Implication of mineralogical and petrophysical property changes to mechanical integrity of reservoir and caprock for safe CO2 storage
Md Shah, Sahriza Salwani
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This thesis is studying the re-injection of CO2 into the same reservoir it originates from. The reservoir is the S Field, Sarawak Basin, offshore Malaysia, and contains contaminated natural gas with ~30% methane and ~70% carbon dioxide. The re-injection, following separation of the CO2 on the platform, is incorporated in the field development plan for adherence to the Paris Agreement and Malaysia’s vision of net zero-carbon emissions by 2050. The in-situ CO2 storage strategy in this offshore Miocene formation is associated with heterogeneous carbonates and extreme reservoir conditions (temperature ~150°C, pressure ~34 MPa), requiring an extensive assessment as well as advanced technology solutions. The main objectives of this study are to firstly reduce subsurface CO2 storage risks for the S Field through improved prediction and advanced understanding of fluid-rock interactions. Secondly, and strongly interlinked with the first point, is to provide a systematic evaluation of the geological, including geochemical and geomechanical, properties at different scales. This study characterises reservoir and caprock properties and investigates CO2-water-rock (CWR) interactions through experimental and modelling approaches. Findings from both laboratory and modelling studies are used for risk assessment for CO2 storage in the S Field. An integrated experimental program was developed to evaluate reservoir and caprock characteristics and their geochemical, geomechanical, mineralogical, and petrophysical analyses during CWR. For the CWR interaction study, carbonates and caprocks were reacted with CO2 saturated brines for up to 35 days and six months respectively, under reservoir pressure and temperature conditions. The samples used for all experiments were core samples from a recent appraisal well, and synthetic brine was formulated using the actual reservoir brine composition. Sensitivity analysis for CWR interaction to quantify mineralogical changes was performed by geochemical modelling using PhreeqC. The carbonate formation has heterogenous properties with the highest porosity (40%) and permeability (3000 mD) observed in the gas zone. The mineralogy in the gas zone is dominated by calcite (80-90 wt %), while mineralogy in the aquifer zone is co-dominated by calcite (50%) and dolomite (40%). The differences in the petrophysical properties and mineralogical composition are due to diagenesis and differences in depositional environment. These differences also influence the geomechanical properties, resulting in stronger carbonates in the aquifer zone compared to the gas zone. The highest peak stress in the stress-strain curve for aquifer zone samples is 40 MPa with static Young’s modulus is 9 GPa compare to 16 MPa of peak stress in gas zone samples and Young’s modulus of 5 GPa. The primary caprock (Seal A), composed of Miocene mudrocks and siltstones has proven to be an effective seal with a thickness of ~500m. The measured porosity is in the range of 2-10% and permeability of 0.5 µD. The main mineral components of Seal A are illite and quartz; some minor amounts of swelling clays (smectite) have been observed. Minimal changes in both mineralogy and petrophysical properties were observed in both reservoir carbonates and caprock shale after exposure to scCO2. Geomechanical properties such as strength and stiffness were similar after exposure to scCO2. Based on the results, the risk assessment shows a low impact with negligible action required to conduct CO2 storage in the S Field. The data derived from the laboratory works were used to develop new and improved correlations on subsurface characterization, specifically in carbonate reservoirs with similar heterogeneity and depositional environments. For example, value creation from the integrated subsurface characterization is the new correlation between porosity-permeability and the relationship of porosity and rock strength in carbonate formation. In addition, findings from the laboratory and sensitivity studies can be used as input for reservoir model calibration and 3D coupled modelling for future CO2 storage development plans in the S Field. Applications of the developed methodology combining various laboratory work in this study have proven satisfactory in studying the identified subsurface uncertainty for CO2 storage development. It had been used as a base methodology for other eight further potential CO2 sites in hydrocarbon fields offshore Malaysia. The unique findings from the extensive and long duration of CO2- water-rock interaction experiments at the extreme pressure and temperature conditions in this study can be a reference or analogue data to other hydrocarbon fields with similar conditions. On top of that, the comprehensive geological risk assessment using bow tie, risk matrix, and heat map developed from this study can guide other high CO2 field development plans in carbonate reservoirs.