As part of the reservoir monitoring effort in Field X (Offshore East Malaysia), five oil producers were deployed with double-ended fiber optics cable across reservoir sections and permanent downhole gauges (PDG). Each well has between 2 to 4 zones. This has enabled various distributed temperature sensing (DTS) benefits such as gas-lift monitoring, well integrity, zonal-inflow profiling, and stimulation job evaluation, etc. This paper demonstrates and discusses the approach of incorporating both DTS & PDG data in Well B-1 to intrepret temperature signatures andanomalies during recent tubing-integrity tests, matrix acidizing and post-job production performance. Well B-1 is a gas lifted well that consists of three zones, and its production has been declining over years due to potential formation damage during drilling and fines migration issue. Hence, Well B-1 has been selected for matrix acidizing treatment to enhance the productivity. Prior to execution of the acidizing job, several conformance jobs such as tubing-integrity tests, injectivity test, and tubing pickling were performed. A baseline temperature was acquired to assist in the evaluation. Due to operational challenges, the DTS data transmission wasn't acquired in real-time. However, each event's temperature profile has been studied thoroughly against the actual event schedule. Some significant findings are i) completion accessories effect (feedthrough packers) creates temperature anomalies, and ii) several leak points detected mainly between two upper zones where there was significant cooling effect due to injected fluid. The first-stage main treatment was conducted focusing on Zone 3. Due to leak points between the two upper zones, Zone 3 didn't get the designated main treatment volume. Second-stage main treatment, Zone 1 & 2 were treated together due to time constraint unlike Zone 3. Post job production temperature profiles showed significant changes in the flowing temperature slope compared to pre-treament profile where there is an increase in overall wellbore temperature indicating increase in liquid volume and Zone 2 indicating higher Joule-Thompson cooling effect (more gas production).

This study aims to validate and track valve positions for all the zones applying recorded distributed temperature sensing (DTS) data interpretation to propose the best combination of downhole inflow control valve (ICV) openings to optimize Well X-2 multizone commingled production. Fiber DTS is relied on as an innovation against downhole conditions that has compromised the three out of four downhole dual-gauges and valve position sensors. For zonal water control purpose, ICV cycling and positioning have been attempted in 2019. The valve position tracking derived from the compromised downhole dual gauges and valve position sensors does not tally with the surface flow indication overall. Consequently, the original measurement intention of the fiber DTS as back-up zonal-rate calculation profiling and as potential sub-layer flow-contribution indicators is brought in as contingency zonal valve-opening tracking and guide that proved valuable for subsequent production optimization. Downloaded DTS data is depth matched and validated against known operating conditions like time of each cycling stage and surface well test parameters (i.e. Liquid Rate, Watercut, Tubing Head Pressure (THP), Total Gas, Gas-Oil Ratio (GOR)), etc. To establish a baseline, several DTS traces of historical operating condition during a known stable period were selected, i.e. stable flowing condition at only Zone 4stable shut-in condition at surface with only ICV Zone 4 is opened Downhole valve-position tracking can be interpreted alternatively from induced fiber temperature activities across the valve depth with a good temperature baseline benchmarking from DTS temperature profiling. In one of these alternative interpretations based on fiber temperature, it is found and validated that Zone 1 ICV is Closed, Zone 2, 3 and 4 are in opened position and continuously producing at any cycles. This is in conflict of zonal production control understanding initially based on the compromised downhole sensor indicating that all the zonal valves are supposedly in fully closed position. In this case-study, DTS data has been proven useful and as an innovative alternative to determine downhole valve opening with analogue to flow contribution derivation methodology. Therefore, anytime in the future where Well X-2 valves cycling is planned to be carried out, there is a corresponding operating procedure that needs to incorporate onsite real-time DTS data monitoring to validate tracked valves positioning.

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.

This study aims to validate and track valve positions for all the zones applying recorded Distributed temperature sensing (DTS) and Distributed acoustic sensing (DAS) data interpretation in order to propose the best combination of downhole inflow control valve (ICV) openings, This is required to optimize Well X-2 multizone commingled production. Fiber DTS and DAS monitoring were relied on as an innovation against downhole conditions that has compromised the three out of four downhole dual-gauges and valve position sensors. For zonal water control purpose, ICV cycling and positioning have been attempted in 2019. The valve position tracking derived from the compromised downhole dual gauges and valve position sensors does not tally with the surface flow indication overall. Consequently, the original measurement intention of the permanently installed distributed fiber-optic which served as back-up zonal-rate calculation profiling and as potential sub-layer flow-contribution indicators is brought in as contingency zonal valve-opening tracking and guides that proved valuable for subsequent production optimization. First part of study involves interpretation of Distributed Temperature Sensing (DTS) data. Downloaded DTS data is depth matched and validated against known operating conditions like time of each cycling stage and surface well test parameters (i.e. Liquid Rate, Watercut, Tubing Head Pressure (THP), Total Gas, Gas-Oil Ratio (GOR)), etc. To establish a baseline, several DTS traces of historical operating condition during a known stable period were selected, i.e. stable flowing condition at only Zone 4 stable shut-in condition at surface with only ICV Zone 4 is opened Downhole valve-position tracking can be interpreted alternatively from induced fiber temperature activities across the valve depth with a good temperature baseline benchmarking from DTS temperature profiling. Second part of study involves interpretation of Distributed Acoustic Sensing (DAS) data. The data was acquired under single flowing condition one month post-ICV cycling. Without any changes made on the well operating conditions, the well is flowing under same condition post ICV cycling. Inflow point detection using joint interpretation of DAS and DTS, where simultaneously DAS spectral content (depth-frequency) was analysed alongside DTS traces to further discriminate between inflow and other noise sources. Through i) acoustic amplitude analysis, ii) DTS inversion, iii) noise speed and flow speed computation, composite production allocation can be derived for Well X-2. Using the alternative co-interpretations based on fiber temperature and acoustic measurement, it is found and validated that Zone 1 ICV is Closed, Zone 2, 3 and 4 are in opened position and continuously producing at any cycles. This is in conflict of zonal production control understanding initially based on the compromised downhole sensors indicating that all the zonal valves are supposedly in fully closed position. In this case-study, DTS and DAS data has been proven useful and as an innovative, alternative monitoring to determine downhole valve opening with analogue to flow contribution derivation methodology. Therefore, anytime in the future where Well X-2 valves cycling is planned to be carried out, there is now a corresponding operating procedure that is incorporated onsite real-time fiber optic DTS and/or DAS data monitoring to validate tracked valves positioning.

Over the last few years, the oil and gas industry had observed a rapid increase in deployment of fiber optic sensing for downhole monitoring. In Field B, 7 wells have been permanently completed with Distributed Temperature Sensing (DTS) fibers that extend through the reservoirs section 2009 and 2015 respectively. After more than 40 years of production history, this was the first permanent installation of fiber-optic in SX Region. Undeniably the DTS provides a new surveillance experience for Field B; multiple conventional monitoring system can be replaced with permanent fiber monitoring while also effectively minimize production deferments. This paper presents the real-life challenges of fiber optic applications in Field B, offshore Malaysia. DTS wells are located in satellite platforms which are not accessible on daily basis. While the focus is always on downhole monitoring deliverables, a large proportion of upfront deployment is to invest on the surface equipment that can be complex and costly for data acquisition continuity. As such, biggest challenges faced by Field B are essentially surface-related. Challenges encountered post DTS fiber installations in Field B includes digital oil field set-up, surface hardware replacement and maintenance, local electric room (LER) power-supply stability, data transfer protocol, continuous streaming of DTS data from offshore to onshore, reduced data resolutions, software and capability development. Over the life of the well, these challenges possess significant cost impact and most of time are not captured during the project planning and development stages. In Field B, throughout 5 years post fiber-optics installation, multiple challenges have been overcome in order to maximize value of information from the downhole monitoring. Knowing that these challenges might impact the downhole monitoring deliverables, the plan for future permanent fiber optic installation in any asset should incorporate all the possible challenges with its mitigation plans identified and set in-place. The lesson-learnt highlighted are turned into future project best practices.