Search Results (656)

The stability of underground building foundations in fractured rock masses is a critical concern in geotechnical engineering, particularly for urban projects situated in complex geological settings. In such environments, the interaction between weak planes, groundwater seepage, and in situ stress plays a decisive role in controlling deformation and failure mechanisms. This study presents a novel weak plane–seepage–stress coupling model specifically developed to evaluate the stability of underground excavations and foundation walls under these challenging conditions. Unlike conventional approaches that often assume isotropy or consider isolated factors, the proposed model integrates multiple interacting variables—including weak plane orientation, seepage coefficient, and excavation direction—to systematically assess their combined influence on stress redistribution and failure pressure. A key innovation lies in the quantitative evaluation of the permeability-sealing coefficient, which reflects the effectiveness of waterproofing measures, and its coupling with weak plane characteristics. The results demonstrate that weak planes significantly alter the surrounding stress field, inducing directional instability. The optimal excavation orientation for minimizing instability is identified within the range of 200° to 280°. Moreover, increasing δ from 0 to 1 leads to a substantial reduction in the required supporting pressure, underscoring the critical role of effective sealing and waterproofing in enhancing foundation stability. While the current model is based on a single weak plane assumption and focuses on short-term mechanical responses, it provides a foundational framework for understanding coupled instability mechanisms. Future work will extend the model to incorporate multi-set weak planes, time-dependent degradation, and dynamic excavation processes. This research offers both theoretical insights and practical guidance for optimizing geotechnical design in fractured rock environments, contributing to more resilient and sustainable underground construction. Full article

Permeability constitutes a critical factor controlling the production of coalbed methane (CBM), and the sensitivity of the CBM reservoirs to stress and the degree of coalification strongly influences permeability variations. Elucidating the mechanism underlying the sensitivity of reservoir permeability to stress and degree of coalification is therefore a crucial prerequisite for enhancing CBM production capacity. Helium permeability tests were conducted on raw coal pillar samples to investigate the variation in coal permeability under different effective stresses and degrees of coalification. The effective stress ranged from 1.5 to 7.5 MPa, and the maximum vitrinite reflectance (R_o,max) varied between 0.456% and 3.211%. The results indicate that permeability decreases with increasing effective stress and R_o,max. When internal fractures in the coal samples are poorly developed, this relationship follows a negative exponential trend. To evaluate the permeability sensitivity of the coal samples, a stress sensitivity index (S₁) and a coalification degree sensitivity index (S_1R) were introduced and constructed. In addition, the permeability damage rate (PDR) and stress sensitivity coefficient (α_k) were also employed to assess permeability sensitivity. The results show that the stress sensitivity of coal decreases with the increase in effective stress but increases with the rise in R_o,max; the coal sensitivity of coalification degree decreases with the rise in R_o,max and increases with the increase in effective stress. Furthermore, S₁ and S_1R exhibit strong positive linear correlations with other sensitivity evaluation parameters, indicating that they can serve as comprehensive indices for evaluating the overall permeability sensitivity of coal samples. A predictive model relating permeability to effective stress and maximum vitrinite reflectance was established for coal reservoirs. Using Pearson’s, Spearman’s, and Kendall’s correlation coefficients, the relationships among effective stress, coalification degree, and permeability were analyzed. The results reveal that coalification degree exerts a stronger control on permeability than effective stress. The permeability control mechanism was thereby clarified, providing theoretical guidance for the efficient development of CBM reservoirs. Full article

Groundwater contamination caused by dense non-aqueous phase liquid (DNAPL) has long been recognized as a persistent environmental challenge, particularly in fractured porous media. DNAPL migration is highly uncertain due to the heterogeneity and complexity of fracture networks, which complicates risk assessment and remediation design. This paper begins with an overview of mathematical models for multiphase flow migration in fractured media, followed by a systematic analysis and classification of DNAPL migration mechanisms based on laboratory experiments and numerical simulations. Subsequently, key challenges in current DNAPL remediation practices are discussed, including difficulties in monitoring and characterizing fractured aquifers, limited delivery and utilization efficiency of remedial agents, and the back-diffusion of DNAPL from low-permeability zones. Based on this analysis, three primary DNAPL remediation approaches—physical, chemical, and biological methods—are reviewed and evaluated. Finally, future research directions for understanding DNAPL migration and improving remediation strategies in fractured media are proposed. Overall, this review bridges mechanistic knowledge, simulation research, and remediation practice, providing insights that contribute to future technological progress and management decision-making in DNAPL-contaminated fractured aquifers. Full article

Grain-scale heterogeneity strongly influences hydraulic fracture initiation and trajectory in crystalline rocks, yet its contributions to non-planar growth and the interaction of multiple nearby cracks remain insufficiently quantified. To address this gap, we perform numerical experiments on a model containing two parallel pre-existing cracks using a hydro-mechanical phase-field framework, systematically quantifying how mineral distribution and axial compression govern non-planar hydraulic fracture growth and inter-fracture competition. The results demonstrate that mineral distribution is the primary driver of fracture complexity. Even within the same Voronoi tessellation, redistributing minerals alone yields markedly different trajectories, deflections, branching patterns, and final morphologies. Furthermore, non-planar growth follows a stepwise, energy-threshold-driven mechanism. When cracks penetrate strong grains or undergo large-angle deflections, propagation is impeded, and injection pressure builds up. Once a critical energy threshold is reached, accumulated energy is rapidly released along the path of minimum incremental energy, manifested as abrupt pressure drops and rapid crack advance. Additionally, the two nearby fractures exhibit strong mechanical competition. Despite negligible hydraulic interference in low-permeability granite, early growth of one fracture redistributes stresses and suppresses the driving force of the other, resulting in asymmetric development. Finally, axial compression primarily governs the overall propagation orientation and influences local failure modes but has a limited effect on peak pressure relative to mineral distribution. Full article

Wellbore stability is one of the major challenges during drilling operations in shale gas formations. Drilling fluid seepage can significantly alter the pore pressure around the wellbore, thereby inducing wellbore instability. In this study, the Darcy pore fluid flow model was applied to both the mud cake and wellbore to predict pore pressure, which helps improve the accuracy of calculating collapse pressure and fracture pressure. Shale samples were collected from the Puguang Gas Reservoir, and their composition and physicochemical properties were systematically analyzed. The results indicate that the clay content in the formation can reach up to 35.5%, with distinct hydrophilic characteristics, and the maximum hydration expansion rate of the shale is 5.79%. The permeabilities of shale and mud cake were measured via the pore pressure transmission test. Specifically, shale samples from Sub-layer 1 exhibit the highest permeabilities for both rock and mud cake, which are 8.27 × 10⁻¹⁸ m² and 2.07 × 10⁻²⁰ m², respectively. In contrast, samples from Sub-layer 3 show the lowest permeability values, being 2.76 × 10⁻²⁰ m² and 1.66 × 10⁻²² m². The borehole tensile breakdown pressure and compressive collapse pressure were calculated using a poro-mechanical coupling model. The Sub-layer with the lowest cohesion strength after drilling fluid immersion presents the narrowest mud density window of 0.04 g/cm³, making it the most susceptible to wellbore stability failures; furthermore, the maintenance of wellbore stability requires strict control of the drilling mud density within the range. This study can provide guidance for accurate prediction of mud density window during drilling operations in shale formations. Full article

Well spacing and reinjection rate are two critical parameters controlling the efficiency and sustainability of hot dry rock geothermal development. Taking the Yangbajing geothermal field in Tibet as the geological setting, permeability experiments were conducted on fractured rock masses under multiple operating conditions, and a three-dimensional fully coupled thermo-hydro-mechanical numerical model was established to systematically evaluate the effects of different well spacing–reinjection rate combinations on heat extraction performance. The experimental results show that axial stress is the dominant factor governing specimen deformation and seepage characteristics. Permeability decreases with increasing axial stress, exhibiting an initial sharp decline followed by a gradual reduction. The effect of temperature varies with axial stress level. Under low to moderate axial stress, permeability decreases monotonically with increasing temperature, whereas under high axial stress, it first decreases and then increases. The simulation results indicate that the production temperature remains relatively stable during the early stage of exploitation and subsequently declines, with the rate of decline increasing significantly as the reinjection rate increases or the well spacing decreases. In addition, an exponential positive relationship is identified between well spacing and the optimal reinjection rate. When a 10% decline in production temperature is adopted as the shutdown criterion, the optimal reinjection rate increases from 60 m³/h to 150 m³/h as the well spacing increases from 500 m to 800 m. Based on the simulation results, the theoretical installed capacity of the first deep reservoir in the Yangbajing geothermal field is preliminarily estimated to reach 31.8 MW. Full article

Permeability prediction of deep metamorphic rock reservoirs in the southwestern Bohai Bay Basin poses an enormous challenge due to the strong heterogeneity. Fractures widely develop in such reservoirs, yet their contributions to permeability were neglected in traditional prediction models. To develop an effective model to predict permeability, parameters related to fracture needed to be taken into account. In this study, taking the Archaeozoic Formation in BZ 19–6 Region—a typical deep metamorphic rock reservoir in the southwestern Bohai Bay Basin—as an example, the porosity frequency spectra were first extracted from electrical imaging logging, and the correlations between the shape of porosity frequency spectrum and rock pore structure were analyzed. Afterwards, two parameters, which were defined as the logarithmic mean (φ_gm) and standard deviation between two golden section points (φ_gsr), were extracted to reflect the main peak position and wide porosity frequency spectrum, and a novel permeability prediction model was established. After the target formations were classified into two types according to the differences in pore types and pore–fracture configuration relationships, the model coefficients were calibrated. Consecutive permeability curves were derived from the proposed model in the intervals where porosity frequency spectra were obtained. Comparisons of predicted permeabilities from the proposed model, traditional method and core-measured results showed that the proposed model yielded far more reliable results, with an average relative error of only 11.12% between the predicted and core-measured permeabilities. In contrast, the average relative error of the traditional method reached 36.10%. The proposed model contributed significantly to the characterization and effectiveness evaluation of fractured deep metamorphic rock reservoirs. Full article

The fracturing development of low-permeability and ultra-low-permeability oil and gas reservoirs urgently requires a fracturing fluid that combines high performance and low damage. To overcome this challenge, this study synthesized a novel polyamine boron crosslinker (PBC) suitable for 0.2% guar gum. The molecular structure was characterized by Fourier transform infrared spectroscopy (FT-IR) and nuclear magnetic resonance hydrogen spectroscopy (¹H NMR). Meanwhile, this study introduced the response surface methodology and established a second-order regression model to determine the optimal synthesis conditions (polyetheramine 10.8 g, n-butanol 7.4 g, and ethylene glycol 20.7 g) with a model prediction error of only 0.7%. The results indicated that PBC exhibited excellent performance in 0.2% guar gum. The viscosity of crosslinked gel fracturing fluid remained stable at approximately 100 mPa·s under 60 °C and 100 s⁻¹ shear. The wall forming filtration coefficient was 2.30 × 10⁻⁴ m/s^1/2, and the initial filtration was 1.30 × 10⁻³ m³/m². The static settling rate was 2.4 cm·min⁻¹, demonstrating good suspended sand capacity. Furthermore, the synergistic interaction between borate ester bond and polyetheramine in the PBC conferred dynamic reversible crosslinking and uniform network formation. This enabled high-strength, low-damage crosslinking effects at low concentrations. This study provides an efficient crosslinker solution for 0.2% guar gum, holding both theoretical and engineering significance for advancing the low-cost development of fracturing fluid. Full article

Efficient development of tight reservoirs in shallow-water delta-front environments is often constrained by misaligned horizontal well design and the underlying geological architecture. To address this, a quantitative optimization workflow is proposed, integrating 3D architectural characterization of single sandbodies with reservoir simulation. Using the Chang 7 Member of the Ordos Basin as a case study, three dominant sandbody types—isolated channels, vertically stacked channels, and mouth bars—were characterized in terms of geometry, stacking pattern, and internal permeability anisotropy. High-resolution geological models incorporating stratigraphic cyclicity and heterogeneity were constructed. Local grid refinement around wellbores and fracture networks was implemented to improve simulation fidelity. Sensitivity analyses identified optimal values for horizontal section length, fracture stage, and fracture half-length for each sandbody architecture. The results indicate that production response is highly sensitive to sandbody geometry and heterogeneity, with diminishing returns observed beyond critical design thresholds. Field validation with three horizontal wells confirmed that optimized parameter sets aligned with geological architecture resulted in significantly improved and more stable oil production. To support application in similar reservoirs, a dimensionless design chart was developed using ratios of horizontal well length to sandbody length (L_h/L_s) and fracture length to sandbody width (L_f/W_s). This empirical tool enables rapid pre-drill assessments and informs well planning strategies aligned with sandbody architecture. By emphasizing the integration of geological and engineering disciplines, the approach offers a scalable framework for optimizing horizontal well design in geologically complex tight formations. Full article

High-pressure water injection (HPWI) can rapidly replenish the formation energy of low-permeability reservoirs, but it may trigger multi-scale fractures, leading to premature water breakthrough between injection and production wells. To identify the main causes and regulate the mainstream line (i.e., the preferential flow path with the highest streamline density/flow rate), a two-zone and five-point numerical model was developed. This model couples the static damage zone (dominated by micro-fractures) and the fracture development zone (dominated by macro-fractures). Through sensitivity analysis, the ways in which micro-fracture damage and macro-fracture geometry control the evolution of seepage patterns and the risk of water breakthrough were quantified. The results show that in the representative scenarios of this paper, micro-fracture damage is mainly associated with an increased risk of water breakthrough by forming equivalent weakening zones and enhancing the directional extension trend of main fractures. The scale of macro-fractures has the strongest correlation with the water breakthrough response. When the fracture scale increases to a certain proportion close to the well spacing, the seepage mode changes from “fracture + matrix cooperation” to “main-fracture-dominated short-circuit channel”. Based on this, a design and verification of a combined control scheme of “chemical profile control + cyclic water injection” was proposed and carried out in well groups with high water cut and strong channeling. Simulations show that this combination helps to weaken the flow conductivity of preferential channels and improve the uniformity of the flow field. This paper can provide technical support for the prevention, control, and early warning of water breakthrough and the regulation of main flow lines in the high-pressure water injection development of similar low-permeability reservoirs. Full article

Shale oil reservoirs are characterized by ultra-low matrix permeability. After large-scale hydraulic fracturing is applied to horizontal wells, fluid transport becomes highly complex, posing major challenges for accurately predicting production performance. In this study, a coupled multi-mechanism numerical model is developed for shale oil reservoirs with complex fracture networks. Using the Embedded Discrete Fracture Model (EDFM), the mass transport between the fracture and matrix and within the hydraulic fracture network can be accurately quantified. Based on core analysis and fluid experimental data, the dynamic evolution of rock and fluid properties is characterized by incorporating nanopore confinement effects, stress sensitivity, and threshold pressure gradient behavior. Numerical simulations are then conducted to investigate the impacts of multiple mechanisms, including nanopore confinement effects, stress sensitivity, and threshold pressure gradient, as well as their coupling effects on shale oil production. A field application is carried out using Well H1 in the Qingcheng shale oil reservoir. Simulation results indicate that nanopore confinement reduces bubble-point pressure, leading to a 3.60% increase in cumulative oil production and a noticeable reduction in the producing gas–oil ratio. Stress sensitivity causes a 2.68% decrease in cumulative oil production and suppresses gas production. The threshold pressure gradient exerts the strongest negative impact, resulting in an 8.01% reduction in cumulative oil production and a slight decrease in gas–oil ratio. When all mechanisms are simultaneously considered, strong nonlinear interactions emerge, yielding a 7.09% reduction in cumulative oil production—significantly different from the linear superposition of individual effects. These results demonstrate the necessity of accounting for multi-mechanism coupling to achieve reliable production forecasting in fractured shale oil reservoirs. Full article

This study systematically investigates the reaction characteristics of laminated shale oil reservoirs in the 7₃ sub-member of the Yanchang Formation, Heshui area, Ordos Basin, under exposure to CNI-I nanoviscous fracturing fluid. The reservoir matrix comprises 84.85% brittle minerals and 15.15% clay minerals. Fluid–rock interactions significantly dissolve calcite and dolomite, releasing Ca²⁺ and Mg²⁺ ions, while clay mineral reactions liberate substantial amounts of Na⁺. Post-reaction, fluid system stability is markedly reduced, elevating the risk of precipitate formation and pore-throat plugging. Exposure to fracturing fluid reduces the T₂ cutoff value of core samples from 3.29 ms to 1.72 ms, indicating a densification of the micro-pore-throat network and a decline in mobile fluid saturation, while fracture apertures exhibit widening. Based on empirical data, a discriminant criterion (R value) defined as the ratio of fracture aperture increment rate to pore-throat diameter reduction rate is established at 1.25, confirming that fracture propagation dominates over pore constriction. Dual-medium modeling yields a net permeability enhancement of 19.35%. Fluid–rock interactions induce overall degradation of rock mechanical properties with pronounced anisotropy: rock strength along the direction perpendicular to bedding declines by 37.546%, Young’s modulus decreases by 1.81%, and Poisson’s ratio increases by 0.02%—all significantly exceeding the degree of degradation parallel to bedding. This anisotropic mechanical degradation predisposes the near-wellbore region to shear slip and wall spalling, prompting the development of targeted engineering mitigation strategies. Full article

To address the pronounced productivity heterogeneity among different well intervals of coalbed methane (CBM) wells in the Weizhou Syncline, as well as the lack of quantitative clarity regarding the respective contributions of geological and engineering factors to well productivity, a systematic analysis of the main productivity-controlling factors of CBM wells was conducted based on geological data from producing wells, hydraulic fracturing treatment parameters, and production dynamic data in the study area. On this basis, a coupled coal reservoir–fracture numerical simulation model was established to quantitatively evaluate the response of CBM productivity to key geological parameters, including porosity, permeability, coal seam thickness, and Langmuir parameters, as well as fracture geometric and flow parameters. Furthermore, multiple machine learning methods were employed to rank and cross-validate the relative importance of factors influencing CBM well productivity. The results indicate that within the parameter ranges representative of the study area, coal seam thickness, permeability, and Langmuir pressure exert a dominant control on cumulative gas production, constituting the primary controlling factors for CBM well productivity. The number of fractures and porosity are secondary influencing factors, and, under the combined effects of multiple factors, fracture geometry, fracture flow parameters, and reservoir pressure make relatively limited contributions to well productivity. These findings provide a quantitative basis and methodological reference for favorable target selection, fracturing parameter optimization, and efficient development of CBM blocks in the Weizhou Syncline and other regions with similar geological conditions. Full article

Carbon dioxide (CO₂) emissions resulting from natural gas flaring are significant contributors to atmospheric greenhouse gases, posing a substantial risk to the Earth’s climate by exacerbating global warming. As a response, both the oil industry and government authorities are actively exploring cost-effective strategies to address this issue through carbon capture, utilization, and storage (CCUS), as well as reducing natural gas flaring and CO₂ leaks in the oil fields to mitigate the adverse consequences of greenhouse gas emissions. This study presents a numerical investigation of CO₂ utilization for enhanced oil recovery (EOR) and associated CO₂ retention in unconventional reservoirs, using the Bakken Formation as a representative case. A compositional reservoir model is developed to simulate CO₂ Huff-n-Puff (HnP) processes in a fractured horizontal well. The model incorporates dual-porosity and dual-permeability formulations, fluid–rock interactions, and an equation-of-state-based compositional framework to capture multiphase flow behavior. Key operational parameters, including reservoir pressure, injection rate, injection duration, and CO₂ molecular diffusion, are systematically evaluated to assess their impact on oil recovery and CO₂ retention. The results show that lower bottom-hole pressures enhance oil recovery through increased drawdown, while operating pressures near the minimum miscibility pressure (MMP) improve CO₂ solubility and overall retention. Extended injection durations and higher diffusion coefficients increase CO₂ dissolution in the oil phase but exhibit diminishing marginal benefits beyond an optimal injection time. The study quantifies residual and solubility trapping mechanisms during the operational timeframe of CO₂-EOR and provides mechanistic insights into optimizing CO₂-HnP performance in tight formations. The proposed framework establishes a technical basis for integrating CO₂-EOR with emission mitigation strategies in unconventional reservoirs. Full article

In recent years, oil and gas exploration in the Lower Cambrian of the central–northern Sichuan Basin, China, has demonstrated enormous resource potential. As a potential interval of high-quality hydrocarbon source rocks, the Canglangpu Formation of the Lower Cambrian remains underdeveloped in exploration and lacks in-depth research. Affected by tectonics, sedimentary environment, and diagenesis, the genetic mechanisms and genetic models of carbonate reservoirs in the Canglangpu Formation within the study area need further clarification. This study utilizes petrological characteristics of dolomite and geochemical data to clarify diagenetic fluids of different reservoir rocks and identifies the main controlling factors and development models of the reservoirs. The results show that the dolomites in Member 1 of the Canglangpu Formation (Cang-1 Member) in central–northern Sichuan are mainly classified into three types: silty–fine crystalline dolomite (D1), granular dolomite (D2), and residual-texture dolomite (D3). The reservoir spaces are dominated by intercrystalline pores, intergranular pores, and structural fractures. The porosity of the Cang-1 Member in the area is relatively low, with an average porosity of 5% or lower. The reservoir porosity average is 3.63%, belonging to low-porosity reservoirs. The permeability average is 2.94 × 10⁻³ mD. Analysis of different geochemical indicators indicates that the diagenetic fluids of the three dolomite types are mainly syndepositional seawater. D1 is formed by penecontemporaneous dolomitization, while both D2 and D3 are formed during the shallow-to-middle burial stage. The main controlling factors of dolomite reservoirs include sedimentary facies, diagenesis, and tectonic movement. This study clarifies the genesis and development model of dolomite reservoirs in the Cang-1 Member, aiming to provide reliable and valuable references for the exploration of dolomite reservoirs in the Canglangpu Formation of the Sichuan Basin. Full article