Advanced Reservoir Simulation to Underpin the Evaluation of Development Options for Tangguh Enhanced Gas Recovery

Abstract

Abstract Tangguh is a major gas development project, contributing approximately 35% to Indonesia's gas production. It produces lean gas containing 85-90% methane with CO2 levels up to 15%, which is currently emitted to the atmosphere after proper treatment. In its expansion, Tangguh incorporates an enhanced gas recovery (EGR) project, aiming to reinject 90% of the produced CO2 back into the subsurface. This serves as a carbon-capture, utilization, and storage (CCUS) initiative with dual objectives: reducing CO2 emissions and enhancing gas recovery through pressure maintenance and gas displacement. This study focused on advanced reservoir simulation and subsurface uncertainty assessment for Tangguh EGR development planning. Following bp's principles of reservoir modeling and subsurface uncertainty and risk management, we developed fully compositional and integrated subsurface-network multi-field models for Tangguh EGR. The modeling process involved integrating industry-standard toolkits with comprehensive static and dynamic data. The models incorporated well-constrained geological models, a calibrated fluid model, measured relative permeability curves, representative well and surface network models, and continuous production data. We identified key subsurface uncertainties potentially influencing EGR performance, including reservoir thickness, reservoir structure, rock quality, trapped gas saturation, and fault transmissibility. We conducted a sensitivity analysis to evaluate the impact of individual uncertainties and identify the most impactful ones. Leveraging bp's Top-Down Reservoir Modeling (TDRMTM), we performed combination modeling to generate multiple models encompassing the wide spectrum of subsurface uncertainties and simultaneously calibrate them while assessing their impacts. Informed by the results from the combination modeling, we established deterministic subsurface cases and development scenarios. We further stress-tested the feasibility of EGR by evaluating extreme subsurface cases. The dynamic modeling study, guided by bp's principles and best practices, produced appropriate models suitable for EGR simulations and for underpinning the Tangguh EGR development plan. Sensitivity analysis identified the reservoir thickness, structure, and trapped gas saturation as the most significant uncertainties controlling the EGR performance in terms of incremental hydrocarbon gas production and the quantity of CO2 stored. Fault transmissibility emerged as another impactful uncertainty affecting the CO2 breakthrough timing. Combination modeling resulted in an ensemble of calibrated models covering a wide range of subsurface uncertainties, demonstrating potential HC gas recovery increases of 0.5–3.2%, CO2 storage of 76–88%, and CO2 breakthrough 3–5 years after injection commencement, while remaining within manageable CO2 limits for existing wells and facilities. Evaluations of extreme subsurface cases further confirmed EGR's viability, showing enhanced Vorwata gas recovery and CO2 sequestration across the examined scenarios. Overall, the sensitivity analysis, combination modeling, and extreme cases evaluations exhibit a sensibly consistent range of recovery enhancement, CO2 sequestration, and CO2 breakthrough timing, with no instances of negative incremental production in any investigated cases, underscoring the technical feasibility of EGR. Besides assessing uncertainties and evaluating development options, the resulting dynamic models were also useful in providing predictions on the spatial and temporal evolution of the CO2 plume, which are very important for devising surveillance and operating plans, as well as for further model calibration. This paper outlines a modeling workflow for constructing fully compositional and integrated subsurface-network multi-field models for Tangguh EGR. The appropriate modeling methodology, combined with a subsurface uncertainty and risk management framework, enabled the formulation of a development strategy that thoroughly explored subsurface uncertainties. This approach resulted in a healthy diversity of models, allowing for the formulation of a robust EGR development plan that considers the risk associated with CO2 injection while enhancing gas recovery. This case study provides valuable insights into reservoir modeling and simulation for CO2 sequestration, particularly in the context of CO2-EGR.