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.

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