This paper summarizes the challenges faced during the well completion design, planning and execution stages in the "Well-B" located on the "Field-A" offshore Malaysia. In addition, it highlights the modifications and techniques incorporated in the completion design to ensure that the well was delivered flawlessly in terms of HSE and quality. At the initial planning stage, the proposal on this well was to complete two oil producer sands with active sand control methods, the upper zone with Cased Hole Gravel Pack (CHGP) and the lower zone with Open Hole Standalone Screens (OHSAS), this concept changed after the analysis of the logging while drilling (LWD) output, when the subsurface team decided to complete an additional zone (midzone) with a stacked Cased Hole Gravel Pack. The well completion operation effectiveness on this well could have been affected by the following challenges: High deviationMultiple sand control techniques in one wellOperation and logistic challengesAdditional zone expected to be completed with the available inventoryLimited resources and time The team incorporated several techniques into the original completion design to enable the effective execution of these three zones and achieving the overall well objective. After the well was successfully completed, it became the first highly deviated well in the field with an open hole standalone screens in the lower zone and two cased hole gravel pack in the upper zones with a dual upper completion string. This well completion will become the benchmark for planning, designing and deploying future wells with similar characteristics and reservoir conditions.

Based on the production data from first development campaign in 2017, contamination reading of CO2 and H2S from gas production wells were observed increasing from 3% to 10% and from 3ppm to 16ppm respectively within one year production. These findings have triggered the revisit in 2019 development campaign optimization strategy in terms of material selection, number of wells, reservoir targets, and completion design. Thus, tubing material was upgraded to HP1-13CR for the upper part of tubing up to 10,000 ft-MDDF (feet measure depth drilling rig floor) to avoid SSC risk due to the geostatic undisturbed temperature is less than 80 deg C, however the material of deeper tubing remains as 13CR-L80 as per 2017 campaign. Moreover, the mercury content from first campaign was observed to be above threshold limit from intermediate reservoir based on mercury mapping exercise done in August 2018.As the mercury removal system is not incorporated in the surface facilities, the mercury reading from the well in the 2019 campaign need a close monitoring during well testing so that appropriate action can be taken in case the recorded contaminant reading is high. Dedicated zonal sampling plan to be performed if the commingle zone (total) mercury reading was recorded to be above the threshold limit, and that zones will be shut off to preserve the surface facilities. Opportunity was grabbed to optimize number of wells by completing both shallow and intermediate sections in a single selective completion to maximize the project value. However, this combination will lead to major challenges during operation due to the huge difference in reservoir pressure and permeability contrast in each perforated reservoir as the required overbalanced pressure of completion brine for shallow reservoir is much lesser than the requirement for the mildly overpressure intermediate reservoir. Thus, a potential risk of severe losses and well control is present at shallow reservoir. To mitigate this risk, loss circulation material was pre-spotted in the TCP (Tubing conveyed perforation) BHA prior to fire the gun to allow for self-curing process should losses take place. During the first development campaign, the completion tubing was running in hole in two stages. The lower completion was deployed via drill pipe and the perforated zones was secured with fluid loss device located between lower completion tubing and gravel pack packer. The upper completion tubing was then deployed and tied back to the lower completion packer. This approach was applied as mitigation to prevent fluid losses and to ensure the tubing can be safely deployed to the intended final depth. However, based on the actual performance and losses rate data during the first campaign, the completion design in second campaign was optimized and deployed in single stage. Since shallow and intermediate reservoir were combined in multiple production zones where five SSD (Sliding Side Door) were installed, the slickline option to set packer was waived due to the risk of setting tubing plug in deep wells. Pump out plug was considered as an option but then dropped due to high hydrostatic pressure. The packer setting pressure was too close to plug shear pressure. Therefore, a self-disappearing plug was utilized as it did not require any slickline intervention and can be ruptured by pressure cycle. With this option, risk of pre-mature rupture of plug was eliminated. The paper will discuss in detail each challenge mentioned above together with details calculation that was performed throughout evaluation and selection processes prior best solution being selected as these optimizations resulted in nearly three days saving of rig time, contributing to 2.6% of well cost reduction and the required number of wells were optimized to be three instead of four wells. Moreover, a safer production life of wells by selecting a suitable tubing material and eliminating the risk of mercury production above the above threshold limit.