The complex viscoelastic and shear-thinning behavior of slickwater fracturing fluids imposes competing effects on proppant transport, complicating the prediction of sand-carrying capacity and increasing the sand plugging risk. This study quantifies slickwater elasticity over a range of shear rates using the Weissenberg number (Wi) and establishes a fracture-scale shear-rate calculation method to estimate elastic energy at different flow velocities. The results show that: (1) the Wi strongly correlates with sand-carrying capacity, demonstrating its effectiveness in characterizing elastic-dominated transport behavior; (2) fracture experiment identify distinct settling-rate thresholds for slickwater systems with different polymer concentrations; (3) at these thresholds, fluids transporting equivalent proppant volumes exhibit identical elastic energies, indicating a the existence of a critical elastic-energy requirement for stable proppant suspension; (4) elastic-energy thresholds are established for three sand concentrations, allowing rapid prediction of sand-carrying capacity across slickwater systems with different viscosities; and (5) a field construction strategy derived from the predicted operating window is validated through field trials conducted both within and outside this window, with close agreement observed between the predicted and actual proppant-transport performance. This study provides a quantitative and practical framework for optimizing slickwater fracturing operations.

Shale formations are considered suitable reservoir and caprock candidates for CO2 geologic sequestration. Upon CO2 injection, fluid–rock reactions may weaken host rocks. Lacustrine shales, with rapid lithofacies shifts and pronounced compositional heterogeneity, warrant close investigation of the mechanisms of CO2–induced chemo-mechanical alteration. In this study, rock–fluid interaction experiments were conducted on three representative types of lacustrine shale – carbonate-rich, felsic, and mixed lithology– at 10 MPa and 40 °C. The results revealed that under supercritical CO2 (SCCO2)–water–shale interactions, carbonate minerals dissolved at significantly higher rates than feldspar, with the carbonate-rich shale showing the greatest carbonate mineral loss (18.53%). Scanning electron microscopy (SEM) imaging revealed marked increases in post-reaction surface porosity and pore connectivity across all samples, with the trend becoming more pronounced at higher carbonate content. Dolomite dissolution was found to initiate at high-energy defect sites and propagate inward into the grain interiors, offering new insight into early-stage weakening under SCCO2 exposure. Following reaction, all shale samples exhibited significant mechanical degradation: Young's modulus decreased by 14.3%–20.5%, hardness by 14.3%–25.0%, and fracture toughness by 11.8%–55.2%. Among them, the carbonate-rich shale exhibited the most substantial reductions, whereas the felsic shale – dominated by feldspar (albite, orthoclase) and quartz – showed the least deterioration. These findings suggest that, in the short term following CO2 injection, the evolution of physical properties in reservoir rocks is primarily governed by the initial carbonate mineral content, establishing a predictive link between mineralogy and short-term storage integrity.

In Offshore high-temperature/high-pressure reservoirs, a quantitative assessment of injectivity during gas re-injection and storage is challenging. A dedicated injection-capacity test setup suitable for HTHP conditions was developed. The Yinggehai–Qiongdongnan Basin A Gas Field HTHP reservoir injection interval was selected as the target. Saturated natural gas core samples were tested under simulated reservoir temperature and pressure for single-phase gas injection. The effects of permeability, fluid composition, reservoir temperature, and reservoir pressure on injectivity were analyzed using one-factor analysis and response surface methodology. Results show that within the test range, the injection index increases with permeability, CO2 content, and reservoir pressure, but decreases with reservoir temperature. The regression model indicates the relative influence as: reservoir pressure > permeability > reservoir temperature > fluid composition (R2 = 0.9947, Adj R2 = 0.9894). Increasing reservoir pressure from 5 to 15 MPa raised the injection index significantly (on the order of several times, depending on permeability and temperature within the tested ranges); raising CO2 content from 40% to 100% increased it by about 14%. The findings provide a basis for parametric optimization of multicomponent CO2 re-injection for the Yinggehai–Qiongdongnan Basin A field and similar offshore HTHP reservoirs.

To investigate the fracture initiation and propagation behavior of fractures in tight sandstone under the supercritical CO2 (SCCO2) shock fracturing, laboratory fracturing experiments were conducted using a true-triaxial-like SCCO2 shock fracturing system. Computed tomography (CT) scanning and three-dimensional fracture reconstruction were employed to elucidate the effects of shock pressure, pore pressure, and in-situ stress on fracture characteristics. In addition, nuclear magnetic resonance (NMR) transverse relaxation time spectra were used to assess the internal damage induced by SCCO2 shock fracturing. The results indicate that, compared with conventional hydraulic fracturing and SCCO2 quasi-static fracturing, SCCO2 shock fracturing facilitates multidirectional fracture initiation and the formation of complex fracture networks. Increasing shock pressure more readily activates bedding-plane weaknesses, with main and subsidiary fractures interweaving into a dense fracture network. Under the same impulse intensity, elevated pore pressure reduces the effective normal stress and alters stress-wave scattering paths, thereby inducing more branch fractures and enhancing fracture complexity. An increase in differential in-situ stress promotes fracture propagation along the direction of the maximum principal stress, reduces branching, and simplifies fracture morphology. With increasing SCCO2 shock pressure, pore volume and connectivity generally increase: small-to-medium pores primarily respond through increased number and enhanced connectivity; when the shock pressure rises to 40-45 MPa, crack coalescence generates larger pores and fissures, which play a dominant role in improving flow pathways and effective storage space, ultimately forming a multiscale pore-fracture network.

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.

Using foam as the jet medium can significantly reduce water consumption while mitigating dust pollution generated by abrasive air jets. In this study, to reveal the flow field characteristics of abrasive foam jets, a numerical model is established, using the discrete phase model to describe the motion of abrasive particles in the jet. The macroscopic characteristics of the flow field in abrasive foam jets are illustrated. The motion characteristics of both the fluid and abrasive are analyzed. The results indicate that low-density abrasive foam jets exhibit the highest jet velocity and optimal particle acceleration effects. Compared with an abrasive water jet, the fluid velocity and abrasive velocity of an abrasive foam jet are increased by 14.53% and 17.93%, respectively. The acceleration efficiency of foam on abrasives reaches as high as 0.97. The abrasive transport trajectory is very complex. Increasing the nozzle pressure drop, reducing the mass flow rate of the abrasive, and increasing the foam quality can enhance the velocity of both the fluid and abrasive particles. Foam demonstrates superior acceleration effects on low-density particles. For an abrasive density of 1060 kg/m3, the abrasive velocity is 224.72 m/s. These findings provide a theoretical foundation for advancing the application of abrasive foam jets.

Fractures in rock masses are a central focus in research areas such as unconventional energy extraction, nuclear waste disposal, and carbon sequestration. Laboratory investigations of fracture parameters are essential for optimizing field operations. In recent years, CT scanning has emerged as a widely adopted non-destructive inspection technique. However, existing methods for post-processing CT scan data face persistent challenges in achieving high accuracy and efficiency. To address these challenges, we propose a novel Python-based post-processing framework that integrates a slice-by-slice thinning algorithm, local thickness computation, and point cloud data processing techniques. This framework enables precise characterization of fractured digital rocks by quantifying fracture width distribution and fracture surface orientation, alongside standard structural evaluation metrics such as the fractal dimension, volume ratio, and the H-index. Its feasibility, accuracy, and flexibility are validated through analyses of diverse fracturing samples, including fluid-fractured samples, shear-induced fracture samples, and samples containing multiple secondary fractures. PROGRAM SUMMARY Program title:Digifrac CPC Library link to program files: https://10.17632/hcynpd9hf4.1 Developer’s repository link: https://github.com/BinWang0213/DigiFrac Licensing provisions: GPLv3 Programming language: Python Nature of problem: This program quantitatively calculates the three-dimensional structural parameters of fracture networks in rocks based on CT scan data. In addition to basic parameters such as fractal dimension, fracture volume, and surface area, it also provides accurate determinations of fracture width distribution and fracture surface orientation. Solution method: The random forest algorithm is employed to improve the accuracy of CT data segmentation, while a slice-by-slice thinning algorithm is used to extract the fracture medial surface, thereby enhancing the precision of fracture aperture distribution calculations. Furthermore, the three-dimensional orientation distribution of fractures is determined from the 3D point cloud data of the extracted medial surface.

The rheology of high-temperature and high-pressure oil-based drilling fluids is critical for managed pressure drilling in deep and ultra-deep wells. This study investigates the rheological behavior of high-temperature and high-pressure oil-based drilling fluid from the Tarim Basin under conditions of 60–160 °C and 60–140 MPa. Three oil-based drilling fluids with densities of 1.8, 2.0, and 2.2 g/cm3 were tested under 60 temperature–pressure–density conditions, and six rotational speeds were selected for each condition, resulting in 360 rheological data points for model evaluation and parameter prediction. Rheological models, including Bingham, Power law, Casson, and Herschel–Bulkley, were established and evaluated to identify the optimal model. An improved high-temperature and high-pressure rheological parameter prediction model was proposed. Unlike previous correlations mainly developed for Bingham rheological parameters, the proposed model directly predicts the three Herschel–Bulkley parameters and introduces a quadratic pressure term to describe the nonlinear pressure dependence under high-temperature and high-pressure conditions. The results indicate that the Herschel–Bulkley model best characterizes the fluid’s rheological properties, with an average relative error of 2.64% in shear stress prediction and superior regression accuracy compared to Landmark WellPlan software, achieving an average error of 2.049%. Density significantly affects yield stress and consistency coefficient, while temperature and pressure have minimal impact on the flow index. Rheological parameters exhibit opposite trends under varying densities. The improved Herschel–Bulkley model enables precise rheological parameter predictions within the tested range, with average prediction accuracies of 81.40% for yield stress, 97.90% for flow index, and 87.05% for consistency coefficient, meeting engineering requirements. These findings provide theoretical support for managed pressure drilling in deep and ultra-deep wells.

Sensitive reservoirs with high clay content commonly suffer from severe water/salt sensitivity and water-lock damage during conventional water-based hydraulic fracturing, which reduces fracture conductivity and post-stimulation performance. To address this issue, we propose a CO2 quasi-dry fracturing approach that combines the low-damage feature of CO2 dry fracturing with the proppant-carrying capacity of a water-based system under atmospheric sand mixing conditions. Taking Well S in the Lulehe Formation (Qaidam Basin) as a case study, we conducted reservoir sensitivity evaluation, laboratory fluid/rock interaction tests, and a field trial with microseismic monitoring. The reservoir is dominated by water and salt sensitivity, indicating high risk of damage when using conventional fluids. Laboratory results show that the CO2 quasi-dry system improves swelling inhibition and enhances core structural stability compared with fresh water. Field implementation was operationally stable and generated an effective stimulated reservoir volume on the order of 10(5) m(3); post-fracturing oil production increased relative to nearby offset wells with a high flowback ratio. The results demonstrate that CO2 quasi-dry fracturing provides an effective low-damage stimulation option for strongly sensitive reservoirs and can be transferred to similar formations.

Supercritical CO2 (SC-CO2) fracturing is an effective method to enhance production from unconventional reservoirs and supports carbon capture, utilization, and storage (CCUS). Owing to its low viscosity and interfacial tension, SC-CO2 readily penetrates micro-scale natural fractures and generates complex secondary fracture networks. Using micron-sized proppants with SC-CO2 promotes better settling and activation of secondary fractures, thereby improving the stimulated reservoir volume. However, the transport and placement behavior of micro-proppants in 3D rough secondary fractures under SC-CO2 conditions remains unclear. A particle-scale multiphase flow model was developed to simulate SC-CO2 micro-proppant transport in rough fractures. The 3D fracture models were validated against high-temperature and high-pressure SC-CO2 transport experiments. Dimensionless parameters, including Reynolds number, dimensionless pressure drop, and effective settlement rate, were introduced to evaluate transport efficiency. The effects of injection flow rate, pressure, temperature, and particle concentration were systematically analyzed. Increasing flow rate (Re = 61.7-308.7) reduced the settlement rate by up to 89.7%, indicating enhanced transport capacity. Higher injection pressure (19-29 MPa) decreased the settlement rate by 18%-25% due to increased SC-CO2 viscosity and density, while elevated temperature (65-105 degrees degrees C degrees C) increased the rate by up to 118% owing to reduced viscosity. Higher particle concentration (0.38%-2%) promoted particle accumulation and fluctuations in pressure drop. Overall, injection flow rate is the dominant factor influencing micro-proppant transport and placement. This study provides insights into optimizing SC-CO2 fracturing and understanding micro-proppant transport mechanisms.

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 degrees 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.

Carbon dioxide (CO2) exhibits strong compressibility and expansion behavior, which enables efficient pressure transmission in tight reservoirs. This property promotes reservoir pressure, improves fracturing fluid flowback, slows production decline, and finally enhances oil recovery. CO2 pre-pad energized fracturing has been widely adopted in shale oil development. However, its theoretical basis and controlling mechanisms are still not well understood. In this study, the energization mechanism of CO2 pre-pad energized fracturing in shale oil reservoirs was investigated. The energization performance was quantitatively evaluated by the pressure coefficient and the energy replenishment range under different geological conditions and operational parameters. The results indicate that pre-injected CO2 increases pressure and reduces effective stress. Part of the CO2 can be permanently stored in the reservoir. The CO2 injection volume is identified as the dominant controlling factor. Increasing the CO2 injection volume expands the energy replenishment range to a maximum of 12,470 m(2). Lower injection rates favor CO2 penetration and diffusion, leading to a wider energy replenishment range. An energy replenishment range exceeding 7000 m(2) can be achieved when the CO2 injection rate is less than 4 m(3)/min. Lower reservoir permeability restricts the energization region, whereas longer soaking time allows pressure to diffuse more fully and enhances CO2-oil interaction. The results provide a basis for further optimization and future studies for the CO2 pre-pad energized fracturing in shale oil reservoirs.

Physical-geochemical coupling between wellbore and reservoir fundamentally governs transient flow dynamics during subsurface energy development and storage. Clarifying the physical and chemical interactions in various wellbore-reservoir coupling simulation scenarios enhances understanding of subsurface dynamic processes while ensuring development safety and efficiency. This paper reviews advancements in transient multiphase thermohydraulic coupling (TH), thermo-hydro-mechanical coupling (THM), and thermo-hydro-mechanical-chemical coupling (THMC) approaches, along with their application characteristics across diverse geo-energy scenarios. This review provides systematic insights for the impact of various simulation tools and coupling schemes on describing physical-geochemical effects in the near-wellbore area, and offers theoretical support and technical references for subsurface energy development under complex geological conditions.

In the global effort to reduce greenhouse gas emissions, Carbon Capture, Utilization, and Storage (CCUS) has become a key strategy. Gas injection well, as a critical component of the CCUS technology, require effective monitoring and precise control during their operation. However, traditional wired communication methods face numerous challenges in the application of gas injection well. Pressure wave wireless communication technology offers a new solution to address these issues. To tackle this problem, this study investigates pressure wave wireless communication in CO2 injection well by establishing an OLGA-based wellbore model. Compared with H2O injection well, the propagation speed of pressure waves in CO2 injection well is about 53

To address two main challenges, i.e. insufficient proppant support in hydraulic fractures and limited oil mobilization from the matrix, in tight oil reservoirs, this study proposes a concept of “fracturing fluid-rock matrix synergistic modification” to formulate a modified slickwater system based on nano-droplets. This nano-modified slickwater system is investigated for its synergistic modification mechanisms through experimental techniques including rheological measurements, visualized proppant transport tests, three-phase interfacial atomic force microscopy measurements, wettability characterization, and core flood experiments. The results indicate that the nano-modified slickwater system exhibits a low viscosity and high elasticity under high shear rates, which facilitates friction reduction and fracture propagation, and exhibits a sharp increase of viscosity while maintaining the high elasticity through restoring the microscopic association structure under low shear rates, which enhances proppant transport by fracturing fluid in distal and branched fractures. This system releases nano-droplets after fluid breaking, which then migrate to deep matrix pores, altering the matrix wettability and enhancing oil recovery through imbibition. It is concluded that the nano-modified slickwater system formulated following the concept of “fracturing fluid-rock matrix synergistic modification” is adaptive to working conditions, and it can simultaneously expand the volume of conductive fracture-network and enhance matrix productivity, enabling fracturing fluids to “enter, migrate, and modify” tight reservoir matrix economically and effectively. The proposed system offers a reliable technical foundation for efficient development of tight oil reservoirs.

A geomechanical model that comprehensively considers well placement schemes and operational parameters was established in response to poor reservoir fracturing results and low efficiency in oil and gas development due to depleted formation energy in mature light oil fields. Simulation studies were conducted to elucidate the initiation and propagation characteristics of fractures in well group energy storage fracturing (WGESF), and a method for optimizing the well group energy storage fracturing process was developed. The research results indicate that: (1) When the stress difference is equal to 3~4 MPa, the fracture propagation consistently develops into symmetric dual-wing configurations; (2) Under high Young's modulus conditions, hydraulic fractures predominantly manifest as asymmetric dual-wing fractures or single-wing branch fractures.; (3) Under high tensile strength conditions, the formation of symmetric dual-wing fractures in injection wells is facilitated; (4) With the increase of stress difference, Young's modulus, and tensile strength, re-fracturing fractures tend to propagate along the maximum horizontal principal stress direction.

Supercritical CO2 fracturing is a reservoir stimulation technology with broad application prospects, and the effective placement of proppant in the rough fracture network produced by fracturing is the key to determining the stimulation effect of the operating wells. In this study, an experimentally validated computational fluid dynamics-discrete element method (CFD-DEM) model is used to simulate supercritical CO2 transport proppant in a rough fracture network. The results show that in rough fracture networks, the use of small-sized proppant (0.2 mm) or low-density proppant (1250 kg/m3) significantly increases the amount of proppant within branching fractures, as well as the transport distance. Combination injection gives better proppant dune placement compared to single type of proppant injection, where the pumping schedule of larger and then smaller proppant sizes is effective in increasing propping of branching fracture. The efficacy of pulse injection in enhancing proppant transport distance using supercritical CO2 is significantly constrained by the absence of suitable fiber materials.

The Mahu conglomerate reservoir has low effective permeability, making it challenging to improve oil recovery. CO2 pre-pad energized fracturing technology can enhance oil recovery by improving the reservoir's physical properties and oil seepage capacity. However, the fracture propagation mechanism in the conglomerate reservoir and the dynamics of CO2 injection and backflow are not well understood. This study combines experimental testing, numerical simulation, and theoretical analysis to investigate the mechanisms of CO2 pre-pad energized fracturing in the Mahu reservoir and optimize construction parameters for effective development. The results show that CO2 aqueous solution dissolves acid-soluble minerals and weak cement more effectively than it precipitates clay particles, thereby improving the reservoir's porosity and permeability. With a longer reaction time between CO2 solution and reservoir core, carbonic acid generation saturates, and the dissolution of soluble matter completes, leading to a decrease in porosity and permeability increase rates. Using the optimized fracturing mode-fracturing fluid + CO2 + fracturing fluid the optimal fracture half-length is 150 m, and the optimal CO2 injection volume is 100 tons per fracture. Field tests indicated that, compared to conventional wells, the average daily oil production of the test wells increased by 18.1%, and cumulative oil production increased by 22.1%. These results offer guidance for optimizing CO2 pre-pad energized fracturing in similar conglomerate reservoirs.

The unique lithology of tight sandy conglomerate leads to severe microscopic heterogeneity, which significantly affects CO2 flooding. In this paper, four lithologies were classified according to gravel size and content, then CO2 flooding experiments were conducted to analyze the impacts of CO2 injection rate, miscible degree, reservoir temperature, and rock lithology. The results show that during initial stage, dissolved gas flooding governs efficient oil production, CO2 storage is mainly free storage in pores and dissolved storage in oil. Following breakthrough, CO2 sweep expands significantly, leading to sustained oil production. Concurrently, dissolved storage decreases while free storage increases. After channeling, oil production rate and storage efficiency decays rapidly. Besides, increasing CO2 injection rate enhances displacement effect, with the highest oil recovery and CO2 storage factor of 37.96 % and 10.7 % at 0.1 mL min-1. However, excessive injection rate induces premature breakthrough and exacerbates channeling, diminishing displacement efficiency. Under miscible condition, extraction of light hydrocarbons by CO2 enhances, increasing oil recovery and CO2 storage factor by 17.7 % and 3.28 %. Increasing reservoir temperature enhances oil fluidity, improving oil recovery factor by 10.93 %, but CO2 storage diminishes. The lithology difference of tight sandy conglomerate induces severe microscopic heterogeneity, diminishing displacement efficiency. As gravel size and content increase, core's permeability increases but porosity decreases, leading to limited oil supply. And compounded by dual tortuosity in such cores, fluid migration pathways become increasingly tortuous, further exacerbating channeling. Therefore, compared with gravel-bearing coarse sandstone, oil recovery and CO2 storage factor in sandy coarse conglomerate decrease by 7.41 % and 4.49 %.