Kvitebjørn is a gas and condensate field in the Norwegian sector of the North Sea which was discovered in 1994. Kvitebjørn produces from Middle Jurassic sandstone in the Brent Group with secondary reservoirs on the Lower Jurassic Cook formation and Upper Triassic Statfjord group. The reservoirs lie at a depth of 4000 mTVD-RKB (meter True Vertical Depth – Rotary Kelly Bushing) with initial HPHT (High Pressure High Temperature) conditions.

Due to production, the reservoir pressure has depleted significantly which has resulted in large reduction of formation strength (fracture gradient) in the depleted sands. The subsurface challenge is the pressure uncertainty spanning from full depletion to initial pressure. Depletion and initial pressure existed within the Brent group reservoir, resulting in no drilling window. The use of MPD-RAS-TTRD (Managed Pressure Drilling – Rig Assist Snubbing - Through Tubing Rotary Drilling) with WSM (Wellbore Strengthening Materials) and customized BHA (bottom hole assembly) were used to ensure 2x barriers could be always maintained if losses and crossflow observed (loss of fluid as primary barrier) while drilling and completing Brent reservoir. In this setup, the upper completion and production packer is installed prior to drilling the reservoir section. It allows stripping in and out of the hole with the BHA in a loss / crossflow event.

The MPD-RAS-TTRD experience provided better understanding of risk and consequences when drilling the Kvitebjørn depleted reservoir. The improved understanding was used to evaluate a different drilling strategy to access the deeper Statfjord group reservoir targets by utilizing MPD, WSM and customized BHA, without the RAS-TTRD.

This paper serves as an experience sharing of drilling strategies which enables a stepwise approach in understanding the risk of drilling highly depleted HPHT reservoirs. Showcasing drilling opportunities and risk in mature HPHT fields with complex subsurface and severe depletion challenges with a combination of depleted pressure below 300 bar / 4351 psi and initial pressure of 775 bar / 11240 psi. To date, the highest differential pressure between wellbore and formation that had been documented were 540 bar / 7832 psi, measured with Formation Pressure While Drilling (FPWD) tool; 660 bar / 9572 psi estimated based on nearby well data because the depleted pore pressure is lower than the maximum drawdown of the FPWD tool. Therefore, it can't be measured.

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