Subsea Well Annular Integrity Repair Using Coiled Tubing and Pressure Activated Sealant
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Abstract Production from a subsea well was halted due to hurricane activity in the Gulf of Mexico. When the well was returned to production, the annulus experienced a loss of pressure integrity. To achieve regulatory compliance and return the well to production, annular integrity had to be restored in a safe, expeditious manner. This paper will describe the process of operations undertaken to cure this well integrity issue utilizing pressure activated sealant deployed via coiled tubing. Pressure activated sealants have been utilized for a number of years to efficiently cure leaks in a wide variety of applications. One of the first challenges to be addressed when considering a sealant repair is the method of getting the material to the leak site. For the purpose of the subsea well in question, coiled tubing was used to convey the sealant to the sea floor from a service vessel. An ROV then connected the coil to an external tree cap via a flying lead after which the sealant was introduced to the annulus by lube and bleed pressure cycles. The annular integrity issue was analyzed in an effort to determine leak severity and location. Pressure trends noted at annular pressures of 4000 psi indicated a leak ranging from 0.15 – 1.5 lit/min. Gradient analysis indicated that the leak was deep in the completion potentially at a liner lap or the packer. Based on this information a sealant blend approximately 2 ppg heavier than the completion fluid was developed for the purpose of curing the leak. An external tree cap was installed on the well in order to provide access to the annulus of the well via a hot stab connection. About eleven cubic meters of sealant was transferred to the annulus through 2" coiled tubing extended to the sea floor connected to the well via a flying lead. A series of lubricate and bleed cycles were performed to accomplish this without exceeding predetermined pressure limits. After allowing the sealant to settle on the packer, annular pressure was maintained to allow the sealant to cure at the leak site. The pressure differential at the leak caused the liquid sealant to form an elastomeric seal. A positive pressure test was obtained shortly after the process and the well was returned to production. An example of how using pressure activated sealants designed to polymerize only at a leak site affords options to expensive workovers on subsea wells will be provided herein. The use of this technology in concert with coiled tubing deployment represents an expeditious, economic approach to solving complex well integrity issues.Keywords:
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Coiled tubing
Abstract Sweeping changes have been experienced throughout the whole of the subsea oil production industry. Space technology has gone subsea, and with it comes the need to properly address the relevant issues. The traditional oil industry, used to measure its tools in multiple of tons and its performance in barrels, has been faced by the challenge of distributed system interfaces and their metrics. This paper describes of how the challenge is being tackled at FMC Kongsberg Subsea (FKS), the Subsea Production System manufacturer with the largest number of system installed in the world.
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Abstract The failure of a subsea production plant could induce fatal hazards and enormous loss to human lives, environments, and properties. Thus, for securing integrated design safety, core source technologies include subsea system integration that has high safety and reliability and a technique for the subsea flow assurance of subsea production plant and subsea pipeline network fluids. The evaluation of subsea flow assurance needs to be performed considering the performance of a subsea production plant, reservoir production characteristics, and the flow characteristics of multiphase fluids. A subsea production plant is installed in the deep sea, and thus is exposed to a high-pressure/low-temperature environment. Accordingly, hydrates could be formed inside a subsea production plant or within a subsea pipeline network. These hydrates could induce serious damages by blocking the flow of subsea fluids. In this study, a simulation technology, which can visualize the system configuration of subsea production processes and can simulate stable flow of fluids, was introduced. Most existing subsea simulations have performed the analysis of dynamic behaviors for the installation of subsea facilities or the flow analysis of multiphase flow within pipes. The above studies occupy extensive research areas of the subsea field. In this study, with the goal of simulating the configuration of an entire deep sea production system compared to existing studies, a DES-based simulation technology, which can logically simulate oil production processes in the deep sea, was analyzed, and an implementation example of a simplified case was introduced.
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Abstract This paper describes a concept for subsea coiled tubing well intervention, without the use of a workover riser system. Coiled tubing analyses and design, surface and subsea equipment design, vessel and operational requirements and limitations are addressed. The novel steps in the development are the lubricator system, where the lubricator resides on top of the injector, and the use of a tensioned coiled tubing configuration with a heave compensation system and a second coiled tubing injector at surface. A comparative risk assessment has been performed, and concluded that the overall personell and environmental risk is the same or reduced compared to a workover riser based system. Introduction With the increasing number of subsea wells, there is a need for more cost-effective intervention methods. For offshore platform wells, typical recovery factor (for the North Sea) is in the 50 - 60 % range, whereas for subsea wells, this number is significantly lower, typically in the 30% range. One of the main reasons for this is the low intervention frequency in subsea wells. While platform wells are commonly intervened as often as 2-4 times a year, subsea wells are in general only intervened if absolutely necessary, i.e. in case of barrier failure or dramatically reduced production. The main reason for this is the cost and difficulty associated with subsea well intervention. Intervention in subsea wells traditionally involves mobilizing a drilling rig and running a workover riser system [1]. With this approach several days of operation is required before any productive work in the well can commence due to the time required for positioning and anchoring of the rig and installing the workover riser system. While the use of dynamically positioned (DP) vessels has eliminated the time required for anchor handling, running of jointed workover riser (WOR) is still a time consuming operation [2]. Operators also tend to use contracted drilling rigs for drilling and completing wells rather than intervention operations, where the outcome is in general more uncertain. While production logging and well test data is usually available for platform wells, this type of information is in general not available for subsea wells, making planning of the intervention operation difficult. Usually diagnostic runs, i.e. production logs are included in the intervention campaign, as well as mobilization of equipment for various outcomes of the diagnoses. For a platform or onshore well, the intervention campaign often continues at another well while i.e. production logs are being analysed and additional equipment is mobilized. This is not practical for subsea wells, with the possible exception of templates or other configurations where the wells are in close proximity to each other so the rig may be moved between wells without pulling the workover riser. Experience from platform wells indicates that well intervention has higher risk of incidents and accidents than drilling and completion operations. When the risk of operating with a workover riser with full well pressure up to the vessel is added to the equation, the risk of incidents and accidents is above operators' comfort level, especially in harsh weather areas such as the North Sea.
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In SRF cavity application, super-fluid helium leak is a issue. Development of highly reliable and cost effective seal method is very important. We have successfully applied MO seal to SRF cavities. We have found out a leak rate limit: 1*E-10 Pam 3 /s with super-fluid helium. When the helium leak rate is smaller than this value, the cavity gradient is expected to be higher than 25MV/m from vacuum point of view. MO seal satisfies well this level. Tightening torque: 15Nm works to get such a small leak rate. As the flange material, SUS316L and Titanium are useable. Copper gasket looks reliable as seal material.
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현대 사회의 필수 자원으로 원유와 천연가스가 자리를 잡으면서 해양 자원의 개발에 관심이 커져가고 있다. 이와 같은 흐름에 따라 조선 해양 분야에서는 해양 자원 개발을 가능케 하는 Subsea system 기술 개발에 주력하고 있다. Subsea 라는 특수한 환경의 특성상, Subsea system 에 대한 정확한 이해를 바탕으로 안전한 Subsea system 구축에 대한 연구의 필요성이 커지고 있다. 본 논문에서는 안전한 Subsea system 구축에 대한 연구에 앞서 Field layout 형태 중 하나인, Multiple well tie-back 을 기준으로 Subsea production system 에 대한 조사를 통해 전반적인 Subsea production system 에 대한 Concept과 Process 의 이해와 향후 연구 분야의 설정을 돕고자 한다.
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Subsea tubing hanger is an important component of Subsea Christmas Tree,used to hold tubings down hole and connect production pipe of Christmas tree,sealing the space between Christmas body. The annular seal of subsea tubing hanger include metal seal and non metal seal.In order to improve the performance of non metal seal,this research take deep analysis on it's Structural mechanics model,get the methods to improve the performance of non metal seal,and verified through experiment.
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These days, subsea development solution is getting quite common option for a marginal field development. In PL089 where Idemitsu Oil Development Co., Ltd. has 9.6% share, subsea development system has been applied for Snorre, Tordis, Statfjord East and Vigdis fields. It seems to a person who has no experience about subsea development/completion that "subsea completion" is very special. But there are no major difference between platform completion operations and subsea completion operations except subsea completion requires special tools for installing tubing hanger and subsea tree. Since people can not access directly to the subsea systems, special attention is paid for operation process and procedure as well as company's internal control system.
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