BD Field is the first development project of Husky-CNOOC Madura Limited (HCML) in Madura Strait, Indonesia which has a pressure of 8,100 psi and a temperature of 300°F. This Kujung gas reservoir contains of 5.5% CO2 and 5,000 ppm H2S, indicating that the reservoir is near High Pressure High Temperature (HPHT) and critical sour environment. This paper describes the best practices, lessons learned and strategy to control drilling issues such as slim hole, horizontal, near High Pressure-High Temperature, high density, and sour/acid gas environment to achieve the well TD with torque and ECD limitation, without compromising production target. Kujung reservoir section was drilled with an overbalance mud system as per CNOOC HPHT and sour well requirement. Drill-In fluid (DIF) system treated with potassium formate and manganese tetraoxide as weighting agents was chosen for drilling the 5-7/8-in. reservoir section. Throughout the drilling operation, higher torque and ECD value was identified compared with Torque and Drag (T&D) Calculation and Hydraulics simulation. This can lead to shallower TD decision, which has consequence of possibility not achieving initial target depth/production. Calibrating T&D model using the pickup/rotate/slack-off value from actual measurements on both cased and open holes was done in order to match the model with actual condition. Several analysis and review of all possible causes was performed, including performance of solids control equipment, inadequate hole cleaning, dog leg severity, wellbore direction and/or formation lithology changes. T&D and hydraulics simulation was also performed to foresee the possible operation limitation with several lateral lengths to ensure having successful drilling operation without compromising both operational safety and future well production. Based on the original model, with friction factor values of 0.25 (cased hole) and 0.35 (open hole), 1000-1500 ft lateral length of 5-7/8-in. slim hole section can be achieved. However, with calibrated T&D model, friction factor values were almost double the original model. Comprehensive planning was done to accomplish the drilling objectives, such as re-plan well trajectory to reduce dog leg severity, selection of drill fluid lubricant additives to ensure its stability at pH > 11 environment as planned to control sour gas and compatibility with other products, maximize centrifuge usage to minimize excessive LGS build-up caused by successive and repetitive mud system re-use for batch drilling operations, and diluted system using rehabilitation mud. Reduced friction factors and decreased torque values were the key parameters to successful drilling through the updated planned horizontal length. In terms of gas well production, the objective of well productivity was achieved during unloading operation when gas production result from the wells yielded higher Absolute Open Flow (AOF) as compared to the planned target. Hence a successful BD wells had been delivered to production.

The geothermal drilling environment presents many obstacles that limit the use of directional-drilling and logging-while-drilling (LWD) technologies, such as borehole washout, mud losses, severe vibration, and high temperature. The case study presented in this paper demonstrates a novel practice to enhance data logging in geothermal drilling by deploying advanced telemetry and LWD technologies. This operation aims for continuous improvement in geothermal drilling operations. The case study covers the 12.25-in. hole section of well XXE-05 in the Sorik Marapi Geothermal Field. The LWD string consisted of electromagnetic (EM) telemetry, pressure while drilling (PWD), vibration (DDSr), and acoustic caliper (ACAL). Through this tool configuration, the operator acquired drilling mechanics and caliper logs in real-time and recorded mode, enabling effective monitoring and evaluation of wellbore stability. Throughout the real-time acquisition, EM telemetry provided a data rate to the surface unit three times faster than conventional tools. Furthermore, with the integration of caliper and drilling mechanics data (vibration and equivalent circulating density), the borehole conditions became more visible to the directional driller, allowing better control of drilling parameters to minimize vibration and achieve optimum hole cleaning in washed-out or tight formation sequences. The recorded data from the caliper sensor indicated an average of 8.6% washout for the entire 12.25-in. interval. Washout intervals were compared with loss occurrence during drilling and the presence of smectite-bearing paleosols, showing that the washout zones associate with the latter, supporting the smectite-bearing paleosol model in explaining the cause of stuck pipe incidents in the Sorik Marapi field. In addition, measurements of hole ovality were compared with the interpreted fault trend, providing further insight into the existing model. In general, this LWD case study has given added value through geothermal borehole characterization, from drilling hazard identification to subsurface analysis. Identified challenges while running LWD in this geothermal environment were addressed for future improvements, such as the effect of tool eccentricity and the impact of vibration. Perusal of both real-time and recorded caliper and drilling-mechanics data has opened various possibilities for maximizing the sensor usage in future wells.

The Company had successfully drilled 4 challenging BD Development Wells (1 vertical and 3 horizontal). BD Field reservoir is aKujung 1 limestone reef, considered near HPHT and critical sour with 8,100 psi Bottom Hole Pressure (BHP), 300℉ Bottom Hole Temperature (BHT), 5.5% CO2 and 5,000 ppm H2S. This paper highlights the design phase and well deliverability covering pressure window, casing design, material selection, wellhead and Christmas tree, directional drilling planning, drilling fluid, cementing consideration, well completion, annulus pressure management, and project challenges. The data from two offset wells with surface location radius fewer than 2,000 ft from BD Platform were used as reference for lessons learnt and design for the casing seat selection. Based on the Wellbore Stability Study and the offset wells data, there exists a narrow mud weight window between pore pressure and fracture pressure. The directional plan was developed to have sufficient well separation in the upper hole section and enable fewer dog leg severity requirement to drill in the down hole section. Material selection for casing was designed based on the expected life of the well and reservoir properties in accordance to the requirements of NACE. Drill-in fluid system (Potassium Formate and Manganese Tetraoxide) with mud weight of 14.9 ppg was used to drill the limestone reservoir section providing minimal damage to the reservoir. Production casing cement was tested and analyzed in the laboratory for 60days in the HPHT chamber simulating reservoir properties. Open Hole Monobore Completion approach was selected to complete the well. In order not to compromise well integrity, annulus pressure management technique was fully implemented during drilling, completion, and well clean up phases. The wells were successfully executed despite several challenges which required unique mitigations to manage. During well clean ups, all wells were able to exceed the Absolute Open Flow (AOF) expectations.

BD Gas Field is located in offshore in the Madura Strait, Indonesia, and has a total of four producing wells - one vertical (Well Y1) and three horizontal (Well Y2, Well Y3, and Well Y4) from an unmanned platform. Its reservoir was considered near HPHT and critical sour with 8,100 psi bottom hole pressure, 300°F bottom hole temperature, 5.5% CO2 and 5,000 ppm H2S. This paper highlights on the Company journey to maintain well integrity during well design phase, well construction phase, and production phase of BD Gas Field. During well design phase, material selection and design for 9-5/8 in. intermediate casing, 7 in. production casing, and 4-1/2 in. tubing were based on the expected life of the well and reservoir properties in accordance to the requirements of NACE. Cementing design for 7 in. production casing cement was tested and analyzed in the laboratory for 60 days in the HPHT chamber simulating reservoir properties. Top of cement was designed to the mud line to minimize wellhead growth. Completion design was monobore type and divided into lower, intermediate, and upper completion strings. All packers were V-0 (zero bubble) rating. Maintaining well integrity during well construction phase was challenging. Batch drilling and completion was applied, and at all times, the wells were required to be suspended with proper and adequate barriers. During drilling and well clean-up phase, inter-casing pressure management (i.e., annulus pressure, wellhead growth monitoring, bleed off program, etc.) was implemented to maintain the casing and tubing integrity. During production phase, routine wellhead growth measurement, constant monitoring and bleed off program were developed and communicated with related departments. Pressure control valves and alarm system were installed and tested to the annulus. In additional to the wellhead growth, transverse wellhead movement was observed in one of the wells especially during rough sea conditions. In order to reduce the tranverse wellhead movement which may induce more stress on the surface pipings and connections, it was planned to install under water shims in between the conductor pipe and platform jacket guide funnel. Some surface piping and platform modification were also considered because wellhead growth leads to limitations on gas production to prevent safety issues.