Search Results (110)

Addressing the stability control challenges of roadways with composite roofs in the No. 34 coal seam of Donghai Mine under high-strength mining conditions, this study employed integrated methodologies including laboratory experiments, numerical modeling, and field trials. It investigated the mechanical response characteristics of the composite roof and developed a synergistic control system, validated through industrial application. Key findings indicate significant differences in mechanical behavior and failure mechanisms between individual rock specimens and composite rock masses. A theoretical “elastic-plastic-fractured” zoning model for the composite roof was established based on the theory of surrounding rock deterioration, elucidating the mechanical mechanism where the cohesive strength of hard rock governs the load-bearing capacity of the outer shell, while the cohesive strength of soft rock controls plastic flow. The influence of in situ stress and support resistance on the evolution of the surrounding rock zone radii was quantitatively determined. The FLAC^3D strain-softening model accurately simulated the post-peak behavior of the surrounding rock. Analysis demonstrated specific inherent patterns in the magnitude, ratio, and orientation of principal stresses within the composite roof under mining influence. A high differential stress zone (σ₁/σ₃ = 6–7) formed within 20 m of the working face, accompanied by a deflection of the maximum principal stress direction by 53, triggering the expansion of a butterfly-shaped plastic zone. Based on these insights, we proposed and implemented a synergistic control system integrating high-pressure grouting, pre-stressed cables, and energy-absorbing bolts. Field tests demonstrated significant improvements: roof-to-floor convergence reduced by 48.4%, rib-to-rib convergence decreased by 39.3%, microseismic events declined by 61%, and the self-stabilization period of the surrounding rock shortened by 11%. Consequently, this research establishes a holistic “theoretical modeling-evolution diagnosis-synergistic control” solution chain, providing a validated theoretical foundation and engineering paradigm for composite roof support design. Full article

Micro-fracturing technology is a key approach to enhancing the flow capacity of oil sands reservoirs and improving Steam-Assisted Gravity Drainage (SAGD) performance, whereas heterogeneity in reservoir physical properties significantly impacts stimulation effectiveness. This study systematically investigates the coupling mechanisms of asphaltene content, clay content, and heavy oil viscosity on micro-fracturing stimulation effectiveness, based on the oil sands reservoir in Block Zhong-18 of the Fengcheng Oilfield. By establishing an extended Drucker–Prager constitutive model, Kozeny–Poiseuille permeability model, and hydro-mechanical coupling numerical simulation, this study quantitatively reveals the controlling effects of reservoir properties on key rock parameters (e.g., elastic modulus, Poisson’s ratio, and permeability), integrating experimental data with literature review. The results demonstrate that increasing clay content significantly reduces reservoir permeability and stimulated volume, whereas elevated asphaltene content inhibits stimulation efficiency by weakening rock strength. Additionally, the thermal sensitivity of heavy oil viscosity indirectly affects geomechanical responses, with low-viscosity fluids under high-temperature conditions being more conducive to effective stimulation. Based on the quantitative relationship between cumulative injection volume and stimulation parameters, a classification-based optimization model for oil sands reservoir operations was developed, predicting over 70% reduction in preheating duration. This study provides both theoretical foundations and practical guidelines for micro-fracturing parameter design in complex oil sands reservoirs. Full article

Low-permeability reservoirs face significant challenges in pressure transmission during field applications of fracturing flooding development. Influenced by reservoir properties and well spacing, fracturing flooding development in such reservoirs often encounters limited propagation of high-pressure zones, ineffective pressure diffusion during water injection, low producer pressure, and poor response. This study develops a numerical simulation model for fracturing flooding development in low-permeability reservoirs of Shengli Oilfield and investigates flow capacity variations under heterogeneous reservoir conditions. Key findings reveal (1) flow capacity is maximized under low-to-high interwell permeability distribution and minimized under high-to-low distribution, with a five-fold difference between the two patterns; (2) flow capacity exhibits near-linear growth with increasing average permeability, while showing an initial increase followed by decrease with growing permeability contrast, peaking at contrast ratios of 4–6; (3) flow capacity improves with injected volume but demonstrates diminishing returns after reaching 0.05 PV, establishing this value as the critical threshold for optimal fracturing flooding performance. Full article

This study presents a comprehensive multifractal characterization of full-scale pore structures in middle- to high-rank coal reservoirs from the Western Guizhou–Eastern Yunnan Basin and establishes a permeability prediction model integrating fractal heterogeneity and pore throat parameters. Eight coal samples were analyzed using mercury intrusion porosimetry (MIP), low-pressure gas adsorption (N₂/CO₂), and multifractal theory to quantify multiscale pore heterogeneity and its implications for fluid transport. Results reveal weak correlations (R² < 0.39) between conventional petrophysical parameters (ash yield, volatile matter, porosity) and permeability, underscoring the inadequacy of bulk properties in predicting flow behavior. Full-scale pore characterization identified distinct pore architecture regimes: Laochang block coals exhibit microporous dominance (0.45–0.55 nm) with CO₂ adsorption capacities 78% higher than Tucheng samples, while Tucheng coals display enhanced seepage pore development (100–5000 nm), yielding 2.5× greater stage pore volumes. Multifractal analysis demonstrated significant heterogeneity (Δα = 0.98–1.82), with Laochang samples showing superior pore uniformity (D₁ = 0.86 vs. 0.82) but inferior connectivity (D₂ = 0.69 vs. 0.71). A novel permeability model was developed through multivariate regression, integrating the heterogeneity index (Δα) and effective pore throat diameter (D₁₀), achieving exceptional predictive accuracy. The strong negative correlation between Δα and permeability (R = −0.93) highlights how pore complexity governs flow resistance, while D₁₀’s positive influence (R = 0.72) emphasizes throat size control on fluid migration. This work provides a paradigm shift in coal reservoir evaluation, demonstrating that multiscale fractal heterogeneity, rather than conventional bulk properties, dictates permeability in anisotropic coal systems. The model offers critical insights for optimizing hydraulic fracturing and enhanced coalbed methane recovery in structurally heterogeneous basins. Full article

The work aims to give a preliminary investigation of the geothermal potentiality of the hot dry granitic rocks in the Hail area, Northern KSA. The Hail area is characterized by a massive exposed belt of radioactive granitic rocks in the southern part, while the northern part is covered by a sedimentary section. A comprehensive methodology utilizing different categories of mineralogical petrographic, geochemical, geophysical well logging and, radiometry datasets, was used to assess the radiogenic heat production capacity of this granite. The measured data are integrated and interpreted to quantify the potential geothermal capacity of the granite and estimate its possible power production. The radioactivity and radiogenic heat production (RHP) of the Hail granites are among the highest recorded values in Saudi Arabia. Land measurements indicate uranium, thorium, potassium, and RHP values of 17.80 ppm, 90.0 ppm, 5.20%, and 11.93 µW/m³, respectively. The results indicated the presence of a reasonable subsurface geothermal reservoir condition with heat flow up to 99.87 mW/M² and a reservoir temperature of 200 °C (5 km depth). Scenarios for energy production through injecting water and high-pressure CO₂ in the naturally/induced fractured rock are demonstrated. Reserve estimate revealed that at a 2% heat recovery level, the Hail granites could generate about 3.15 × 10¹⁶ MWe, contributing to an average figure of 3.43 × 10¹² kWh/y, for annual energy per capita Saudi share. The results of this study emphasized the potential contribution of the Hail granite in the future of the energy mix of KSA, as a new renewable and sustainable resource. It is recommended to enhance the surface geophysical survey in conjunction with a detailed thermo-mechanical laboratory investigation to delineate the subsurface orientation and geometry of the granite and understand its behavior under different temperature and pressure conditions. Full article

Fractured vuggy reservoirs exhibit intricate fracture networks, where large fractures impose significant shielding effects on smaller ones, posing formidable challenges for efficient exploitation. A systematic evaluation of foaming volume, drainage half-life, decay behavior, and viscosity under varying temperatures and salinities was conducted for conventional foam, polymer-enhanced foam, and gel foam. The results yield the following conclusions: Compared to conventional foam, polymer-enhanced foam exhibits markedly improved stability. In contrast, gel foam, cross-linked with chemical agents, maintains stability for over one week at elevated temperatures, albeit at the expense of reduced foaming capacity. The three-dimensional network structure formed post-gelation enables gel foam to retain a thicker liquid film, exhibiting exceptional foam stability. As salinity increases, the base liquid viscosity of conventional foam remains largely unaffected, whereas polymer foam shows marked viscosity reduction. Gel foam displays a non-monotonic viscosity response—initially increasing due to ionic cross-linking and subsequently declining from excessive charge screening. All three systems exhibit significant viscosity decreases under high-temperature conditions. Visualized plate fracture model experiments revealed distinct flow patterns and mobility control performance; narrow fractures exacerbate bubble coalescence under shear stress, leading to enlarged bubble sizes and diminished plugging efficiency. Among the three systems, gel foam exhibited superior mobility control characteristics, with uniform bubble size distribution and enhanced stability. Integrating the findings from the foam mobility control experiments in parallel fracture systems with the diversion outcomes of mobility control and flooding, distinct performance trends emerge. It can be seen that the stronger the foam stability, the stronger the mobility control ability, and the easier it is to start the shielding effect. Combined with the stability of different foam systems, understanding the mobility control ability of a foam system is the key to increasing the sweep coefficient of a complex fracture network and improve oil-washing efficiency. Full article

In view of the flow zoning phenomenon existing in condensate gas reservoirs and the complex pore structure and strong heterogeneity of carbonate rock reservoirs, this study investigates the pressure dynamic behavior during the development process of such gas reservoirs by establishing corresponding models. The model divides the reservoir into three zones. The fluid flow patterns and reservoir physical property characteristics in the three regions are different. In particular, the fracture system in zone 1 has permeability stress sensitivity. The model is solved and the sensitivity analysis of the key parameters is carried out. The research results show that reservoir flow can be divided into 12 stages. Stress sensitivity affects all stages except the wellbore storage stage and becomes increasingly obvious over time. The closed boundary causes fracture closure from the lack of external energy, reducing effective flow channels and triggering the boundary response stage earlier. The increased condensate oil increases the flow resistance and pressure loss, and shortens the duration of the flow stage. The research suggests that improving reservoir conditions and enhancing fluid fluidity can reduce pressure loss and increase production capacity, providing valuable theoretical and practical guidance for the development of carbonate rock condensate gas reservoirs. Full article

This paper investigates the repeated disturbance of weakly cemented overburden rock caused by closely spaced coal seam mining, focusing on the effect of water infiltration on the strength degradation of weakly cemented mudstone. The study compares the fissure and fissure distribution characteristics of the overburden rock under seepage conditions. It also examines the dynamic evolution of seepage parameters during repeated mining and their impact on the overburden rock’s bearing capacity and structural stability. The findings are as follows: (1) After water infiltration, the clay mineral content in weakly cemented mudstone decreases, leading to a significant reduction in strength, increased microcrack development, and a moisture content increase from 0% to 3.27%. Uniaxial compressive strength decreases by 59.83%. (2) In the absence of seepage effects, the fissure development zone in the overburden rock changes from a positive trapezoidal shape to an inverted trapezoidal one, with a water-conducting channel forming first on the setup entry side. When seepage is considered, the fissure development in the weakly cemented overburden rock significantly increases, and the location of large-scale fissure initiation and expansion is advanced by 80 m. (3) During coal seam mining, excavation of the upper seam reduces the pore water pressure in the roof, causing the region of reduced pore pressure to shift from a trapezoidal to an “M” shape. As mining progresses to the lower seam, a seepage channel forms near the setup entry and expands. (4) Under repeated mining conditions, seepage field evolution in the overburden rock triggers the migration and transmission of formation water and pore pressure. The sustained influence of fissure water infiltration and seepage pressure accelerates the development of the water flowing fracture zone. As the overburden rock experiences renewed fracturing and caving, secondary fissure formation intensifies the movement of formation water. Consequently, the bearing capacity and water-resistance properties of the overburden rock are gradually degraded, significantly increasing the extent of structural damage within weakly cemented mining overburden rock. Full article

Objectives: This study aimed to analyze the load-bearing performance of upper incisors and evaluate the curing of the luting polymer composite at various depths within the canal. Methods: A total of one hundred maxillary central incisors (10 groups, n = 10/group) were subjected to various restorative techniques. Approach A used Gradia Core for post-core and crown; Approach B employed prefabricated fiber posts (4 mm or 8 mm) with Gradia for luting and core build-up; Approach C used short-fiber composite (everX Flow) for post-core build-up; and Approach D used fiber posts with everX Flow for luting and core build-up. Restorations underwent cyclic fatigue (40,000 cycles at 95 N) and quasi-static fracture testing. Surface hardness of luting polymer composites was also measured. Results: Data showed that restorations with additional fiber posts (Approaches B and D) had significantly higher load-bearing capacity (p < 0.05), while post material and length had no significant impact (p > 0.05). Short-fiber composite as luting and core material (Approach D) enhanced load-bearing performance compared to Gradia-based restorations (Approach B, p < 0.05). Conclusions: The use of short-fiber composite as both the post luting and core material in restoring compromised incisors, along with a conventional fiber post, demonstrated favorable results in terms of load-bearing capacity. Full article

Routine core permeability and porosity are crucial in assessing flow units within a reservoir because they define a reservoir’s storage and flow capacities. A limited amount of work has been conducted on the lower cretaceous (Barremian to Valanginian) sandstones in the Bredasdorp Basin, offshore South Africa, focusing on the flow zones and the possible effect of diagenetic minerals on the individual flow zones, limiting understanding of reservoir quality and fluid flow behavior across the field. Nine hundred routine core analysis datasets were used to determine the flow units within the reservoir from three wells (F-A10, F-A13, and F-O2) from independent methods, namely: the Pore Throat Radius, Flow Zone Indicator, Stratigraphic Modified Lorenz Plot, and Improved Stratigraphic Modified Lorenz Plot. The results showed six flow units: fracture, super-conductive, conductor, semi-conductor, baffle, and semi-barrier. The super-conductive flow units contributed the most flow, whereas the semi-barrier and baffle units contributed the least flow. Petrography analyses revealed that the diagenetic minerals present were smectite, illite, glauconite, siderite, micrite calcite, and chlorite. The pore-filling minerals reduced the pore spaces and affected pore connectivity, significantly affecting the flow contribution of the baffle and semi-barrier units. Micrite calcite and siderite cementation in FU5 of F-A13 and FU9 of F-O2 significantly reduced the intergranular porosity by filling up the pore spaces, resulting in tight flow units with impervious reservoir quality. It was noted that where the flow unit was classified as super-conductive, authigenic clays did not significantly affect porosity and permeability as they only occurred locally. However, calcite and silica cementation significantly affected pore connectivity, where the flow unit was classified as a very low, tight, semi-barrier, or barrier. Full article

As shale gas development gradually advances to a deeper level, the economic exploitation of deep shale gas has become one of the key technologies for sustainable development. Large-scale, long-term and effective hydraulic fracturing fracture networks are the core technology for achieving economic exploitation of deep shale gas. Due to the high-pressure and high-temperature characteristics of deep shale gas reservoirs, traditional seepage models cannot effectively simulate gas flow in such environments. Therefore, this paper constructs a fluid–solid–thermal coupling model, considering the creep characteristics of deep shale, the effects of proppant embedment and deformation on fracture closure, and deeply analyzes the effects of proppant parameters on the shale gas production process. The results show that factors such as proppant concentration, placement, mechanical properties and particle size have a significant effect on fracture width, fracture surface seepage characteristics and final gas production. Specifically, an increase in proppant concentration can expand the fracture width but has limited effect on increasing gas production; uneven proppant placement will significantly reduce the fracture conductivity, resulting in a significant decrease in gas production; proppants with smaller sizes are more suitable for deep shale gas fracturing construction, which not only reduces construction costs but also improves gas seepage capacity. This study provides theoretical guidance for proppant optimization in deep shale gas fracturing construction. Full article

With the accelerating global transition to clean energy, underground hydrogen storage (UHS) has gained significant attention as a flexible and renewable energy storage technology. Ontario, Canada, as a pioneer in energy transition, offers substantial underground storage potential, with its geological conditions of salt, limestone, and sandstone providing diverse options for hydrogen storage. However, the hydrogen transport characteristics of different rock media significantly affect the feasibility and safety of energy storage projects, warranting in-depth research. This study simulates the hydrogen flow and transport characteristics in typical energy storage digital rock core models (salt rock, limestone, and sandstone) from Ontario using the improved quartet structure generation set (I-QSGS) and the lattice Boltzmann method (LBM). The study systematically investigates the distribution of flow velocity fields, directional characteristics, and permeability differences, covering the impact of hydraulic changes on storage capacity and the mesoscopic flow behavior of hydrogen in porous media. The results show that salt rock, due to its dense structure, has the lowest permeability and airtightness, with extremely low hydrogen transport velocity that is minimally affected by pressure differences. The microfracture structure of limestone provides uneven transport pathways, exhibiting moderate permeability and fracture-dominated transport characteristics. Sandstone, with its higher porosity and good connectivity, has a significantly higher transport rate compared to the other two media, showing local high-velocity preferential flow paths. Directional analysis reveals that salt rock and sandstone exhibit significant anisotropy, while limestone’s transport characteristics are more uniform. Based on these findings, salt rock, with its superior sealing ability, demonstrates the best hydrogen storage performance, while limestone and sandstone also exhibit potential for storage under specific conditions, though further optimization and validation are required. This study provides a theoretical basis for site selection and operational parameter optimization for underground hydrogen storage in Ontario and offers valuable insights for energy storage projects in similar geological settings globally. Full article

Understanding the flow behaviors of two-phase fluids in rock mass fractures holds significant importance for the exploitation of oil and gas resources. This paper takes rock fractures with different surface roughness characteristics as its research object and conducts experiments on the gas–water seepage laws of fractures under various confining pressures and shear displacements. The results indicate that the higher the fracture surface roughness, the larger the equivalent fracture width and the higher the single-phase permeability of gas/water in the fractures. During gas–water two-phase flow, when the water phase split flow rate is high, the influence of the confining pressure and fracture surface morphology on the water phase is significantly higher than that on the gas phase. The relative permeability at the isosmotic point of the fractures increases with the increase in confining pressure and decreases with the increase in roughness. After the dislocation of shale fractures, the interphase resistance within the fractures reduces. The relative permeability of the water phase increases more significantly compared to that of the gas phase. The water phase split flow rate at the isosmotic point does not change significantly, and the relative permeability at the isosmotic point increases. This research is helpful for guiding the protection based on the conductivity capacity of the rock mass fracture network. Full article

The carbonate fracture-cave reservoir in the Tahe oilfield, China, encounters development challenges because of its substantial burial depth (exceeding 5000 m). Its characteristics are low permeability, pronounced heterogeneity, extensive karst cavern systems, diverse connection configurations, and intricate spatial distribution. Prolonged conventional water flooding leads to predominant water channels, resulting in water channeling and limited sweep efficiency. Surfactant flooding is usually adopted in these conditions because it can mitigate water channeling and enhance sweep efficiency by lowering the interfacial tension (it refers to the force that is generated due to the unbalanced molecular attraction on the liquid surface layer and causes the liquid surface to contract) between oil and water. Nonetheless, the Tahe oilfield is a carbonate reservoir where surfactant is prone to loss near the well, thereby limiting its application. High-pressure injection flooding technology is an innovative method that utilizes injection pressure higher than the formation rupture pressure to alter reservoir permeability, specifically in low-permeability oil fields. Because of the high fluid flow rate, the contact time with the interface is decreased, enabling the ability for surfactants to reach the deep reservoir. In this article, based on the mixed adsorption mechanism of two surfactants and the hydrophilic and lipophilic equilibrium mechanisms, a set of high-temperature and high-salinity resistance surfactant systems appropriate for the Tahe oilfield is developed and its associated performance is evaluated. An oil displacement experiment is carried out to examine the effect of surfactant flooding by high-pressure injection. The results demonstrate that the ideal surfactant system can lower the interfacial tension to 10⁻² mN/m and its capacity to reduce the interfacial tension to 10⁻² mN/m after different aging periods. Besides, the surfactant system possesses excellent wettability (wetting angle changed from 135° to 42°) and certain emulsifying abilities. The oil displacement experiment shows that the oil recovery rate of surfactant flooding by high pressure reaches 26%. The effect of surfactant flooding by high-pressure injection is better than that of high-pressure injection flooding. Full article

Hydraulic fracturing is a commonly used technical tool in the extraction process of unconventional shale gas reservoirs. However, the damage caused by fracturing fluids to the proppant fracture inflow conductivity during the whole fracturing, reentry, and production process is very obvious, which affects the fracturing and production increase effect. Conventional proppant fracture inflow conductivity test experiments only use a single-phase fluid in the gas or liquid phase to complete the test and evaluation, and few scholars have paid attention to the change rule of inflow conductivity during the whole fracturing and re-discharge process. Therefore, combined with the characteristics of shale gas production, we simulated the whole fracturing–returning–production process, carried out three consecutive phases of proppant fracture inflow conductivity test experiments, and investigated the change rule of fracture inflow conductivity during the whole process. The results show that under the condition of closure pressure 35 MPa, after distilled water simulated fracturing, the damage to mineral sand flow-conducting capacity is as high as 81.55% due to the effect of shale hydration. During the simulated return discharge process, the gas-measured flow-conducting capacity experiments were carried out at 25%, 50%, 75%, and 100% of the initial gas-measured discharge, and the fracture flow conductivity kept rising, and its maximum recovery value was 54.67% of the original one; the experiments simulated the fluctuations caused by changes in the wellbore flow pressure on the closure pressure in the process of production as well as the influence of fracture flow-conducting capacity under the condition of long-term soaking of the proppant, and the results of this study are useful for the design of fracturing programs and high-efficiency fracturing of shale gas. The results of this study have certain reference significance for the design and efficient development of shale gas reservoir fracturing programs. Full article