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.

While optimizing hydrocarbon production, combining well intervention solutions can enable significant benefits due to reductions in risk exposure: fewer rig-ups and downs, less in-the-hole operating time and the carbon production and costs associated with rig time, especially when working from sub-sea intervention vessels. Operators in general, prefer to achieve multiple intervention objectives in a single descent in the well, if the operations complexity does not increase the risk exposure to an unacceptable level. Often, the risk of a mis-run, causing a second run, meets the cost vs value criteria for acceptable risk, when the large operating time savings of a successful combined run is considered. In collaboration with a mechanical e-line provider, North Sea operators developed three reliable combination solutions which increased their operational efficiency. Combining these most run services under more standard, common scope of work procedures, saved the operator time in planning, execution, risk exposure and money, while enabling them to produce hydrocarbons in the saved time. This paper will present the technology involved with these combined services, use a typical example of each and the cost savings achieved.

Re-entry of subsea wells can always hide unforeseen difficulties. Contingency mobilization of coiled tubing (CT) usually gives a wide spread of solutions to overcome most of the possible events. However, when operating on a winterized semisubmersible rig in the remote fields of the Barents Sea, rig-up of CT spread can be costly and complicated. Furthermore, lighter and easily deployable wireline powered mechanical tools have proven to be effective in tackling most of the possible challenges. Possible tubing obstruction issues can be resolved via clean-out/suction, pumping, or milling methods. In this instance, all three were used with different tools to clear the obstruction from the tubing and to clean with precision inside an internal fishing profile of a well head barrier plug to allow for well access. The first challenge encountered when re-entering the tubing in Well-1 was the presence of a 151m long hydrate plug. It was easily removed by an e-line tool capable of applying 10 bar of dynamic underbalance, while maintaining a continuous flow circulation. Such an application is a novel development in the use of existing tools. After removing the hydrate plug, it was discovered that the tubing was plugged by 246m of wax deposits, which were preventing communication with the reservoir. To overcome this problem, a jetting tool was utilized to continuously pump fresh wax solvent inside the landing string. Pumping continuously fresh wax dissolvent provided a unique and effective means to mechanically and chemically remove a significant obstruction. Once the communication with the reservoir was re-established, an additional obstruction of almost 129m (resistant to the wax dissolvent) was encountered. To overcome this challenge an e-line milling tool was utilized, and the resulting debris was bullheaded down into the reservoir. Similarly, when re-entering Well-2 a challenge was encountered to pull a barrier plug due to debris deposits inside the internal fishing profile. Both e-line milling and suction tools were sequentially used to resolve the problem and prepare the plug for retrieval. The tools used were already available on the market for different applications. In this case the tools were used in an alternative way, using their features to solve issues beyond conventional expectations. The result fosters confidence to plan future re-entry without the need for mobilizing a CT spread.

Pipe cutting operations are often a critical part of stuck pipe situations, well interventions and plug and abandon operations which all need to remove cut sections of pipe from the well. Unlike traditional ‘blade’ style e-line cutters, which can jam under pipe compression or explosive pipe cutters, which need to dress-over the jagged cut by the rig, a new electric line mechanical cutter's unique design enables performance even if the pipe is under compression, in tension or is neutral. It can also perform multiple cuts in the same run, while creating a clean and machined cut with tool-entry friendly shape. This paper will describe the technology of the new generation cutter, present two case histories; one of multiple cuts of stuck drill pipe, per each run in hole, from Germany and one of a critical tubing cut from a subsea well in Nigeria, using electric wireline and tractor conveyed services for many tasks traditionally performed with coiled tubing in highly deviated wells. These "light vs heavy" solutions can often be done off-line from the rig.