Surface Controlled Subsurface Safety Valve Research Articles

Analysis Clarifies Failures of Gas Lift Valves in Subsea Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215010, “Failure Analyses of Gas Lift Valves That Caused Improper Tubing/Annular Communication in Subsea Wells,” by Sebastião T.X. Bastos, Galileu P.H. Oliveira, and Tatiana Sanomya, Petrobras, et al. The paper has not been peer reviewed. _ This work presents the results of several failure analyses of gas lift valves (GLVs) retrieved from the operator’s subsea wells. These valves were unable to prevent backflow from tubing to annulus, thereby compromising well integrity. These investigations allow a more-precise diagnosis of GLV failures that tends to reduce the risk of problem recurrence and can guide the correction of fragilities in current designs. They also can contribute to better planning and definitions in future well completions, resulting in increased reliability for this method of artificial lift. Failure-Analysis Procedure Usually, GLV failures are detected in tubing-integrity tests. Every time a leak rate above the limits for surface-controlled subsurface safety valves is registered in such an integrity test, a procedure is performed to try to restore the sealing capacity of the GLV by flushing the valve with diesel. Then, another tubing integrity test is performed. When removing a supposedly failed GLV from a well, special care must be taken at the rig to preserve the equipment, retaining its condition inside the well as much as possible. For this reason, the following recommendations are prescribed: - The GLV, and any material adhered to any part of its body, must not be washed. - If parts of the valve, debris, or any material adhered to the valve detach from its body, they shall be collected, placed inside clean plastic bags, and shipped along with the valve for failure analysis. - Equipment packaging requires placement in a proper box for transportation after bubble-wrapping the valve’s body and detached parts. - Equipment storage and transportation shall preserve its original conditions. - Mechanical shocks must be avoided. The failure analysis itself occurs at the valve’s manufacturing shop and must be witnessed by at least two specialists from the operator. A database on GLV failures is kept and provides statistical data and general information on these incidents. This procedure constantly has been subject to changes as new lessons learned point to the incorporation of improvements. For instance, the requisite for not cleaning the GLV at the rig came after observing that deposits could have been removed in the process. Also, more recently, some questions have been raised regarding the execution of the leakage test at the beginning of the inspection at the shop, because such tests could interfere with the position of the GLV’s internals or displace or disarray any deposited material. Thus, this step has been discontinued unless a good reason exists to suppose that the valve internal seals are functional. Failure-Analysis Excerpts The complete paper presents seven cases of failure analysis (four are included in this synopsis) for GLVs retrieved from subsea wells in recent years, accompanied by a short description of the facts of the case. Ordinary actions and events are omitted for brevity.

Life-cycle integrity design method considering load robustness of offshore oil and gas equipment: SCSSV as a case study

Components that are vulnerable to the external environment and harsh working conditions easily fail during their life cycle under variable loads of offshore oil and gas equipment. The reliability of the system in the life cycle is reduced, various risks are increased, and substantial maintenance costs are generated. However, the current reliability-based design optimization method has difficulty meeting the situation that the life cycle is taken as the time dimension of design considering reliability, risk, and maintenance. To solve the problem, a life cycle integrity design optimization method considering robustness is proposed. A simplified integrity model is established through random load sampling and global sensitivity analysis. A multiobjective particle swam hierarchical optimization algorithm is proposed, in which hierarchical optimization order is determined by the priority of objectives, and the optimization design with structural integrity as the optimization objective is completed. The method is applied in the design of pressure pipeline of all-electric surface-controlled subsurface safety valve system.

Technology Focus: Artificial Lift (October 2021)

What, a second artificial lift focus feature this year? What’s going on? Well, maybe I can answer your questions with another round of questions: Do you know how many of your organization’s wells are artificially lifted? Or, more importantly, do you know what fraction of your production volumes are dependent on artificial lift? I would wager that the percentages are higher than you would expect, and I encourage you to seek out that information and share it. Share it with your asset team, share it with other asset teams, share it with other functions, share it with your management, shout it from the rooftops! Seriously, though, this information can be quite useful to you and your organization. Did you ever wonder if someone else could be struggling with the same artificial lift selection, installation, operation, or reliability challenges that you are? The answer you’re looking for may be in the SPE archives, or it may be just down the road with a colleague in a different part of the region, country, or world. Do you have a novel new technique, system, or invention that you want to try out? Why not leverage the knowledge that others in your company could also benefit from? Maybe they would even like to participate and strengthen your pilot with a broader range of test conditions. Do you need more personnel or technical or financial support for artificial lift in your asset? Show precisely what those electrical submersible pumps (ESPs), rod pumps, gas-lift valves, and plungers (among others) are lifting to the flowline. Sometimes a step back to a higher-level view can motivate and reinforce the people behind the day-to-day efforts to extend the time between failures and chase optimum performance. I’m certain that you are now a (possibly unwilling) expert at videoconferencing. That’s why I would like to encourage you to attend the 2021 SPE Electric Submersible Pumps Symposium, to be held 4–8 October in The Woodlands, Texas. Of course, the technical presentations will be well worth it, but you may gain even more value from the networking, collaboration, and idea generation that happens between the events listed in the program. Not an ESP person? Do gas and sand separators, power cables, advanced materials, and downhole sensors apply to other lift methods or well systems in general? How about applied artificial intelligence, reliability studies, and predictive analytics? Maybe they don’t for you right now, but they could. I hope to see you there. Recommended additional reading at OnePetro: www.onepetro.org. SPE 201153 - Intermittent Gas Lift for Liquid-Loaded Horizontal Wells in Tight Gas Shale Reservoirs by Daniel David Croce, Colorado School of Mines SPE 202668 - Insert Sucker Rod Surface-Controlled Subsurface Safety Valve: A Step Ahead To Improve the Well Integrity for Sucker Rod Artificial Lift Retrofitting by Salvatore Pilone, Eni, et al. SPE 201136 - New Stage of Rodless Artificial Lift Operation: The First Field Application of Submersible Motor Cable Plug With Electric Submersible Progressing Cavity Pump in CNPC by Shijia Zhu, China National Petroleum Corporation, et al.

Electro Magnetic Wireline Retrievable-Surface Controlled Subsurface Safety Valve: A New Backup For Surface Controlled Subsurface Safety Valve To Avoid WorkOver

The scope of this document is to summarize the field trial of Expro FlowCaT and Geoservices GEM-Valve Wireless Electromagnetic Surface Controlled Sub-surface Safety Valve in Fiume Treste field, in sud of Italyt and provide a final technical evaluation. In 2007, COMP started a study about existing Surface Controlled Sub-surface Safety Valve, to have a complete knowledge of their status in worldwide wells and to make a statistic analysis of the most common failures.The control line‟s failure is the most critical, since it prevents the installation of a contingency WR-SCSSV, which would be impossible to control. In these cases, the only available contingency, till now, was the installation of a SSCSV (Sub-Surface Controlled Safety Valve), but it doesn‟t guarantee the same level of reliability as the SCSSV‟s: These valves are not controlled from the surface, they are not fail-safe and they are operated by particular events on the well (such as high flow rate or low pressure), which are very uncertain. To address this issue, COMP made a survey with valves‟ suppliers and a solution to, this problem was identified in the new wireless electromagnetic technology. After a strict “ISO-modified” qualification process and a 6-months field installation in a STOGIT gas storage well with monthly tests and a final slam test, both the considered Electromagnetic Wireless Surface Controlled Sub-surface Safety Valves: Expro 3.65” FlowCaT & Geoservices 3.72” GEM-VALVE are considered qualified and field proven to be installed in eni wells.

Design and Development of All-Electric Surface-Controlled Subsurface Safety Valve System

SummaryThe subsurface safety valve (SSV) is an essential device of a subsea production system. The hydraulic SSV is widely used, but it has some drawbacks when used in deep water: It needs a long pipeline from platform to wellhead, and brings additional pressure loss. The system needs higher pressure and manufacturing costs, but the response is slower. To solve the problem, a new all-electric surface-controlled SSV (E-SCSSV) system consisting of an E-SCSSV body and a control system is developed. The innovative structural designs include electric-drive mechanisms and a magnetic coupler that can transfer linear motion. The mechanical property of E-SCSSV body is analyzed to determine the ability to resist well pressure. The coupling rule of the magnetic coupler is studied through experiment and finite-element analysis. The dynamics of the failure-safety mechanism is investigated to obtain the optimal performance and combination of structural parameters. Using sensors on the E-SCSSV body, the operation status of the E-SCSSV can be monitored. An E-SCSSV system prototype has been developed to validate the function of the E-SCSSV. Reliability requirements are discussed. Compared with existing SSVs, the biggest advantage of the E-SCSSV is its quick response.

Determining optimal preventive maintenance interval for component of Well Barrier Element in an Oil & Gas Company

An oil and gas company has 2,268 oil and gas wells. Well Barrier Element (WBE) is installed in a well to protect human, prevent asset damage and minimize harm to the environment. The primary WBE component is Surface Controlled Subsurface Safety Valve (SCSSV). The secondary WBE component is Christmas Tree Valves that consist of four valves i.e. Lower Master Valve (LMV), Upper Master Valve (UMV), Swab Valve (SV) and Wing Valve (WV). Current practice on WBE Preventive Maintenance (PM) program is conducted by considering the suggested schedule as stated on manual. Corrective Maintenance (CM) program is conducted when the component fails unexpectedly. Both PM and CM need cost and may cause production loss. This paper attempts to analyze the failure data and reliability based on historical data. Optimal PM interval is determined in order to minimize the total cost of maintenance per unit time. The optimal PM interval for SCSSV is 730 days, LMV is 985 days, UMV is 910 days, SV is 900 days and WV is 780 days. In average of all components, the cost reduction by implementing the suggested interval is 52%, while the reliability is improved by 4% and the availability is increased by 5%.

Riglessly Restoring the Functionality of Subsurface Safety Valves

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164370, ’Innovative Methodology To Riglessly Restore the Functionality of Subsurface Safety Valves (SC-SSSVs) With Damaged Control Lines,’ by Mohamed Fahim, Hossam Elnaggar, Abd Allah ElBarbary, Mohammed Abu Arab, Ashraf Keshka, Hamdi Bouali Daghmouni, and Mohamed Al Karra, ADCO, and Ammar Soufan, Joseph O'Connor, and Magdi Elasmar, Baker Hughes, prepared for the 2013 SPE Middle East Oil and Gas Show and Exhibition, Manama, Bahrain, 10-13 March. The paper has not been peer reviewed. The surface-controlled subsurface safety valve (SC-SSSV) is an integral part of the overall safety system of any well, and it is the only method that provides subsurface isolation in case of emergency caused by uncontrolled surface or subsurface events. The effectiveness of these valves can be threatened by leaks, plugs, or breaks in the control lines (CLs). This paper describes a methodology that deploys CLs on the inside of the tubing, reducing cost and ensuring continued effectiveness of SC-SSSVs. Introduction Functional SC-SSSVs must be installed in production tubing in all gas and oil wells, irrespective of location, as a safety barrier to halt flow in case of a catastrophic failure. SC-SSSVs are held in the open position by introducing hydraulic positive pressure from the surface. This pressure is applied through a CL in the tubing/ casing annulus running from the valve to the surface. In case of an emergency shutdown, the hydraulic pressure will be lost, forcing the safety valve to close. CLs for SC-SSSVs could leak, plug up, or break, leading to loss of the capability to control the valves’ operating condition, causing environmental and safety concerns in addition to a loss of production upon closure of the valve. In one of the giant Abu Dhabi onshore oil fields, approximately 160 strings have with damaged-CL problems. In the past, the only way to rectify SCSSSV problems was to pull out the production tubing through a rig workover. Hence, all affected wells were enrolled in a drilling workover schedule. Rig availability is one of the major challenges affecting field-development plans, and so any rigless technologies that can be used in place of rig workovers are of high importance to save on rig time. A multidisciplinary team was formed to survey the market and carry out an evaluation of technologies that could remedy the problem of the damaged CL by replacing or modifying the existing SC-SSSV riglessly. The findings of this survey indicated that there were two technologies that could restore the functionality of the SC-SSSV riglessly. One of these is an SC-SSSV with a CL line deployed inside the tubing (Fig. 1). This can be compared with conventional CLs, which are set in the annulus (outside the tubing string) and hence require rig intervention in case of damage. The running and retrieval of this modified SCSSSV are performed by a conventional slickline unit; however, the CL requires special equipment (a capillary unit) for installation and retrieval.

Remotely operated vehicle (ROV) intervention technology allows early production from subsea wells

Subsea fields, particularly in deepwater, continue to challenge the economics of development for operators. Production of subsea wells by tying into existing facilities and rig-less intervention solutions undertaken during the initial phases of the project are being used to drive better economic outcomes. A recent deepwater development in the Asia Pacific region used locally developed technology to bring subsea wells into production using an ROV with a custom pumping package to open the formation isolation valve (FIV). This operation on the first two wells was done in 2012 from a vessel and the remaining wells were brought online using the same technology during 2013. As the operator wanted to tie-in production from existing subsea wells to an FPSO in an adjacent field while the development specific facility was still being constructed, an ROV-based remote intervention skid was developed to open the FIV and also leave a negative pressure above the surface-controlled subsurface safety valve (SCSSV). The skid was interfaced with a multi-quick-connect plate to provide bi-directional pumping capability to cycle the ratcheting mechanism of the FIV. This methodology allowed the operation to be completed much faster and at a lower cost compared with the use of a rig and is highly beneficial in locations where subsea wells have been drilled and need to be fast tracked for production. The project was a significant success for the operator and has proven to be a breakthrough in remote intervention technology and custom tooling capabilities in the Asia Pacific region.

Development and Qualification of a New Wirelessly Controlled Retrofit Safety Valve: An Alternative to Well Workover That Enhances Well Safety and Maximizes Production Uptime

Summary There are many examples of wells around the world today that are shut in because of failure of surface-controlled subsurface safety valves (SCSSVs). While these valves are generally very reliable, the control line that runs to the surface in the annulus is susceptible to plugging by contaminants in the hydraulic control fluid and also to corrosion, which causes leaks; both are outcomes that render the valve inoperable. The failure of the control line also means that the contingency solution of installing a wireline-retrievable surface-controlled subsurface safety valve (WR-SCSSV) is not possible. When a safety valve fails, the most common remedial solution today involves installing a subsurface-controlled safety valve (SSCSV), such as an ambient valve or storm choke. While this solution is lower cost and more straightforward than performing a full rig-based well workover, it is not as safe. SSCSVs are directly influenced by changing well-flow conditions, such as high flow rates and low pressures, or by water slugs, and thus are notoriously unpredictable in operation. Additionally, they are not controllable from surface and not fail-safe, which is undesirable from a wellcontrol and safety standpoint. By transmitting electromagnetic (EM) signals from surface to downhole, it is possible to control downhole hardware. A wirelessly controlled safety valve has been developed that can be retrofitted into a well using conventional slickline intervention equipment and procedures. Being controllable from surface and of a fail-safe closed design, this valve offers both functional and safety advantages over existing SSCSV solutions. This new valve also offers a retrofittable solution for wells having no hydraulic control line installed. In situations where a capillary string may need to be installed for foam- or chemical-injection purposes, it also provides an opportunity to free up the hydraulic control line. A prototype valve was subjected to qualification and functionality testing in accordance with a modified International Organization for Standardization (ISO) 10432 test procedure. This testing was followed by installation in an onshore gas well for a 6-month trial that involved both flowing and injection phases. The valve was cycled and inflow-tested regularly and performed reliably, consistently, and fully in accordance with specification throughout the trial period. This successful trial of a new wirelessly controlled safety valve marks the introduction of a more-controllable and -predictable alternative to an ambient valve or storm choke, minimizes deferred production, and increases the well's safety. Following the successful onshore trial, the valve is now considered ready for wide-scale field application onshore, and at the time of writing this paper, plans for performing a first trial on an offshore platform are well advanced.

A Dynamic Simulation Study of Water Hammer for Offshore Injection Wells To Provide Operation Guidelines

Summary In water injectors, rapid shut-in creates a water hammer. Water-hammer effects resulting from the shutting in of water-injection wells have a considerable impact on injection-well performance and longevity. Over time, injectors that undergo repeated rapid shut-ins often have significantly reduced injectivity and show evidence of sanding and even failure of the downhole completion. This study seeks to provide an operational reference for the well-injection operation and valve installation to mitigate backflow and maintain the downhole- sand-control-device integrity and thus good water injectivity. Two different shut-in scenarios for an offshore injection system have been investigated. One of the scenarios is that two wells are shut in and the third well is kept open. The other scenario is that the topside pump is stopped while the injection wells are still kept open. Water-hammer sensitivity on different parameters, such as valve-installation position, stroke time, water-backflow conditions, and the hydraulic characteristics, has been performed. For Scenario I, the pressure change because of the wellhead shut-in is approximately 200 psi at bottomhole, which is much lower than the amplitude seen at the wellhead (3,400 psi). The third well, which stays open for injection, experiences an even larger pressure surge (approximately 450 psi at bottomhole). Backflow for the opening well could be close to 10,000 STB/D. With increasing skin because of cumulative injectivity damage by water-particle plugging and thermal-induced fracture closure at shut-in, the water-hammer-pressure fluctuation can be as high as 1,200 psi. For Scenario II, pressure fluctuation because of topside shut-in is 300 psi. With the surface-controlled subsurface safety valve (SCSSV) closing when backflow is felt, the water-hammer fluctuation can be reduced to 200 psi. Unlike the classic water hammer in pipelines, water hammer in injection wells is much less in surge amplitude because the high-injectivity reservoir behaves like a cushion to absorb the water-hammer impact on the downhole completion and sandcontrol infrastructure. Water hammer in the wells and pipeline system experiences (1) after-flow with reduced bottomhole pressure (BHP) and flow rate into formation, (2) backflow when BHP becomes less than reservoir pressure, and (3) resumption of water flow into reservoir when BHP starts to increase. This cyclic process continues with reduced amplitude in each cycle because of friction. A check valve set at the bottomhole could stop the backflow in less than 1 second. This study provides useful reference and operation guidelines on offshore water-injection and completion design consideration.

Analysis of Control Lines Strapped to Tubing

Summary Hydraulic control lines are commonly used to actuate surface- controlled subsurface safety valves (SCSSVs), and new applications include choke operation and the control of more-complex "smart-well" completions. In general, control lines are not subject to routine failures. However, the analysis of worldwide completion failures indicates control lines to be a critical component of failure. In fact, control lines and associated components, such as clamps and fittings, are not engineered with the same rigor as the rest of the well completion. The first step in understanding control-line failure is predicting the loads and stresses in a control line strapped to the tubing. Tubing movement causes loads in the control line through stretching and bending. To a lesser degree, the tubing is loaded by the control lines. To determine this interaction, a calculation is performed in which the control line and the tubing are treated as a composite, with axial displacement constrained to be the same in both. This analysis provides the average stress state in the control line. Because the control line is fixed at only certain points along the tubing, the variation in stress from the average must be determined between clamps. This paper provides the technical details for both calculations. Several example cases based on field data are presented that give insight into the potential problems that typical production scenarios create for control lines.

Subsea Control Fluids: Avoidance of Hydrate Formation

With the increasing number of deep offshore production wells, it becomes essential to develop, test and qualify new hydraulic control fluids with enhanced temperature and pressure ranges. These requirements apply especially with focus on the avoidance of hydrate formation in subsea control systems. Due to these technical reasons, but also due to recent changes in environmental legislation, the qualification of new control fluids has become one of the central topics of Cameron's R&D activities. Evaluation of the newly developed fluid “Castrol Transaqua HC10” and the required qualification activities is briefly discussed. The fluid was developed in order to extend the application range especially for deepwater production wells. Drivers for the development have been parameters such as temperatures and pressures, which can lead to hydrate formation in case of a potential gas leakage at the surface-controlled subsurface safety valves. A comprehensive qualification program has been started with the goal to approve the fluid for the use in its first subsea application.

Technology Focus: Deepwater Exploration and Production (June 2009)

Technology Focus Even in today's changing times, the challenges of deep water continue to demand new and innovative technologies. Explorers are finding new fields hidden tens of thousands of feet below the mudline, reaching depths that cannot be completed currently. To produce from these depths, companies are developing completion equipment rated to high pressures both in absolute and in differential terms. Successful qualification of new high-yield metal alloys is a key enabler for delivery of high-pressure/high-temperature completion-equipment solutions; specifically in the development of a 20,000-psi-rated surface-controlled subsurface safety valve, 15,000-psi-differential-rated completion equipment, and 30,000-psi-rated downhole-test-tool equipment. The current mechanical-property limits for high-yield metal-alloy materials must be extended with material solutions that provide robust corrosion performance. Past experiences by many operators have led to a rigorous assurance process to ensure that new equipment will work and work the first time. Equipment statement of requirements, detailed design reviews along with comprehensive qualification plans, system-integration tests, and, potentially, field trials are part of the overall equipment-integrity assurance. As we continue to explore in deep water, new horizons at depths never before completed demand new ideas and new technologies to enable development. As professionals working in the oil industry, we need to continue working together to find new ways to develop these deeper high-pressure reservoirs and then to develop the equipment to produce them. We need to keep that "can-do" attitude. Deepwater Exploration and Production additional reading available at the SPE eLibrary: www.spe.org SPE 113727 • "Optimizing Wireline-Gun-System Design and Perforating Performance for Very Late Changes in a Gulf of Mexico HP/HT Deepwater Well" by L. Sabbagh, SPE, Schlumberger, et al. Additional reading available at OnePetro: www.onepetro.org OTC 20022 • "Geohazard Assessment in a Deepwater Subsea Development—A Contractor's Perspective" by Roberto Bruschi, Saipem Energy Services, et al. OTC 20087 • "Early Testing—Jabuti Extended Well Test" by J.R.C. Melo, Petrobras, et al.

Improving Well Safety With an Innovative Surface-Controlled Subsurface Safety Valve

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113829, "Improving Well Safety and Maximizing Reserves Using an Innovative Surface- Controlled Subsurface Safety Valve (SC-SSSV)," by Francois Millet, SPE, Harve Petit, and Gery Wallez, Geoservices Equipment, and Philippe LaLanne, Alain Ducasse, and Emile Barzu, Total E&P France, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed. A common cause of failure of surface-controlled subsurface safety valves (SCSSSVs) is a defect in the downhole hydraulic line that controls the valve from the surface. Such a failure generates production losses and requires the intervention of a costly workover rig. To alleviate this type of situation, a system has been developed in which the physical control line has been replaced by a communication system based on electromagnetic (EM) waves. The surface emitter continuously sends a signal to the SCSSSV. Both are designed to be fail-safe. Introduction Lacq field was developed from 1951 to 1957, while solving metallurgical constraints caused by the 15% H2S and 10% CO2 in its gas composition. Nearby, three other fields produce the same long and narrow reservoir and started production in late 1967. From 1968 to 1982, gas production reached approximately 33×106 m3/d, the production from the four fields being centralized at the Lacq treatment plant. These fields are now at the end of their life. The last well was drilled at the end of 1990. Since 1957, well pressures have dropped from 70 MPa to as low as 2 MPa. Unstable water production started in the early 1980s on some wells in the Meillon and Saint Faust fields, causing high operating costs because of water-disposal problems. Furthermore, the normally open velocity and ambient valves used on some wells are no longer acceptable because unstable flowing conditions do not allow accurate and repetitive closure. To extend the life of the wells and maximize the recovery factor, Total E&P France has been looking for a solution to replace subsurface-controlled safety valves (SSCSVs) and nonfunctioning SCSSSVs with new SCSSSVs without the need for a work-over. One solution is surfactant injection at the reservoir level. In this case, the challenge is to free the available nipple and set an injection device in the nipple, again without any work-over or wellhead modification. Avoiding WorkoverThere currently are two types of safety systems being used.The SSCSVs are wireline retrievable (WR) and are calibrated well by well according to the latest production conditions. They are less and less compliant with safety regulations.The SCSSSVs are fail-safe production-rate independent, and testable from the surface whether they are tubing retrievable (TR) or WR.

Reliability modeling of surface controlled subsurface safety valves

The article discusses the consequences of choosing a Weibull life distribution instead of an exponential distribution. The discussions are based on a specific data set for surface controlled subsurface safety valves (SCSSVs) used in offshore oil and gas production wells. The estimates of the mean time to failure and the mean fractional dead-time based on the stochastic censored data set, are shown to be non-robust with respect to variations of the Weibull parameters. The availability of the SCSSV as a safety barrier against blowouts is discussed in relation to risk acceptance criteria and the principle of ‘as low as reasonably practicable’. Replacement policies to balance the risk and operational cost are proposed and discussed.

Reliability Management of Surface-Controlled Subsurface Safety Valves for the TOGI Project

Summary This paper describes Norsk Hydro and SINTEF's efforts to obtain higher reliability of surface-controlled subsurface safety valves (SCSSV's) for the Troll-Oseberg gas-injection (TOGI) project. Because of the severe consequence of system failures, reliability management was fully implemented on the TOGI subsea production system. The methodology used combines reliability theory with operating experience. Data bases with relevant field data, design review techniques, valve prototype testing, and review of test results are other elements of the reliability management program. Although this specific application was for SCSSV's, the methodology presented in this paper can easily be applied to systems where the consequence of failure is severe.

Safety Systems in Subsea Completions

Summary This paper focuses on safety systems used in Challis field subsea wells. Itexamines the design philosophy covering subsurface tubing and annulus shut-in, as well as the requirement to maintain annulus integrity with gas-lift valves(GLV's). The paper covers design, development, and testing of safety equipment, which should aid in design of completions for similar applications. Introduction Offshore completions require safety systems to prevent injury to persons, damage to equipment, and serious pollution. Subsea completions presentadditional complexity in terms of installation, reliability, and mode ofequipment failure. The Challis field in the Timor Sea is being developedexclusively with subsea completions equipped with gas lift, which will beginearly in the life of the field. This remote marginal development, which uses afloating production facility, requires low capital and production facility, requires low capital and has minimal operating costs. Costly subsea workoversshould be avoided to ensure that operating costs are minimized. Therefore, itis important that the surface-controlled subsurface safety valve (SCSSV) andthe GLV, traditionally the prime components for failure in a completion, becritically examined. The use of gas lift in a well introduces hydrocarbons intothe annulus and creates a potential leak path through the GLV. A catastrophicfailure in which the subsea tree is forcibly pulled off the completion mayresult in a large amount of gas escaping from the annulus and the potential forthe well to flow back through the GLV. A design specification for thecompletion included both tubing and annulus shutoff when the subsea tree failsand requires that the valve have a 10-year working life. At Challis, tandemtubing-retrievable SCSSV's were used to achieve a tubing shutoff system capableof operating for the 10-year life of the well. A unique solution developed for@ annulus safety system consisted of a shear orifice GLV and an annulus safetyvalve below the tubing hanger. Background Subsea completions should be designed to withstand a catastrophic failure inwhich the subsea tree is removed forcibly from the well. This could occur whenan anchor chain or fishing net is dragged over the subsea tree. Two generalfailure modes can be identified in subsea completions: mechanical failure aboveand below the tubing hanger. In failure below the tubing hanger, which is themore serious of the two, the SCSSV's must be located at a position in thetubing that is below the calculated point of failure. The SCSSV then shuts inthe tubing, but because the tubing is no longer supported by the tubing hanger, it may fail from the resulting high compressional forces. Tubing failure causedby excess buckling or failure at the packer seal system could occur, dependingon the particular design and the condition of the components. Corrosion willsignificantly increase the chance of a leak developing in the tubing. A leakmay occur at a depth greater than the SCSSV setting depth, allowing well fluidto flow into the annulus. If insufficient hydrostatic head is present in theannulus, the well will flow present in the annulus, the well will flowuncontrolled. To circumvent this problem, a secondary tubing hanger can beinstalled below the failure point (Fig. 1) and a weak joint positioned abovethe secondary hanger to ensure that the tubing fails at a predetermined pointin the completion. The predetermined point in the completion. The primary roleof the secondary tubing hanger primary role of the secondary tubing hanger isto support the tubing at an intermediate point in the completion, although italso may point in the completion, although it also may be desirable toincorporate an annulus isolation feature by use of an annulus packoffarrangement. The packer may be ported to allow flow communication through itand to include some kind of annulus shutoff device, such as an SCSSV. Analternative to using a secondary tubing hanger is to position the SCSSV's belowthe casing packer. This configuration has several advantages:protection from casing, tubing, and GLV leaks;setting below the depth at which earth movements occur;protection from directionally drilled offset wells;setting below the depth at which hydrates and paraffins occur; andisolation of the formation from kill fluid circulated above the packer. The disadvantage of this design is that the SCSSV's are located at a much greaterdepth and therefore must be capable of operating at higher temperatures. Thenew design of deep-set SCSSV'S, which use nonelastomeric seals in both staticand dynamic modes, allows them to operate reliably at high temperatures. JPT P. 80

An Operational Subsea Wireline System

This paper describes an operational subsea wireline system that is self-contained and flexible and offers a safe, economical, and proven method for riserless re-entry into any subsea well. The system discussed here was developed over a number of years and has been used to carry out a comprehensive range of wireline tasks from floating vessels in the North Sea. Although generally deployed from a diving support vessel (DSV), the system has been successfully used from a drilling rig to conduct wireline operations in a well, simultaneously with workover operations in an adjacent well, on a subsea template.

Analysis of SCSSV performance data

Abstract This paper presents some results from a comprehensive reliability study of Surface Controlled Subsurface Safety Valves (SCSSV) used in the North Sea. SCSSV performance data have been collected from 26 oil/gas fields in the North Sea area. Reliability estimates are presented for the main types of valves. Cox Proportional Hazards models have been applied to evaluate the impact of well parameters and valve characteristics on the reliability of the valves.

Elastomers Are Eliminated in High-Pressure Surface-Controlled Subsurface Safety Valves

Summary Industry well completions are currently limited by the uncertain finite life of elastomers. The useful life of subsurface equipment with elastomeric seals is shortened by temperature, pressure, amines, acids, and completion fluids. All-metal, hydraulically operated surface-controlled subsurface safety valves (SCSSV's) that meet and exceed all regulatory requirements and standards are now available with no elastomeric seals. This fully developed design, awarded the Special Meritorious Award for Engineering Innovation in May 1983, has been completely laboratory and field tested and is being used in critical service well completions. Development of subsurface high-pressure completion equipment indicates that at 10,000-psi [69-MPa] working pressure; elastomers perform at minimum acceptable levels. The longevity of subsurface completion equipment is limited and uncertain. Combining sound engineering principles with state-of-the-art metallurgy, reducing galling tendencies of high-nickel/chrome alloys, and using diffused-surface alloys have resulted in the technology for all-metal hydraulically operated equipment. This technology is expandable to an entire subsurface completion system without any elastomers.