Fines migration is the common formation damage mechanism in the sandstone reservoir of field B which has less established information on mineralogy distribution. There were many attempts to remediate the formation damage using conventional mud acid fluid system but resulted in mixed success rates. This situation warrant for the need for a modified acid recipe to avoid aggravation of fines migration problems in this field post acid treatment. This paper presents the pilot application of a modified HF acid recipe incorporating chelate. The paper also depict the evaluation process that includes candidate selection, laboratory workflow and results, treatment design, execution strategy and the post job analysis on well B-1S. In order to increase the acid stimulation success rate, the team analyzed numerous post job reports of the nearby wells that were previously treated with conventional mud acid system. The root causes of the previous job failures were identified, such as prolonged soaking of acid in the formation due to unplanned platform shutdown and limited platform deck space. Taking these factors into account, the modified HF acid system (with 1.0% HF) was selected for execution in B Field. The pilot execution resulted in double the production compared to the pre-treatment rate. The modified HF acid system has also improved the economics of the project due to its lower cost since it is a one-step system and has lower additives requirement.

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.

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.

In this paper, we evaluate the effectiveness of production enhancement activities for well B Long-string (i.e. well BL) using distributed temperature sensing (DTS) technology. Installation of permanent fiber-optic cable across the reservoir sections has enabled gas lift monitoring, identification of well integrity issues and zonal inflow profiling from perforation contribution. Recent DTS interpretation indicated leak point at 4,025ft with sub-optimal gas lifting which has resulted in loss of 300 BOPD. Hence, well intervention such as tubing patch and gas lift valve change-out (GLVC) were conducted consecutively to restore its initial production. The effectiveness of executed remedial jobs will be discussed along the findings and interpretations of the temperature survey result from DTS. Well BL is a long-string gas lifted producer that flows from two zones. Prior to the tubing patch, the multi-finger caliper tool was logged in well BL to further validate the leak point indicated by DTS. The caliper logging survey identified that maximum penetration (100%) occurs at 4,025 ft, which classified it as a leak hole. Time-lapsed DTS measurement, specifically; pre-, during-, and post-tubing patch and GLVC were acquired. It is analyzed along with Permanent Downhole Gauge (PDG) data and surface parameters [e.g., tubing head pressure (THP), casing head pressure (CHP), Gas lift injection rate, etc]. The multi-measurement interpretation is further complemented by nodal analysis for a more conclusive finding. A baseline temperature was acquired during the shut-in period as a geothermal gradient reference to determine any anomalies against the temperature acquired during each event. Operation quick-look indicated both GLVC and tubing patch are deemed to be successfully carried out as per the program with minimal workover challenges. However, the executed remedial jobs that are expected to resume the production from Well BL to its initial production shows it is still underperforming. Production rate keeps declining during the post-job execution. Qualitative interpretation from DTS temperature profiles, reveals another significant tubing leak detected at 4,007ft after the tubing patch. By accidental find, the DTS data also showed that the production from top zone (short string) was produced through the leak hole at the long string to surface. Further investigation applying nodal analysis and PDG data indicated that crossflow was observed from the top zone production through and into bottom leak hole at the long string. This has led to serious production loss in well BL. Furthermore, temperature profile that's demonstrated the injected gas was unable to reach the orifice (operating node) due to multi-pointing, thus resulted in the well's underperforming production post-remedial job execution. In this root-cause finding showcase, DTS data have been providing valuable findings on the effectiveness of executed remedial jobs in well BL. DTS measurement and monitoring is proven useful and as an innovative alternative for deciding the definite success of any remedial job to improve oil, against the recorded "flawless execution" on paper.