Search Results (73)

Supercritical CO₂ injection can mitigate depletion-induced deterioration of shale oil, but the relationship between laboratory-scale fluid-property changes and field-scale recovery remains insufficiently understood. This study integrates time-lapse produced-oil characterization, high-pressure PVT experiments, whole-hydrocarbon gas chromatography, and compositional reservoir simulation for the Mabei shale oil reservoir. From October 2023 to October 2025, the viscosity of dehydrated and degassed produced oil at 80 °C increased from 20.93 to 56.8 mPa·s, accompanied by depletion of light hydrocarbons and enrichment of heavy components, indicating progressive compositional deterioration during depletion. At 106.75 °C and 65.07 MPa, increasing the added CO₂/oil molar ratio from 0 to 80% reduced live-oil viscosity from 9.7841 to 3.8470 mPa·s and density from 0.8326 to 0.7897 g/cm³. Most viscosity, density, and oil-phase compositional changes occurred within the first 6 h in the closed, continuously stirred PVT cell. CO₂ contact preferentially transferred C3–C7 hydrocarbons out of the analyzed oil-rich phase, resulting in relative enrichment of C15–C37 components in the residual oil. The history-matched compositional model showed that CO₂ improved reservoir pressure maintenance and expanded low-viscosity regions primarily along fracture-connected flow paths, although the incremental response became limited between the 20 and 25% cases. Regional compositional analysis further demonstrated that strongly CO₂-contacted residual oil became heavier, whereas the produced oil was enriched in mobilized light and intermediate hydrocarbons. These results establish a consistent laboratory-to-field interpretation of CO₂-induced compositional redistribution and provide a basis for optimizing CO₂-assisted development in deeply buried shale oil reservoirs. CO₂-induced asphaltene precipitation/deposition and the associated permeability impairment were not measured or represented in the numerical model. Therefore, the reported recovery response reflects CO₂–oil property and transport effects in the absence of solid-phase formation damage. Full article

This study demonstrates that supercritical carbon dioxide phase-change fracturing technology can reduce acute pressure-related injury potential compared to conventional explosives in underwater reef clearance operations along the Yangtze River. Employing a stepwise “pipe test, numerical simulation and engineering application” framework, a novel rock–water–fish coupled HJC–Gruneisen elastoplastic model was established to simulate cross-medium shock wave attenuation processes. The supercritical CO₂ shock wave exhibits characteristics of “low peak overpressure (13% of equivalent explosives) and long duration (6–7 times longer than conventional explosives),” attenuating in water with a power-law index α = 0.717. A dual-parameter “resistance line (intact rock buffer between the fracturing tube and the rock–water interface)–water depth” correction model indicates that the resistance line reduces peak overpressure by 18.6%, while each 10 m increase in water depth enhances attenuation by 60.6%. The preliminary engineering critical safety threshold for 30 cm silver carp (indicated by swim bladder rupture) is 0.20 MPa. Based on the representative engineering scale of the Chaofu Waterway Regulation Project, characterized by water depths of approximately 6–16 m and a resistance-line-controlled buffer condition, a theoretical safety distance model R_safe was also derived. Under these engineering constraints, the application results indicate that the lethal zone was confined to 7.5–9.9 m, enabling precise lethal-injury-safe zoning. This work establishes a fish injury threshold and safety assessment system for supercritical CO₂ subaquatic fracturing, providing direct green guidelines for Yangtze River navigation projects. Full article

Strong heterogeneity in unconventional reservoirs leads to complex fracture propagation and challenges in quantitative stimulation evaluation. This study integrates true triaxial fracturing experiments, three-dimensional CT reconstruction, multi-field coupled numerical simulation, and multiple linear regression to investigate the fracture behavior of Gulong shale (Q1, Q9) and tight sandstone under supercritical carbon dioxide (SC-CO₂) fracturing. A fracture complexity index (FCI) that incorporates fractal dimension, spatial uniformity, and aperture distribution is proposed as a quantitative metric. The results show that SC-CO₂ significantly reduces breakdown pressure and increases fracture complexity compared to water. For Q9 shale, SC-CO₂ gives a breakdown pressure of 32.91 MPa (10.46% lower than water), a fractal dimension of 2.41, and an FCI of 8.92. In tight sandstone, the SC-CO₂ breakdown pressure is 34.12 MPa, whereas water increases it to 44.50 MPa; the fractal dimension and FCI are only 2.05 and 3.40, respectively, lower than those of shale fractured with water. Multiple linear regression quantifies contribution weights: lithological weak-plane development dominates fracture complexity (41.6%), far exceeding the brittleness index. The injection rate mainly controls stimulation scale: the damage area ratio rises from 1.79% to 2.90% when the rate increases from 10 to 40 mL/min. The horizontal stress difference is key to complexity enhancement: the fractal dimension increases from 1.9230 to 1.9901 as the stress difference rises from 0 to 4 MPa. The numerical simulations further reveal the coupled thermal-hydraulic-mechanical effects. The proposed FCI-based evaluation and regression models provide a quantitative framework for optimizing SC-CO₂ fracturing design in heterogeneous unconventional reservoirs. Full article

Reservoir stimulation through fracturing is essential for the commercial development of unconventional oil and gas resources. Supercritical CO₂ (scCO₂) combines liquid-like density with gas-like viscosity and compressibility, enabling efficient conversion of stored energy into shock waves and jet impacts. This study introduces an innovative scCO₂ shock fracturing technique, in which a downhole pressure-control valve rapidly releases compressed scCO₂ to generate transient shock pressures that induce rock fracture initiation and propagation. A series of scCO₂ shock fracturing experiments were conducted on sandstone and shale to evaluate the influence of different impact loads on both macroscopic and microscopic damage. Rock damage evolution was characterized using computed tomography (CT), nuclear magnetic resonance (NMR), mercury intrusion porosimetry (MIP), and quantitative analysis of fracture surface morphology. The results showed that increasing shock pressure enhanced fracture surface roughness, shear slip, and particle spalling in sandstone, producing rough tensile–shear fracture surfaces with a potential self-supporting tendency. NMR results indicated that sandstone mainly exhibited a single-peak T₂ response, and scCO₂ shock loading primarily affected pores and pore-fracture spaces larger than 0.08 µm. In contrast, shale showed a broader and more heterogeneous pore-fracture response, with preferential enlargement and connection of large pore-fracture spaces. The NMR-MIP-calibrated equivalent pore-fracture diameter distribution showed that scCO₂ shock fracturing mainly promoted pore-fracture spaces larger than 0.2 μm in shale; at 40 MPa, the volume of this pore-fracture range increased by approximately 6.75 times. However, the characteristic equivalent pore-fracture diameter decreased at 45 MPa, which is attributed to severe specimen fragmentation, fragment displacement, scCO₂ escape, and energy dissipation. These findings suggest that scCO₂ shock fracturing is a promising stimulation approach for enhancing macroscopic fracturing and microscopic pore-fracture reconstruction in unconventional reservoirs. Full article

China hosts abundant coal-rock gas (CRG) resources, which have become a critical unconventional natural gas contributor to national reserve expansion and production increment. Supercritical carbon dioxide (ScCO₂) fracturing is recognized as a green and efficient stimulation technology, exhibiting great potential for high-efficiency CRG exploitation. To clarify the effects and intrinsic mechanisms of ScCO₂ treatment on coal fracture initiation, propagation, and CRG recovery enhancement, true triaxial fracturing and CO₂-CH₄ displacement experiments were performed in combination with multiple microscopic characterization methods, including X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), and Scanning electron microscopy (SEM). The multi-scale experimental investigation systematically revealed the fracture development mechanism, permeability variation characteristics, and microstructural evolution of coal reservoirs under ScCO₂ interactions. The results indicate that ScCO₂ fracturing significantly lowers the coal fracture initiation threshold compared with conventional hydraulic fracturing, with the breakdown pressure reduced by 26.2% and the initiation time shortened by 37.5%. Such advantages facilitate coal fracture activation and the development of complex fracture networks. Long-term ScCO₂ soaking induces the dissolution of inorganic minerals (e.g., calcite, plagioclase, and clay minerals) and the extraction of inherent organic matter within coal matrices. The coupled hydro-chemical reactions reconstruct the coal pore structure, enlarge pore throats, and improve reservoir permeability, achieving a maximum permeability enhancement of approximately 1.6 times. Meanwhile, ScCO₂ displacement yields a prominent CRG recovery performance, with an ultimate gas recovery factor up to 93.85%. The CRG enhancement mechanism of ScCO₂ fracturing is comprehensively attributed to three core coupled effects. First, ScCO₂ dynamic fracturing generates intricate fracture networks, which greatly optimize reservoir seepage channels and flow space. Second, the ScCO₂–formation water–coal interaction modifies coal physical properties via mineral dissolution and organic matter extraction, thereby improving reservoir permeability. Third, the preferential adsorption of CO₂ over CH₄ triggers effective competitive adsorption and gas displacement, further promoting adsorbed methane desorption and elevating CRG recovery efficiency. This study provides a solid theoretical foundation for the field application of ScCO₂ fracturing technology and offers valuable insights into the green, efficient, and sustainable development of deep coal-rock gas resources. Full article

CO₂ is a promising fracturing fluid for tight reservoirs because it avoids water-phase damage and offers low viscosity, high diffusivity, and strong penetration into fine pore throats, but its pore-scale flow in pore-fracture systems remains difficult to evaluate because thermodynamic state, fractures, and mass transfer act together. In this study, a radial microfluidic model containing randomly distributed microfractures was used with a temperature- and pressure-controlled visualization platform to compare CO₂–oil and water–oil flow. Image segmentation and areal-fraction statistics quantified swept area and final fluid distribution. Gaseous CO₂ at ambient pressure and compressed-liquid CO₂ below the critical temperature differ substantially in density and viscosity, but both retain a discernible CO₂–oil interface and exhibit pressure-driven preferential-path flow. The gaseous case shows strong fracture guidance and fingering, whereas the compressed-liquid velocity series demonstrates increasingly rapid advancement and stronger channeling at excessive velocity. Under near-critical supercritical conditions (35 °C, 8 MPa), progressive oil-color fading ahead of the displacement front shows that dissolution participates while flow expands through matrix pores. Under higher-temperature supercritical conditions, disappearance of the sharp interface and continuous color attenuation identify dissolution-assisted diffusion as a significant transport mechanism and produce diffuse redistribution across the pore space. Water undergoes immiscible channelized displacement and remains capillary-trapped in small throats and low-permeability regions. The results identify three flow regimes: distinct-interface pressure-driven displacement, near-critical convection–dissolution coupling, and higher-temperature supercritical dissolution-assisted diffuse redistribution. Full article

Multilithologic interbedded reservoirs commonly consist of frequent alternations of fine-grained rocks, carbonate rocks, and soluble evaporite interlayers. The contrasts in mechanical properties and fluid–rock interactions tend to induce hydraulic-fracture deflection, height containment, and complex cross-interface propagation. To elucidate fracture initiation and cross-layer connectivity, a self-developed true-triaxial hydraulic fracturing simulation system was used to systematically investigate the effects of lithologic configuration, fracturing-fluid viscosity, injection rate, interface position, and injection-fluid type on fracture morphology and cross-interface behavior. Integrated analyses were performed by jointly interpreting injection-pressure responses and three-dimensional fracture reconstructions. The interactions between hydraulic fractures and lithologic interfaces/natural fractures can be categorized into three modes: (i) deflection with restricted growth, (ii) penetration without activation, and (iii) penetration with synchronous activation. Under water-based fluids, soluble evaporite interlayers predominantly develop dissolution-induced conductive pathways, which reduce stress concentration at the fracture tip and weaken interface strength, thereby promoting activation of interfaces or natural fractures. Moderately increasing viscosity and injection rate enhances cross-layer connectivity while lowering the probability of passive activation of interfaces/natural fractures; however, excessively high injection rates may induce fluid diversion and increase the likelihood of complex fracture growth. The injection-fluid type exerts a pronounced control on breakdown pressure and connectivity patterns: supercritical CO₂ yields the lowest initiation pressure, water-based fluids the highest, and alcohol-based fluids an intermediate response. In the pressure curves, attenuation of propagation pressure corresponds to enhanced cross-layer penetration, whereas a sustained pressure increase indicates dominant diversion or restricted propagation. These findings provide experimental support for parameter optimization and fracture-control design in multilithologic interbedded reservoirs in Southwest China and analogous geological settings. Full article

Supercritical carbon dioxide (SC-CO₂) fracturing has been recognized as an effective technology for developing unconventional oil and gas resources. The extent to which natural fractures can be activated is a critical factor controlling overall reservoir stimulation. A thorough understanding of the activation and propagation mechanisms of natural fractures during SC-CO₂ fracturing is therefore essential for elucidating fracture network evolution and optimizing stimulation strategies. In this work, a multiphysics-coupled numerical model for intersecting fracture propagation was developed using the phase-field method, incorporating formation pressure evolution and variations in CO₂ properties (density and viscosity). Based on this model, the influences of fracture approach angle, horizontal stress difference, injection temperature, and injection rate on fracture propagation patterns and pressure diffusion were systematically investigated. To quantitatively describe the stimulated reservoir volume, a “diffuse interface” was defined to represent the region affected by SC-CO₂ injection. The simulation results demonstrate that larger approach angles enhance the activation of natural fractures, with a 60° angle producing the maximum diffuse interface ratio of 72.5%. Although higher horizontal stress differences tend to suppress fracture activation, they promote plastic deformation at fracture tips, enlarging the diffuse interface to 86.72% at 15 MPa. Elevated injection temperatures further facilitate fracture propagation; as the temperature rises from 313.15 K to 403.15 K, the lateral fracture length increases from 2.8 cm to 3.7 cm, accompanied by continuous expansion of the diffuse interface. Under constant injection rate, a greater injection volume also enhances natural fracture activation and drives fractures to extend farther. These results provide theoretical insights for the design and optimization of SC-CO₂ fracturing in naturally fractured reservoirs. Full article

Supercritical carbon dioxide (SC-CO₂) fracturing has emerged as an environmentally friendly alternative to conventional water-based hydraulic fracturing; however, its inherently low viscosity restricts proppant-carrying efficiency and reduces fracture conductivity. To address this limitation, this study systematically investigates the rheological behavior and sand-carrying mechanisms of CO₂ dry fracturing fluid under various thermodynamic and compositional conditions. Rheological measurements were conducted to evaluate the effects of thickener concentration, temperature, and pressure on viscosity, while visualized experiments were performed to examine the influence of injection rate, sand ratio, thickener concentration, and temperature on proppant migration and deposition. A numerical model developed in Fluent was further employed to simulate the temporal evolution of proppant transport within the fracture. The results show that higher thickener concentrations and injection rates significantly enhance proppant transport distance and uniformity, whereas elevated temperature and sand ratio promote localized settling. The simulation results agree well with the experimental observations, validating the model’s reliability. This study elucidates the coupled effects of rheology and operating parameters on CO₂ dry fracturing behavior and provides theoretical and experimental guidance for optimizing CO₂-based fracturing fluids in low-permeability reservoirs. Full article

The Gulong shale oil reservoir is characterized by high clay content and strong heterogeneity, with substantial variations in mineral composition among different intervals. However, existing fracability evaluation methods for such continental shales remain inconsistent and often rely on oversimplified two-dimensional fracture descriptors, lacking a multi-parameter quantitative framework derived from three-dimensional fracture characterization. In this study, the Q1 and Q9 members of the Gulong shale oil were selected, and laboratory-scale hydraulic fracturing simulation experiments were conducted using supercritical carbon dioxide (SC-CO₂), liquid CO₂, and water as the fracturing media. Within a fractal-theory framework based on CT-derived three-dimensional reconstructions, a multi-scale evaluation index system was established by integrating fractal dimension, fracture density, and spatial connectivity. The experimental results demonstrate that fluid properties exert a decisive influence on rock failure behavior. Owing to its ultra-low viscosity and strong diffusivity, SC-CO₂ can significantly reduce formation breakdown pressure while effectively activating natural weak planes to generate a more complex fracture network. For the Q9 shale, the breakdown pressure under SC-CO₂ is reduced by 11.91% and 8.33% relative to water and liquid CO₂, respectively. Moreover, the fracture fractal dimension reaches 2.41 under SC-CO₂, which is markedly higher than the values obtained under liquid CO₂ (2.18) and water (2.12). Mineral composition and densely developed bedding are the key factors inducing fracture branching and deflection, whereas injection rate and an asymmetric stress field regulate the internal energy-release rate and stress path, thereby influencing fracture crossing capability and aperture evolution. Based on the experimental dataset, a fracture complexity index (FCI) evaluation model was developed: under SC-CO₂ fracturing, the FCI values are 8.92 for the Q9 member and 4.43 for the Q1 member, and the model predictions are in good agreement with physical observations. This work elucidates the failure mechanism of the Gulong shale under multi-field coupling and provides a theoretical basis for optimizing hydraulic fracturing and evaluating fracability in unconventional reservoirs through the proposed FCI-based assessment framework. Full article

Supercritical CO₂ gas explosion is an important technique for enhancing permeability in low-permeability coal seams, as it can improve gas drainage efficiency while avoiding the open-flame hazards of conventional explosion and the high water consumption associated with hydraulic fracturing. This study aims to reveal the crack propagation patterns and stress-wave dynamics under different hole configurations. Using LS-DYNA, fracture models were established for three configurations under supercritical CO₂ explosions: single-hole, symmetrical double-hole, and symmetrical double-hole with a control hole. The fracture processes were analyzed to investigate the effective fracture radius of single-hole explosions, the optimal spacing for symmetrical double-hole explosions, and the influence of control holes on crack development and connectivity. The simulation results indicate that the effective fracture radius of a single-hole explosion reaches up to 2.6 m under the modeled conditions. Compared with the single-hole gas explosion case, the symmetrical double-hole configuration with a spacing of 7 m significantly enhances fracture interaction and connectivity, resulting in an approximately 98% increase in the effective damaged area. Permeability enhancement was further quantified by introducing a damage–permeability mapping (k/k₀) based on the simulated damage factor, and the permeability-enhanced zone was evaluated using the criterion of k/k₀ ≥ 2. Full article

Enhanced geothermal systems (EGS) are a key technology for developing deep geothermal resources, yet they face significant challenges in constructing efficient thermal reservoirs within high-stress, high-strength, and low-permeability crystalline rock formations. Traditional hydraulic fracturing (HF) techniques encounter deep challenges in these environments, including excessively high fracturing pressures, limited fracture network patterns, and the risk of induced seismicity. This paper reviews the multi-scale thermal-mechanical mechanisms, fracture evolution patterns, and control strategies associated with thermal stimulation and permeability enhancement in the modification of deep geothermal reservoirs. Research indicates that thermally induced fracturing triggers intergranular and transgranular cracks at the microscopic scale due to mineral thermal expansion mismatches, which macroscopically manifests as nonlinear degradation of rock strength and modulus. The redistribution of the thermal elastic stress field significantly lowers the breakdown pressure, while matrix thermal contraction increases fracture aperture, leading to an exponential enhancement of permeability following a cubic law. However, the high confining pressure constraints, true triaxial stress anisotropy, and thermal short-circuiting risks present substantial suppression and challenges to the effectiveness of thermal stimulation in deep in situ environments. Different fracturing media, such as water, liquid nitrogen (LN₂), and supercritical CO₂, exhibit varying advantages in thermal stimulation efficiency due to their unique thermal-flow characteristics. Future research should focus on the thermal-mechanical coupling mechanisms under true triaxial stress conditions, and develop intelligent control strategies for permeability enhancement and thermal short-circuiting risk mitigation. This study synthesizes existing analyses and proposes potential engineering strategies for stimulating deep EGS reservoirs, offering significant strategic value for the development of geothermal energy as a baseload renewable resource. Full article

Rational design of high-performance viscosifying polymers is critical for enhancing supercritical CO₂ flooding efficiency in enhanced oil recovery (EOR). Traditional experimental and simulation approaches are limited in exploring the vast design space of polymer architecture, flexibility, and intermolecular interactions. This work presents an integrated machine learning (ML) and mesoscopic simulation framework using Dissipative Particle Dynamics (DPD) to accelerate the development of tailored polymeric thickeners. We systematically investigate synergistic effects of linear and branched polymer blends on solvent viscosity under Poiseuille flow, representative of flow in micro-fractures and pore throats. Key molecular descriptors are varied to generate a comprehensive rheological database. This data trains a deep neural network (DNN) surrogate model linking molecular parameters to macroscopic viscosity. The DNN is coupled with gradient ascent optimization for inverse design, enabling rapid virtual screening of thousands of formulations. A focused case study demonstrates that the star-like architectures with associative cores and semi-flexible backbones outperform linear analogs for supercritical CO₂ viscosity enhancement. The optimal candidate—a four-arm star polymer with linear side chains—was validated by DPD simulation. This multiscale “simulation-to-surrogate” methodology bridges molecular design with continuum-scale flow behavior, offering a transformative tool for formulating cost-effective, efficient, and sustainable next-generation EOR chemicals. Full article

Geothermal energy is a clean, renewable, and baseload-stable resource of strategic importance for carbon neutrality. Hot dry rock (HDR) reservoirs are characterized by high temperatures, great depths, and abundant reserves. However, their extremely low natural permeability requires artificial fracturing to establish effective heat exchange networks. Conventional hydraulic fracturing in enhanced geothermal systems (EGS) faces major challenges under HDR conditions, including excessive water consumption, strong water–rock interactions, and elevated induced seismicity risks, limiting its engineering applicability. Waterless or low-water fracturing technologies offer alternative stimulation pathways due to their distinctive physicochemical properties. Existing reviews have mainly addressed individual aspects, such as specific fracturing media or proppant transport, without systematically integrating recent advances in supercritical CO₂ fracturing, foam fracturing, liquid nitrogen fracturing, and hybrid-fluid fracturing technologies, or comprehensively evaluating their engineering implications. This review systematically analyzed the fracturing mechanisms, heat exchange performance, environmental risks, and HDR-specific engineering challenges of these technologies. Results indicate that waterless/low-water fracturing technologies enhance heat extraction efficiency by generating complex fracture networks while mitigating seismic and reservoir damage risks. However, large-scale application requires further advances in the high-temperature stability of fracturing media, material durability, multiphase flow control, and field validation. Full article

Natural gas represents a pivotal transitional clean energy resource, and biogenic coalbed methane (CBM) is ubiquitously distributed in coal reservoirs worldwide. In the context of carbon neutrality targets and the growing demand for large-scale commercial CBM exploitation, innovative technological solutions are urgently required. CBM bioengineering aims to substantially enhance CBM production by stimulating biomethane generation, promoting gas desorption, and improving reservoir permeability, while simultaneously enabling effective CO₂ sequestration. The potential for biomethane generation is largely governed by the intrinsic physicochemical characteristics of coal, including aromatic structures, maceral composition, and pore–fracture architecture. In addition, hydrogeological conditions—such as geothermal gradients, pH variability, and redox potential—play critical roles in regulating microbial functional gene expression and metabolic enzyme synthesis. Core pretreatment strategies in coalbed gas bioengineering can be broadly classified into approaches that enhance coal bioconversion potential and those that optimize functional microbial consortia. Electric fields and conductive materials can influence microbial community structure by enriching electroactive microorganisms and facilitating interspecies electron transfer. In addition to engineered conductive interventions, reservoir environmental conditions also play an important role in shaping methanogenic community structure. Experimental observations under reservoir-relevant CO₂ pressure and temperature conditions indicate that deep coalbed environments are associated with shifts in methanogenic community composition, including an increased relative abundance of hydrogenotrophic methanogens. These observations suggest that physicochemical conditions in deep coal seams may favor hydrogen-dependent CO₂ reduction pathways, thereby supporting hydrogenotrophic methanogenesis and contributing to biomethane generation. The integration of supercritical CO₂ with microbially acclimated stimulation fluids as an innovative reservoir fracturing strategy offers multiple advantages, including effective reservoir stimulation, permanent carbon sequestration, and sustainable biomethane generation. Future research should focus on modulating coal matrix bioavailability, optimizing microbial consortia, enhancing interspecies metabolic synergies, and advancing carbon fixation bioprocesses to facilitate the large-scale implementation of coalbed gas bioengineering systems. This review synthesizes recent advances in microbially mediated CBM enhancement and CO₂ sequestration, with a particular focus on field-scale evidence and the key challenges that must be addressed for large-scale implementation. Full article