Xiaofei Fu

Accurately evaluating fracability is crucial for improving shale gas fracturing efficiency. This study proposes a new mechanical deformation modulus to characterize rock fracture modes under coupled effects of stress conditions and mechanical parameters. Combined with tensile strength and fracture toughness, a ternary-index fracability evaluation method is established covering the full process of “fracture initiation–propagation–network formation”. Taking intervals Q1–Q9 of Gulong Shale as the research object, experiments were conducted to classify main intervals into four mechanical models: (1) “low tensile–low toughness–low modulus” (Q2), where fractures crack and grow easily but exhibit small apertures and weak fracture-forming capacity; (2) “low tensile–low toughness–medium modulus” (Q1, Q3, Q6), where fractures crack and grow easily, forming low-angle intersecting fracture networks; (3) “low tensile–low toughness–high modulus” (Q7, Q9), where fractures crack and grow easily, creating large-aperture, high-angle through-going fracture networks; and (4) “high tensile–low toughness–high modulus” (Q4, Q5, Q8), where fractures crack with difficulty but grow easily, developing high-angle through-going shear fractures. The evaluation results are consistent with the actual fracability characteristics of the Gulong Shale. Compared with conventional evaluation methods, the ternary index evaluation method can more clearly reveal the progressive evolution process of fractures from crack to propagation and then to fracture network formation, providing a reliable basis for fracture network prediction and fracturing optimization.

During the injection and withdrawal of natural gas, faults may cause lateral leakage, resulting in the loss or migration of natural gas out of the gas storage area. Therefore, the lateral sealing property of faults is crucial for the safe operation of gas storage facilities. This paper uses the L gas storage reservoir as a case study to conduct a statistical analysis of the fault dip, reservoir thickness, and overburden thickness within the faulted structure. It integrates a fault sealing triangle diagram derived from logging data to ascertain that the gas storage facility in this study primarily depends on lithological contact sealing and fault rock sealing mechanisms. Furthermore, it evaluates the sealing capacity of these confining faults and develops a quantitative model for assessing their lateral sealing capacity based on an anatomical examination of the original gas reservoir. Through the analysis of dynamic development data for the safe operation of gas storage facilities, pressure variations on both sides of the faults during different injection and production phases were systematically identified. The pressure differential at the end of production was selected, and a numerical simulation incorporating time effects was conducted to assess the dynamic sealing capacity of the fault. A model representing fault sealing capability based on this dynamic development data was established, which elucidates the sealing mechanisms present on either side of the fault across various periods and identifies factors (fluid pressure, tectonic stress, changes in fluid properties) contributing to pressure differentials. The model demonstrates 89% prediction accuracy through machine learning-assisted history matching of 12 injection-production cycles, significantly outperforming conventional methods by 32%. Additionally, the study discusses discrepancies in lateral sealing capacities among different stages and clarifies the fundamental reasons behind variations in pressure differences over time. These findings provide a robust theoretical foundation for assessing sealing capabilities in gas storage facilities during subsequent development phases.

In this study, we employ the homotopy renormalization (HTR) method to analytically investigate Rasmussen’s problem, which characterizes the viscous fluid motion between a pair of infinitely large, coaxially rotating disks. The original set of nonlinear ordinary differential equations is reformulated within a homotopy-based framework, allowing us to construct global asymptotic approximations with closed-form expressions. The HTR method overcomes the limitations of traditional perturbation and renormalization techniques, and avoids the need for asymptotic matching. In addition, the analytic expressions allow for direct estimation of flow parameters such as boundary layer thickness. These results demonstrate the effectiveness of the HTR method in asymptotic analysis and highlight its potential for broader applications in nonlinear fluid dynamics.

Fault zones play a key role in controlling subsurface fluid migration, influencing hydro-carbon accumulation, CO₂ sequestration, and geo-energy storage safety. Most previous experimental studies, however, have been restricted to static outcrop or core observations, which fail to capture the progressive evolution of fault zone structures in time as a response to changing stresses. Moreover, existing analogue experiments often use unconsolidated sediments, which cannot accurately represent brittle faulting in consolidated rocks, and quantitative analyses remain limited. To address these challenges, a new method based on ring-shear experiments was developed to physically simulate fault zone formation in consolidated sandstones. The method simulates shear deformation under variable stress and displacement conditions, followed by multi-scale quantitative analyses, including computed tomography imaging, thin section analysis, and porosity-permeability testing under confining pressure. This comprehensive testing routine allows to quantify changes in fault zone thickness, particle and pore size distributions, and grain orientations during progressive deformation and depending on shear parameters. The results demonstrate systematic relationships between effective normal stress, shear displacement, and fault zone structural attributes. The fault zone thickness shows a nonlinear trend with stress, while cataclasis and compaction intensify with increasing displacement. This work provides a methodological foundation for future applications in fault seal analysis, fluid flow modeling, and numerical simulation, offering a practical reference for petroleum systems studies, hydrogeology, and underground gas storage including CO₂ and hydrogen Document Type: Original article Cited as: Jiang, M., Jin, Y., Fu, X., Liu, Q., Misch, D. Physical simulation and quantitative characterization of fault zones based on ring-shear experiments. Advances in Geo-Energy Research, 2025, 17(3): 256-266. https://doi.org/10.46690/ager.2025.09.07

Understanding the failure behavior and mechanisms of mudstone is very important for engineering applications. While confining pressures play an important role in mudstone deformation, the limitations of laboratory conditions and mudstone sample preparation preclude scaled models of the mechanisms of deformation transition from brittle to ductile, especially for high confining pressures. In this study, dry indurated mudstone of the Kuqa depression in North China acted as the prototype rock for a numerical model. We performed numerical experiments for different confining pressures. Overall, the numerical model captured the stress–strain behavior and failure modes demonstrated by triaxial loading experiments from the laboratory at low confining pressures. Subsequently, the mudstone failure modes were predicted for high pressures. A new model to predict brittle–ductile failure behavior is proposed based on the understanding of the mudstone failure mechanism. The model showed the following. (i) For brittle failure stages, a shear dilatancy fracture is developed at low confining pressures. The rock failure modes undergo a high-angle shear fracture and a high-angle conjugate shear fracture. (ii) For brittle–ductile transition failure stages, a shear compaction fracture appears in rock deformation at high confining pressures. The fracture modes are exhibited as low-angle shear fractures and low-angle conjugate shear fractures.

The development of the effective source rocks of the Eocene and Oligocene directly determines the oil and gas exploration potential in the northern Yinggehai Basin in China. Based on the analogy with the Hanoi Depression in Vietnam and the Yacheng District in the Qiongdongnan Basin and the comprehensive analysis of self-geological conditions, the development conditions of Eocene and Oligocene source rocks in the northern Yinggehai Basin are examined, focusing on tectonic evolution, sedimentary facies, and the paleoenvironment. Finally, the sedimentary models for the effective source rocks are established. The tectonic activity controlled the formation of the sedimentary deep depression and the migration of the sedimentary trough center, which migrated from east to west and then south from the Eocene to the Oligocene, leading to the sedimentary migration of good muddy source rocks. There are multiple sedimentary facies in favor of source rocks, including lacustrine facies, shallow marine facies, and delta plain swamps. The paleoenvironment indicates that the paleoclimate transitioned from warm and humid to cold and arid, the redox conditions evolved from semi-reducing to oxic, and paleoproductivity increased from the early to late Oligocene. Therefore, the early Oligocene was more conducive to the enrichment of organic matter. It is speculated that the warm and humid paleoclimate, reducing environment, and high paleoproductivity of the Eocene promoted the sedimentation and preservation of more organic matter. The above studies show that the northern Yinggehai Basin, especially the sedimentary period of the Eocene and Oligocene, has favorable geological conditions for the development of effective source rocks. The sedimentary models for Eocene lacustrine mudstones and Oligocene marine mudstones and marine–continental transitional coal-measure source rocks were established. These studies make up for the serious deficiency of previous research and mean that there is great exploration potential for oil and gas in the northern Yinggehai Basin in China.

Thermal maturity of the shales from the Ziliujing Formation of the Jurassic age in the Sichuan Basin is in the hydrocarbon generation window, which makes it a candidate for shale oil and gas development. The meso- and macropore characteristics and heterogeneity of shales are important factors affecting the occurrence and development of oil and gas. However, the meso- and macropores of the Ziliujing shales have not been systematically studied. Thus, the mineral compositions and total organic carbon (TOC) of samples from this formation, as well as its pore structure, are analyzed by low-temperature N₂ adsorption technique. Moreover, the heterogeneity of the pores was determined by multifractal analysis. The results show that the Ziliujing shales can be classified into three types according to the distributions of mineral compositions of carbonate and mixed and argillaceous shales. Results revealed that the smallest meso- and macropore volume (PV), the smallest specific surface area (SSA), and the largest average pore diameter (APD) occur in the carbonate shales. However, the largest PV and SSA and the smallest APD are observed in the argillaceous shales. The porosity of carbonate shales is mainly concentrated between 5 nm and 30 nm. Compared with carbonate shales, the porosity with pore sizes less than 30 nm of mixed and argillaceous shales shows a rapid increase. Furthermore, inorganic minerals are the main factors affecting the pore distributions, while TOC shows a weak effect. Herein, clay minerals significantly increase the mesopore volume and the pore number with a size of less than 30 nm. The D_q-q curves reveal that the meso- and macropore distributions of Ziliujing shales show multifractal behavior, but the multifractal characteristics of pores of various shales are distinctly different. The information dimension D₁, the Hurst exponent H, and the width of the right side D₀–D₁₀ are key indicators to distinguish the local variations within the pore structure of different types of shales. The carbonate shales have the largest multifractal spectra width and the smallest D₁ and H, while the opposite trend is found for the argillaceous shales. Clay minerals reduce the heterogeneity of the meso- and macropore distributions and increase the pore connectivity. Nevertheless, the carbonate minerals exhibit a reverse trend. Finally, it was found that TOC does not impact pore complexity as much. Collectively, this study supports our understanding of the occurrence of shale oil within various reservoir facies, thereby providing a guideline for future explorations in the Ziliujing Formation of the Jurassic age in the Sichuan Basin.