SS field is located offshore East Malaysia. 2 exploration wells discovered multiple dipping reservoirs, with oil column of about 40 m. The heterogeneous reservoirs, combined with a very large gas cap (i.e. m size of 2) and moderate aquifer strength impose challenges to maximize recovery from this field. Field development study has formulated 14 horizontal wells with 3 water injectors to achieve recovery factor of 30%. Optimum reservoir management strategy requires a delicate balance of gas cap expansion and water injection drive, where the optimum voidage replacement ratio is only 0.25. However, reservoir dynamic modelling shows that all the wells will get early gas and water breakthrough. ICD technology is therefore evaluated to address the above production and recovery dilemma while prolonging the production life.In this paper, optimization of 12 horizontal ICD wells out of 14 wells will be discussed. This includes the process of qualifying and designing the ICD application in each candidate through static modelling. Full field dynamic modelling was also conducted to quantify the real benefits of ICD, and confirming the robustness of the design throughout field life. In view of high uncertainty of fluid contacts and reservoir quality in unappraised areas, the team has adopted the unique yet challenging approach of field appraisal from pilot holes during the initial implementation stage. This has provided valuable data prior to horizontal drilling and final optimization of ICD. Subsequently, the production performance from the first ICD wells will also be discussed to provide evidence on its effectiveness and lessons learned.Finally, the paper highlights the importance of seamless teamwork and coordination between project team and service providers to deliver superior performance. This can be an informative workflow source for future applicants of such technology with similar fields' nature and risks.

The 'S' field, located offshore East Malaysia, consists of multiple-dipping heterogeneous sandstone reservoirs with unconsolidated formation. These multi-stacked reservoirs have an overall 40m thick oil column with marginal Oil-Initial-In-Place (OIIP). A large gas cap, i.e. twice the OIIP equivalent, also exists. Scenarios of zonal gas-out leaving huge oil bypass and moderate aquifer strength with inevitable water invasion cautioned the asset team to consider intelligent zonal flow control especially in its horizontal producing wells.Two of the 14 horizontal producer wells in this marginal field have been screened to apply the modular integrated intelligent completions system (IICS) to actively control and permanently monitor zonal inflow for optimal production. Future selective production control and data surveillance enabled by the IICS are essential to fulfill the needs for delicate downhole zonal flow balance for ultimate oil incremental and recovery. It provides control against the aggressive gas cap expansion at the heels while addressing the moderate aquifer coning-up problems from the dipping toes as the field depletes. This paper highlights the successful implementation of the next generation intelligent completions system in a complicated, highly-dipping, multi-layered sandstone reservoir with commingled production. In this multi-zonal production solution, the conventional surface-controllable downhole zonal flow control valves are now integrated with data surveillance gauges, intelligent sensors and isolation packers all into one single completion joint, instead of the precedent multi-joints system (i.e. splicing required up-to 3 joints per zone conventionally). This single modulated joint system has reduced installation time substantially in comparison to conventional intelligent completions installations. The risk of surface completions make-up damage before run-in-hole is also greatly reduced with less connecting components. This robust yet compact system has made on-site completions tally adjustment easier and is enabled with LWD data update while drilling. As a result, intelligent completions design becomes more flexible and responsive to actual reservoir challenges and drilling surprises -providing an all together "intelligent" solution.This paper also discusses the screening process from simulation performed for candidate evaluation to the resulting impact on production post-installation. Future applicants of such technology with similar fields' nature and risks can benefit from the discussed lesson-learnt; best-practice workflow and seamless teamwork and coordination between the project team and service providers in delivering an advanced fit-for-purpose solution.

The 'S' field, located offshore East Malaysia, consists of multiple-dipping heterogeneous sandstone reservoirs with unconsolidated formation. These multi-stacked reservoirs have an overall 40m thick oil column with marginal Oil-Initial-In- Place (OIIP). A large gas cap, i.e. twice the OIIP equivalent, also exists. Scenarios of zonal gas-out leaving huge oil bypass and moderate aquifer strength with inevitable water invasion cautioned the asset team to consider intelligent zonal flow control especially in its horizontal producing wells. Two of the 14 horizontal producer wells in this marginal field have been screened to apply the modular integrated intelligent completions system (IICS) to actively control and permanently monitor zonal inflow for optimal production. Future selective production control and data surveillance enabled by the IICS are essential to fulfill the needs for delicate downhole zonal flow balance for ultimate oil incremental and recovery. It provides control against the aggressive gas cap expansion at the heels while addressing the moderate aquifer coning-up problems from the dipping toes as the field depletes. This paper highlights the successful implementation of the next generation intelligent completions system in a complicated, highly-dipping, multi-layered sandstone reservoir with commingled production. In this multi-zonal production solution, the conventional surface-controllable downhole zonal flow control valves are now integrated with data surveillance gauges, intelligent sensors and isolation packers all into one single completion joint, instead of the precedent multi-joints system (i.e. splicing required up-to 3 joints per zone conventionally). This single modulated joint system has reduced installation time substantially in comparison to conventional intelligent completions installations. The risk of surface completions make-up damage before run-in-hole is also greatly reduced with less connecting components. This robust yet compact system has made on-site completions tally adjustment easier and is enabled with LWD data update while drilling. As a result, intelligent completions design becomes more flexible and responsive to actual reservoir challenges and drilling surprises - providing an all together "intelligent" solution. This paper also discusses the screening process from simulation performed for candidate evaluation to the resulting impact on production post-installation. Future applicants of such technology with similar fields' nature and risks can benefit from the discussed lesson-learnt; best-practice workflow and seamless teamwork and coordination between the project team and service providers in delivering an advanced fit-for-purpose solution.

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Moving into electronic age, completion tool and accessories are getting advanced. For the past 10 years, permanent downhole gauge (PDG) technology has been supported with tremendous investment in its research and development. This pacing technology is no longer new to the industry oil and gas operators. Some operators have made it as standard practice but however, some operators are still performing financial model analysis to justify for PDG installation. Is it a real need to install PDG or it is just another fancy luxury that give limited financial returns to the project? How much data is required by petroleum and reservoir engineer to understand the reservoir? This paper presents in detailed about the financial model analysis and demonstrates the tangible and intangible benefit of the PDG and the added value to full field life cycle.