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.

This paper discusses an offshore coiled tubing (CT) application to address a complex well situation and well control issue. Multi-engineering designs and 100% yard testing were used successfully during this campaign. Parted production tubing was identified some 50 m from the surface. The control line of the downhole safety valve failed and one barrier was lost in the well. This paper describes efforts to regain pressure integrity for a plug and abandonment (P&A) procedure in this live gas well. CT was inserted through the parted production tubing in an attempt to regain pressure integrity. A carefully planned cement placement strategy was critical to operational success. Key challenges and solutions included the following: Wellhead pressure (WHP), friction, and a highly deviated trajectory affected CT pulling capabilities. Therefore, extra-lightweight cement was used to reduce weight inside the CT.The downhole safety valve failed to close, so the downhole tool was redesigned to help ensure that the tool would not stick. 100% Yard testing for the application was performed to simulate onsite, downhole operations. Well pressure integrity is a primary priority for global operators. An option to regain pressure integrity was introduced and involved running CT and placing cement into the live well. A combination of multi-engineering designs aided this successful CT campaign. The CT was run through the parted production tubing and the failed downhole safety valve. The well was killed and extra-lightweight cement was successfully placed. The operator was able to regain pressure integrity and perform a P&A procedure. The success of this case study indicated that this procedure could be used for future downhole equipment and tubing failures in live gas wells.

Unwanted water production in mature wells is one of the main issues for oil and gas operators worldwide, causing several economic issues related to hydrocarbon production. Furthermore, in this scenario, the swell packer installed between the water and oil-producing intervals had failed, resulting in communication behind the casing. This created difficulties when trying to shut off water-producing intervals without impacting the oil-producing intervals. This paper will discuss and outline the shut-off technique, factors considered as part of the job design, the sealant and temporary gel protection design with lab testing, and describe the job implementation of this case study. Hydroxyethyl Cellulose (HEC) based gel was selected as the temporary zonal protection in the lower, low-pressure reservoir interval, while the sealant gel was designed to shut off the higher pressure upper reservoir interval. The use of Coiled Tubing (CT) allowed the fluids to be placed precisely at the desired interval before applying squeeze pressure to force the treatment fluid further into the near-wellbore region, increasing the overall chance of success. Several critical concerns were outlined, such as the inability of the HEC based gel to be able to set and self-degrade in the required time, excessive gel penetration into the formation leading to formation damage, difficulties for wellbore clean up after the treatment, and the uncertainty of the leaking swell packers capability of sealing between the intervals behind the casing. Multiple lab tests were also designed to verify the suitability of the temporary gel and thixotropic particulate gel systems in achieving overall operational success. The zonal protection fluid treatment was successfully mixed and pumped according to plan to create the temporary zonal protection (barrier). Verification was achieved by tagging the top of the barrier and observing the pressure change in the real-time downhole gauge. The thixotropic particulate gel sealant treatment was then tailed in and squeezed into the upper interval to shut off the zone and create an annular barrier behind the casing to isolate different intervals. Once the fluid treatment stage was complete, all the remaining gel in the tubing was successfully removed using CT with a rotating jet nozzle. An organic acid blend was then squeezed across the lower intervals to accelerate gel degradation time, followed by the flow back operation to test the treatment effectiveness. Final flow test results showed a reduction in water cut from 82% to 64% and an oil production increase of 400 bopd to 550 bopd. A significant challenge was to create the temporary zonal protection of the lower oil-producing intervals and shut off the water-producing interval above while creating an annular barrier behind the casing within the same well. This achievement of a successful operation with detailed fluid design, placement techniques, risk mitigation plans, and good collaboration between the service company and operator can serve as a recommendation for wells with similar issues while providing an alternate cost-effective solution to extend the life of the well without the need to abandon intervals or re-complete existing wells.