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SUMMARYThe role of shear dilation as a mechanism of enhancing fluid flow permeability in naturally fractured reservoirs was mainly recognized in the context of hot dry rock (HDR) geothermal reservoir stimulation. Simplified models based on shear slippage only were developed and their applications to evaluate HDR geothermal reservoir stimulation were reported. Research attention is recently focused to adjust this stimulation mechanism for naturally fractured oil and gas reservoirs which reserve vast resources worldwide. This paper develops the overall framework and basic formulations of this stimulation model for oil and gas reservoirs. Major computational modules include: natural fracture simulation, response analysis of stimulated fractures, average permeability estimation for the stimulated reservoir and prediction of an average flow direction. Natural fractures are simulated stochastically by implementing 'fractal dimension' concept. Natural fracture propagation and shear displacements are formulated by following computationally efficient approximate approaches interrelating in situ stresses, natural fracture parameters and stimulation pressure developed by fluid injection inside fractures. The average permeability of the stimulated reservoir is formulated as a function of discretized gridblock permeabilities by applying cubic law of fluid flow. The average reservoir elongation, or the flow direction, is expressed as a function of reservoir aspect ratio induced by directional permeability contributions. The natural fracture simulation module is verified by comparing its results with observed microseismic clouds in actual naturally fractured reservoirs. Permeability enhancement and reservoir growth are characterized with respect to stimulation pressure, in situ stresses and natural fracture density applying the model to two example reservoirs.

Injecting CO2 into oil reservoirs appears to be cost-effective and environmentally friendly due to decreasing the use of chemicals and cutting back on the greenhouse gas emission released. However, there is a pressing need for new algorithms to characterize oil/brine/rock system wettability, thus better predict and manage CO2 geological storage and enhanced oil recovery in oil reservoirs. We coupled surface complexation/CO2 and calcite dissolution model, and accurately predicted measured oil-on-calcite contact angles in NaCl and CaCl2 solutions with and without CO2. Contact angles decreased in carbonated water indicating increased hydrophilicity under carbonation. Lowered salinity increased hydrophilicity as did Ca2+. Hydrophilicity correlates with independently calculated oil-calcite electrostatic bridging. The link between the two may be used to better implement CO2 EOR in fields.

Carbon capture and storage (CCS) is a developed technology to minimize CO2 emissions and reduce global climate change. Currently, shale gas formations are considered as a suitable target for CO2 sequestration projects predominantly due to their wide availability. Compared to conventional geological formations including saline aquifers and coal seams, depleted shale formations provide larger storage potential due to the high adsorption capacity of CO2 compared to methane in the shale formation. However, the injected CO2 causes possible geochemical interactions with the shale formation during storage applications and CO2 enhanced shale gas recovery (ESGR) processes. The CO2/shale interaction is a key factor for the efficiency of CO2 storage in shale formations, as it can significantly alter the shale properties. The formation of carbonic acid from CO2 dissolution is the main cause for the alterations in the physical, chemical and mechanical properties of the shale, which in return affects the storage capacity, pore properties, and fluid transport. Therefore, in this paper, the effect of CO2 exposure on shale properties is comprehensively reviewed, to gain an in-depth understanding of the impact of CO2/shale interaction on shale properties. This paper reviews the current knowledge of the CO2/shale interactions and describes the results achieved to date. The pore structure is one of the most affected properties by CO2/shale interactions; several scholars indicated that the differences in mineral composition for shales would result in wide variations in pore structure system. A noticeable reduction in specific surface area of shales was observed after CO2 treatment, which in the long-term could decrease CO2 adsorption capacity, affecting the CO2 storage efficiency. Other factors including shale sedimentary, pressure and temperature can also alter the pore system and decrease the shale “caprock” seal efficiency. Similarly, the alteration in shales’ surface chemistry and functional species after CO2 treatment may increase the adsorption capacity of CO2, impacting the overall storage potential in shales. Furthermore, the injection of CO2 into shales may also influence the wetting behavior. Surface wettability is mainly affected by the presented minerals in shale, and less affected by brine salinity, temperature, organic content, and thermal maturity. Mainly, shales have strong water-wetting behavior in the presence of hydrocarbons, however, the alteration in shale’s wettability towards CO2-wet will significantly minimize CO2 storage capacities, and affect the sealing efficiency of caprock. The CO2/shale interactions were also found to cause noticeable degradation in shales’ mechanical properties. CO2 injection can weaken shale, decrease its brittleness and increases its plasticity and toughness. Various reductions in tri-axial compressive strength, tensile strength, and the elastic modulus of shales were observed after CO2 injection, due to the dissolution effect and adsorption strain within the pores. Based on this review, we conclude that CO2/shale interaction is a significant factor for the efficiency of CCS. However, due to the heterogeneity of shales, further studies are needed to include various shale formations and identify how different shales’ mineralogy could affect the CO2 storage capacity in the long-term.