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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.

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.

Sand production is one of the operators’ intimidating challenges as the cascading effects can cause significant damages to the surface equipment and often lead to costly clean-up effort. Its effects are further amplified in gas wells with higher gas velocities lead to more detrimental effects on the facilities. Consequently, the facilities will deteriorate, leading to uncontrolled hydrocarbon release which compromise the operation safety considerably. Hence, sand detection devices such as acoustic sensors are extremely crucial to detect sand production as early as possible prior to any undesirable damage. This paper highlights the selection reasoning and advantages of permanent acoustic sensors as well as the method in maximizing the data value through integration with digital field monitoring. Various sand monitoring equipment are available in the industry and its selection is mainly driven by operators’ purpose with cost-benefit analysis. The multi-disciplinary team collaboratively decided on a holistic approach of utilizing the permanent acoustic sensors to its maximum potential. Integration of permanent acoustic sensors with digital field monitoring further improves the investment return as the sensors can provide real-time sand production data. Effective real time sand monitoring can be performed by both offshore and onshore crews where immediate countermeasure can be deployed if abnormal readings detected. When handling sand prone wells, proactive measures have been proven to be more effective if compared to reactive measures. Each well production potential can be maximized by installing sand sensors to ensure safe operating envelope without sand production as well as to trigger alarm if sand detected. The key to unlocking the potential is to ensure data is effectively transmitted to the command center and to the office via our digital field system. The operators are also trained on the next course of action such as beaning down the wells to safe operational envelope in case of sand breakthrough. The value of the acoustic sensors outweighs the total cost involved as real-time sand monitoring system helps to safeguard surface facility integrity considerably.

A prolific gas producer in Sarawak waters was shut-in and idle due to a tubing leak resulting in a significant decline in the total hub production. The well remained idle and required immediate remedial action to meet the contractual sales target. Hence, an expandable tubing patch was proposed to isolate the leak and reactivate the well faster. This paper presents data gathered to identify leak location, tubing patch design, and installation using real-time coil tubing. Several logging surveys were performed to detect leak depth including caliper log, leak detection log (LDL), and downhole camera run; since no pressure build-up was observed post bleed-off tubing and casing, while SCSSV was in closed-state. Running caliper log could not indicate severe metal loss of 7-inch tubing, hypothesizing that the leak could be of a smaller dimension. Therefore, LDL was conducted, indicating temperature gradient and acoustic energy changes at a single depth location of 247 ft.THF, above SCSSV. Utilizing the leak depth marker from acoustic log, a downhole camera was staged to verify geometry of tubing leak. Root cause failure analysis (RCFA) was carried out for this tubing anomaly using diagnostics data to determine the possibility of UHP-17Cr-110 tubing failure. The likelihood of tubing failure is attributed to two main causes namely oxygen corrosion cracking and stress corrosion cracking. Based on RCFA outcome, Hastelloy C276, a nickel-molybdenum-chromium superalloy with the addition of tungsten was selected for the patch material, which is V0 rated, internal gas-tight qualification for temperatures up to 150 degrees Celsius and 5,000 psi. Moreover, this patch material satisfies the well conditions at approximately 20% CO2, 200 ppm H2S, 1000 mg/L salinity, and varying Hg concentrations from 800-2,000 ug/Nm3. The design of patch has been improved by adding AFLAS elastomer for the whole exterior of patch to eliminate contacts between the two metals: reducing the risk of galvanic corrosion. Real-time coiled tubing application was selected for setting the patch to ensure accurate depth-sensing control. Additionally, patch is a rig less intervention technique that will not disrupt the production from the existing wells sharing the same drilling platform. Generally, for high-rate gas wells, economic indicators seem lucrative with tubing patch application, where the payout can be achieved within a month of continuous production. The first step in ensuring the success of tubing patch is by running right diagnostics tools such as leak detection logging and downhole camera run, since multi-finger caliper analysis alone would not locate the leak depth and the leak geometry precisely. Valid design inputs are quintessential for the fitting recommendation of tubing patch design which includes accurate reservoir and fluid properties to ensure sustainability of the expandable tubing patch application.