Low oil prices, coupled with operational challenges in offshore environment due to COVID-19 restrictions, have driven oil and gas operators to implement low-cost technological solutions to optimize fields’ production. For mature oil fields in offshore East Malaysia, sand production has become one of the onerous challenges that requires this approach. Sand production is known to adversely affect the well deliverability and it also contributes to safety concerns due to surface flowline leak and equipment failure. Hence, it is of upmost importance for operators to address the sand production downhole. To achieve this, through-tubing sand screens (TTSS) installation is opted due to its ease of installation and low-cost slickline operation. Although there have been many TTSS installations to date, there is still limited understanding of the factors that affect TTSS lifespan, and this has led to frequent TTSS changeout. Based on the operator's experience, TTSS lifespan can vary significantly across different wells ranging from just a few days to years of production. To improve the understanding of TTSS performance with the aim to increase TTSS longevity, a comprehensive study on potential contributing factors has been conducted by analyzing the past TTSS installations. Over the years, there were more than 75 TTSS installations performed in oil fields offshore East Malaysia. Lookback analysis was conducted to evaluate the effectiveness of TTSS as remedial downhole sand control and investigate the factors affecting TTSS performance such as TTSS type, well production rates, TTSS deployment method, installation depth relative to perforation interval and well interruption frequency. Several criteria identified as the key performance indicators have been investigated to evaluate the performance of each TTSS installation, including the well flowing parameters, production uptime and sand production trend. Thorough study across different TTSS installations has concluded that TTSS lifespan varies according to well properties and well operating parameters. This paper presents best practices and lessons learnt from past installations to predict and improve the mean time between failures (MTBF) for TTSS. Case studies for several wells have been scrutinized to highlight the learnings for further enhancement of TTSS lifespan. Additionally, recommendations for further research and development of erosion resistant TTSS technology are also discussed.

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.

Well B-2 is a dual-string producers with Distributed Temperature Sensing (DTS) fiber installed along the long string (i.e. Well B-2L) across the reservoir sections. Each zone comprises of sub-layers. This system enabled the operator to continuously monitor the wellbore temperature across all the producing intervals including gas-lift monitoring, well integrity identification, zonal inflow profiling and stimulation job evaluation. This paper mainly discusses the post matrix acid stimulation job with interpreted DTS and zonal Permanent Downhole Gauge (PDG) data. Well B-2L has been selected for matrix acidizing treatment to improve the productivity due to potential formation damage, proven by the declining production over the years. Prior to the execution of the acidizing job, several conformance jobs such as injectivity test, tubing pickling were performed. This is followed by the main acid treatment and flow back. DTS & zonal PDG data were acquired throughout the operation. A transient simulator model was built incorporating all the reservoir properties including well trajectory and completion schematic to analyze the DTS profile and understand the zonal inflow profiling for each zone post treatment. A baseline temperature was acquired for the geothermal evaluation. The DTS data has been studied according to actual event schedules. Some significant findings are; i) completion accessories effect (feedthru packers) creates temperature anomalies, ii) leak points detected at top producing zone signifies cooling effect due to injected fluid. The main treatment was intended at zone 2 and 3 using nitrified acid. However, leak points at top zone caused bypassed injection into Zone 1 and 2 instead. Fiber optic DTS warmback profiles post main-treatment was analyzed to quantify the fluid intake from sub-layer in each zone. Qualitatively from the DTS-interpreted zonal profiling, the data clearly shows most of treatment fluid is being injected into Zone 1 and 2 with no intakes at Zone 3. Furthermore, warmback analysis confirmed the high intake zones from sub-layers within the main zone based on the permeability contrast. This paper will further discuss the zonal injectivity understanding for improvement from the zonal-inflow profiling evaluation by incorporating DTS, PDG and surface production data.

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Formation damage caused by organic and inorganic deposition particularly near and around wellbore, can substantially reduce the hydrocarbon production. In depleted oil reservoirs, when reservoir-driving forces are low and in declining stage, even small resistance can restrict the fluid flow resulting in loss of well productivity. Single stage chemical system was designed to restore the oil production of Malaysian oil producers that suffers with complex deposition problems. Extensive well selection activities and laboratory analysis were conducted prior to the well treatment. This paper presents five case studies of treated wells that have been revived or boosted using the single stage chemical system. The well treatment consist of bull-heading a pill of pre-flush to facilitate the action of the main chemical system, followed by the main chemical, soaking for 24 hours and flow back the well. The well treatment job was completed successfully and safely with chemical cost saving of 40%. Post well treatment showed mixed results by instantaneous average production improvement of more than 400% for Well BK1, BK2 and BK3 and 26% production gain for Well BT2. The improved production sustained up to five months before a drop in production back to the old trend. Well BT3 wellbore damage was partially removed with less incremental in terms of gross production post treatment. Primary hypothesis of short sustainability of the post well treatment is likely due to re-deposition of wax within the subsurface environment. Confirmation on this hypothesis is planned through slick line intervention. The instantaneous production gain highlighted the opportunity to replicate the technology with improved method by incorporating the inhibition chemical component to other potential wells that face similar deposition problem through proactive and preventive approach to ensure production sustainability and minimize the number of idle wells.