This paper serves to share the success story of utilizing Carbon Dioxide (CO2) well tracer surveys to conduct gaslift optimization, resulting in identifying additional oil production of 650 bopd and gaslift savings of 8 MMscf/d. In field B, located in the East Malaysia Region, wells in production are mainly operated with the assistance of gaslift. With over 70 active strings requiring gaslift, this creates a predicament in data acquisition of each string through the conventional Flowing Gradient Survey (FGS) method for gaslift optimization. The main setback of performing FGS in each string includes prioritization of slickline intervention for data acquisition against production enhancement activity, operation windows availability and production deferment. From the CO2 tracer survey, the root causes of well lifting issues such as multi-pointing, Gaslift valves malfunctioning, and tubing leaks can be identified. The accuracy of gaslift injection rate transmitters and total gas output from well test separators are also established together with the gaslift split factor for dual string wells. In the CO2 well tracer campaign in field B, 55 surveys were conducted of which 21 were on single string and 17 performed on dual strings. Around 20-30 pounds of CO2 was injected into the gaslift injection line and its concentration recorded at the well head. Injected CO2 travels through the tubing-casing annulus into the tubing through injection point/s. The travel velocities inside the tubing and casing were used to back calculate the operating lift depths. By importing the results of the CO2 well tracer survey into a software, the exact depth of injection can be measured, and any indication of multi-pointing can be seen. Accurate gaslift modelling can be conducted by incorporating actual measured injected gas rate, well test rate at time of survey and single/multi-point depth obtained from the survey. The CO2 well tracer campaign has proven to provide effective and reliable data on the lift gas entry points in the well, especially for fields with large number of gaslift strings. A total of around 650 bopd oil gain with gaslift savings of 8 MMscf/d was identified and will be realized by conducting Gaslift Valve Change (GLVC). CO2 well tracer campaign should be considered for fields with high quantity of gaslift wells as an alternative to FGS as it requires minimum equipment hook-up, has minimal production deferment, and does not require invasive well intervention. A presentation and discussion of the successful results, limitations, best practices, and lessons learnt from the CO2 tracer campaign aspires to be additive to the production surveillance tools in the oil and gas industry by providing alternatives in data acquisition from the conventional FGS.

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.

Field A begun water injection in 2016 via four water injector smart wells, which were equipped with Permanent Downhole Gauges and Inflow Control Valves. The water injection module was housed on a rented MOPU due to space limitation. Amidst the study to revamp the reservoir management plan, the team found multiple discrepancies in the reservoir zonal allocation dating back to start of injection. Inherently, this affects the Voidage Replacement Ratio tracking. Hence, the question remains: How efficient is the water injection in Field A? As Field A injects from a rented facility, the long term RMP strongly influences annual OPEX. This paper explains the journey of reallocating Field A water injection volumes from 2016 until today, and how it affects the outcome of the RMP study. PETRONAS has an offshore monitoring system which visualizes historical pressure and temperature trends at any tagged equipment. Field A water injectors consists of multi-zones completed with ICVs and PDGs. ICVs allow choking and zone changes to happen without intervention, and PDGs show downhole pressure and temperature changes over time. Coupled with the manual database which tracks ICV changes and water injection rates, the team re-modelled the injected volume allocation changes to each zone by anchoring the model on PDG trends, ICV size and choke coefficient, and water injection rates via an advance nodal analysis software. For reservoir characteristics calibration, properties from past FBUS interpreted results were used as a basis. From the modelling journey, at the same injection scheme, results showed that zonal allocation with small PDG pressure changes of less than 5% during stable injection conditions does not significantly affect allocation ratio in the well. Overall, the allocation would change between 0 - 3% in total. As one of the objectives of the exercise was also to gauge expected injected volume allocation to a specific zone when there were obvious pressure changes but no records of changing ICV sizes, this could be achieved via a calibrated model. Once a good anchor was made on reservoir pressure, formation gas-oil ratio, permeability and skin, devoid periods in the past could be modelled for expected ICV sizes by varying the choke size openings till the pressure differential between tubing and annulus pressure was achieved. Hence, modelling the expected zonal allocation during that period. This improved VRR tracking for the injection reservoirs and aided to in the efforts to revamp the reservoir management plan. This paper will explain the lessons learnt of having proper surveillance data as the impact on long term reservoir management plan is significant. In future, fields with smart wells but disorganized data can utilize this alternate method to reallocate production/injection volumes without the need for intervention.

Early monetization of resources has become the key to have a competitive edge in our oil business today. In brownfields, this requires critical analysis of the existing performance, the sweep pattern, well drainage, and faster generation of robust cost effective redevelopment plan followed by rapid execution to get those early barrels. In Peninsular Malaysia BX is an oil rim reservoir with a large gas cap and moderate water drive. Oil production has declined rapidly in last few years with increasing GOR and water-cut. Existing models could not explain the current production behaviour. Apprehending building new models would take significant time, thus to arrest the unexpected decline in oil production, a classical reservoir engineering approach was adopted to identify bypassed oil and propose infill wells for additional production. With integration of production data, seismic, well logs and sand geometry, an innovative approach was used to find the less depleted areas. Well decline analysis, complemented by polygon balancing and normalised EUR bubbles at wells helped to identify locations where infill wells were proposed.The team deliberated the subsurface and operation risks and assessed them as internal or external risks, prioritised them and built a mitigation plan. These fast track infill wells without dynamic model were very successful in increasing production and reserves, and provided high economic returns due to reduced costs and early oil. The field oil production increased by more than 80%. This paper covers how the analytical approach with polygon balancing and normalised EUR bubbles was carried out to find the undrained areas. It also highlights challenges encountered during the planning and execution phases and the steps taken by the integrated team to overcome them. Encouraged by this success a number of this early monetisation projects were initiated which gave positive results thus proving the success of the technique.

Multiphase flow meters (MPFM) have been known save costs for new installations, are compact and as effective as a test separator. Field "F" is a green field with 2 wells and has been producing since 2018 from the same reservoir. The test facilities consist of an MPFM, and F flows to a hub called Field "G". Towards Q2 of 2019, there was a significant increase in production rates from both wells without any changes to surface choke size and without enhancement jobs performed. Added to that, reservoir pressure showed steady depletion. Daily production allocation for F showed lower than usual reconciliation factor when combined with G hub production. This suboptimal allocation raised doubts about the MPFM well test readings which launched a full investigation into the accuracy of the meter. From the offshore remote monitoring system, the first suspect was the increased inlet pressure causing parameters to be out of the MPFM operating envelope range. However, after further checking, there were other pressing issues such as faulty transmitter, and low range sensors. As these issues were being dealt with amidst the COVID-19 pandemic, the process to fix the meter was longer than usual. Rectification involved troubleshooting the MPFM post performing Multi Rate Tests, back allocation check to hub production and PROSPER/GAP model matching to check on the credibility of the well tests. These efforts were made due to budget cuts, as there was no advantage to bring onboard an entire well test package (separator) to test the F wells. Post several rectifications, the liquid, gas and oil rates were within 10% difference from allocation meter back allocation and PROSPER model calculation. Reconciliation factor for field G has also increased to normal range of 0.92 to 0.95. However, the rectification also showed a significant drop in metered rates, proving that the MPFM was indeed generating incorrect well tests since Q2 2019. The drop was higher than 30% in gross production rates which lead to a better understanding of the reservoir, and corrections to be made to dynamic models for any future development projects. This hence proves that even with the similar reservoir properties in both wells, the MPFM well tests still require vigorous checking and should not be treated in the same way as a test separator. This paper will describe the efforts by surface and subsurface faculties to ensure the quality of well tests from the MPFM. For future projects considering the MPFM installation, best to frequently quality check the MPFM well test figures with a test separator. However, if that option is not feasible, the efforts in this paper can act as a guide for the field.