Objectives/Scope: Accidental plug setting and stuck tools is a cause of great frustration, operational delays and ultimately deferred production. A cost-efficient and swift resolution is always desired. This paper presents a new development in engineering in the form of a hydraulic stroking tool with the ability to apply 60,000 lbs of force. The tool has already been applied in the North Sea; lessons learned from these recent operations are disclosed in this paper. Methods, Procedures, Process: In one operation, a plug was accidentally set across the Christmas-Tree (XMT) and blowout preventer (BOP), effectively eliminating the XMT as a well barrier element and constituting a serious HSE risk. Conventional solutions failed to release the plug due to an insufficient pull force and then a failing jar. In another well, the setting tool had malfunctioned, resulting in a partially set plug and a stuck tool. Repeated attempts with heavy duty fishing equipment had damaged the fishing neck, further complicating the fishing operation as the seting tool had failed before it could break the stud connecting to the plug. Results, Observations, Conclusions: The high performance of the recently developed stroking tool turned out to be the solution to save both of these demanding operations. In the first well, it was estimated that the force required to shear the plug from the setting tool would be 43,300 lbs. The operation was completed in three runs with no misruns, which saved the operator from prolonged exposure to HSE risk, including well control situation. In the second well, the force required to shear the stud and free the setting tool was 40,000 lbs. Two release devices were combined in the toolstring, one below the hydraulic stroker and one below the cable head in order to allow further contingencies to mitigate risk and increase safety. After four attempts, the shear stud parted, thus completing the setting sequence and freeing the stuck setting tool. The operator got the well back on track, saved five days of rig time and avoided the costs of a workover rig. Novel/Additive Information: The case stories in this paper constitute the first jobs performed with the new tool. Two important features discussed are reduced HSE risks and increased operational efficiency.

Objectives/Scope: This paper will present an improvement in engineering in the form of a hydraulic stroking tool with the ability to apply 60,000 lbs. of force. The tool has already been applied offshore Norway and lessons learned from these recent operations will also be disclosed. Methods, Procedures, Process:In one operation, a plug was accidentally set across the christmas tree and blowout preventer (BOP), effectively eliminating the christmas tree as a well barrier element, and constituting a serious HSE risk. Conventional solutions failed to release the plug due to an insufficient pull force and then a failing jar. In another well, the setting tool had malfunctioned resulting in a partially set plug and a stuck tool. Repeated attempts with heavy duty fishing equipment had damaged the fishing neck, further complicating the fishing operation as the setting tool had failed before it could break the stud connecting to the plug. Results, Observations, Conclusions:The high performance of the recently developed stroking tool turned out to be the correct solution for both of these demanding operations. In the first well, it was estimated that the force required to shear the plug from the setting tool would be 43,300 lbs. The operation was completed in three runs with no misruns, which saved the operator from prolonged exposure to HSE risk including well control situation. In the second well, the force required to shear the stud and free the setting tool was 40,000 lbs. Two release devices were combined in the toolstring, one below the hydraulic stroker and one below the cable head, in order to allow further contingencies to mitigate risk and increase safety. After four attempts the shear stud parted, thus completing the setting sequence and freeing the stuck setting tool. The operator got the well back on track, saved five days of rig time and avoided the costs of a workover rig.Novel/Additive Information: The case stories in this paper constitute the first jobs performed with the new tool. Two important features are reduced HSE risks and increased operational efficiency, which will also be captured in the paper.

Objectives/Scope This paper will present several case histories on the subject of mechanical pipe cutting on electric line (e-line) as well as the operational steps selected to make the pipe cuts. A description of a new pipe cutting tool together with lessons learned to improve future operations will also be discussed. Methods, Procedures, Process A recently introduced mechanical pipe cutter tool has enabled pipe cutting operations to be performed with e-line. Operations can be executed from fixed platforms and mobile drilling units (MODO) and as Riserless Light Well Intervention (RLWI) through a subsea lubricator for wireline work. With expanded Surface Read Out (SRO) capabilities for collected data this has increased the possibility to determine a positive cut of the tubing. The scope of work includes drill pipe, liner, tubing and casing recovery operations. Results, Observations, Conclusions The described cutting tool leaves a cut profile in the well ideal for subsequent fishing operations because the cut is performed as a grinding inside the tubing, which creates a smooth beveled surface. This minimizes flaring at the cut and thus the time to prepare the pipe for an overshot or retrieval through restrictions. Case #1 P&A operation where the objective was to cut a 7″ tubing, which had severe scale deposits from a depth between 5 ,905 – 7, 717 ft. A Multi Finger Caliper (MFC) indicated a consistent 5.5” ID at 6, 565 ft, which also was the required cutting depth. The mechanical cutter tool was used to break through the scale as well as cutting the tubing, all in one operation. The cut was performed flawlessly with increased operational efficiency as additional runs where made redundant. Case #2 An operator challenged a service company to perform a “double” cut in one run as they were required to pull the tubing in two sections. The well was undergoing a full P&A and cuts were aimed to be performed at depths 15,590 ft and 11,414 ft . There was a restriction in tubing measured to be 3.747” caused by tubing buckling. The mechanical cutter tool was run and cuts completed as planned, yet with unexpected timing with regards to the cutting process itself, but the technical objective was met. Case #3 Cutting tubing in smart wells and allowing for control lines to be parted at weak point has its challenges. By modifying the cutting pads to ensure cutting in connections, the service company has established best practice for cutting above production packers within the confined length for “exposed” control lines. Multiple operations have successfully been carried out in the North Sea basin. Novel/Additive Information The mechanical cutting tool is a novel tool that provides several benefits to the industry. A key benefit to safety and efficiency is that explosives are not required. The transfer of explosives is logistically cumbersome and may incur significant operational delays. Another benefit is the cutting crown design that precludes the tendency for sticking, which is a major concern with other mechanical cutters. The tool further incorporates a fail-safe mechanism that prevents it from remaining anchored. There is also a constant review for re-developments and optimization of this tool as new and complementary technology becomes available.

Operators often struggle with a complex phenomenon causing unwanted and often unpredicted hydrate plugs to form in producing or injection wells, blocking production and re-entry to the well. Conventional remediation methods can be costly, time consuming, and are often ineffective. This paper will share the knowledge gained from a world's first operation, demonstrating that hydrates can be milled using electric line (e-line) tools. The operation was performed from a Vessel Fit for Purpose (VFFP) as a Riserless Light Well Intervention (RLWI) operation in the North Sea, offshore UK. A hydrate plug was tagged below the subsea tree in a water injection well. This unconventional solution was chosen to restore injectivity to wellbore and minimize non-productive time (NPT). Unfortunately, during the operation, harsh weather caused operations to be stopped due to safety issues, and prevented removal of the entire hydrate plug. At that point, reestablishing functionality to the downhole safety valve became a major issue. Fortunately, in less than 20 hours of milling time 173 ft (52 m) of hydrates were removed on e-line and the operator was able to re-establish the functionality of the downhole safety valve. E-line technology provided a swift and accurate resolution to the problem, proving that hydrates can be dealt with as easily as doing any other e-line intervention and that the technology can be run in a ‘live’ well under pressure.