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Abstract Recovery factor in gas fields is heavily reliant on the abandonment pressure. As reservoir pressure declines and water cut increases, matured assets experience declining well productivity. Fields at a gas hub within Sarawak Basin faces immense challenge to maximize field recovery following an infill drilling evaluation study which indicated no further potential. This paper provides the details on the hub opportunity to lower the abandonment pressure identified from network modelling, optimization works and execution lessons learned. Started with the vision to sustain the gas hub production which was anticipated to cease production in year 2025, when production falls below turndown rate (TDR) of 60 MMscf/d, a gas hub network model has been setup to represent the gas hub configuration with 3 natural depletion drive gas fields tie-in to the export compressor, with the aim to assess the incremental gains and recoverables by lowering down the field abandonment pressure. Material balance (MBAL) model for the gas fields were developed and history matched with production data. The MBAL model was then incorporated into the gas hub network model in General Allocation Package (GAP) model. The network model prediction run results demonstrated up to 12% substantial gas recovery improvement, from lowering down the compressor operating envelope from 48 Barg to 20 Barg in 3 stages; 36-28-20 Barg from year 2021 to 2024, which subsequently reduces its compression capacity from 600 MMscf/d to 300-250-200 MMscf/d, via compressor change-out activities. The single to dual stage compressor change-out Phase 1 implementation has been declared a success with reserves addition beyond 60 MMBOE and prolonging the gas hub life till year 2030. Post execution field performances indicated comparable performances and volumes as per forecasted by the network model, leading to robust project economic returns. Good production attainability at 105% was achieved for the first 12 months of production. The reinstatement of 2 idle wells during the project execution has also proven the value-added benefits from the project. The fields have successfully executed compressor change-out Phase 2 in Q3 2023 and continuous evaluation using updated network model is performed to optimize the Phase 3 timing currently predicted to happen in 2026. Various useful lessons learned were captured during the phased implementation of this project, both operational and subsurface, which included lower CGR than prediction and capped flow rates due to compressor gas turbine exhaust temperature limitation. As part of a continuous improvement process, all lessons learned were documented to be integrated into the network model updates, to improve future projects and to ensure good practices are replicated for future applications in PETRONAS.
Yip et al. (Mon,) studied this question.