Field A, an oil field located in Peninsular Malaysia, was completed in 2007 with an initial production of 6,000 BOPD and managed to reach a peak production of 15,000 BOPD the same year, with a water cut of 15%. Toward the end of 2014, a decrease in production was observed with an increase in water cut to 85%. Coupled with high water cut, some of the wells experienced sand production issues. Most of the wells were completed with either standalone screens or without any sand control methods. After a few years in production, the sand-producing wells were shut-in to help prevent damage to surface facilities. Two idle oil wells, Wells 1 and 2, were identified and efforts were made to reactivate them. High costs can be associated with remedial mechanical sand control to work over a well, so a chemical consolidation treatment using solvent-based resin was identified as a less expensive solution for remedial sand control for these wells. Chemical sand consolidation using solvent-based epoxy resin was tested in a laboratory using produced sand samples from the selected wells and showed good results. The chemical consolidation treatments for Wells 1 and 2 were designed based on these results. Before treatment was performed for either well, Well 2 was replaced with Well 3 because of a gas supply shortage, which affected total field production. In October and November 2015, Wells 1 and 3 were intervened and chemical sand consolidation was executed on both wells. After the treatment, Wells 1 and 3 were brought back on production. Sand production for Well 1 was below the threshold limit of 15 pounds per thousand barrels (pptb). However, the performance of Well 3 did not meet expectations. This paper describes the process of treatment design and execution for the chemical sand consolidation of Wells 1 and 3 and explains the workflow used during the design stage. Coiled tubing isolation technique and bullhead treatment technique are discussed together with lessons learned from Wells 1 and 3 in terms of designing chemical sand consolidation treatments for future applications.

This paper demonstrate a unique combination of techniques and equipment that enabled dynamic reservoir evaluation process using simplified Drill Stem Test (DST) string and completion accessories. The well testing was conducted on a shallow slanted offshore well, drilled into faulted reservoirs with multilayer and complex fluids environment. Key technical challenges to perform well testing includes designing a custom DST string to cater for the multilayer reservoir and articulating a surface well testing equipment that capable of efficient separation to ensure safe and environmental friendly disposal while having accurate flowrate measurements, to deliver good interpretable data given that the uncertainty and complexity of the formation and the well itself. During drilling campaign, contingency plan to mitigate against losses was implemented which had a significant impact on the well testing program. As such, uncertainty-based well test design and interpretation methodology was used to address this and to achieve well objectives. This involved numerical model analysis considering reservoir uncertainties and their interaction with each other, to identify which parameters can be interpret confidently and to indicate the test duration for the well testing program. Since the area is nearby to producing fields, several cases model based on reservoir pressure regime was also constructed during the design stage to tolerate flexibilities for the decision tree. The well testing was successfully conducted result from integrated approach to well test design and realtime data support throughout the operation along with innovative DST string design, customize completion accessories for multiple zones testing and adaptive intervention tools for highly deviated well. Matching with nearby wells were also conducted during monitoring to predict future pressure behaviour which allow for the duration of final build-up to be optimized. Given that Health, Safety and Environment (HSE) is the top of priority, an important aspect of the surface well testing package was the water treatment equipment to treat the produced water from reservoir before being discharge in order to guarantee safe environmental disposal. The well was successfully test at maximum flowrate 2,000bpd of oil and 20MMscf/d of gas with traces of produced water. Data gathered thru the Tubing Stem Test (TST) can used to interpret reservoir parameters and all the well testing objectives were successfully achieved despite the many challenges encountered during the drilling campaign and design stage. The end results may contradict traditional testing methods for pressure transient analysis, but hopefully this paper might create the opportunity to replicate TST as quick and effective reservoir evaluation in other parts of the world.

The use of oriented perforation as a means of sand control technique has been adopted by many operators in industry. Two low angle wells completed in D field offshore Sarawak, Malaysia with moderate to weak rock strength quality required this method not only to limit the sand production but also to sustain the minimum production of 2500bopd each. Based on onset sand production analysis, reservoir M is predicted to have sand production in the direction of a maximum stress of 135degrees from true north. The wells then are suggested to be shot 0-180degree parallel to maximum stress and it saved the expense of no installation of downhole sand exclusion. This paper outlines the perforation analysis conducted to design the optimum perforation using Tubing Conveyed Perforating (TCP) Gun with Dynamic Underbalance (DUB) that effectively clean the newly created perforations. The operational approach applied to overcome the challenge of achieving desired orientation in almost vertical deviation wells by positioning electronic gyroscope siting on Universal Bottom Hole Orientation (UBHO) sub is also discussed in this paper. The available centralization solutions in market are limited to 30° degrees well inclination with 5°accuracies at three times more cost than conventional TCP. The proposal of oriented perforation at both slanted wells significantly saved lot of project economic and proved as effective sand control method, so far the production target is achieved and maintained with no record of sand production at field. Two newly drilled and completed wells located in offshore Sarawak, Malaysia required oriented perforation with dynamic underbalance using Tubing Conveyed Perforating (TCP) guns. The reservoir quality was weak to moderate rock strength with expected sand production in the direction of a maximum stress (135 degrees from true north) within the nearly vertical wellbore. To limit the sand production, the requirement was to shoot 0-180 degree guns parallel to maximum stress, to save the expense of any sand exclusion method. Another requirement was to use Dynamic Underbalance (DUB) to properly clean perforations, reduce skin, and maximize production. The objective was to achieve a minimum production of 2500 BPD. From Geo-mechanic study, in deviated well, the orientation of perforation is aligned with the trend of maximum horizontal stress. Based on breakout analysis, Shmax direction is 135° from the North. The expected production rate can be achieved with Oriented Perforation even at 0 deg phasing and PI reduced from 55 STB/day/psi to 38 STB/day/psi based on Figure 1 below. The studies conducted on Field D available data concluded that sanding risk is very low with Cased & Oriented Perforation strategy.

In the oil and gas industry, operators strive to minimize loss time and production while keeping its facilities and operations safe. Over the past few decades, technological innovation has equipped the industry with the equipment and practices necessary to make the exploration and production more efficient, safe and environmental friendly. This paper discusses successful implementation of several non-intrusive technologies by the operator for redevelopment of maturing oilfield in offshore East Malaysia. The field was discovered in 1967 and oil has been produced since 1972 from the major hydrocarbon accumulation in 8 producing reservoirs, sandwiched between shallow gas-bearing reservoirs and deeper gas/condensate-bearing reservoirs. Enhanced Oil Recovery (EOR) redevelopment project in the field began in 2018, targeting the major oil reservoirs and Non-Associated Gas (NAG) reservoirs. Crestal gas injection and flank water injection will be implemented to further develop the oil rims of A and B reservoir while Immiscible Water-Alternate-Gas (IWAG) injection will be implemented in the C reservoir. The EOR scheme will include infill drilling of new wells and workover of existing wells to deliver targeted incremental oil recovery. The journey towards EOR redevelopment project consistently requires integrated contributions from multiple disciplines such as Petroleum Engineering, Production, Well Services, Facilities and Process Engineering, which has been facilitated effectively through Reservoir, Well and Facility Management (RWFM). This holistic work process involves creating critical strategy for EOR redevelopment activities, optimization decisions and asset management, ensuring the delivery of remaining reserves and long-term production maximization. By implementing RWFM collaboration and support, several non-intrusive technologies have been evaluated & implemented to solve long overdue problems such as online acoustic sand monitoring system, non-intrusive acoustic valve inspection device and active sonar meter. Overall, this paper highlights the working principles, actual field results and lessons learnt from the application of non-intrusive technologies through RWFM collaboration that deliver significant cost and efficiency benefits as well as safety for prudent brown field EOR redevelopment.

This paper presents the success story of an exploration well in Malaysia which exemplary applied a breakthrough integration of 3-1/2″ tubing in 8-1/2″ hole cemented monobore utilizing a new well testing concept of Tubing Stem Test (TST) to save cost and rig time. The Tubing Stem Test (TST) concept which is the new approach of testing a well that integrates both completion and well test technology into a single system compared to conventional Drill Stem Test (DST). The cemented monobore technology was successfully implemented by smooth and flawless planning and execution. A comprehensive planning and collaboration of multiple disciplines in Wells and Subsurface team had ensured a successful delivery of the first Tubing Stem Test (TST) with 3-1/2″ Tubing Cemented Monobore in a near-field exploration well targeting marginal reservoir in Malaysia. During planning stage, the challenges were to ensure that the cementing design concept suits TST application to be executed smoothly by incorporating multiple of risk assessments, lessons learnt, best practices review, feasibility studies and multiple design challenge sessions. This is to ensure that the well integrity is not jeopardized by achieving good cement bond across 3.5″ × 8.5″ annulus section with exclusion of WAB (Welltec Annular Barrier) packer. During execution stage, main concern in cementing operation pushed project team to re-design the fit-for-purpose cementing slurry and multiple cement tests were performed to ensure cementing objectives were achieved. Project team optimized the design by using G Cement Silica blend which has been proven to eliminate fluid migration and provide good compressive strength (UCS). This has allowed additional perforation zone for the new target as CBL/VDL shown good cement bonding to targeted top of cement. Some of the good practices includes good tubing standoff, efficient pre-flush, spacer & cement slurry design with fast compressive strength development, good displacement efficiency and effective plug bump strategy. The thought process, design requirement both for the hardware and cement slurry, and execution follow through of cemented monobore operation in driving for cost savings and operational efficiency will be elaborated. This collaborative initiative has resulted significant cost savings by eliminating cost of wellbore clean-up (WBCU), eliminate 7″ Casing or Liner for reservoir section, DST package, DST tubing rental, simpler completion accessories and 5 days of rig operation days. Despite facing with challenging cement issue with challenging cement batch used, well has achieved good CBL/VDL result and 100% zonal isolation which has enabled perforation of planned and additional target hydrocarbon zones. Simultaneously, formation damage risk was reduced by eliminating the time the formation is exposed to overbalance brine This paper presents the planning and operational execution of 3-1/2″ Tubing in 8-1/2″ Hole Cemented Monobore to realize the feasibility of Tubing Stem Test (TST) as new approach of well testing operation to save cost and rig time.