AB field has undergone secondary recovery of water injection for pressure support and sweep efficiency improvement. From proactive surveillance program, it was further discovered that AB field performance is improving without water injection. Pilot shut-in water injection study initially commenced post 5 years of production. From the pilot water injection shut-in, surveillance data was used for thorough analysis to conclude that secondary recovery through water injection will reduce field recovery due to early water out coupled with moderate to strong aquifer strength. Close pressure monitoring, surveillance database, and other diagnostic plots used to gauge the water injection healthiness in AB field. Reservoir modelling was built to validate the implication of water injection secondary recovery to the field. Complete surveillance data and gathering method will be presented in this paper to permit readers to replicate the analysis prior to conclude secondary recovery type of mechanism, typically water injection, is beneficial to the field or proven otherwise. Pilot shut-in water injection has proven the following: (1) It was observed that AB field pressure still maintains above the pressure target of initial Field Development Study, (2) Watercut performance has significantly increased post pilot water injection shut-in, (3) no substantial impact on the reserves loss, while in contrast, water injection stoping will improve recovery due to delaying the wells watered out time. For this marginal field of AB, an incremental of 0.8-1.7 MMstb reserves recovery will contribute to higher recovery factor. This is also due to the moderate to strong aquifer strength against weak to moderate aquifer strength anticipated earlier in FDP. Casehole contact logging was conducted at two wells in the field to monitor the contact movement. From all the observation and analysis conducted, AB field was further optimize by the Reservoir Management Plan (RMP) revision. Lesson learned from the case study will enhance others' understanding and view prior to deciding on secondary recovery method to any field. RMP study should be updated as the production continues and once more data is acquired from the right surveillance program.

SS Field with its longer production data now available has enabled further validation of the previous assessment (i.e. SPE-17005 by N. Noridah et all, 2013) of the reservoir needs and technology respond in this field to-date. This paper also highlights the effectiveness of the field-wide downhole flow control solution in terms of more oil and managing undesired field water-cut. It is scrutinized based on the actual field Ultimate Recovery (UR) versus the predicted recovery to further optimise recovery in infills plan. Extensive evaluation on production performance was conducted well-by-well to engage the overall field performance. The actual production performances are clustered in the categories from the ‘underperformers’ to the excellent producers, considering the reservoir attributes such as reservoir characterization, geological understanding and contacts movement. Meanwhile, technology responds in terms of zonal control efficiency across the sandface is analyzed for improved comingled oil production multi-zones. The assessment is further applied in the infill well-creaming for the extended development plan in SS field. The study correlates the best reservoir attributes to the technology respond in order to maximize future infill recovery in ensuring fit-for-purpose implementation. Years of production experience have demonstrated a consistently better recovery of SS field against the expected FDP. 75% of the producer meet the FDP production target which contributes towards overall field > 25% EUR despite only near the half of the production life (~20 years). SS Field is the first pilot PETRONAS field applying field-wide downhole flow control (12 wells) and intelligent Completions (2 wells). An integrated evaluation of the production performance in this field with subsurface understanding is paramount for technology replication. It is a case study that serves as a benchmark for development decision in other fields with similar reservoir characteristics. It also serves as best-practices and lesson-learnt to provide a better insight of a downhole flow control solution efficiency in the late-production strategy of suppressing water for further production enhancement via EOR / infills.

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.

More than 50% of Malaysia fields are matured or at its late life stage. These fields are mostly highly dependent on gas lift as the artificial lift method to maximize well potential and reserves recovery. Many of these fields are presently facing matured field operational challenges such as high water cut, shortage of gas lift supply, reservoir pressure depletion and aging facilities. As host authority for all hydrocarbon resources in Malaysia, PETRONAS Malaysia Petroleum Management (MPM) has initiated a Malaysia- wide effort to improve the production rate and recovery of hydrocarbon by expanding the usage of Electric Submersible Pump (ESP) as an alternative artificial lift method. ESP is an alternative artificial lift method that has been successfully pilot deployment. This paper focuses on the strategy of ESP replications at Malaysia to address production decline and extending well life through various enabler to support the target. PETRONAS has identified 10% of producing wells in Malaysia that will benefit from ESP technology, resulting in 6% incremental production. Subsequently, PETRONAS embarking ESP Feasibility Study with Solution Partner to mature ESP opportunities basket in integrated approach surface and subsurface and acts as an enabler for PAC to evaluate future fields for ESP replications. There are four main scopes in Feasibility Study which are, (i) Data Gathering and Well Screening, (ii) Potential Candidate Identification, (iii) Maturation of Opportunities Proposal and (iv) cost effective solution for ESP implementation. At the same time, ESP Integrated Contract which will serve as end-to-end solution for all PACs, is being developed by MPM as a key enabler to enhance ESP replications via more volume of work, lower cost, and improved lifecycle efficiency. There were five fields were under the ESP Feasibility Studies where comprehensive of subsurface and surface study were conducted. More than 500 strings were evaluated. A 50 well proposals were completed and the ESP opportunities to be implemented by phases to address production decline and to increase well life, leveraging on ESP Integrated Contract to create more value to PETRONAS and PAC. The feasibility study has also guided PETRONAS in candidate prioritization. Long term roadmap on ESP replications was developed to fully capitalize on ESP Technology to enhance Malaysia production and reserves monetization by creating the right ESP eco-system for the Oil & Gas Industry. The feasibility Studies approach enable future ESP studies in Malaysia fields.

Well X, a gas producer located in offshore Malaysia had to be beaned down and subsequently shut in due to sand issues after 7 years of production through pressure depletion. It was completed in cased and perforated completion without any sand exclusion and has been producing since 2014. The evaluation on the sand control solution for Well X prioritizes remedial downhole sand control that is able to withstand highly erosive environment due to its high fluid velocity. As such, a ceramic coated Through Tubing Sand Screen (TTSS) was installed in 2021 and successfully reactivated the well to produce with minimal sand. A series of qualification testing was conducted during the technology evaluation to demonstrate the ceramic coated TTSS resistance towards erosion and corrosion i.e. Gas Screen Erosion Test (GSET), Corrosion Test and Mechanical Strength Test. Studies on erosional velocity, Particle Size Distribution (PSD) and production analysis were conducted to determine the wire wrapped screen slot size and ensuring the mixture velocity is within the screen operating envelope. Upon installation, the well performance was monitored using Acoustic Sand Monitoring (ASM) sensor and Online Sand Sampler (OSS) during the initial flowback and continued using manual spot sampling at the multiphase flowmeter. The screen retrieval was planned after 4 months flowing period for evaluation and the same screen was reinstalled as it was in good condition and met the inspection criteria. The installation of the ceramic coated Through Tubing Sand Screen (TTSS) at Well X has successfully demonstrated its resistance against erosion with good production and sand control performance. This paper will share on the overview of the ceramic coated TTSS including the analysis on screen design selection, screen retrieval findings and well performance post TTSS installation.