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.

Due to the increasing demand and importance of natural gas in the global energy mix, its expeditious recovery is crucial, especially from large-scale unconventional geo-resources. Hydraulic stimulation is an established means of productivity increase especially from tight gas reservoirs. The fracture conductivity generally depends on proppant properties, particularly the shape. Therefore, in this research, the effect of using rod-shaped proppants was investigated. Using rod-shaped proppants instead of conventional spherically shaped proppants, can make a significant difference. Due to the cylindrical shape, higher porosity and permeability are generated, resulting in better conductivity fractures. Thus, to analyze the effect of different proppant shapes on post-fracture performance, a production model was implemented in the FLAC3D^plus-TMVOC framework. Later, an in-depth sensitivity analysis was performed to investigate the effects of the proppant shape, size, strength, and effective stress on the fracture aperture reduction and conductivity due to proppant deformation and embedment. The application to a generic model revealed that recovery can be increased by about 7% using aspect ratio 1 rod-shaped proppant with the same diameter as the spherical proppant. Then, increasing the rod-shaped proppant size from an aspect ratio of 1–10 can significantly increase the gas recovery by 13% but results in higher proppant deformation. Finally, the application of rod-shaped proppants to fracturing proposals in well x in a tight gas reservoir of Germany showed that the recovery could be significantly improved if spherical proppants are replaced with rod-shaped proppants.

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.