A 7-in. single-trip multizone (STMZ) gravel pack system was installed successfully in two wells in the T field, Sarawak offshore. This paper highlights the system performance and knowledge obtained during this first-time installation performed in Malaysia. The most common sand control techniques established in the H, I, and J sands of this mature field include stacked gravel pack, 9 5/8-in. single-trip multizone gravel pack, and openhole standalone sand screen (OHSAS) systems. Internal gravel pack completions have provided proven, robust sand control for the sand-prone reservoirs in the T field and can save four to five days of rig time depending on the well configuration, compared with the standard stacked gravel pack completion, which was initially planned during the field development plan (FDP) stage. This paper presents the extensive technical works performed post-FDP approval to ensure the change from the 7-in. stacked gravel pack to the 7-in. single-trip multizone gravel pack completion was executed safely and efficiently and most importantly able to maximize the recoverable reserves from the multiple unconsolidated reservoirs. The technical challenges, such as unexpected drilling of additional zones, limited annulus clearance between the 7-in. liner and gravel pack tool string to reverse out proppant efficiently, intersands spacing, and gross sand interval constraints within certain tolerance because of bottomhole assembly (BHA) limitations, are also discussed. The 7-in. single-trip multizone gravel pack installation helped reduce rig time and provided a cost savings of nearly USD 1.1 million. Subsequently, the two oil-producing (OP) wells (two OP wells and four OP strings) are producing sand-free at higher than expected reserve and flow rates.

The current topic being discussed rigorously by all oil and gas operators is declining production rates. This has caused them to put more efforts into getting the oil out of their matured reservoirs including PETRONAS. One of the initiatives by PETRONAS recently was to undergo a short term production enhancement project. There were various recommendations and opportunities evaluated. Among them is the Low Pressure System, which was chosen due to its simplicity and mobility. The Low Pressure System or LPS in short, is a system that utilises the well test unloading concept, using the common well testing equipment package. It is relatively easy to assemble and is not a permanent structure and can be mobilised from one platform to another. The sizing of the equipment can be customised based on the deck space availability as well as the reservoir potential. Well candidates for the system are those with low tubing head pressure and flowing with biggest choke size as these wells are unable to flow due to the back pressure effect from the export pipeline. To date, two fields were tested and the gains were more than initially expected. One of the fields has had all of its idle wells flowing and producing more than 500bopd. This paper will share how the wells were selected, the results and challenges during the implementation of LPS. Introduction Across the world, production has gone pass peak oil. Clearly, the days of easy oil have long gone. With soaring demand and depleting reserves, every oil company in the world is scrambling to maximise their production. With matured oil fields, many wells are no longer producing i.e. idle or producing with very little oil. Not so much due to depleted reserves, but due to declining reservoir pressure. In Malaysia, this is no exception as it is estimated that more than 60% of the producing fields have been producing for more than 30 years. Therefore, continuous efforts are needed to ensure the production from these fields is maximised and optimum amount of recoverable oil is being extracted from these matured reservoirs. One of the many initiatives to optimise field reserves recovery that was introduced by PETRONAS recently was the Short Term Production Enhancement (STPE) Project. The project involved ten matured fields and the study period took two months to complete. It studied all the short term opportunities that can be implemented in the matured fields within the next 6 months.. Various opportunities were evaluated and several recommendations were considered and implemented as a result from the STPE study. One of them is the Low Pressure System, which was chosen for implementation due to two characteristics; simplicity and mobility. The Low Pressure System or LPS in short, is a system that utilises the well test unloading concept, using common well testing equipment package. The uniqueness of LPS is that it utilises old technology but repackaged as a new solution. What is LPS? Low Pressure System or LPS for short is an innovative total solution aimed at enhancing field production within a short time cycle. LPS is a unique integrated subsurface and surface approach encompasses engineering study, system design and system operation as shown in Fig. 1.

This paper discusses a comprehensive study to address the uncertainties and troublesome major field development. The west Malaysia field has 7 platforms, and 110 wells. Production started in 1979. The highly complex, elongated anticline structure, possess over 330+ interpreted normal, reverse and wrench faults. It is deposited in Lower Coastal Plain within transgressive system tract. Despite the strong and consistent reservoirs production, recovery Factor (RF) remained at 19% indicating potential remaining value. The new look requirement were imposed as a result of disappointing drilling results mainly due to Key uncertainties in hydrocarbon redistribution, sand continuity and its quality, oil production across adjacent fault blocks. Multicomponent seismic was acquired, to establish an updated reservoirs framework and assist in mapping hydrocarbon, water as well as lithology identification (sand/shale/coal). Several wells were suspended based on the indicative study result. 85 new opportunities were identified, and tiered based on technical confidence and risk appetite. A roadmap consists of detailed development strategies spanning over 5 years and beyond associated with ~100MMstb reserves value that will bring the RF to 31% were proposed. Main study outcomes resulted of reducing sand distribution uncertainty, reservoir extension was clarified and confirmed with the new seismic interpretation result. By passed oil were mapped.

To further develop and recover reserves volume from a major oil field in Malaysia utilizing the latest and most premium seismic technology 3D 4C OBC. The overall field development was imposed due to a disappointing drilling results. Field A, located offshore West Malaysia, is a laminated Lower Coastal Plain sandstone deposited with occasionally marine transgressions. A highly complex, elongated anticline structure that possess over 330 interpreted normal, reverse and and wrench faults (normal, reverse and wrench). Production started in 1979. Despite the strong and consistent production, the Recovery Factor (RF) remains at 19% indicating potential remaining value. The time-consuming and costly azimuth 3D 4C OBC was acquired in 2015, to benefit from its capability in mapping hydrocarbon and water as well as lithology identification (sand/shale/coal). The 4C data was processed using 3D pre-stack. An improved continuity and sharpness of the main reflectors on the P/Z cube was clear to allow an efficient brown field redevelopment analysis specifically in the areas of infill and injectors well placements. Attributes maps were calibrated with newly acquired logs, and combined with re-evaluation of existing well logs and production data to ascertain development areas, and potential secondary recovery mechanism. Results were translated to static and dynamic models where possible, with 2D volumetric exercise for the smaller, and non-producing reservoirs. The opportunities identified were classified according to risk matrix, and uncertainties, an overall full-field redevelopment plan was proposed including an aggressive project tiring approach with fast execution process and higher risk appetite. Results coming from PP PSDM and PS PSDM confirmed the reasoning behind unsatisfactory outcome of 2015 infill campaign. The previously high uncertainty in sand distribution and reservoir extensions were clarified and confirmed with the new seismic interpretation result. Two wells were suspended based on the indicative result that showed addition of fault planes within the area. Subsequently, moving forward a total of 85 areas of new opportunities were identified and tiered based on technical confidence and risk appetite. A roadmap consists of detailed development strategies spanning over 5 years and beyond associated with ~100MMstb reserves value that will bring the RF to 31% were proposed and proceeded towards project sanctioning. The first four wells of its campaign was sanctioned, executed and spudded in August 2018. The objective while developing existing producing area is to target virgin location for additional data and to de-risk the undeveloped areas. The results from the first two wells allowed clearer picture of the complexity of the fields with mixed results combined with the operational challenges due to unexpected reservoir losses. Immediate recovery plans and decision matrix were quickly devised and re-entry and deviations were made to the original plans. The completed wells successfully produce up to 1100 stb/d, which was higher than the planned 750 stb/d. In addition to the completed targets, 6 BCO targets were also identified for future production enhancement activities.

This paper presents overall challenges and experiences that the team were facing during offline well unloading campaign recently. On paper, offline well unloading is more favorable as an option to minimize environmental impact, economize rig days and reuse produced clean-up oil. This practice is not new. The implementation of this practice to a 40-year-old brown fields led to successfully bring adopted for two drilling campaign. The well unloading to the existing facilities requires substantial strategies to be adapted and possibilities to handle drilling fluids and solid/debris are extensively discussed within multi disciplinary team whereby risk evaluation was conducted ensure the good progress of this operation. The assurance part to handle production of solid/debris along with produced fluid to surface within 12 hours operation with the assitace from Hook-Up and Commissioning (HUC) work barge initially and resumed later by daily trip via boat to offshore site will be discussed in this paper. Almost 90% of this activity is carried out with crews mobilized with 45-minute boat trip from Bintulu to site, highly depended on weather condition. This paper also will share the major challenges that resisted the good progress of unloading for four wells such as limitation associated setting of the surface Hi Lo Pilot safety switch that cannot handle the transient flow condition, huge pressure drop exerted by the inline surface strainer that temporarily installed to filter any solid production, unintentional jammed close of Tubing Retrieveable Surface Controlled Subsurface Safety Valve (TRSCSSV), unanticipated low performance of gas lift compressor that restricted the wells to continuously flow to the test separator and temporary high H2S gas release throughout the well unloading operation. Due to daily tripping, the crew left with constrained time of 4 - 5 effective hours only per day in attempts to kick off and flow the wells. On paper, offline well unloading indeed offered 70% cost saving compared to clean up with rig. However, in actual it resulted to increase 3 times in well cost and delay in achieving first production target which was 6 months later from the plan due to unanticipated causes that prolong the unloading activities.