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Coiled tubing was utilized as a conduit-type riser to deliver high-pressure fluids from a rigless multi-service vessel (MSV) during a GOM multi-well treatment campaign. The campaign consisted of high pressure pumping into a number of subsea wells for extended durations. The coiled tubing (CT) downlines are deployed with a clump weight through open water and connected to the subsea safety module and well stimulation tool. The depths of these operations were on the order of 1,372m (4,500 ft) and quite similar (±100 ft). Fluids (including acid) were pumped continually through the conduit at pressures up to 10,000 psi for extended periods of duration (on the order of several days) from the MSV to the fixed subsea safety module. Waves and currents impose pitch and roll on the MSV, along with the need for continual dynamic repositioning. This motion causes discrete wrapping and unwrapping at the point where the tubing just exits the sheave (the "hot spot"). This leads to elastic strain fluctuations that can lead to significant high cycle fatigue (HCF) damage. The MSV must continually adjust its heading for optimal metocean response. A unique system was designed and implemented to coordinate this positioning with minimized CT HCF damage accumulation. The system uses a robust position transducer to provide continual input about the critical components of vessel motion. This information is used by a program to compute the near real-time dynamic stress response of the tubing at the hot spot and the corresponding HCF damage accumulation, along with the low cycle fatigue (LCF) damage accumulation that occurs along the entire length of the tubing as it is deployed during each job. The system facilitated the management of multiple jobs, assuring that hot spots were not over-exercised from job to job. This was important due to the similar depths of the wells. The hot spots were tagged with paint to confirm their location. The mechanics underlying the fluctuating stresses at the hot spot are described along with how these are computed from the MSV motion. Post campaign fatigue testing was conducted to validate the residual life in the tubing, as predicted by the program.
Coiled tubing was utilized as a conduit-type riser to deliver high-pressure fluids from a rigless multi-service vessel (MSV) during a GOM multi-well treatment campaign. The campaign consisted of high pressure pumping into a number of subsea wells for extended durations. The coiled tubing (CT) downlines are deployed with a clump weight through open water and connected to the subsea safety module and well stimulation tool. The depths of these operations were on the order of 1,372m (4,500 ft) and quite similar (±100 ft). Fluids (including acid) were pumped continually through the conduit at pressures up to 10,000 psi for extended periods of duration (on the order of several days) from the MSV to the fixed subsea safety module. Waves and currents impose pitch and roll on the MSV, along with the need for continual dynamic repositioning. This motion causes discrete wrapping and unwrapping at the point where the tubing just exits the sheave (the "hot spot"). This leads to elastic strain fluctuations that can lead to significant high cycle fatigue (HCF) damage. The MSV must continually adjust its heading for optimal metocean response. A unique system was designed and implemented to coordinate this positioning with minimized CT HCF damage accumulation. The system uses a robust position transducer to provide continual input about the critical components of vessel motion. This information is used by a program to compute the near real-time dynamic stress response of the tubing at the hot spot and the corresponding HCF damage accumulation, along with the low cycle fatigue (LCF) damage accumulation that occurs along the entire length of the tubing as it is deployed during each job. The system facilitated the management of multiple jobs, assuring that hot spots were not over-exercised from job to job. This was important due to the similar depths of the wells. The hot spots were tagged with paint to confirm their location. The mechanics underlying the fluctuating stresses at the hot spot are described along with how these are computed from the MSV motion. Post campaign fatigue testing was conducted to validate the residual life in the tubing, as predicted by the program.
Scale buildup due to water production can choke oil production and require repetitive scale treatments across entire fields. In subsea wells, the common solution employs a deepwater rig to conduct either workover operations or large-volume scale inhibitor squeezes. Less frequently, coiled tubing (CT) is used from a moonpool vessel. However, current oil prices required a custom solution for subsea well treatments that was more cost effective than either a rig or a moonpool vessel. Similar previous operations successfully used 1 ¾-in. and 2-in. (44.4 mm. and 50 mm.) CT at the same time from a moonpool vessel. A remotely operated vehicle (ROV) in the open water connected the CT to the subsea safety module (SSM) through a dynamic conduit and connected the SSM to the wellhead. An engineered solution to change to 2 7/8-in. CT and use high-rate stimulation pumps was planned to deliver subsea treatments at up to 15 bbl/min. The equipment layout was designed for a multipurpose supply vessel with chemical storage tanks; to increase the available selection of vessels, the CT was designed to run overboard rather than through a moonpool. This project was initiated after accelerated scale buildup occurred because of a pressure decrease close to the bubble point, which happened when the drawdown was increased for aggressive production targets. To effectively inhibit scale in this environment, treatments required thousands of barrels of inhibitor. For wells with more-severe scale conditions, acid treatments were planned. These treatments were delivered with one complete CT package, stimulation pumping fleet, and subsea equipment, which were all installed on the spare deck space of the available vessel. A custom overboard CT deployment tower was designed. The new tower improved the dynamic bend stiffener (DBS) placement, which allowed the clump weights to be deployed with the bottomhole assembly (BHA) and simplified the rig-up. The chosen vessel worked well for the operation; however, the equipment layout and the local weather conditions combined with the response amplitude operator (RAO) of the vessel shortened the projected fatigue life of the CT. CT integrity monitoring with magnetic flux leakage (MFL) measurement was introduced here, and the vessel’s motion reference unit (MRU) provided an input to a fatigue calculator, based on the global riser analysis (GRA). The measurements and the analysis were utilized successfully to prevent CT pipe failures in the open water and deliver the required well treatments. To allow further improvements in deepwater operations, the new engineering work-flow was carefully documented.
Recent industry trend to increase the production from current offshore assets without significant green field investment require more intervention operations. Riserless light well intervention system is gaining more popularity due to quick turn-around and efficiencies. A typical riserless light well intervention system is composed by coiled tubing downline system, umbilical and wireline system, and well control package. The existing coiled tubing and riserless light well intervention system unfortunately is not designed for open water intervention operations, especially in challenging deepwater environment. For offshore interventions on a floating vessel, the coiled tubing is deployed from a reel through an injector, and is subject to significant dynamic movements due to wave loadings, ocean current and vessel movement. Integration of umbilical, wireline and other pressure control equipment causes additional constraints on the system's already limited operability windows. Additionally, the crowded subsea infrastructure and dropped object risks create extra challenges for safe and efficient operations. This paper presents the key challenges and solutions faced by operators in design and operation of the offshore riserless light well intervention system. The challenges are presented from several perspectives: from the equipment capacity and integrity, system operability limitations, risk awareness, procedure controls, to industry standards. The methods and processes to tackle each challenge are presented. The equipment capacity and weak point are identified and improvement options of various components are evaluated. The equipment improvement opportunities include LARS hoisting capacity assessment, UTA and mudmat tipping over prevention, wireline lazy wave and buoyancy configuration, injector head and guide optimization, subsea jumper and ROV pulling load specification. The operability limitations are increased by engineering analysis optimization and detailed 3D finite element modelling of critical components. Risk awareness and procedure controls are improved by operation guidance and fatigue monitoring mitigations. The novel approaches presented in this paper can be considered for improvement of other riserless light well intervention systems and development of a common industry standard.
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