Special Issue: Advances in Enhancing Unconventional Oil/Gas Recovery

In recent years, unconventional reservoirs such as tight gas/oil reservoirs [1], shale gas/oil reservoirs [2], and coalbed methane [3] have garnered significant attention and have played a crucial role in meeting the world’s growing energy demands. Characterized by low porosity and low permeability, these reservoirs differ substantially from conventional ones, with pore sizes often falling into the micro- or even nanoscale. These unique features render traditional theories, approaches, and technologies less effective for unconventional reservoirs. Microscopic fluid distribution modes, fluid transport mechanisms, and fluid phase behavior evolve with pore size, presenting numerous challenges in accurately describing these relationships. Consequently, the development of unconventional reservoirs demands many novel solutions to enhance oil and gas recovery efficiencies.

This Special Issue of Processes collects together original research and reviews focused on the latest advances in enhancing unconventional oil and gas recovery. The contributions span laboratory measurements and modeling, field case studies, multi-scale simulation studies, mathematical modeling, and more. The studies presented here provide new insights into the complex dynamics of unconventional reservoirs and propose innovative solutions to the challenges they present.

1. Reservoir Characterization

The accurate characterization of unconventional reservoirs is critical for effective exploration and production. This section includes a range of studies focusing on different aspects of reservoir characterization. Ali et al. [4] present multiple rock physics diagnostic models to quantitatively characterize shallow marine sediments in tight gas fields of the Middle Indus Basin; they found that sorting the grain and coating cement onto the grain’s surface both affected the cementation process. Xu et al. established an interpretation model that integrates response characteristics of logging curves, including shale content, porosity, permeability, and saturation, into tight sandstone reservoirs. Jia et al. predicted longitudinal superimposed “sweet spots” in tight gas reservoirs through a case study of Block G in Canada. The findings indicate that the key engineering parameters for horizontal wells are lateral length, number of stages, fluid volume, and proppant quantity, with lateral length emerging as a crucial independent parameter. Gao and Lei employed a combination of site surveys and numerical simulations to address the gas over-run issue in the upper corner of the “U-type ventilation” end-mining working face, and developed a gas control scheme for it involving “U+ omni-directional large-diameter high-level boreholes along the roof strike”. Zhang and Li et al. offer a dynamic permeability model for shale matrix post-hydraulic fracturing, considering mineral and pore size distribution, dynamic gas entrapment, and poromechanics variations.

2. Fluids in Porous Media

Understanding fluids’ properties and behaviors in the porous media of unconventional reservoirs is essential for optimizing extraction techniques. (1) In order to determine fluid properties, Wan and Wang et al. optimized sulfur solubility testing methods for high-sulfur natural gas; the enhanced filtration system can measure sulfur dissolution directly in real gas samples. Compared to the previous method, this approach results in less residual sulfur during the testing process, and the measured sulfur solubility is 2.13% higher. Zhao et al. introduced oil removal technology for water injection in low-permeability reservoirs using a micro-vortex flow approach, which demonstrated a 9.4% increase in oil removal efficiency while reducing the coagulant dosage by 30.0%. (2) For nanoscale effects, Zhou and Wang et al. provided molecular insights into the displacement resistance of deep oil with associated gas methane during water flooding in nano-pore throats, and they observed that oil and methane displacement efficiency was enhanced as the methane content increased. Wu et al. [5] examined methane transport behavior in nanoscale porous media through pore network modeling, highlighting the dramatic improvement in apparent gas permeability when pressure is low (1 MPa) and pore sizes are at nanoscale (5–80 nm). Wan and Niu et al. incorporated wettability-dependent viscosity into a pore network modeling framework to understand the nanoconfined effects for single water-phase flow. (3) For multiphase flow, Chen et al. and Wei et al. utilized digital core methods to study gas and water flow behavior in fractured tight gas reservoirs and shale oil reservoirs, focusing on matrix imbibition and gas invasion behavior. Both of the studies were able to provide a visualization of the fluids’ distribution in unconventional rocks. Ye and Gong et al. used the volume of fluid (VOF) method to explore gas invasion behavior under different conditions, and the effects of different drilling fluid properties and fracture morphology on gas invasion were analyzed. Li et al. investigated the effects of pore water content on stress sensitivity in tight sandstone oil reservoirs in the Mahu Block, Xinjiang Province, China. They noticed that the stress sensitivity coefficient is not a constant value but decreases as water saturation increases, therefore optimizing a power-law model for stress-sensitive damage.

3. Productivity Evaluation

Because of the low porosity and low permeability of unconventional reservoirs, a hydraulic fracturing operation is commonly adopted to enhance productivity, causing the fluid flows in these reservoirs to exhibit highly nonlinear characteristics. Therefore, novel methods are established to accurately evaluate productivity, which is vital for predicting reservoir performance and optimizing recovery strategies. (1) In terms of analytical or semi-analytical models, Wang and Xie et al. introduced a new capacity evaluation method for both vertical and horizontal wells in offshore low-permeability reservoirs with natural fractures. The method incorporated vertical gradation and fractal analysis to effectively represent the fracture’s complexity and connectivity, and demonstrated a reduction in the average prediction error to less than 15%. Using a dual-medium model to characterize the stress sensitivity, Chen and Sun developed semi-analytical models for gas–water two-phase productivity prediction in carbonate gas reservoirs. In addition, Wang and Li et al. established a semi-analytical gas–water two-phase productivity prediction model for deep CBM reservoirs. Although analytical methods can evaluate productivity quickly, the evaluation accuracy is not very high in highly heterogeneous reservoirs. (2) In terms of numerical simulations, Liu and Zhou et al. investigated fluid–solid coupling mechanisms around open-hole wellbores under transient seepage conditions based on the Biot consolidation theory and the finite difference method, attempting to simulate the pore pressure field and effective stress field around the wellbore. To investigate the impact of various drainage methods on the production performance of coalbed gas wells, Wang and Liu et al. developed a fluid–solid coupling mathematical model by accounting for the effects of coal and shale matrix shrinkage, effective stress, and interlayer fluid flow on reservoir properties. Zhou and Pu et al. [6] focused on connectivity analysis and injection–production optimization in strong, heterogeneous sandstone reservoirs, and the practical application results show that the method can increase the annual output of oil by 1.3%.

4. Enhanced Oil/Gas Recovery

The oil/gas recovery rate for unconventional reservoirs is very low compared with conventional ones. Enhancing oil and gas recovery in unconventional reservoirs is a primary goal which poses large challenges. Xiao et al. [7] reviewed the development and influencing factors of microbial consortiums for enhanced oil recovery after polymer flooding. The process of updating microbial-enhanced oil recovery includes microbial products, mechanisms, merits and demerits, displacement fluid, and effects of the conditions on microorganisms. Zhang and Bai et al. investigated CO₂ injection for enhanced gas recovery and geo-storage in complex tight sandstone gas reservoirs through indoor experiments, and they examined the effects of displacement rate, fracture dip angle, core permeability, and core wetness and dryness on CO₂ gas displacement efficiency and storage efficiency. To avoid rapid water-cut rise and low water-flooding efficiency, Lu et al. proposed a new method, a combination of a rock property test, a brittleness evaluation, and a productivity numerical model to optimize the fracture parameters of low-permeability sandstone reservoirs under fracturing flooding conditions. Additionally, novel products have been developed to enhance oil/gas recovery: Liu and Huang et al. developed a novel water-based drilling fluid (PLUS/KCL) for complex pressure system formations in the South China Sea, Kong et al. optimized foam acid systems for plugging removal in low-pressure oil and gas reservoirs, and Li et al. examined the adsorption behavior and dynamics of micrometer-sized polymer microspheres on quartz sand surfaces.

5. Machine Learning and Data Science Applications

Machine learning and data science are increasingly utilized for parameter optimization, trend prediction, and decision-making in unconventional reservoirs. Ye and Li et al. [8] predicted single-well production rates after hydraulic fracturing in unconventional gas reservoirs using ensemble learning models. Five machine learning algorithms were applied alongside reservoir geology, engineering parameters, and production data to develop the foundational models, indicating that the ensemble model offers higher predictive accuracy and reliability than any single algorithm. Li utilized the Bayesian Adaptive Direct Searching Algorithm for the fast-assisted history matching of fractured vertical wells in coalbed methane reservoirs. The application showed that the proposed method is capable of deriving reasonable estimates of key reservoir properties within 50 numerical simulation runs, which is far more efficient than existing methods. Gao et al. present the intelligent optimization of gas flooding based on a multi-objective approach for a well pattern in the Middle East. Over 400 days, the cumulative oil production increased 25.3% compared to the average distribution method and 12.7% compared to the reservoir engineering method. Based on large data resources, it is possible to predict the evolution of target parameters quickly, while saving measurement costs. To give examples, Su et al. explored the scaling mechanism and countermeasures in tight sandstone gas reservoirs using a BP neural network model, and Sun et al. applied XGBoost for bottomhole pressure prediction in carbonate reservoirs.

6. Conclusions

This Special Issue presents a comprehensive collection of research addressing critical areas in unconventional oil and gas recovery. The integration of multidisciplinary research, multiscale simulations, advanced laboratory tests, and cutting-edge computational tools highlights the forward-thinking nature of the studies, each aiming to overcome the unique challenges posed by unconventional reservoirs and improve overall recovery efficiencies. We hope that the innovative approaches and findings presented here can provide valuable insights and practical solutions for industry professionals and researchers alike.