Over the years, Multiple Array Production Suite (MAPS) has been run several times in Offshore Peninsular Malaysia but never in Offshore East of Malaysia. Field A is located 260km North-North West of Bintulu, Offshore Sarawak and was discovered in 1992 with first gas produced in 2004. One of the many challenges currently faced in managing the field is the prediction and handling of water breakthrough at the existing producers. Based on historical data, water breakthrough from carbonate Zone T begin around 2010 which then followed by series of Water Shut-Off (WSO) campaign. To strengthen the understanding, evaluate the remaining potential and to optimize near term well and reservoir management of the field, an integrated remedial approach is essential. Well-AA was identified for mechanical WSO in an effort to remediate high water production and improve well productivity. The target well was chosen as the well unable to sustain production after a rapid tubing pressure drop due to the highest water production in the field. Moreover, its production had to be capped due to the water production constraints at the receiving hub. Production Logging (PL) was planned across the carbonate sections to accurately identify the appropriate zones for WSO operations. The long horizontal section and high water production typically create a stratified flow regime that forces a smaller volume of hydrocarbon to flow on the high side of the well, hence the conventional PL technology would have been unable to deliver accurate and insightful results. As such, the MAPS technology was run for an initial assessment to identify the water producing zones. MAPS was deployed using wireline tractor and was combined with the Noise Tool (NTO) to provide a comprehensive 3D image of the multi-phase flow profile across the entire wellbore and to investigate the integrity of annular swell packers located in between the carbonate sections. This paper illustrates the best practices involved in the successful downhole Production Logging with a Multiple Array Production Suite and Digital Noise Tool (PL-MAPS-NTO) toolstring, which served as the key input in determining the WSO treatment depth and strategy in Well-AA, that may lead to a potential gain of 10.8MMscf/d.

Many oil and gas fields have long been suffering from sand production due to either the absence or failure of primary well sand control. To avoid mobilizing costly work-over rig to pull out the tubing, operators have tried various thru-tubing remedial sand control. The well's condition such as sands accumulation and space constraints due to small inner diameter of tubing always make this remedial job challenging. It is not surprising that the results are not all satisfactory. Among the industry-recognized remedial sand control, Stand Alone Screen (SAS) is the simplest and the cheapest method. Many SAS have been installed but most were failed with screen erosion as the main failure mechanism. Flowing high velocity fluid with sands wears out the screen fast making it impossible for the sands to bridge and to create formation sand pack around the screen. Ceramic Sand Screen (CSS) technology which was recently introduced to the industry aims to address this erosion issue. Having more than ten times hardness of stainless steel, sintered silicon carbide ceramic material in CSS offers superior resistance to wear. The pilot was conducted by installing CSS in three (3) selected wells with sand production history. While waiting for acoustic sand monitoring installation, the wells were put on production with the same choke size and regular manual samplings were conducted to monitor the sand production. The acoustic sand monitoring campaign began in November 2017. Sands production was carefully monitored during the process to determine the final choke size at which the wells would continuously produce. In the middle of the campaign due to adverse weather conditions, all non-essential personnel had to be abruptly demobilised from the field leaving acoustic sensors hooked-up to the respective flow line. This gave opportunity to have unplanned extended sand monitoring window. Loss of Primary Containment (LOPCs) occurred in two CSS wells not long after that. In one the choke body was heavily eroded and the other well had a punched hole at the first elbow of the flowline. These incidents prompted full investigation to be conducted. This included pulling out the installed CSS and performed tear down analysis. Acoustic sand monitoring that just happened to be available in one of the wells proved to be critical in understanding the CSS failure. The paper presents briefly on the CSS pilot project, the chronology of events until the incident, sands production trend from the acoustic sand monitoring. Using all available information, the paper provides details analysis on CSS failure mechanism.

Formation sand production is one of the major production challenges in most of the mature fields in Malaysia. Often, failure in primary sand control equipment requires the operators to adopt through-tubing sand screens as remedial sand control. Due to the erosion prone nature of the thru-tubing metallic sand screen, operators are forced to impose limitation on the production rate coupled with stringent surface sand monitoring system to avoid surface flow line leakage and loss of primary pressure containment. Therefore, to seek a more robust technology than conventional metallic screens, alternative technology with through-tubing ceramic sand screen (TTCSS) has been considered with the idea of higher durability and resistance against erosion. This paper will discuss the performance and lessons learnt from the application of through-tubing ceramic sand screen throughout several mature fields in Offshore East Malaysia. Over the past two years, there have been about twenty-five TTCSS installations in Offshore East Malaysia. Seven pre-mature failure cases were observed, where sands were produced to the surface and even caused leaks on the flow line. The average effective production period for all TTCSS across all the fields ranges from 6 to 11 months. Teardown investigations have been conducted to diagnose the failure root cause. Most failed TTCSS exhibited similar failure patterns at the end caps, which house the spring compensator. Failure to stop the flow through the end caps led to substantial erosion at spring compensator and base pipe, inducing large flow path for sand production to the surface. Other than the design failure, application failure was observed at the ceramic rings due to their brittleness. Computational fluid dynamic simulation and laboratory testing have been conducted at the higher incremental production rates to support the observations from teardown inspections, refine the hypothesis of failure mechanism and enable an incremental design change to be modified into TTCSS. In order for TTCSS to be one of the competent candidates for remedial sand control, new improved standard design of TTCSS with strengthened end cap area will be studied to prevent similar failure.

Objectives, Scope This paper provides valuable insights on aqueous retarded acid system evaluation based on laboratory testing, literature review and engineering analysis prior to the field application for a candidate well in a gas field, offshore East Malaysia (Figure 1). The field is a reefal carbonates build-up overlayed by a thick shale sequence and is one of the deepest fields in Sarawak Asset, in which the produced fluid contains up to 3,500ppm H2S, 20% CO2 and bottomhole temperature up to 288°F. Production enhancement for this carbonate reservoir requires application of a more effective approach to address challenges associated with acid placement and reservoir contact in long pay zones of complex diagenetic facies high temperature carbonate reservoirs, thereby improving return on investment. Figure 1Structural map of Central Luconia carbonate platform offshore Sarawak, Malaysia (Janjuhah et al. 2016) Methods, Procedures, Process The workflow adopted for the stimulation job involves thorough historical production data analysis, detail petrophysical review to evaluate reservoir properties, in-depth production performance analysis (i.e. nodal and network modeling), completion review to ascertain damage mechanism and economic evaluation that include decision risk analysis to evaluate all range of probabilistic outcome. Initial selection of stimulation fluids was based on the mineralogical composition of the main producing formation. A detailed study of reservoir rock and its reaction to various acid systems has been based upon software modeling where sensitivity analyses involving multiple treatment schedule scenarios incorporating various acid and diverter fluid systems are considered. Coreflood experiment was then performed to determine the Pore Volume to Breakthrough (PVBT) comparing emulsified acid with aqueous retarded acid at temperature of 250°F, injection rate of 3ml/min and at confining pressure of 1,500psi. The low PVBT values (i.e. 1.125 and 0.521) and unique breakthrough features obtained from the coreflood confirmed that aqueous retarded acid is effective to stimulate the carbonate reservoir. Compatibility testing was also conducted to assess the stability of the retarded acid recipes and potential reaction with reservoir fluids (i.e. water and condensate), downhole completion and surface equipment. Results, Observation, Conclusion An established stimulation software was used to refine the acid volume calculation and placement analysis. Field trial was made using combined application of the aqueous retarded acid and viscoelastic diverting acid. Considering several case scenarios, the remedial treatment was performed via bullheading to achieve optimum injection rate within 5bpm to 7bpm. Total of 197bbls acid and 197bbls diverter was be pumped during the treatment that will be split in several stages to achieve average invasion profile of 2.8ft and -1.3 skin value. This paper presents aqueous retarded acid system as alternative to widely used emulsified acid systems. Field application of the approach supports the theoretical findings based on substantial improvement in well production, pressure matching of the remedial treatment and calibrated nodal analysis assessment. This demonstrates the value of holistic approach of laboratory testing, comprehensive software modeling and application of enhanced stimulation fluids to overcome complex technical challenges Novel, Additive Information The field production was previously constrained by its high CO2 levels and the supply gas ratio agreement. The information and lessons learnt from this paper will be applicable as evident of practical improvements to achieve sustainable production from the field since it has a strategic importance as production, processing and export hub to other four gas fields. Recent CO2 blending project has allow a better distribution of gas across the network and therefore demand higher production from the field, thus further unlock it potential to achieve economic optimization.

Immiscible Water Alternating Gas (iWAG) scheme was adopted in Echo field, offshore Sarawak Malaysia, to increase recovery factor of the matured oil reservoir after more than two (2) decades of peripheral water injection. It was implemented through four (4) horizontal wells located at reservoir’s eastern and western flanks. Since the commencement of iWAG injection, multiple challenges occured interrupting the stable injection that halting the success of this integrated mega scale project. It started with prolonged iWAG performance test run due to surface constraint, measurement and well issues on executing switching test, followed with low injectivity during switching operation. Subsequently, injectivity issues occured in the gas phase after several injection cycles. In addition to that, injector wells facing high downtime due to surface facilities and well integrity issues, causing low injection rates and unavailability to meet cycle volume within the stipulated duration. Reactivation of iWAG benefiter wells also prove to be challenging due to wells have been idle for a long time and multiple interventions required to revive the well. Injection data for both gas and water phase were analysed to improve iWAG operating procedure and understand the wells performance. INJ-J2 was installed with temporary pressure gauge during the water to gas switching, while the other two (2) wells are equipped with Permanent Downhole Gauge (PDG) to monitor the well injectivity. Application of non-intrusive flowmeter was also proven useful in calibrating the Flow Transmitter (FT) for both water and gas injectors, ensuring the accuracy and precision in the water and gas injection measurement. Besides that, fluid temperature trending was referred to validate on the meter measurement. Low injection rate compared to original plan were reviewed with the Reservoir Management Plan (RMP). Several approaches are implemented in order to achieve the iWAG RMP target and idle well reactivation. Analysis of injection data showed that gas injectivity issue occurred after the water to gas switching cycle. Injectivity improves slightly after long duration of continuous gas injection and applying higher Tubing Head Pressure (THP), unfortunately some wells remain with low injectivity because of insufficient discharge pressure to push the water from the near-wellbore deep into the reservoir to improve injection. Low injection rate issue is mitigated by extending injection cycle duration in order to meet the RMP cycle volume. Besides that, wells are normally injected with higher injection rate to cater for the high downtime. Both gas and water injection are balanced to ensure that the wells reached their cycle volume at similar duration. With limited new field discovery by the Operator, tertiary recovery on the mature field is inevitable. However, there is less implementation of iWAG in offshore field. Through this paper, authors wish to provide insights and lesson learnt for others when planning for iWAG tertiary recovery, taking account of various challenges faced.