Approximately 3,762 m of coiled tubing (CT) became stuck downhole in a live, offshore high-pressure well. The CT parted after fatigue limitations were exceeded. This paper discusses a snubbing operation that was conducted to fish the parted CT. To ensure flawless execution the following was employed: Successful job design, operational planning, and execution. A complex engineered solution to improve the fishing operation and clean up debris. Introduction of well control applications (hot tapping) to help minimize risk of pressure becoming trapped in the CT. Multiple successful trials. A unique job design was introduced and executed according to plan. Careful engineering, study, and yard trials supported the actual operation. The crew's technical expertise helped improve safety and enhanced efficiency. Significant underbalance skill and fishing proficiency helped make the fishing operation successful. The operator and service company improved their understanding and operational competence by fully communicating with all parties involved. The operator was able to remove parted CT and perform plug and abandonment (P&A) operations in this live, high-pressure offshore well with no incidents or spills. The successful engineering and testing during this campaign are discussed.

The permanent tubing patch is a primary method widely used to isolate water production zones, especially in slim-hole wells. As the name implies, the permanent tubing patch is non-retrievable equipment and presents a significant challenge when removal is needed. None of the global records of permanent tubing patches installed in slim-hole wells demonstrate successful removal. This paper will discuss the methods used to achieve the first-ever Coiled Tubing (CT) milling of a permanent tubing patch in a slim-hole well. CT was selected to convey the BHA for milling the tubing patch sealing section. An eccentric pilot milling bit (2.780 in OD) was carefully designed as it needed to pass an ID restriction (2.813 in) in the Downhole Safety Valve (DHSV) while still being able to peel off the tubing patch sealing ID (2.250 in) until reaching the full drift of tubing ID (2.992 in) and ensure that the tubing wall would not be damaged during the milling operation. Once the tubing patch sealing section was removed, a braided-line (WL) operation was run to pull free and retrieve the tubing patch body to surface. The well was then restored to enable further intervention and production. CT performed the milling operation flawlessly, and a carefully designed surface equipment stack-up design provided downhole tool deployment accessibility and convenience for both CT and WL intervention. Nitrified fluid was used with CT to mitigate loss problems in several depleted zones above the milling depth. As a result, the tubing patch seal was successfully milled without jeopardizing the tubing integrity. Once the tubing patch seal element was successfully removed and the patch body became free, the WL was deployed through the CT stack to fish the tubing patch body. This is the first-ever operation to remove and retrieve a permanent tubing patch to the surface in this way without damaging the primary completion. Its success results from a well-thought-out pilot mill bit design and careful execution. This case study can now be shared across the industry to improve intervention efficiency and minimize the chance of early plug and abandonment due to permanent tubing patch removal issues.

An operator recently launched a "water-shutoff" polymer development project for an onshore injector well in a brownfield operation in Thailand. To effectively improve water flooding performance in this field, shutting off a water thief zone was a prerequisite. Several conservative expanding tubing pads placed in the upper zones restricted access to the lower zone perforations or placement of another tubing pad in the lower zones; therefore, operational planning and strict laboratory testing were performed. This included setting-time testing using an actual chemical blend in batch mode, which closely simulated bottomhole conditions. The process required shutting off the upper zone to facilitate water injection into the lower zone, employing coiled tubing (CT). The design consisted of a shut-off treatment with a lost-circulation material (LCM) to help ensure wellbore fluid placement and shutoff in the high-permeability water thief zone at the designated positions, and to ensure that the pressure response could be monitored from the surface. The shut-off operation was performed as planned, and CT was used for cleanup after placement. Water-production monitoring has shown that the shut-off polymer is one of the best solutions for this field in terms of safety, economics, and operation. As a result of well testing, after the thief zone shut-off treatment, water injectivitywas decreased by approximately 97%, demonstrating the effectiveness of the technique in terms of safety, economics, and operation. A long-term monitoring program was established to evaluate the polymer’s seal-off performance for development of future field strategies. Such an operation could help increase oil recovery by 5 to 10% of oil in place. This technique does not require mechanically sealing off the perforations, making it more feasible for future well interventions and enabling a greater injection rate for chemical EOR where desired.

Coiled Tubing (CT) is a commonly used well intervention technique for sand/debris cleanout, milling, fishing, cementing, and gas lifting applications. Performing cement plug operations with CT in high-pressure live wells can present a relatively high level of risk of getting stuck, improper placement of cement plugs, and poor quality cement plugs. In this scenario, an offshore well in Vietnam was left with CT held only on the surface by the Blow Out Preventers (BOP) after getting stuck downhole more than a year previously. Retrieval of the CT was required without any downhole barrier in place and circumstances that made the conventional killing of the well difficult. This paper will discuss the equipment necessary, factors to consider in the job design, sealant design with lab testing, and describe the technique used to safely retrieve the fish from the well. During the design phase of the solution, risk assessments were carried out to cover various scenarios such as: Poor condition of one or more of the CT string, BOP, dual ball kelly cock valve, double flapper check valve. Inability of the Organic Crosslinked Polymer sealant to hold well pressure. Difficulty in latching the surface CT stump, and the potential requirement for freezing to establish a surface barrier. Along with the specially designed sealant treatment, multiple yard tests for dressing the sheared CT and latching were performed to represent actual conditions during the operation and allow risk mitigation plans to be put in place. Firstly, the barrier verification process was performed to monitor any well pressure build-up from the downhole/surface pressure reading to confirm a barrier was in place, allowing surface equipment to be rigged up. After this was confirmed, the equipment was rigged up, and a fluid circulation test followed by the inflow test of the double flapper check valve in the bottom hole assembly was performed to verify CT integrity. The first of the organic crosslinked polymer was then pumped to plug inside the CT before electric line (E-line) was run into the CT to cut at the free-point above the stuck location. The second organic crosslinked polymer was then placed to plug between the CT and annulus, forming a barrier allowing the makeup of the spoolable connector. Finally, retrieval of the 1,700 meters of CT string took place without any loss of well control. Retrieving the CT from this high pressure well presented a lot of challenges. Achieving a safe and successful operation showed that with proper planning, design, and risk mitigation plans, a potential well control situation can be prevented with the well being secured and successfully returned to production. This paper can now serve as a guideline for future operations with similar circumstances requiring retrieval of stuck CT from high-pressure wells where it has been held on surface for an extended period of time.

An offshore operator in Vietnam faced high water production in a sub-hydrostatic and highly aromatic gas well. In addition to low productivity, the high water cut also strained the water treatment facility. Previous treatment attempts to shut off the high water-producing zones have been unsuccessful due to challenging well conditions. [EB1]With the treatment facility reaching maximum capacity, and expansion of the water treatment capacity being a time-consuming and costly option, a subsurface well intervention was chosen as the most effective way to reduce water production from the well. The well had complex reservoir characteristics due to highly depleted zones that made treatment placement even more complicated, increasing the risk for the operation. The well produces aromatics, and using packers for isolation reduces the packer element sealing performance. Due to the high deviation angle, a Thixotropic Organically Crosslinked Polymer (TOCP) was designed and pumped for the high water-producing zones. A customized solution using a TOCP with extensive laboratory testing was found to be the most suitable treatment design for this well. The new placement technique provided prevention of losses to the depleted zones. The thixotropic treatment provided higher viscosity when pumping stopped, allowing the polymer to seal off at the target zone. As a result of the treatment, the well responded positively. The operator significantly reduced produced water from 5,000 BPD to 2,000 BPD, accommodating the capacity of the water treatment facility. Meanwhile, gas production also increased from 4.6 M SCFD to 6.1 M SCFD, reducing the possibility of the well getting loaded up during platform shutdown. The careful engineering design and laboratory testing played a significant part in the successful campaign, with collaboration from the operator and service company leading this campaign to be a successful project. This approach and solution can help enhance production performance and reduce the cost associated with water production.