Search Results (21)

To address critical limitations of ultra-low viscosity supercritical CO₂ fracturing fluids, including excessive fluid loss and inadequate proppant transport capacity, a series of thickeners designed to significantly enhance CO₂ viscosity were synthesized. Initially, FT-IR and ¹H NMR characterization confirmed successful chemical reactions and incorporation of both solvation-enhancing and -thickening functional groups. Subsequently, dissolution and thickening performance were evaluated using a custom-designed high-pressure vessel featuring visual observation capability, in-line viscosity monitoring, and high-temperature operation. All thickener systems exhibited excellent solubility, with 5 wt% loading elevating CO₂ viscosity to 3.68 mPa·s. Ultimately, molecular simulations performed in Materials Studio elucidated the mechanistic basis, electrostatic potential (ESP) mapping, cohesive energy density analysis, intermolecular interaction energy, and radial distribution function comparisons. These computational approaches revealed dissolution and thickening mechanisms of polymeric thickeners in CO₂. Full article

Supercritical carbon dioxide (Sc-CO₂) thermal shock fracturing emerges as an innovative rock fragmentation technology combining environmental sustainability with operational efficiency. This study establishes a thermo-hydro-mechanical coupled model to elucidate how in situ stress magnitude and anisotropy critically govern damage progression and fluid dynamics during Sc-CO₂ thermal shock fracturing. Key novel findings reveal the following: (1) The fracturing mechanism integrates transient hydrodynamic shock with quasi-static pressure loading, generating characteristic bimodal pressure curves where secondary peak amplification specifically indicates inhibited interwell fracture coalescence under anisotropic stress configurations. (2) Fracture paths undergo spatiotemporal reorientation—initial propagation aligns with in situ stress orientation, while subsequent growth follows thermal shock-induced principal stress trajectories. (3) Stress heterogeneity modulates fracture network complexity through confinement effects: elevated normal stresses perpendicular to fracture planes reduce pressure gradients (compared to isotropic conditions) and delay crack initiation, yet sustain higher pressure plateaus by constraining fracture connectivity despite fluid leakage. Numerical simulations systematically demonstrate that stress anisotropy plays a dual role—enhancing peak pressures while limiting fracture network development. This demonstrates the dual roles of the technology in enhancing environmental sustainability through waterless operations and reducing carbon footprint. Full article

Hydraulic fracturing is a widely employed technique for stimulating unconventional shale gas reservoirs. Supercritical CO₂ (SC-CO₂) has emerged as a promising fracturing fluid due to its unique physicochemical properties. Existing theoretical models for calculating breakdown pressure often fail to accurately predict the outcomes of SC-CO₂ fracturing due to the complex, nonlinear interactions among multiple influencing factors. In this study, we conducted fracturing experiments considering parameters such as fluid type, flow rate, temperature, and confining pressure. A fully connected neural network was then employed to predict breakdown pressure, integrating both our experimental data and published datasets. This approach facilitated the identification of key influencing factors and allowed us to quantify their relative importance. The results demonstrate that SC-CO₂ significantly reduces breakdown pressure compared to traditional water-based fluids. Additionally, breakdown pressure increases with higher confining pressures and elevated flow rates, while it decreases with increasing temperatures. The multi-layer neural network achieved high predictive accuracy, with R, RMSE, and MAE values of 0.9482 (0.9123), 3.424 (4.421), and 2.283 (3.188) for training (testing) sets, respectively. Sensitivity analysis identified fracturing fluid type and tensile strength as the most influential factors, contributing 28.31% and 21.39%, respectively, followed by flow rate at 12.34%. Our findings provide valuable insights into the optimization of fracturing parameters, offering a promising approach to better predict breakdown pressure in SC-CO₂ fracturing operations. Full article

With the introduction of China’s “dual carbon” goals, CO₂ is increasingly valued as a resource and is being utilized in unconventional oil and gas development. Its application in fracturing operations shows promising prospects, enabling efficient extraction of oil and gas while facilitating carbon sequestration. The process of reservoir stimulation using CO₂ fracturing is complex, involving coupled phenomena such as temperature variations, fluid behavior, and rock mechanics. Currently, numerous scholars have conducted fracturing experiments to explore the mechanisms of supercritical CO₂ (SC-CO₂)-induced fractures in relatively deep formations. However, there is relatively limited numerical simulation research on the coupling processes involved in CO₂ fracturing. Some simulation studies have simplified reservoir and operational parameters, indicating a need for further exploration into the multi-field coupling mechanisms of CO₂ fracturing. In this study, a coupled thermo-hydro-mechanical fracturing model considering the CO₂ properties and heat transfer characteristics was developed using the phase field method. The multi-field coupling characteristics of hydraulic fracturing with water and SC-CO₂ are compared, and the effects of different geological parameters (such as in situ stress) and engineering parameters (such as the injection rate) on fracturing performance in tight reservoirs were investigated. The simulation results validate the conclusion that CO₂, especially in its supercritical state, effectively reduces reservoir breakdown pressures and induces relatively complex fractures compared with water fracturing. During CO₂ injection, heat transfer between the fluid and rock creates a thermal transition zone near the wellbore, beyond which the reservoir temperature remains relatively unchanged. Larger temperature differentials between the injected CO₂ fluid and the formation result in more complicated fracture patterns due to thermal stress effects. With a CO₂ injection, the displacement field of the formation deviated asymmetrically and changed abruptly when the fracture formed. As the in situ stress difference increased, the morphology of the SC-CO₂-induced fractures tended to become simpler, and conversely, the fracture presented a complicated distribution. Furthermore, with an increasing injection rate of CO₂, the fractures exhibited a greater width and extended over longer distances, which are more conducive to reservoir volumetric enhancement. The findings of this study validate the authenticity of previous experimental results, and it analyzed fracture evolution through the multi-field coupling process of CO₂ fracturing, thereby enhancing theoretical understanding and laying a foundational basis for the application of this technology. Full article

The rapid expansion of reservoir fractures and the enlargement of the area affected by working fluids can be accomplished solely through fracturing operations of oilfield working fluids in geological reservoirs. Supercritical CO₂ is regarded as an ideal medium for shale reservoir fracturing owing to the inherent advantages of environmental friendliness, excellent capacity, and high stability. However, CO₂ gas channeling and complex propagation of fractures in shale reservoirs hindered the commercialization of Supercritical CO₂ fracturing technology. Herein, a simulation method for Supercritical CO₂ fracturing based on cohesive force units is proposed to investigate the crack propagation behavior of CO₂ fracturing technology under different construction parameters. Furthermore, the shale fracture propagation mechanism of Supercritical CO₂ fracturing fluid is elucidated. The results indicated that the propagation ability of reservoir fractures and Mises stress are influenced by the fracturing fluid viscosity, fracturing azimuth angle, and reservoir conditions (temperature and pressure). An azimuth angle of 30° can achieve a maximum Mises stress of 3.213 × 10⁷ Pa and a crack width of 1.669 × 10⁻² m. However, an apparent viscosity of 14 × 10⁻⁶ Pa·s results in a crack width of only 2.227 × 10⁻² m and a maximum Mises stress of 4.459 × 10⁷ Pa. Additionally, a weaker fracture propagation ability and reduced Mises stress are exhibited at the fracturing fluid injection rate. As a straightforward model to synergistically investigate the fracture propagation behavior of shale reservoirs, this work provides new insights and strategies for the efficient extraction of shale reservoirs. Full article

With the characteristics of low fracturing pressure, little damage to the reservoirs, and assuming the role of carbon storage, supercritical carbon dioxide (SC-CO₂) fracturing is suitable for the development of unconventional oil and gas resources. Based on the tensile failure mechanism of rocks, this paper establishes a thermal-fluid-solid coupling initiation pressure model for SC-CO₂ fracturing. Using this model, the changes in formation temperature and pore pressure near a wellbore caused by invasion of CO₂ into the formation are analyzed, as well as the impact of these changes on the tangential stress of reservoir rocks. The field data of SC-CO₂ fracturing in a sandstone gas well are used to validate the reliability of the model. The results show that SC-CO₂ fracturing can significantly reduce the initiation pressure, which decreases with the increase in fracturing fluid injection rate. The minimum value of tangential stress is located at the well wall, and the direction of tangential stress caused by formation temperature and pore pressure is opposite, with the former greater than the latter. The increase in Poisson’s ratio, the increase in elastic modulus and the decrease in bottom hole temperature can reduce the initial fracturing pressure of the reservoir. The computation model established in this paper provides an effective method for understanding the reservoir fracturing mechanism under the condition of SC-CO₂ invasion. Full article

Supercritical CO₂ fracturing has unique advantages for improving unconventional reservoir recovery. Supercritical CO₂ can penetrate deep into the reservoir and increase reservoir reform volume, and it is less damaging to reservoir and easy to flow back. However, when the supercritical CO₂ flows as the sand-carrying fluid in the fracture, the settlement of the proppant is still worth studying. Based on the study of supercritical CO₂ density and viscosity properties, assuming that the reservoir has been pressed out of the vertical crack by injecting prepad fluid, the proppant characteristics in sand-carrying fluid under different conditions were studied by numerical simulation. After the analysis, the proppant accumulation and backflow will occur at the end of the crack. Large sand diameters, high fluid flow rates, high sand concentrations, high reservoir temperatures, and low reservoir pressures can help to shorten deposition time, and the small particle size, high fluid flow rate, low sand concentration, low reservoir temperature, and high reservoir pressure can help increase the uniformity of sand deposition. Shortening the sand deposition time can help to complete the fracturing efficiently, and increasing the deposition uniformity can improve the fracture conductivity. This article has studied the proppant settling and crack formation characteristics. It is hoped that this study can provide theoretical support for field fracturing and provide theoretical assistance to relevant researchers. Full article

Multiphase flow properties of fractures are important in engineering applications such as hydraulic fracturing, evaluating the sealing capacity of caprocks, and the productivity of hydrocarbon-bearing tight rocks. Due to the computational requirements of high fidelity simulations, investigations of flow and transport through fractures typically rely on simplified assumptions applied to large fracture networks. These simplifications ignore the effect of pore-scale capillary phenomena and 3D realistic fracture morphology (for instance, tortuosity, contact points, and crevasses) that lead to macro-scale effective transport properties. The effect of these properties can be studied through lattice Boltzmann simulations, but they require high performance computing clusters and are generally limited in their domain size. In this work, we develop a technique to represent 3D fracture geometries and fluid distributions in 2D without losing any information. Using this innovative approach, we present a specialized machine learning model which only requires a few simulations for training but still accurately predicts fluid flow through 3D fractures. We demonstrate our technique using simulations of a water filled fracture being displaced by supercritical CO${}_2$. By generating highly efficient simulations of micro-scale multiphase flow in fractures, we hope to investigate a wide range of fracture types and generalize our method to be incorporated into larger discrete fracture network simulations. Full article

Supercritical carbon dioxide (SC-CO₂) fracturing has been used in developing low permeability and water-sensitive reservoirs in recent years, which is expected to become a new generation of unconventional reservoir fracturing fluid. However, the water-rock interaction characteristics of various lithology shales under SC-CO₂ circumstance and its influence on fracturing effect still need to be investigated. Two kinds of shale samples from C7 and S1 formations of the Ordos Basin were treated by SC-CO₂ with formation water. The aims of the research are to determine the processes taking place in shale reservoir when considering minerals components transformation, porosity/permeability variation, and micro pore-structure change during the SC-CO₂ fracturing. Static and dynamic SC-CO₂ immersed experiments were conducted and the scanning of electron microscopy (SEM) and X-ray diffraction (XRD) was employed to analyze the surface morphology and newly formed minerals. Helium porosimeter, the ultralow permeability meter, and the CT scanner are employed to record the alternation of physical parameters during SC-CO₂ dynamic injection. The experimental results show that the C7 samples are rich of chlorite and easily reacting with SC-CO₂ saturated formation water to form new minerals, but the S1 samples are insensitive to aqueous SC-CO₂. The minimum value of permeability and porosity of the C7 cores appear at 24h in the long-interval experiment, but in the short-interval dynamic experiment, the minimum values move ahead to 12h. The optimal flowback time for the C7 reservoir is before 12 h or after 24 h. The high-pressure SC-CO₂ flooding pushes the new forming minerals particles to migrate to the outlet side and block the pore throat. For the S1 core results, the porosity and permeability change little in both short and long interval experiments. There is no strict flow-back time requirement for S1 reservoir during SC-CO₂ fracturing. This study is significance for the efficient application of SC-CO₂ in the exploitation of shale oil reservoirs. Full article

Supercritical carbon dioxide (SC-CO₂) is suitable to extract low-polar organics and to assist in the dissolution of pores and fractures in shale. In this work, we investigate the effect of temperature on the structure of five shale samples via high pressure reaction assisted with SC-CO₂. Shale samples were analyzed using X-ray diffraction, field emission scanning electron microscopy, and ImageJ software. Due to the extraction of CO₂, after Sc-CO₂ treatment, carbonate and clay content decreased, while quartz and plagioclase increased slightly, which improved gas and oil flow in microscopic pores and shale cracks. Shale samples showed an increase in surface fracture area as experimental temperature increased. Since Sc-CO₂ fluid density and solubility increase with temperature, more organics can be extracted from shale pores and fractures, resulting in newly formed pores and fractures. As a result, the threshold temperature for shale high-temperature Sc-CO₂ cracking was confirmed to be 400 °C, and the fracture area increased by more than 45% at this temperature. Based on the findings of this study, Sc-CO₂ technology can be used to potentially recover low-maturity shale oil efficiently. Full article

In this study, we innovatively use sulphoaluminate cement slurry and its additives as a fracturing fluid system for supercritical CO₂ graphene-permeable cement stone (referred to hereafter as the SCGPCS) fracturing without sand. Utilizing small fluid volumes, small displacement and small pump pressure, we obtain the success of the first field test in an extra-low desorption pressure coal seam. Laboratory experiments have proven that sulphoaluminate cement is suitable as base cements for the SCGPCS system due to their rapid setting and fast hardening characteristics. The reaction of sodium carbonate + aluminum sulfate system and sodium bicarbonate + aluminum sulfate system will generate precipitation to block the internal pore structure of cement stone, leading to a decrease in permeability. Calcium hypochlorite (1.5 wt.%) + urea (0.6 wt.%) system is preferred as a gas-generating agent system for SCGPCS. Sand (30 wt.%) with 300–425 μm particle size is preferred as a structural strength substance for SCGPCS. Graphene poly-gel (referred to hereafter as the GPG) has a high FCI and good CO₂ foam stability. GPG (6.0 wt.%) is preferred as a foam stabilizer for SCGPCS. The thickening time of graphene–foam–cement slurry is 138 min at 50 °C, with long pumping time, normal thickening curve and excellent performance. The SCGPCS has a corrosion rate of 11.25 mpy in the formation water and can be stable in the formation. Acid is more corrosive to SCGPCS, and it can be used to improve the permeability of SCGPCS. Field tests have proven that SCGPCS fracturing injected 33 m³ of fluid, of which 27 m³ entered the formation. Graphene–foam–cement slurry was injected into the formation through the casing for 13 m³, with a displacement of 0.4–0.6 m³/min and tubing pressure 8–13 MPa. The formation was fractured with a fracturing crack half-length of 71.58 m, a supported fracturing crack half-length of 56.95 m, and a supported fracturing crack permeability of 56.265 mD. Full article

Foam gel fracturing fluid has the characteristics of low formation damage, strong flowback ability, low fluid loss, high fluid efficiency, proper viscosity, and strong sand-carrying capacity, and it occupies a very important position in fracturing fluid systems. The rheological properties of gel fracturing fluid with different foam qualities of CO₂, under different experimental temperatures and pressures, have not been thoroughly investigated, and their influence on it was studied. To simulate the performance of CO₂ foam gel fracturing fluid under field operation conditions, the formula of the gel fracturing fluid was obtained through experimental optimization in this paper, and the experimental results show that the viscosity of gel fracturing fluid is 2.5 mPa·s (after gel breaking at a shear rate of 500 s⁻¹), the residue content is 1.3 mg/L, the surface tension is 25.1 mN/m, and the interfacial tension is 1.6 mN/m. The sand-carrying fluid has no settlement in 3 h with a 40% sand ratio of 40–70-mesh quartz sand. The core damage rate of foam gel fracturing fluid is less than 19%, the shear time is 90 min at 170 s⁻¹ and 90 °C, the viscosity of fracturing fluid is >50 mPa·s, and the temperature resistance and shear resistance are excellent. The gel fracturing fluid that was optimized was selected as the base fluid, which was mixed with liquid CO₂ to form the CO₂ foam fracturing fluid. This paper studied the rheological properties of CO₂ foam gel fracturing fluid with different CO₂ foam qualities under high temperature (65 °C) and high pressure (30 MPa) and two states of supercooled liquid (unfoamed) and supercritical state (foamed) through indoor pipe flow experiments. The effects of temperature, pressure, shear rate, foam quality, and other factors on the rheological properties of CO₂ foam gel fracturing fluid were considered, and it was confirmed that among all the factors, foam quality and temperature are the main influencing factors, which is of great significance for us to better understand and evaluate the flow characteristics of CO₂ foam gel fracturing fluid and the design of shale gas reservoir fracturing operations. Full article

In response to the difficulty of fracture modification in inter-salt shale reservoirs and the unknown pattern of hydraulic fracture expansion, corresponding physical model experiments were conducted to systematically study the effects of fracturing fluid viscosity, ground stress and pumping displacement on hydraulic fracture expansion, and the latest supercritical ${\mathrm{CO}}_2$ fracturing fluid was introduced. The test results show the following. (1) The hydraulic fractures turn and expand when they encounter the weak surface of the laminae. The fracture pressure gradually increases with the increase in fracturing fluid viscosity, while the fracture pressure of supercritical ${\mathrm{CO}}_2$ is the largest and the fracture width is significantly lower than the other two fracturing fluids due to the high permeability and poor sand-carrying property. (2) Compared with the other two conventional fracturing fluids, under the condition of supercritical ${\mathrm{CO}}_2$ fracturing fluid, the increase in ground stress leads to the increase in inter-salt. (3) Compared with the other two conventional fracturing fluids, under the conditions of supercritical ${\mathrm{CO}}_2$ fracturing fluid, the fracture toughness of shale increases, the fracture pressure increases, and the fracture network complexity decreases as well. (4) With the increase in pumping displacement, the fracture network complexity increases, while the increase in the displacement of supercritical ${\mathrm{CO}}_2$ due to high permeability leads to the rapid penetration of inter-salt shale hydraulic fractures to the surface of the specimen to form a pressure relief zone; it is difficult to create more fractures with the continued injection of the fracturing fluid, and the fracture network complexity decreases instead. Full article

The low sand-carrying problem caused by the low viscosity of supercritical carbon dioxide (SC–CO₂) limits the development of supercritical CO₂ fracturing technology. In this study, a molecular simulation method was used to design a fluorine-free solvent-free SC–CO₂ thickener 1,3,5,7-tetramethylcyclotetrasiloxane (HBD). Simulations and experiments mutually confirm that HBD-1 and HBD-2 have excellent solubility in SC–CO₂. The apparent viscosity of SC–CO₂ after thickening was evaluated with a self-designed and assembled capillary viscometer. The results show that when the concentration of HBD-2 is 5 wt.% (305.15 K, 10 MPa), the viscosity of SC–CO₂ increases to 4.48 mPa·s. Combined with the capillary viscometer and core displacement device, the low damage of SC–CO₂ fracturing fluid to the formation was studied. This work solves the pollution problems of fluoropolymers and co-solvents to organisms and the environment and provides new ideas for the molecular design and research of SC–CO₂ thickeners. Full article

Supercritical carbon dioxide (SC-CO₂) jet is capable of decreasing the threshold pressure of rock breakage and mitigating formation damage, owing to its low viscosity, high diffusivity, and extremely-low surface tension. The swirling-round jet holds the advantages of both a swirling jet and a round jet. Therefore, the comprehensive technique, swirling-round SC-CO₂ (SR-SC-CO₂) jet, is expected to substantially enhance rock-breaking efficiency. However, theoretical analysis of the flow field characteristics of SR-SC-CO₂ has not been reported yet. This work aims to lay a theoretical foundation for employing SR-SC-CO₂ in drilling and fracturing. The flow field is simulated using Naiver-Stokes equations and the RNG k-ε turbulence model. Sensitivity analysis, regarding pressure drop of the nozzle, confining pressure, fluid temperature, jetting distance, the diameter of the nozzle’s central hole, and grooving area, are performed. We show that the combined swirling-round SC-CO₂ jet flow could maintain a relatively larger axial as well as tangential velocity compared to a single approach of swirling jet or round jet, enabling one to acquire a deeper oillet and expand the perforation area effectively. The simulation results substantiate the enormous potential of SR-SC-CO₂ in improving rock-breaking efficiency and clarify the influence of relevant parameters on the impact pressure of the jet flow. Full article