Brunei Shell Petroleum (BSP) is undergoing a significant modernization of its gas-lift system in the Champion field in Brunei. With smart gas-lift flow control valves, BSP is continuously controlling the gas for gas lifted wells on remote, unmanned production facilities. Shell Global Solutions is assisting this process by the implementation of the FieldWare* Real-time Optimization (RTO) system. This system, which uses data driven models to optimize production, has already proven its value in this field during a prior pilot installation. The successful implementation of BSP Champion field gas-lift optimization is an example of the significant value that Smart Fields* implementation brings to a brown field. As a result Gas-lift efficiency has been sustainably increased by 40% in one of the implemented platforms. This paper discusses the RTO project execution, technology involved, the implementation process, its results and finally the business benefits achieved. Background BSP operates the highly complex Champion field offshore Brunei - reservoirs with stacked sand/shale sequences and wells with commingled zones production. The field has been producing since the early 1970's, with 500 reservoirs, 300 well strings, 30 platforms/jackets, 5 production separation platform complexes and 185 offshore pipelines. Reservoir pressure decline means that 80% of the producers are gas-lifted. Six compressors supply lift-gas to 260 gas-lifted wells (located across 29 platforms) via the gas-lift supply pipelines network. Historically, the gas-lift flow to each well has been controlled predominantly by the size of the orifice in the downhole operating valve. As the well conditions evolved, inappropriate orifice sizes occasionally caused lifting instability. Orifice enlargement or leaking was not picked-up as there was no real-time measurement of these rates and no ability for active gas lift gas injection control and allocation. Well and field-wide gas-lift optimization was therefore not possible. Associated gas GORs were often considered unreliable and of little value for reservoir modelling, resulting in the loss of a significant history matching variable. * Trade marks owned and used by companies of the Shell group
This case study highlights the difficulties and challenges faced by a mature brownfield (40+ year field life and 330+ wells) producing via multiple offshore satellite platforms. Daily production issues include sub-optimal well-testing facilities, uncertainties in well performance, sand production, well flow assurance, gas-lift compressors uptime, bottlenecked pipelines and integrity problems. This paper showcases the journey of an operator in using portable high frequency MPFM well-test unit for closing the well-test data gap in offshore brownfields of Peninsular Malaysia. Here, the paper shares the lessons learnt and workflow for effective well-test data gathering and validation, diagnosing well performance using dynamic well behaviour recorded by high frequency MPFM, and subsequent well optimisation activities (such as choke optimisation, gas-lift optimisation and flowline de-bottlenecking) for rapidly improving well production. Moreover, this paper also highlights key findings such as related to PVT data input and how it can affect MPFM measurement accuracy. Ultimately, the use of portable high frequency MPFM has helped field operation to maximise oil production and arresting field production decline.
The Seligi field, located 240 kilometers offshore peninsular Malaysia in the Malay basin was discovered in May 1971 and is one of the largest oil fields in Malaysia. Sand production in the Seligi field has been observed, especially from the J reservoirs group. Within the Seligi field, Well G was identified as one of the wells with sand production to surface that could lead to sand accumulation at surface facilities and erosion of equipment. Historically, there had been no in-situ sand control measures in the well. The default practice for sand control was to choke back the well, to prevent triggering of the surface sand probe (production with maximum sand-free rate). This approach however is a compromise, while it limits sand production, it also limits the production potential of the well (well technical potential). As part of the production enhancement assessment program, remedial sand-control methods were considered to increase the oil production while minimising sand production. Among the options considered was ceramic downhole sand screen installation. Ceramics have been used in many extreme erosion and corrosion applications, with ceramic sintered silicon carbide being 50 times harder than steel. Ceramic sand screens made with sintered silicon carbide offer much higher erosional resistance at speeds of 300ft/s sand impingement velocity. Due to the aggressive nature of the sands and high velocities of greater than 50ft/s in Well G, a through-tubing ceramic sand screen was selected. The ceramic sand screen served as a fit for purpose solution that allowed the well potential to be fully maximised, enabling a continuous production with minimal sand production at surface. This paper reviews the first successful pilot installation of through-tubing ceramic sand screen in Well G in the Seligi Oil Field, Offshore Peninsular Malaysia. Discussed are careful analysis and planning, i.e. velocity calculations, tool deployment simulations, tool inspections and detailed job procedure leading to a successful installation. With the ceramic sand screen installed, the well was able to produce at 100% production choke opening with lower tubing head pressure and has not produced sand at surface despite multiple shutdowns and well bean ups. The installation has also removed the need to have sand handling facilities at topside and has generated an implicated cost saving from expensive intervention programs. Given the success of this pilot installation, a baseline in sand control has been set for this field, with new well candidates being considered for future replication.
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