Field BY Coiled Tubing (CTU) Operation comprised of 2 wells to be cleaned out and perforated that are A1 and A4. These two wells target reservoir was untapped and has good potential of increasing gas production rate from BY Field. Well A1 is an infill well while A4 is a workover well, which both operations were commenced in October 2009 using a jack up drilling rig. Problem started when these wells experienced held up as there was solid restriction inside the liner, which prevented further movement of the wireline tool and as such, perforation can't take place. After considering the escalating daily spread cost, in February 2010, decision was made to release the rig and temporarily suspend the wells for future well intervention. Few options were available for the intervention job. After assessing all risks, the drilling team has decided to deploy CTU operation with Catenary system. This operation was considered unique and the first for Drilling Departrment. The challenge was high for the inexperienced team in handling the CTU Catenary operation. With shear determination and commitment, the drilling team managed to deliver the operation, where both wells were successfully cleaned out, perforated and flowed exceeding the minimum target. This paper discusses the challenges faced by the drilling team in carrying out the CTU operation and lessons learnt throughout the operation. Introduction Upon suspension of well A1 and A4, the drilling team has started to look for solution to carry out the intervention job. Factors like cost, rig availability, effectiveness and offshore/weather condition played important roles in making the decision. Based on detail technical discussion, the team had decided to use Rig-less CTU Catenary system. Instead of rig, a workboat was required to support the operation. It allowed Catenary system equipments (Coiled tubing Reel, Catenary System Power Pack, and Coil Feeder) to be positioned on a workboat and at the same time provided space for temporary storage of other major equipment such as tank and silos for clean-up fluids storage. Other major equipment were CTU Power Pack, Control Cabin, Injector Head stack up and flying Gooseneck were positioned on platform deck. Besides that, the platform was loaded with Well Testing equipment to control the flow by choke manifold and disposal of return from the wells by flaring through Burner Boom. On the other hand, a Slick line and Wire line equipments were placed on the platform deck for the purpose of tubing clearance check and perforation operation respectively. Using a workboat essentially saved the overall project cost because the daily charter rate for a workboat package including one support vessel is a quarter of a standard jack up rig daily cost.
The ‘B’ Field is located about 40 KM, offshore Sarawak and was discovered in 1967 with 70-80 m water depth. Structurally, ‘B’ field is charaterised by a simple relatively flat, low-relief domal anticline which is bounded to the north and south by the north-hading growth faults. The major faults are acted as effective lateral seal, which is indicated by the difference in the fluid type and fluid contacts across those faults. ‘B’ field consist of multiple hetereogenous sandstone reservoirs with permeability and porosity ranging from 25 −1700 mD and 16 −29% respectively. ‘B’ Field injectivity conformance for reservoir pressure support is very crucial as the field is undergoing severe depletions over years and unable to meet the production target. The Operator realized the importance in order to further increase the recovery factor, hence has included ‘B’ field in the Improved Oil Recovery (IOR) project to boost the production and prolong ‘B'field's life. Based on comprehensive IOR/EOR screening study, water injection process has been identified as the most amenable IOR process in ‘B'field. Hence, in Phase 1 drilling campaign, two (2) water injectors were drilled in 2016 in order to achieve the target oil recovery. Both well BWI-01 and BWI-02 were completed with Intelligent completions (IC) and expected to come online in Q4 2018. This paper further discusses the injection strategy in ‘B’ field multi-zones to meet the zonal injectivity and reservoir zonal voidage replacement requirement for pressure maintenance over field production life. The discussion covers the reservoir characteristics and zonal injectivity challenges with surface constraints that require intelligent completions solution for IOR phase. Completions architecture and customized metallurgy needs is crucial to meet operational challenges. Fit-for-purpose and maintaning development cost is pre-requisite to achieve well injection performance for optimal production
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.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
This site is protected by reCAPTCHA and the Google Privacy Policy and Terms of Service apply.
Copyright © 2025 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.