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Senoro is a carbonate gas field in Banggai basin in Eastern Indonesian, an area with active collision margin. A comprehensive field-scale study is carried out to investigate the potential geomechanical related risks associated to the field production for the entire life of the Southern part of Senoro field. Well-centric geomechanical models were built for the exploration and appraisal wells in the South Senoro field. A robust field-scale geomechanical model is built for the area of interest which covers the entire South Senoro field. This is done by propagating the well-centric geomechanical model properties and parameters in the field-scale model using geostatistical approach tied with seismic attributed. Using a finite element approach, the model is then coupled with the reservoir flow dynamic model and simulated for the entire life of the field. The simulation results were used to assess the field-scale geomechanical related risks associated to production. The changes in stresses, strains and displacement induced by the carbonate reservoir depletion are obtained over the entire model at the end of each geomechanical simulation step. These are used to conduct detailed geomechanical analyses over the life of the field. The results shows that a stress path of approximately 0.69 is expected in the carbonate reservoir. This is while the stress changes in the caprock layer is relatively lower, and as expected, with a reverse trend. This is mainly because the reservoir compaction is relatively low with a maximum of 0.13% after 2,500 psi reservoir depletion. Subsequently, the maximum surface subsidence is also insignificant with less than 0.12 meters. Since the stresses within the caprock tend to slightly increase by production, the risk of tensile failure reduces over time. The risk of shear failure in the caprock appears to be negligible. The fault tau-ratio seems to increase only in the carbonate reservoir. However, it does not exceed more than 0.60 which indicates a stable state for the fault surfaces. Overall, the results show that there is no risk associated to compaction, surface subsidence, stability of the faults and caprock layer for the entire life of South Senoro field. The comprehensive workflow used to carry out the study covers all the geomechanical aspect of the risks associated to producing from South Senoro field which is essential to optimize the development plan and design of the surface and subsurface facilities.
Senoro is a carbonate gas field in Banggai basin in Eastern Indonesian, an area with active collision margin. A comprehensive field-scale study is carried out to investigate the potential geomechanical related risks associated to the field production for the entire life of the Southern part of Senoro field. Well-centric geomechanical models were built for the exploration and appraisal wells in the South Senoro field. A robust field-scale geomechanical model is built for the area of interest which covers the entire South Senoro field. This is done by propagating the well-centric geomechanical model properties and parameters in the field-scale model using geostatistical approach tied with seismic attributed. Using a finite element approach, the model is then coupled with the reservoir flow dynamic model and simulated for the entire life of the field. The simulation results were used to assess the field-scale geomechanical related risks associated to production. The changes in stresses, strains and displacement induced by the carbonate reservoir depletion are obtained over the entire model at the end of each geomechanical simulation step. These are used to conduct detailed geomechanical analyses over the life of the field. The results shows that a stress path of approximately 0.69 is expected in the carbonate reservoir. This is while the stress changes in the caprock layer is relatively lower, and as expected, with a reverse trend. This is mainly because the reservoir compaction is relatively low with a maximum of 0.13% after 2,500 psi reservoir depletion. Subsequently, the maximum surface subsidence is also insignificant with less than 0.12 meters. Since the stresses within the caprock tend to slightly increase by production, the risk of tensile failure reduces over time. The risk of shear failure in the caprock appears to be negligible. The fault tau-ratio seems to increase only in the carbonate reservoir. However, it does not exceed more than 0.60 which indicates a stable state for the fault surfaces. Overall, the results show that there is no risk associated to compaction, surface subsidence, stability of the faults and caprock layer for the entire life of South Senoro field. The comprehensive workflow used to carry out the study covers all the geomechanical aspect of the risks associated to producing from South Senoro field which is essential to optimize the development plan and design of the surface and subsurface facilities.
As the world is facing challenging climate targets, one of the initiatives is to reduce carbon dioxide (CO2) emission through carbon capture and storage (CCS). However, to understand the viability of CCS study, field scale geomechanical risk assessment is key to determine short- and long-term injection and storage capacity. A comprehensive study was carried out to investigate the geomechanical risks associated with injection in the depleted reservoirs. This was done by preparing well-centric (1D) geomechanical models using inputs from petrophysical, drilling and production data of historical wells. This was then extended to a 3D geomechanical model for the entire area of interest in the field. The model was then used to investigate the caprock integrity (threshold of maximum injection pressure), reactivation of the existing faults (caprock & reservoir) and thermal stress effect on caprock & reservoir, A caprock integrity analysis was carried out for all the storage layers, and it was found that the storage layer pressures (reservoir pressure increase during injection) did not exceed the fracture pressure values of the caprock that will cause tensile failure. A fault stability analysis was carried out for the modelled faults and the Tau ratio for the maximum reservoir pressure (close or greater than initial reservoir pressure) was calculated. Results shows that there is no risk of fault stability using the current injection design (injection pressures close to the initial reservoir pressure). The stress changes induced by the thermal expansion/contraction of the rocks are calculated from the thermoelastic equations for the start of injection stage for both the reservoir and caprock. The caprock fracture pressure incorporating the thermal stress effect at the well location reduced significantly for the shallowest storage layer. With the focus of managing carbon emissions, this is one of the best principal practices and fit for purpose methodology which can be adopted for field scale geomechanical risk assessment to evaluate the short- and long-term CO2 injection risk and storage capacity in any field of interest.
Increasing the working gas capacity is a goal that Underground Gas Storage (UGS) companies have been pursuing. The objective of this paper is to demonstrate a strategy and practice to broaden the operational pressure range, in order to enlarge the working gas capacity of UGS reservoirs, based on a 4D coupling simulation and integrity study. This is a real case in southwest China which has been put into effect and shown good results so far. The overall approach is to carry out integrated subsurface and well engineering studies, numerical simulation, evaluation, step-wised implementation, and monitoring processes. This is a thoroughly integrated UGS study including: 1) Dynamic reservoir simulation which is coupled with a 4D geomechanical study of integrity evaluation of caprocks, faults and underpinning layers; 2) Research on increasing upper limit pressure and expanding storage capacity; 3) Well engineering design evaluation and integrity research. Five steps are recommended to increase working gas volume (WGV), where the most crucial step is to ensure that injection pressure exceeds original reservoir pressure in a safe manner. Thus, a rigorous monitoring, measuring and verification (MMV) plan must be proposed and carefully put into place. This UGS project has been online since 2013 and has operated safely for 11 years, with three phases construction. The Operation Pressure Expansion and Capacity Increments (OPECI) Project was launched in Phase 3. The main purpose of OPECI is to increase WGV and storage capacity (SC) through expanded operational pressure range. The study suggests step-wise operational changes to achieve working gas volume target increase of about 10-15% through enlarging operation pressure range. This "pressure expansion" is to lower the minimum tubing head pressure (THP) and increase maximum injection bottom hole pressure (BHP). This process involves facility upgrade, optimum rate and pressure from each injector and producer, emergency supply & demand, and safety operation. From the perspective of production performance, the practice showed that the simulation forecast accuracy is above 95% both for the single well and the entire gas reservoir. The actual implementation has increased BHP to 32 MPa for most wells at the instantaneous stage, overall exceeding the original reservoir pressure (28.7 MPa) to 30 MPa at the balance stage. After raising injection BHP, the gas storage capacity increased by 2.4 × 108 m3, WGV increased by 3.0 × 108 m3, with emergency capacity increasing by 9.45 × 106 m3. The effect of the pressure expansion is very significant, and the economic benefit is obvious. The MMV implementation is on schedule and partly in place, and the forward plan is to improve the microseismic early warning functionality, strengthen dynamic monitoring and integrity management, and ensure the dynamic sealing of the UGS. The implementation of "operation pressure expansion and capacity increase (OPECI)" - expanding range of operation pressure beyond the original reservoir pressure to increase WGV and SC, is an innovative attempt, the first in China, in the practice of construction of gas storages utility.
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