This paper focuses on tubing material selection study conducted for a high CO2 oil field located offshore of Peninsular Malaysia. The field's CO2 concentration varied laterally and with depth. The highest CO2 concentration of 66 mol% in gas had been recorded from well test and fluid data. This resulted in severe corrosive environment in the wells. Based on the well surveys, many existing wells which were completed with API-5CT L80-13Cr had suffered from localised corrosion within a span of two (2) years of production. Existing material selection was revisited in order to prevent corrosion in future development wells. An important change made was to conduct material qualification test specific for the field conditions on several corrosion resistant alloy (CRA) materials. The details of the test and findings are presented. To better understand the corrosion severity in existing well completion, well survey results are also discussed.
Challenges associated with horizontal wells production in a barefoot or only standalone screen are well documented in the industry. Inflow control devices have been around for years and have been the answer to mitigate the challenges typically associated with heterogeneity in horizontal wells, as was applied in an offshore brown field in East Malaysia, Field S. However, as the field gets more mature, increasing production challenges posed by the reservoir leads to conventional passive inflow control device solution becoming less effective. Over time, as water production from the reservoir increases due to the rise of aquifer column, new infill wells have to be completed shallower and closer to gas oil contact to maximise recovery leading to risk of high gas production. The risk is further compounded by uncertainty in the fluid contacts in a complex dipping reservoir. In order to mitigate these challenges, Autonomous Inflow Control Device (AICD) was selected for Field S infill wells to control excessive gas production anticipated due to the wells placement. AICD's ability to choke production based on the fluid properties allows for improved flow control together with influx balancing from segmentation into compartments by swellable packers. In total, seven (7) horizontal wells were completed in an infill drilling campaign in Field S, with the wells placed at around 5 m from prognosed gas oil contact. AICD was installed with premium sand screen and swellable packers in the wells’ lower completion and has managed to control excessive gas production while enabling production at the targeted oil rate. This paper describes the implementation of AICD in Field S infill drilling campaign with challenges of complex dipping reservoir and fluid contact uncertainty. The workflow to investigate the feasibility of the candidate and the completion design process will be discussed. Well modelling (nodal analysis) using production data was performed to characterise the well performance and to understand the impact of AICD in controlling gas and inflow of producing fluid into the producing horizontal section.
Wells that are producing with high gas oil ratio (GOR) or gas wells with sand production exhibit highly erosive environment due to their high fluid velocity. Well A, oil producer and Well B, gas producer in Peninsular Malaysia had experienced sand production issues since 2017 which caused the wells to be beaned down and subsequently shut in. The conventional metallic screen is not suitable for these wells as the screen will be impaired rapidly due to erosion. In 2021, erosion resistant ceramic coated Through Tubing Sand Screen (TTSS) have been successfully piloted in these two wells to produce with manageable sand production. In order to select the right technology, Gas Screen Erosion Test (GSET) and Mechanical Strength Test were conducted as qualification requirement to ensure the screen operating envelope can accommodate the wells’ erosive environment. Once the technology is qualified, detailed design of the screen was established to specify the screen opening size, screen length, location and conveyance method. Post-installation, the opening up of the well is in accordance with the bean up procedure to avoid sudden surge or high velocity flow that can damage the screen. In addition, acoustic sand monitoring and sand sampling were also performed to monitor any solid production. The wells’ performances were then monitored for 3 months flowing period prior to the screen retrieval for visual inspection and pilot result evaluation. The ceramic coated Through Tubing Sand Screen (TTSS) was successfully installed in both wells despite multiple operational challenges encountered during installation process. Both wells showed satisfactory production performance with minimal sand production observed. Based on these promising results, the technology is planned to be replicated in wells with similar erosive environment. This paper will cover the end-to-end process of ceramic coated Through Tubing Sand Screen (TTSS) pilot installation including technology selection, screen design, execution, operational challenges and well performance.
This paper serves to share the findings and best practices of sustaining production for a mature field with high sand production with analysis from Acoustic Sand Monitoring (ASM) paired with Online Sand Sampling (OSS). Field B, located in the East Malaysia Region, is a high oil producer for over 40 years under a strong water drive mechanism. Water production has significantly increased over the past 5 years, which has led to significant sand production impacting surface facilities and well integrity. Hence, the need for a reliable and efficient sand management surveillance in field B. As the first application for oil fields in the region, ASM and OSS was conducted with the objective to determine the maximum sand free production rate from over 80 active strings in Field B over the span of 4 months to safeguard production rates of 10 kbopd. With ASM and OSS, a reduced data surveillance duration can be achieved within 2 hours compared to conventional well sand sampling per well which requires a minimum of 24 hours before sand production rate is determined. ASM sensors are clamped on the well flowline to detect and record the noise vibrations produced by the sand while OSS is conducted concurrently by diverting parts of the same flow from the flowline through a sand filter to have a quantitative representation of sand produced for a predetermined duration. During the campaign, choke sizing was manipulated to control reservoir drawdown. For most wells, a lower drawdown resulted in lower amplitude readings from ASM and less sand observed from OSS. However, there are several wells that had higher sand production at a smaller drawdown due to a change in flow regime (steady flow to intermittent flow) resulted from inefficient gas lift production (multi-pointing). As ASM provided the raw velocity signal which is heavily influenced by the liquid flow regime, gas oil ratio and sand production, OSS results (from physical sand produced and weight of sand particles) established a baseline for ASM signals which indicate a sand free production. Overall, ASM and OSS analysis provided a baseline for determining the optimum rate of production with minimum sand to avoid well integrity issues and protecting the surface facilities, thus allowing continuous field production of 10 kbopd. A presentation and discussion of the successful results, limitations, best practices, and lessons learnt of the ASM and OSS campaign aspires to be additive to the production surveillance sand management in the oil and gas industry by providing a fast and reliable means of identifying optimum sand free production rates for a high number of wells in a mature field.
Managing sand production has been a common problem and one of the most difficult challenges within the oil and gas industry. Various techniques are available to control sand production such as downhole sand screens. More than half of the wells in Malaysian fields are completed with downhole primary sand control or require sand management throughout their lifetime. To further aggravate the issue, most primary sand controls installed have suffered from failure after an extended period of production due to unacceptable high pressure drop in the near wellbore area which causes the screen to lose the ability to retain the formation sand particles. There are four (4) common mechanisms that can lead to the screen failure which include plugging, corrosion, erosion, and mechanical deformation. Erosion occurs when the formation particles hit the screen surface with high velocity or by continuous production through the screen openings. Operators are often compelled to rely on thru-tubing metallic sand screen to reactivate the idle wells back into production. However, most metallic sand screens suffer from sustainability issue due to excessive erosion especially for gas wells. Most operators have shifted their focus to maximize the screen lifetime against erosion, which consequently leads to the development of a novel sand screen design where an inventive coating consists of ceramic or hard metal amalgamation was applied by plasma spraying technique on the screen (i.e., outside surfaces facing the formation) to reinforce its resistance against severe erosive environment. An extensive development and verification program was conducted to select over 50 possible coating combinations, guarantee predefined slot size, assess corrosion resistance, and ascertain mechanical integrity of both the coating and screen. The technology has been considered and applied in Field A, offshore Borneo Island as remedial sand control due to its superior durability and resistance compared to metallic sand screen. Extensive technology hunting had been conducted by the operator to identify new erosion resistant thru-tubing sand screen for gas well application. As part of the overall project requirement, test facility was built by the Service Partners that consists of a flow loop testing designed to simulate accelerated erosive downhole condition with the combination of high flowrate and volume-controlled particle coalesced into an acceleration tube. The screens were tested for 60 hours at maximum velocity of 18 m/s during liquid erosion test and for 48 hours at maximum velocity of 80 m/s during gas erosion test. Rigorous analysis was conducted focusing on among others optical criteria, mass loss and sand retention tests (SRT) before and after the erosion test to verify the functionality and validate its performance prediction prior to the actual field application. Velocity calculation was also conducted using in-house and commercial software to adjudicate the design limit, to set the target gas rate for the pilot wells and establish the well unloading procedure as guidance for offshore personnel. Pilot field trials have been designed to demonstrate screen installation, risk mitigation and sustained production. Dual-pot sand filter (DPSF) and online sand sampler (OSS) was deployed as additional assurances to safeguard topside integrity, to closely monitor the sand production at surface and collect any sand grains larger than the screen slot sizing throughout the well unloading sequence. Close inspection on both erosion tests indicated no significant wear or slot size widening of the coated screen samples as compared to the uncoated screen samples that show severe erosion with slot size increases more than doubled in some places. The coated screen samples show the equivalent sand retention capabilities before and after the erosion tests, while the uncoated screen sample subjected under the same conditions lost its ability to retain sand. During field trial, the screen was successfully installed using nipples plug via slickline to revive the idle wells back to production at a lower total cost without HSE related issue and production gain beyond the initial target. Actual field results supported by the extensive laboratory testing presented herein, demonstrate the inherent benefit of plasma spray coatings ensuring mechanical integrity and durability of sand screen in highly erosive environment. Teardown analysis will be conducted to investigate the performance prediction, authenticate erosion resistance of the sand screen bottomhole assemblies (BHA) and document the findings for future improvement.
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