Carbon dioxide (CO₂)-enhanced oil recovery (EOR) has great potential and opportunity for further development, and it is one of the vital carbon capture, utilization, and storage (CCUS) technologies. However, strong heterogeneity is one of the several challenges in developing reservoirs, especially for China’s continental tight oil reserves. This study investigates the effects of heterogeneous porosity and permeability on CO₂ flooding evolution in low-permeable tight formation. We simulated CO₂-EOR using a numerical model developed on the platform of TOUGH2MP-TMVOC to evaluate the effect of different levels of heterogeneity on oil production, gas storage, and flow behaviors in a tight reservoir, controlled by standard deviation and correlation length. A comparison of nine cases reveals that porosity heterogeneity commonly intensifies flow channeling, and there is an oil production decline with higher standard deviation and longer correlation length of porosity field. In addition, the porosity correlation length has a negligible effect on reservoir performance when the standard deviation is relatively low. Furthermore, strong heterogeneity also has a negative impact on the storage capacity of CO₂ and oil production. Notably, as the standard deviation was raised to 0.1, a small sweep region arose with the early CO₂ breakthrough, which led to a worse flooding effect. Finally, this study exemplifies that a higher injection/production rate and CO₂ alternating N₂ injection strategies can improve oil recovery in highly heterogeneous reservoirs.

The meaningful utilization of artificially created multiple fractures in tight formations is associated with the performance behavior of such flow channels, especially in the case of thermal energy extraction from sedimentary geothermal system. In this study, an innovative idea is presented to develop a numerical model for geothermal energy production based on concrete physical performance of an artificially created tensile multi-fracture system in a simplified manner. The state-of-the-art software FLAC3D^plus-TOUGH2MP-TMVOC are integrated to develop a coupled thermo-hydro-mechanical (THM) fictive model for constructing a multi-fracture scheme and estimating heat extraction performance. By incorporating the actual fracture width of newly created subsequent fracture under the effect of stress shadow, cubic law is implemented for fluid flow and geothermal energy production. The results depict that fracture spacing plays a vital role in the energy contribution through multiple fractures. Afterwards, a field case study to design huge multiple hydraulic fractures was performed in the geothermal well GB X1 in North Germany. The attenuation of fracture propagation becomes more significant when massive multiple fracturing operation is performed especially in the case of lower fracture spacing. The fictive model results will be extended to study the geothermal utilization of the North German basin through massive multiple fractures in our future work.

Conventionally, high-pressure water-based fluids have been injected for hydraulic stimulation of unconventional petroleum resources such as tight gas reservoirs. Apart from improving productivity, water-based frac-fluids have caused environmental and technical issues. As a result, much of the interest has shifted towards alternative frac-fluids. In this regard, n-heptane, as an alternative frac-fluid, is proposed. It necessitates the development of a multi-phase and multi-component (MM) numerical simulator for hydraulic fracturing. Therefore fracture, MM fluid flow, and proppant transport models are implemented in a thermo-hydro-mechanical (THM) coupled FLAC3D-TMVOCMP framework. After verification, the model is applied to a real field case study for optimization of wellbore x in a tight gas reservoir using n-heptane as the frac-fluid. Sensitivity analysis is carried out to investigate the effect of important parameters, such as fluid viscosity, injection rate, reservoir permeability etc., on fracture geometry with the proposed fluid. The quicker fracture closure and flowback of n-heptane compared to water-based fluid is advantageous for better proppant placement, especially in the upper half of the fracture and the early start of natural gas production in tight reservoirs. Finally, fracture designs with a minimum dimensionless conductivity of 30 are proposed.