packing in the Master thesis Norwegian University of Science and Technology, 2005 13

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Well Integrity of Subsea Wells during Light Well Interventions stuffing box body. During operations the packing is tightened against the solid WL by a packing nut which is either manually or hydraulically operated. The stuffing box incorporates a plunger which in the event of a packing failure or wire breakage is designed to automatically seal off flow. Stuffing boxes also include a quick union connector which can be connected to the lubricator. Typical working pressure for the stuffing box is up to 1000 bar. 3.1.2 Lubricator The lubricator is a pressure containing cylinder that allows the running and removal of WL service tools from a well without having to kill it. Its purpose is to allow the WL tool string to be raised above the wellhead valve prior to and after the WL operations and therefore enables the wellhead valve to be opened and closed allowing entry and exit from the wellbore. The lubricator is normally of long enough to cover the entire workstring. DHSV can be used as lubricator barriers. The sections are joined together by quick unions that can be tightened by hand, and are practically impossible to open while under pressure. 3.1.3 Blow Out Preventer (BOP) The BOP, also called well control package, is a ram equipped stack that involves different valves designed to prevent or control blowouts. Normally at least two rams are used in series, alternatively a dual ram with the same functions can be used. One of the rams will close and seal around the wire, isolating the well pressure from the lubricator section and the other ram is a shear type ram to cut the wire in emergency situations. The BOP is normally hydraulically operated from the workover control system, and is qualified to seal against pressures up to 1000 bar. In addition to the primary power supply from the hydraulic pump an accumulator bank is used as a secondary power system in case of a primary system failure. 3.1.4 Wireline unit The wireline unit consists of an electric or hydraulic driven reel drum containing the wire used to run the tools into and out of the well and a control panel to hydraulically operate actions. The length of the wire stored on the reel depends of the wire diameter, but its typically 7 500 meters. 3.1.5 Hydraulic powerpack The hydraulic powerpack supplies the WL unit with sufficient pressure and flow rates. It is driven by a diesel or electrical motor. 3.1.6 Measuring device The measuring device is an indicator for paid out wire length, and provides the operator with valuable information concerning the tool depth. This is normally performed with a measuring wheel mounted on the WL drum holding the running WL. A weight indicator is used to monitor the load on the wire, and is especially important during pulling operations to protect from equipment failure. The unit consist of a strain pad mounted onto the reel unit connected to a display in a cabin. The pulling force is corrected for the WL angle relative to the wellbore. Master thesis Norwegian University of Science and Technology, 2005 14

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Well Integrity of Subsea Wells during Light Well Interventions 3.1.7 Control system The control functions of the reel and the BOP are located in the control, cabin or close to, and metering parameters such as weight on reel and paid out length are displayed on dials. 3.1.8 Tool string The basic tool string for WL operations consists if a: rope socket, WL stem, knuckle joint, jar and tools. The rope socket is a device to connect the wire and toolstring. The WL stem are weight elements used to add weight to the toolstring for jarring operations. The amount depends on the well pressure and weight of the device to be run or pulled. The knuckle joints are formed as balls or sockets joints that provide a flexible element to permit angular movement in crooked or cork screwed tubing. These joint can rotate 360 deg. and bend up to 15 deg. The jar is mechanical or hydraulically operated device used to impose jarring impacts using the weight of the stems to supply force. The tools required to perform the specific operation will be attached to the end of the basic tool string and can be divided into four categories: Service tools. Running and pulling tools. Testing, gauging and monitoring tools. Shifting tools. 3.1.9 Well tractor A well tractor can pull and retrieve a WL or a CT in and out of deviated parts of a well. The tractors contain wheels that make it possible to run and retrieve tools. The main limitations incorporated with WL operations have traditionally been to reach the operation area in deviated wells due to use of the gravity principle. As a rule of thumb a maximum deviation angle of 70 deg. have been considered to be the limit for the WL method. This is carried out by use of WL tractors. Figure 3-2 shows a well tractor.

Figure 3-2: Wireline tractor. Adapted from (Hansen, 2002)


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Well Integrity of Subsea Wells during Light Well Interventions 3.1.10 Wireline There are mainly three types of wireline. Slick line. Braided line. Electrical line. Slickline is the one with smallest diameter continuous solid wire. It is only capable of pulling and pushing by jarring action. Typical breaking strength of a 0.108 wire is between 7500 N and 12500 N dependent of material specifications. Braided line is used for more heavy duty pulling work. The wire consists of two layers of spirally coiled armour wire. Braided line without an electrical conductor in the middle is also referred to as sand line and is used as a heavy-duty slickline. A typical 3/16 braided wire has normally a breaking strength between 20000 N and 30000 N depending on the material applied. The third application WL method is an electrical line also called mono-conductor cable. This is a braided line with one or more electric conductors in the middle. It is used when using intervention tools that require electric power or signal. The electrical lines have reduced breaking strain compared to a slick line because of the conductor inside. The electrical lines that only have one conductor inside are called mono-conductor cables. They are commonly 3/16, 7/32 5/16 3/8 and 7/16. The smallest sizes are used for through tubing well servicing, while the larger sizes usually are used for smaller suites of openhole logs. Some electrical lines have 7 conductors (logging cables,) and are used exclusively for openhole logging. These logging cables are normally used on drilling rigs with well control by means of a column of mud. An important issue for WL operations are that the wire should not be worked past the plastic deformity limit, which usually is 50 % of the breaking strength. The electrical lines are not used to manipulate tools downhole and the toolstring does not contain any jars or running/pulling tools. The rope socket or cable head that attaches the electric line to the toolstring is specially made. If electric WL tools get stuck in the hole, a pull below the breaking strain of the wire will break a weak point in the cable head and allow the wire to be retrieved. In addition to being stronger, the main difference between slick and braided line is the pressure control required. Because the braided line is made of an inner core and two layers of wires, is it possible for well pressure to pass through the inside of the cable. This makes it necessary to use grease as a seal within the wire.Table 3.1-1: Typical tasks for wireline operations.

Slick line Braided line Electrical line Running and pulling Heavier and deeper Data gathering/ plugs, chokes, valves. work outside the logging tools. working scope of Perforation. slick line. Opening and closing Chemical cutting circulation devices. Fishing for larger lost Setting packers and objects. bridge plugs. Running gas lift or Pulling and retrieving Determining freepoint chemical injection WL-SCSSV. (stuckpoint) equipment.


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In a few years the WL may be replaced by a carbon composite line. The main features of such a line are increased strength and more flexibility, because it reduces the wear in the tubing. A slick or braided WL can sometimes have a cutting effect on the completion component. This has been a problem especially for the down hole safety valves (DHSV). The WL creates a risk of damaging the sealing capabilities for this valve and other valves, which can lead to leakages and malfunctions of completions components. In general it is desirable to use slickline for WL operations because it is smaller, cheaper and easier to seal around. With increased water depths the capabilities and application area for slickline decreases. The application area for a braided line is therefore in general where a slickline is to week.

3.2 Coiled Tubing (CT)The other frequent method of light intervention is use of CT. This is a process where a reel of small-bore continuous tubes is run into a well that is still under pressure also called live well. The coiled tube consists for pipe sections welded together to form a continuous long string. It has constant outside diameter normally ranging from 1 to 3.5. A continuous string is often made up with 2 to 3 different wall thicknesses; the thickest part is located in the upper section where the highest load will interfere. This tapering gives several benefits such as reduced weight, reduced cost, and lower pressure loss with larger inner diameters. Typical CT tasks include: Cleaning operations after workover. Spotting acid at the perforations either to clean the perforations or remove formation skin damage. Fishing operations. Cleaning out ratholes. Spotting cement plugs. Running through tubing tools such as straddle packers and bridge plugs. Stiff WL (CT with a logging cable inside). Sidetracking ad drilling small diameter holes. Drilling/milling operations inside pipe. Opening/closing sliding sleeves that WL is unable to perform. The coiled tubing intervention unit comprise of the following main components: Injector head, coiled tubing, reel, well control equipment, power pack, gooseneck and lifting frame. 3.2.1 Injector head This unit is the driving mechanism that forces the tubing into and out of the well, and at the same time support the weight of the tubing in the well. Its principle of operation is that two opposed endless rotating chains of interlock drive blocks driven by hydraulic motors, pressed against the tubing by hydraulic cylinders and give a frictional grip. A hydro-pneumatic accumulator bank is used as backup for the hydraulic cylinders acting on the drive blocks. The unit is equipped with a load cell measuring the axial force in the tubing displayed in the control cabin. The capacity of a standard unit is a static pull of 27 tons and a maximum running speed of 1 m/s.


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Well Integrity of Subsea Wells during Light Well Interventions 3.2.2 Coiled tubing reel The CT reel stores and winds the tubing, and comprises of: framework, reel, hydraulic motor, winding system, depth meter, swivel and a flushing system. The framework function is to protect the reel and its components during transportation and operation, while the reel facilitates storage for tubing. The reel can store up to 5000 m of 1 tubing. The hydraulic motor ensures power supply to keep the tubing under constant tension during wrapping of the tubing. During unwrapping a torque brake keeps the tubing under constant tension and rotating momentum. The winding system is made of a lead screw and a tubing guide arm. The tubing guide positions the tubing onto the reel and is synchronized to the rotation of the reel by a chain drive from the axle. The depth meter measures the length of tubing paid out. The swivel facilitates fluid to pump through the tubing while the reel is in motion and at any pressure. Modification to the swivel enables an electrical connection to be made to a logging cable placed inside the tubing. The last main component of a conventional coiled tubing assembly is the flushing system. It prevents the outside of the tubing from corroding by spraying oil based corrosion inhibitor when the tubing is winded onto the reel. 3.2.3 Well control equipment The well control equipment protects people, equipment and the environment in the event of an emergency situation. It can be subdivided into: BOP stack Shear/seal BOP Stripper The BOP stack comprises up to four ram valves with the following functions: Blind ram that seals against open bore. Shear ram that cuts the tubing. Slip ram that holds tubing. Tubing ram that seals around tubing. The ram valves can be operated both hydraulically and manually. Valves integrated in the body allow circulation and pressure equalization before opening. An accumulator backup power supply is also connected to the circuit. The shear BOP is located just above the XT and its function is to cut and seal the bore in an emergency situation. It can be both manually and hydraulically operated and it is controls independently of the BOP stack. Also, an accumulator backup is connected to the circuit in the event of a power failure. The stripper is located between the injector head and the BOP and allows the CT to be stripped in and out of a live well. It consists of two sealing rubber elements that are forced against the tubing by a piston that is acted on by the well pressure. Also, a hydraulic circuit is incorporated in the system to allow further pressure increase if necessary. 3.2.4 Powerpack The powerpack provides the hydraulic and pneumatic power to operate the functions of the intervention unit. The hydraulic fluid is supplied at 200 bars. As a safety precaution there is an auto-shutdown of the engine if the temperature or pressure exceeds a preset level.


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Well Integrity of Subsea Wells during Light Well Interventions Integrated into the power pack is a diesel engine that drives the hydraulic pumps and a hydraulic system that comprises of pumps, motors accumulators and a power supply to operate the well control system in addition to injector head and tubing reel. The powerpack unit further consists of an air system that supplies power to the brake control, reel unit, unit control system and safety system and a hose reel containing the umbilical for transportation of hydraulic fluids and air to the operating units. 3.2.5 Gooseneck The gooseneck is a device mounted on top of the injector head in order to guide the coiled tubing from the tubing reel into the injector head. 3.2.6 Lifting frame The lifting frame houses the injector head and the BOP stack during well intervention. It is suspended in the elevator and compensated using the rigs heave compensation system. Since the frame is motion compensated it provides for the operator a motionless unit relative to the riser. During operation, the CT is uncoiled from the reel when going into the well and coiled back when going out of the well. The handling imposes plastic deformation to the tubing; hence it is of utmost importance that a record of the number of runs is kept. When the tubing has experienced plastic deformation a predefined numbers of times, it is replaced with new tubing. The small diameter tubing imposes reduced flowrates and high pressure losses. System and general equipment descriptions for the WL and the CT operations are conventional technologies. There are constant changes in design to enhance and simplify the intervention operations. Later in the thesis, focus is directed to a riserless light well intervention system. This is in general an improvement of light intervention technology in the sense of simpler topside demands, which induce reduction in time and complexity. This enables light intervention tasks to be more cost efficient than existing methods.


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4 Light well intervention as a project. Framework for project risk analysisThis chapter gives a general introduction to project risk analysis in addition to when and where it is suitable to utilize project risk analysis. The target group is the staff, planning and conducting offshore well intervention operations. The aim is to clarify how to use a framework for a project risk analysis in a simple and a precise manner.

4.1 IntroductionRisk and uncertainty are inherent in all projects. The size, complexity, location and speed of a project are all factors that represent risk elements. The evolution of risk management has showed continuously more focus on the subject of project risk. Clients and service contractors are aware of the consequences if work fails to succeed. Therefore a proactive way of performing business is a must to survive within the industry. In this section an introduction to risk theory, project risk management and project risk analysis is given. NORSOK Standard Z-013 Risk and emergency preparedness analysis defines risk analysis as: use of available information to identify hazards and to estimate the risk. The methods considering risk and project risk analysis tend to have different approaches to what kind of risk considered. Project risk analysis mainly deals with risks related to parameters such as time, cost and quality. Project risk analysis has previously tended to cover quantitative methods. Risk analysis methods take more into consideration risks related to accidents, human loss and environmental damage (Walker, 2002). Therefore the main difference in the methods is that risk analysis tends to cover a broader perspective than project risk analysis.

4.2 The objectives of project risk analysis.The overall goal of a project from a risk point of view, is not necessary to eliminate all risk elements which is an unsolvable task. It is rather to establish control of the risk factors. The primary goal of a risk analysis is to calculate and evaluate the risk associated with operations and compare it against acceptable criteria for risk. To execute this, it is essential that the purpose and scope of the analysis is clearly defined and is in accordance with the needs of the activity. The purpose of a framework is to provide a consistent and systematic approach to risk handling in projects in order to allow project teams to proactively identify and prevent unwanted incidents before they occur or by reducing the impact of them if they occur. Risks need to be continuously assessed throughout the project as the nature, probability, and impact of risks change by phase and activity. The outcome of a project risk analysis shall therefore as fare as possible give a picture of all critical situations and thereby make a better foundation for decision making.

4.3 Standards and guidelines for project risk analysisGuidelines and recommendations for handling project risks are carried out in NORSOK Z013 and BS 6079-3:2000 Project management - Part 3: Guide to the management of business related project risk. BS-6070 is a general standard for all types of business related Master thesis Norwegian University of Science and Technology, 2005

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Well Integrity of Subsea Wells during Light Well Interventions projects while NORSOK Z-013 is a more specifically designed standard for the petroleum industry. BS 6079 specifies a more general methodology and describes a process for identifying, assessing, and controlling risk within a broader framework than NORSOK Z-013. The main features of this process are illustrated in the figure 4-1. The risk management process described in this standard is applicable for each aspect of the business activity and focuses at each level of decision making. Another framework for dealing with project risk analysis is given by DNV in DNV-RPH101:Risk Management in Marine and Subsea Operations. This is carried out as a specific procedure for handling project risk in marine operations. The recommended practice gives more detailed guidelines for planning and handling project risks than the BS-6079 and NORSOK Z-013. It goes into a wider perspective of specific tools and processes in the core of the risk analysis. The NORSOK Z-013, BS 6079 and DNV-RP-H101 can all be applied for handling project risk analysis. For more specific information of different methods, tools and risk handling techniques the ROSS community at www.ntnu.no/ross gives a good perspective and application of how to conduct risk analysis.


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Figure 4-1: The steps in a risk management process. Adapted from (BS 6079-3, 2000)

4.4 The process of project risk analysisThere are several ways of performing a risk analysis. How it should be carried out depends on the subject of investigation such as the projects complexity, time, organization and costs. BS 6079 recommends using a set of guide words for each step of the process of the risk analysis. NORSOK Z-013 recommends a guidance framework in the form of block diagrams describing how the analysis should be conducted.


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Figure 4-2: Procedure framework for risk -and project risk analysis. Adapted from (Ross community, 2005)

The process for risk and project risk analysis is more or less the same. The first step in the process is to define the scope and context of what to be analyzed. A typical lead question according to the BS 6079 in the first step is to identify what is at risk and why. NORSOK Z013 emphasizes that the analysis shall be planned in accordance with the development and operation of the activity ensuring that the risk studies are used actively in the design and execution of the activity. The second step contains risk identification, the sources of risk in addition to what and where the risk elements are. Third step is the risk analysis itself, while the fourth step is risk evaluation. The fifth step is treatment of the outcome and the measures that should be taken about the risks revealed in the analysis. A risk evaluation is based on the outcome of the risk analysis where likelihood and potential consequences of the individual risks or sets of risks is identified. The evaluation is then suitable to determine which risks take the highest priority, which risks require further studies and which risks need less attention. When the risk picture is identified and evaluated, there is always a remaining risk. The remaining risk after risk treatment measures have been taken is often in literature referred to as residual risk. The issue of handling residual risk is a cost/benefit evaluation.


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4.5 Event and parameter uncertainties in projectsParameter or estimate uncertainty is the span of uncertainty elements in a base estimate or time plan. Estimates that describe the consequence of certain conditions are often represented in a continuous distribution. Event uncertainties on the other hand, are elements that indicate the probability and consequence of the interference of undesirable event i.e. situations that occur or not. This implies the probability and consequence of event that is not included in the parameter uncertainty. (Metier, 2002). It is a difficult task to estimate and handle event uncertainty for a project organization, because interactions and consequences are diffuse to put in a base estimate. Statoil have the latest years experienced how event uncertainties can affect a project. The latest major event was a gas leakage at Snorre A in 2004 during heavy well intervention of a water injection well. The measures to deal with event uncertainties in a base estimate are to make sure there are proper procedures for handling of unwanted incidents.

4.6 Contingency planningThe term contingency include an alternative plan if something differs from the original intention. In the field of risk management, there are other types of contingencies also. Chapman and Ward (1997) explain contingency planning as setting aside resources to provide a reactive ability to cope with impacts if they eventuate, introducing that the contingencies may be different types of resources, e.g. time, cost, personnel, etc. Wideman (1986) states that contingency planning includes the management of contingency budget, the development if schedule alternatives or work-arounds and complete emergency responses to deal with specific major risk areas. Wideman further indicates that contingencies may be in the form of alternative solutions. This is supported by Dinsmore (1993), who identifies that contingency planning may result in some redundancy in the project. An example of this is when two or more promising solutions to same technical problem exist, and none clearly has a better chance of success (Mogstad, 2000). Consequently, risk contingencies may be in the form of cost reserves, time allowances, risk allowances in specifications, contract options, alternative approaches and alternative design.

4.7 Qualitative risk analysisQualitative risk analysis is a process that primary have to aims: risk identification and initial risk assessment. The objective is to identify a list of the main risk sources and a description of their likely consequences. This is often illustrated through risk matrixes where the probability of interaction and consequences is represented.

4.8 Quantitative risk analysisQuantitative analysis uses descriptive scales to describe the risk i.e. the magnitude of potential consequences and probability of occurrence (Mogstand, 2000). Quantitative analysis differs from qualitative techniques in the way of quantifying the risk elements involved. To be able to conduct this it is essential that correct input information is available. Offshore experience databases such as OREDA and Wellmaster have in the latest years made it possible to get more specific information as input to risk analysis, and thereby more suitable for quantitative techniques. Fault tree and Event analysis is examples of quantitative methods.


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4.9 Semi-quantitative analysisThis is another type of analysis in which the scale is given values, often between 0 and 1, or percentages. This provides a more detailed priority than qualitative analysis, but does not give any realistic values as attempted in qualitative analysis (Mogstad, 2000). Table 4.9-1 shortly summarize the main differences in the different methods described.Table 4.9-1: Estimating scales: Adapted from (Mogstad, 2000)

Analysis level Qualitative Semi-quantitative Quantitative

Example of scale Low/medium/high 0-1 or 0-100 %

4.10 Application area for project risk analysisThe application area for project risk analysis depends on the complexity of the project that is to be conducted. There are generally three forms of planning operational work.

Complexity

Project Risk Analysis

Procedure HAZOP SJATimeFigure 4-3: Indication of complexity versus time for planning and handling of operations.

4.10.1 Toolbox meeting/ Safe Job Analysis (SJA) Toolbox meeting or SJA are simple and practical orientated tools to identify hazards and operability risks. These are conducted at the worksite just before operations shall be executed. In short text toolbox meetings or SJAs consists in briefing involved personnel of hazards and possible operational threats. 4.10.2 Procedure Hazard and Operability (HAZOP) analysis A procedure HAZOP is a systematic and structured technique to examining a defined system. It is a detailed problem identification process carried out by a team dealing with the identification of potential deviations from the design intent. Further an examination of their possible causes and assessment of their consequences.


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4.11 DiscussionOne central part of definition of a project is that no projects are alike. Therefore risk evaluation and risk approximation also differs from every project. There are several approaches for dealing with risk element both qualitative and quantitative methods. Risk management has to be integrated through the project processes. In some cases the perception of risk analysis is additional work. Another important issue is a balance between threats and opportunities. When planning and conducting intervention operations it is of utmost importance to find a balance of how extensive the risk analysis should be. Factors affecting the level of risk investigation are dependent on technology, the environment, experiences and complexity of scope. For a regular intervention task, a Procedure HAZOP and SJA might be the most suitable methods of handling the risk involved. While for an intervention program involving new technology and harsh environmental conditions, it may be more suitable to conduct a more detailed project risk analysis.


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5 Well integrityThis section introduces and discusses the concept and factors which affect the integrity of subsea wells during light well interventions based on NORSOK D-010.

5.1 IntroductionNORSOK D-010 defines the minimum functional -and performance oriented requirements, and guidelines for operations on the NCS. The standard are developed by the Norwegian petroleum industry to ensure adequate safety, value adding and cost effectiveness for petroleum industry developments and operations. It is carried out and prepared with support from The Norwegian Oil Industry Association (OLF) and Federation of Norwegian Manufacturing Industries (TBL). NORSOK D-010 is the leading document for minimum well design, planning and execution requirements of safe well operations.

5.2 Well integrityNORSOK D-010 defines well integrity as: The application of technical, operational and organizational solutions to reduce the risk of uncontrolled release of formation fluids throughout the entire life cycle of a well. Well barriers are the main elements that represent the technical solutions to fulfill the specification of well integrity design. NORSOK D-010 introduces a life cycle well perspective. There are generally three different stages that influence the well integrity during a life time period. These are: Drilling operations. Production. Intervention.

The three stages can be further subdivided. In this context focus is set on well integrity during subsea light well interventions or in other words; deployment of tools and equipment in a completed well and thereby how that affects the well integrity. This is influenced by technical, organizational, and operational barrier elements. 5.2.1 Well Barriers There are several types of barriers. In everyday language the word barrier is used with different meanings. In this thesis focus is set on well barriers. A well barrier is defined in NORSOK D-010 as: an envelope of one or several dependent well elements that prevent fluids or gases from flowing unintentionally from the formation, into another formation or to surface. These are further subdivided into primary and secondary well barriers. A primary barrier is the first object that prevents flow of hydrocarbons from a formation. In well completions a typical primary barrier is the production tubing and the production packers which are in direct contact with the well stream. The primary barriers are often marked with blue lines in barrier schematics. A secondary barrier is then logically the second object that prevents flow from a source to another. A well casing is a typical example of a secondary barrier. This are often marked as red lines in barrier schematics. Figure 5-1 adapted from NORSOK D-010 which illustrates the concept of sketching barriers. Master thesis Norwegian University of Science and Technology, 2005

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Figure 5-1: Well barrier schematic of a CT intervention stack up. Adapted form (NORSOK D-010, 2004)

5.2.2 Well Barrier methodology According to NORSOK D-010 there shall always be two available well barriers during all well activities and operations, including suspended or abandoned wells, where a pressure differential exists that may cause uncontrolled outflow from the borehole/well to the external environment. Furthermore D-010 states that the primary and secondary well barriers shall to the extent possible be independent of each other without a common well barrier element. If a common well barrier element exists, a risk analysis shall be performed and risk reducing/mitigation measures applied to reduce the risk to as low as reasonably practical. The philosophy of two independent well barriers is set as a rule of thumb on the NCS to keep the well integrity as high as possible. D-010 further states that well barriers shall be designed selected and or/ constructed such that; It can withstand the maximum anticipated differential pressure it may be exposed to. It can be leak tested and function tested or verified by other methods. No single failures of well barrier or well barrier elements lead to uncontrolled outflow from the borehole/well to the external environment. It can operate competently and withstand the environment it may be exposed to over time. Its physical location and integrity status of the well barrier is known at all times.


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Well Integrity of Subsea Wells during Light Well Interventions 5.2.3 Barriers in well operations Barriers are divided into different types. They are grouped according to their functions, how they are operated or how barrier failures are observed. This is illustrated in the table below.Table 5.2-1: Typical well barriers. Adapted from (Holand et al, 2003)

Barrier typeOperational barrier

DescriptionFunction while the operation is carried out. A barrier failure will be observed when it occurs. An external action is required to activate the barrier. Barrier failures are normally observed during regular testing. A barrier in place that functions continuously without any external action. A barrier that is either not always in place or not always capable of functioning as a barrier

ExampleDrilling mud, Stuffing box

Active barrier (Stand-by barriers)

BOP, XT, SCSSV

Passive barrier

Casing, tubing, Well kill fluids, packers Stabbing valve, (WR-SCSSV)

Conditional barrier

There are typically two main types of barrier; Static barriers. Dynamic barriers.

A static barrier is a barrier that is in place over a long period of time. This situation applies during production/injection or when the well is temporary closed in. For static barriers, barrier diagrams may be used to illustrate and analyze the relationship between the barriers and the conduits. A dynamic barrier is a barrier that varies over time. This applies for well drilling, intervention and completion phases (Holand et al, 2003). 5.2.4 Well barrier characteristics There are many factors affecting the level of well integrity during a light or heavy intervention task. This affects the level of well integrity. The well barrier picture changes during different operation modes. Well barrier can be described as active and passive. These can further be broken down to dynamic and static well barrier elements. A passive well barrier is contributing in a static manner to perform the functioning of a system. Production tubing and Polish bore receptacle (PBR) are examples of this. Active barriers require input signals or some kind of trigger mechanism to perform a change of state. Active well barriers changes over time. Closure of a DHSV is a typical example of an active barrier. DHSV function as a barrier element if a critical situation requires. The definition of well integrity in NORSOK D-010 uses the term application of technical, organizational and operational. Well barriers are mostly technical appliances meanwhile the two last elements are more barriers in the sense of Merriam-Webster Online Dictionary: Something immaterial that impedes or separates. This can be exemplified through behavioral barriers. In other words a technical well barrier is typically in the nature of physical elements like casings, valves or packers. Operational and organizational measures are used to ensure the integrity of the physical components. During light well interventions a typical organizational and operational barrier might be calculations of the mud column weight


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Well Integrity of Subsea Wells during Light Well Interventions which acts as a dynamic barrier during well operations. Miscalculations can either lead to damage of formation or unintentional leakages to the surroundings. Figure 5-2 is meant to clarify the connections and breakdown of well barriers.

Well Barrier

Active Dynamic

Passive

Dynamic

Static

Level?

Primary Secondary Tertiary

Technical Organizational Operational

Figure 5-2: Methodology for breakdown of well barriers.

5.3 DiscussionAs mention in chapter 6, D-010 is a guiding standard for well integrity and well operations on the NCS. The standard is static in the way of determining the safety level for well activities. Standards are in general cost effective in the sense of standardization of equipment and accessory needs. One question that can be raised is: Have the D-010 in some cases a negative effect on the value adding? In some cases the answer is probably yes. Every well has it own characteristics when it comes to pressure, temperature, and reservoir fluids. The differences in well characteristics do not to date reflect the safety level of the completion and intervention tasks. This raises the question of how the standard should be handled and maintained. In the introduction to D-010 it is stated that the standard focus, is to add value and cost effectiveness. But is the safety level too high in some cases? Can the standard in some cases hinder a cost efficient way of producing hydrocarbons? There must be a balance between the risk involved and the safety measures taken. Since early 1980 there has been a major collection of experience data from the NCS. Historical databases such as OREDA and WellMaster provide key information input parameters in well risk evaluations to the safety level and can contribute in some cases to lower the demand for well operations. D-010 opens up for risk evaluations for specific projects. This should be the object for introducing a concept of well integrity levels where risk evaluations for specific cases can estimate the most correct and optimal level of choice to ensure well integrity without to use of extra costs. By getting a more cost efficient way of producing hydrocarbons without necessarily reducing the safety level, can increase the net incomes on the NCS significantly. Light well intervention performed by RLWI is an example of reducing well intervention costs. Historical experiences of oil and gas production on the NCS give valuable data to evaluate the safety level. The handling of D-010 could probably be more cost efficient and value adding if the standard had corporate specific levels of well integrity based on specific well and equipment Master thesis Norwegian University of Science and Technology, 2005 30

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Well Integrity of Subsea Wells during Light Well Interventions characteristics. Today the regulation handling is the same for all activities. The Kristin and Ormen Lange field developments where reservoir characteristics, water depths and application of new technological solutions represent challenges for safe well operations. Today the same regulation is prevailing, either it is a low or high profile risk operations. An issue for current standards in general, is handling of new technology. Rules and regulation should dynamically adaptable for new technological solutions when the quality of safety barriers and well integrity can be documented.


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6 Riserless Light Well Intervention (RLWI)This section covers a describing and discussion of the main operational benefits and weaknesses by using the RLWI system. This chapter is the basis for identifying hazards and operability problems related to well intervention operations. The literature are based on (Andrersen, 2004) and (Inderberg, 2005).

6.1 IntroductionAs the offshore oil and gas production continues to grow, subsea wells are becoming increasingly important. According to FMC Energy Systems there are approximately 2 000 subsea wells in water depths down to 2 000 meters. These wells are normally installed and maintained by large and costly semi-submersible drilling rigs. Potential cost savings provides the principal driving force for performing light well intervention. Well interventions can be performed using Dynamic Positioned (DP) vessels instead of using large anchored drilling rigs designed for more complex operations and heavy equipment handling. The main purpose in using DP vessels is to enable well intervention without rigid connections between vessel and seabed. Therefore the main purpose of RLWI systems in general is to minimize the costs of subsea well interventions. Today surface wells have a higher recovery rate than subsea wells. A RLWI system can contribute to close this gap because the costs can be reduces with 2/3. This will make subsea installations more beneficial as a field development solution.

6.2 Area of applicationTypical well intervention tasks for light well intervention include: Verification of fluid properties from different perforated zones. Installation of various mechanical devices such as plugs and screens. Well stimulation by acid treatment of the reservoir to remove substances such as scale of calcium. Re-perforation. Well abandonment. The WL services available are many, but the services used for subsea wells is normally product enhancing services such as; production logging to identify reservoir characteristics and contribution from different perforated zones, installation of plugs and packers to isolated zones in the well and perforation of new zones in the well. RLWI is equipped with a flushing system that returns all hydrocarbons into the well. It also enables the options of chemical treatments of the well such as scale squeezing operations. A weakness of using the RLWI system is limited space topside. If a critical situation occurs and there is a demand to kill the well by pumping kill fluids to regain well integrity, a semisubmersible rig is required. A small DP vessel has not enough space to store kill mud. There are not stored risers on the vessel for contingency actions. The RLWI system is either not capable to perform fishing operations if the toolstring has to be cut during operation. In such cases there is also a need for a semi-submersible rig to recover a cut wireline in the well. The benefits of using the RLWI system for light well intervention operations are discusses in the introduction. The drawback of using the system is when a critical situation occurs when the toolstring is cut and well control is lost. This can be caused by a gas kick. The costs if a Master thesis Norwegian University of Science and Technology, 2005 32

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Well Integrity of Subsea Wells during Light Well Interventions semi-submersible rig is required are approximately 2 MNOK per day (Sangesland, 2004). The time period such a rig is required depends on availability, mobilizations, transportation and complexity of operation. There are a limited number of semi-submersible intervention rigs available on the world marked. The mobilization and de-mobilization of a rig depends on where available and necessary equipment is stored. The rigs transportation time to and from the well location, can be high. Loss of production is also an impacting factor. This cost is normally not directed to the company providing the intervention services. The operator company is not happy when a well is unable to produce over a period of time. When the factors above are all summarized, it is difficult to estimate the time period, costs and consequences if a semi-submersible rig is required but they are significant.

6.3 Description of the Riserless Light Well Intervention (RLWI) systemThe RLWI system consists of several modules that can be independently installed and retrieved from the seabed. This systems main differences from conventional technology are that operations are carried out with no use of marine riser from the XT to the topside unit. Figure 6-1 shows the RLWI system configuration.

Figure 6-1: The modules of the RLWI configuration. Adapted from (Andersen, 2004)


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Well Integrity of Subsea Wells during Light Well Interventions 6.3.1 Lower Intervention Package (LIP) The LIP is located on top of the XT. The purpose of the LIP assembly is to provide a well safety barrier during intervention. This is designed to interface with both conventional and horizontal subsea XTs. Included in the LIP is a shear/seal ram with the capacity to cut wireline tools and coiled tubing. The lower intervention package represents the main barrier element and safety head of the system. 6.3.2 Lower Lubricator Package (LLP) LLP is the connection between the LIP and the Lubricator Tubulars in the RLWI stack-up. The LLP acts as the running tool for the LIP and is where the connection between the control umbilical, well kill hose and control module is. The LIP contains the main control systems in the stack. There is a control module is located inside which is supplied by energy and signals from the umbilical. The umbilical is connected to the LLP which can be activated to free the vessel in case of vessel drive/drift off and case emergency situations. In addition the LLP contains a well kill hub and a subsea grease injection system for the wireline. Located at the bottom of the assembly there is a connector that locks the assembly to a XT hub. The connector is available in a variety of designs to allow for interfacing with different type of XTs. At the bottom of the assembly is a subsea tool trap which prevents unintentional dropping of the toolstring into the well. On top of the tool trap is the lubricator section. 6.3.3 Lubricator Tubular (LUB) The lubricator section is the parking space for the wireline toolsting on its way in or out of the well, while pressurizing the system before opening the well or depressurizing the system after the well is closed in. The Lubricator section is long enough to house toolstrings up to 22 meters. If excessive forces are applied to the stack in an emergency situation, the lower part of the lubricator section will bend and act as a weak link in the system located in the safety head above the LLP. This will ensure that excessive bending forces are not transferred from the well intervention system to the permanent installation system. The lubricator assembly is locked on to the LIP assembly by means of a connector. The wireline toolsting is located below the pressure control head (PCH) and is connected to a wireline which is treaded through narrow tubes into the PCH. 6.3.4 Upper Lubricator Package (ULP) The ULP assembly is the connection between the PCH and the lubricator providing a well barrier element during well intervention. A Wireline Shear/Seal ram has the capacity to cut all standard braided wires. 6.3.5 Pressure Control Head (PCH) As part of the subsea lubricator system rig-up, the PCH is connected on top of the lubricator and functions as a pressure barrier and seal toward the well bore during wireline operations, allowing intervention access to wells under pressure. Located on the bottom of the PCH is a tool catcher. The tool catcher will catch and hold the tool if the toolsting is unintentionally pulled into the PCH and break the WL. The PCH represents the primary seal when the WL is run into the well. The seal around moving Wl is performed by pumping viscous grease into the limited free space in the wireline and the narrow tubes in the PCH. The grease pressure is Master thesis Norwegian University of Science and Technology, 2005 34

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Well Integrity of Subsea Wells during Light Well Interventions supplied by a grease injection system located in the LLP and must always be higher then the wellhead pressure. 6.3.6 Umbilical system The main umbilical connects to the LLP with a remote operated multi-bore connector to allow for a emergency quick disconnect function. The umbilical system is lowered to the seabed along with the LLP/LIP assembly. 6.3.7 Control system The subsea control system consists of a Workover Control Module, subsea camera, subsea transducers and sensors, subsea jumpers and XT control valves. The system is designed to be as fare as practical with redundancy. If a critical system should occur the control system will activate fail safe close (FSC) procedures of valves in the main bore to prevent a blowout situation.

6.4 Riserless Light Well Intervention system in operationThis section is a short summary of the RLWI system operation. The section is adapted form FMC Kongsberg Subsea homepage RLWI operations are performed from the moon pool, which is a 6x5 meters hole in the middle part of a surface vessel and assisted by a Remote Operated Vehicle (ROV) subsea. The first step is lowering the LIP and the LLP. Like all the other assemblies the LIP/LLP is run on an active heave compensated wire, using guide wires. In addition there is a guiding system that supports the assemblies, when they are located in or passing the splash zone. On its way down to the subsea stack, the sea current can apply substantial forces to the WL and toolstring. This requires continuous monitoring to avoid twisting of the wireline with the guide or the guideline wires. When the WL toolstring enters the top of the lubricator assembly the toolstring is guided with a combination of ROV and guide cones. The PCH is locked in place by means of a connector. The RLWI system is then ready for replacing the seawater in the stack by flushing in inhibitor fluids to avoid hydrate formation. The next step is to pressure test the stack before opening the well and running the WL toolsting into the well. The toolsting is run into the well by means of gravity until the well deviation reaches approximately 70 degrees. Beyond this point a well tractor, described in section 3.1.9, is required to help the toolsting into the high deviated parts of a well.


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7

Hazard assessment during well intervention

The purpose of this section is to describe a basis for identification and evaluation of hazards and operability problems related to light well interventions in general.

7.1 IntroductionWhen new techniques and equipment for conducting subsea light well intervention is introduced, sufficient planning and documentation of the tasks are important. Proper evaluation of functionality, operability and hazards need to be conducted carefully. A hazard is defined as a situation with a potential for human injury, damage to property, damage to the environment, or some combinations of these (Rausand, 1993). Operability is according to Statoil doc TR0034 defined as: the possibility to perform a planned well operation, within a target weather window, without compromising structural safety. In other words, operability comprises a systems availability to operate. Further on standards and methods are described before hazard and operability problems during a light well intervention is identified and discussed.

7.2 Standards and regulationsGeneral requirement for intervention tasks is described in NORSOK D-010 and NORSOK D002. These procedures are made for light intervention tasks in general. These standards do not in detail specify procedures for new light intervention techniques such as RLWI. This might be a weakness in the mentioned standards. Operator companies therefore needs to prepare their own procedures for handling specific operations.

7.3 Methods to identify hazards and operability problemsThere are several techniques developed to identify hazards associated with an installation or an activity, for example HAZOP/HAZID, FMECA, checklist, Top Down Approach, qualitative review and What-If analysis (Walker, 2002). The technique to be used depends on the type of risk analysis to be conducted and the type of operation or facility to be assessed. 7.3.1 Hazard Identification (HAZID) Hazard identification (HAZID) is a common and frequent used technique within the petroleum industry. It is commonly used on a great variety of areas, projects, and operations. Similar techniques are Preliminary Hazard Analysis (PHA) and Rapid Risk Ranking. HAZID is a method usually carried out in groups where the objective is to reveal potential hazards in an early stage of a project. The most common application is technical system reviews, but also for reviews of operational procedures. A description of potential causes, e

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