CO2 Fracturing Research Articles

A Prediction Method for Calculating Fracturing Initiation Pressure Considering the Modification of Rock Mechanical Parameters After CO2 Treatment

The establishment of a more realistic CO2 fracturing model serves to elucidate the intricate mechanisms underlying CO2 fracturing transformation. Additionally, it furnishes a foundational framework for devising comprehensive fracturing construction plans. However, current research has neglected to consider the influence of CO2 on rock properties during CO2 fracturing, resulting in an inability to precisely replicate the alterations in the reservoir post-CO2 injection into the formation. This disparity from the actual conditions poses a substantial limitation to the application and advancement of CO2 fracturing technology. This work integrates variations in the physical parameters of rocks after complete contact and reaction with CO2 into the numerical model of crack propagation. This comprehensive approach fully acknowledges the impact of pre-CO2 exposure on the mechanical parameters of reservoir rocks. Consequently, it authentically restores the reservoir state following CO2 injection, ensuring a more accurate representation of the post-fracturing conditions. In comparison with conventional numerical simulation methods, the approach outlined in this paper yields a reduction in the error associated with predicting fracturing pressure by 9.8%.

Supercritical CO2-driven intersections of multi-well fracturing fracture network and induced microseismic events in naturally fractured reservoir

PurposeSupercritical CO2 (SC–CO2) fracturing is a potential technology that creates a complex fracturing fracture network to improve reservoir permeability. SC–CO2-driven intersections of the fracturing fracture network are influenced by some key factors, including the disturbances generated form natural fractures, adjacent multi-wells and adjacent fractures, which increase the challenges in evaluation, control and optimization of the SC–CO2 fracturing fracture networks. If the evaluation of the fracture network is not accurate and effective, the risk of oil and gas development will increase due to the microseismicity induced by multi-well SC–CO2 fracturing, which makes it challenging to control the on-site engineering practices.Design/methodology/approachThe numerical models considering the thermal-hydro-mechanical coupling effect in multi-well SC–CO2 fracturing were established, and the typical cases considering naturally fracture and multi-wells were proposed to investigate the intersections and connections of fracturing fracture network, shear stress shadows and induced microseismic events. The quantitative results from the typical cases, such as fracture length, volume, fluid rate, pore pressure and the maximum and accumulated magnitudes of induced microseismic events, were derived.FindingsIn naturally fractured reservoirs, SC–CO2 fracturing fractures will deflect and propagate along the natural fractures, eventually intersect and connect with fractures from other wells. The quantitative results indicate that SC–CO2 fracturing in naturally fractured reservoirs produces larger fractures than the slick water as fracturing fluid, due to the ability of SC–CO2 to connect macroscopic and microscopic fractures. Compared with slick water fracturing, SC–CO2 fracturing can increase the length of fractures, but it will not increase microseismic events; therefore, SC–CO2 fracturing can improve fracturing efficiency and increase productivity, but it may not simultaneously lead to additional microseismic events.Originality/valueThe results of this study on the multi-well SC–CO2 fracturing may provide references for the fracturing design of deep oil and gas resource extraction, and provide some beneficial supports for the induced microseismic event disasters, promoting the next step of engineering application of multi-well SC–CO2 fracturing.

Experimental investigation on fracture propagation in shale fractured by high-temperature carbon dioxide

The productivity of shale reservoirs was significantly enhanced by the high-temperature CO2 fracturing technique. The injection of high-temperature CO2 into the formation induced rock fracture propagation, creating advantageous pathways for fluid flow. In this research, a self-developed in situ high-temperature convective heat simulation experimental apparatus was employed to systematically conduct simulated experiments on high-temperature CO2 fractured shale under different influencing factors. The experimental results demonstrated that the permeability of CO2 increased as the injection temperature increased. The rock fracture pressure was effectively reduced by high-temperature CO2 fractured shale. Higher complexity was observed in fracture propagation, accompanied by a substantial increase in microcracks and branching fractures. The shale fracture pressure increased with increasing triaxial stress and CO2 injection rate. The confining pressure restricted the further propagation of fractures under relatively high stress conditions, thereby reducing the width and density of fractures, lowering the fracture complexity. Nevertheless, the thermal shock effect of the fluid was exacerbated as the injection rate of high-temperature CO2 increased. The initiation of microcracks was facilitated by the intensification of local thermal stress in shale, inducing multiple curved fractures and forming a more complex fracture network. Compared to horizontal bedding shale, the fracture pressure of vertical bedding shale was relatively higher during high-temperature CO2 fracturing. In addition, the geometric morphology of fracture propagation was more complex, characterized by rougher fracture surfaces, leading to a greater improvement in reservoir reconstruction volume. This research contributed to the optimization of CO2 resource utilization, provided experimental evidence for the application of high-temperature convection fracturing technology in in situ shale conversion projects.

Fracture propagation characteristics of water and CO2 fracturing in continental shale reservoirs

Exploring the adaptability of CO2 and water-based fracturing to shale oil reservoirs is important for efficiently developing shale oil reservoirs. This study conducted fracturing experiments and acoustic emission (AE) monitoring on the Jurassic continental shale. Based on high-precision computed tomography scanning technology, digital reconstruction analysis of fracture morphology was carried out to quantitatively evaluate the complexity of fractures and the stimulation reservoir volume (SRV). The results show that the fracturing ability of a single water-based fracturing fluid is limited. Low-viscosity fracturing fluid tends to activate thin layers and has limited fracture height. High-viscosity fracturing fluid tends to result in a wide and simple fracture. A combination injection of low-viscosity and high-viscosity water-based fracturing fluid can comprehensively utilize the advantages of low-viscosity and high-viscosity fracturing fluids, effectively improving the complexity of fractures. CO2 fracturing is adaptable to Jurassic shale. The breakdown pressure of the supercritical CO2 (SC-CO2) fracturing is low. Branch fractures form, and laminas activate during SC-CO2 fracturing due to its high diffusivity. Under high-temperature and high-pressure conditions, the aqueous solution formed by mixing CO2 with water can promote the formation of complex fractures. Compared with water-based fracturing fluid, the complexity of fractures and effective stimulation reservoir volume (ESRV) increased by 8.7% and 47.6%, respectively. There is a high correlation between SRV and ESRV, and the proportion of AE shear activity is also highly correlated with the complexity of fractures. The results are expected to provide better fracturing schemes and effectiveness for continental shale oil reservoirs.

The mechanism of proppant transport dynamic propagation in rough fracture for supercritical CO2 fracturing

Supercritical CO2 fracturing technology has shown great potential for enhancing production in unconventional reservoirs. It is essential to clarify the transport mechanism of proppant under the dynamic propagation conditions within rough fractures. A realistic rough fracture model is reconstructed, and Computational Fluid Dynamics simulations are conducted to track proppant movement during fracture propagation. The typical transport characteristics of proppant within rough fractures are revealed, and the effects of fracture propagation rate, proppant density, mass flow rate, particle size, sand ratio, and temperature on the support effect are discussed. The results show that the flow channels formed by sand carrying fluid in rough fractures are complex, with fracture propagation changing some flow channels. The proppant forms an irregular sand bed interspersed with unfilled areas, and complex flow characteristics are generated. The increase in fractal dimension increases the resistance in the fluid flow process and affects the movement of the proppant, which tends to create unfilled areas. Low density and size of proppant can improve the proppant placement length. In a certain temperature range, high temperature injection of sand carrying fluid can improve the proppant placement effect. In addition, the low sand ratio and high mass flow rate pumping can be used to form the dominant channel, followed by pumping with a high sand ratio and low mass flow rate for effective support.

Experimental Evaluation of Energy Enhancement and Fracturing Fluid Flowback Effect for CO2 Pre-Fracturing in Shale Reservoirs

Abstract Liquid CO2 pre-fracturing is a promising reservoir stimulation technology due to its advantages of increasing reservoir energy, low reservoir damage, and high fracturing fluid flowback rate. The on-site flowback scheme currently relies mainly on experience and requires further optimization of the energy enhancement effect and the flowback system. This paper presented a study on the changing law of liquid CO2 pre-fracturing energy-enhancing effect and fracturing fluid flowback rate in shale reservoirs was carried out by applying the experiments of drive-off and pressure-reducing flowback. The results indicate that, the injection of CO2 followed by linear gel fracturing fluid increased the energy (pressure) of the core system by approximately 322.8% compared to the injection mode of CO2 fracturing alone, and increased the energy (pressure) of the core system by approximately 24.1% compared to the injection mode of linear gel fracturing fluid. The energizing effect of the core system showed a trend of increasing and then decreasing with the increase of CO2 injection, and the best effect was achieved when the injection ratio of linear gel fracturing fluid to CO2 was 1:1. The flowback rate of the fracturing fluid and oil recovery both increased as the flowback differential pressure increased. Extending the soak time can increase the oil recovery, but the increase gradually decreases with the extension of the soak time. Additionally, the increase in soak time can improve the flowback rate of the core with relatively high permeability, but it has little effect on the flowback rate of the core with very low permeability.

Fracture propagation characteristics driven by liquid CO2 BLEVE for coalbed methane recovery

Fracture propagation induced by liquid CO2 phase transition blasting (LCO2-PB) is the major reason for the spotty fracturing performance of LCO2-PB for enhancing coalbed methane (ECBM). Measures to effectively control the fracture propagation are of significant importance for ECBM recovery. Many researches to date have conducted the responses of the fracture propagation upon the CO2 fracturing under various injection conditions, and some have found that the thermodynamic state of CO2 can dominate the cracks distribution to some extent. This study therefore investigates the effect of various operated parameters of LCO2-PB on the fracture propagation alteration of coal seam subjected to the thermodynamic state of CO2 with different reservoir conditions. A series of fracture process simulations were performed based on the pressure–temperature-phase coupling model, and results indicate that high temperature of CO2 flow in the fracture process greater fracture expansion; the fracture width decreased around by 66.8 % from smaller smash district to larger one, especially for low CO2 flow rate; high elastic modulus and the temperature of coal seam favors greater length reduction and extensive crack connection, and as temperature of CO2 induces the interlaced fractures earlier formation in the higher reservoir temperature.

Research on microscale displacement characteristics of supercritical CO2 fracturing in shale oil reservoirs

AbstractThe great success of CO2 fracturing in shale oil reservoirs has not only increased the production capacity of shale oil, but also effectively carried out CO2 geological storage. In this paper, focusing on the microscale displacement characteristics of CO2 fracturing in shale oil reservoirs, first, the impact of oil saturation and gas invasion pressure on gas invasion is discussed. Then, the coupling control mode of oil saturation/pressure for various mechanisms of gas invasion is revealed. Results show that: (a) at lower displacement, the rock core has a lower initiation pressure and is fractured in a shorter period of time; (b) at higher displacement, the required fracturing time is longer and the fracturing pressure increases, but the fracturing effect is good and it is easy to form complex fracture networks; and (c) under higher pressure conditions, more complex fractures can be formed, which is beneficial for reservoir transformation and production improvement.

Simulation Study on Rock Crack Expansion in CO2 Directional Fracturing

In underground construction projects, traversing hard rock layers demands concentrated CO2 fracturing energy and precise directional crack expansion. Due to the discontinuity of the rock mass at the tip of prefabricated directional fractures in CO2 fracturing, traditional simulations assuming continuous media are limited. It is challenging to set boundary conditions for high strain rate and large deformation processes. The dynamic expansion mechanism of the 3D fracture network in CO2 directional fracturing is not yet fully understood. By treating CO2 fracturing stress waves as hemispherical resonance waves and using a particle expansion loading method along with dynamic boundary condition processing, a 3D numerical model of CO2 fracturing is constructed. This model analyzes the dynamic propagation mechanism of 3D spatial fractures network in CO2 directional fracturing rock materials. The results show that in undirected fracturing, the fracture network relies on the weak structures near the rock borehole, whereas in directional fracturing, the crack propagation is guided, extending the fracture’s range. Additionally, the tip of the directional crack is vital for the re-expansion of the rock mass by high-pressure CO2 gas, leading to the formation of a symmetrical, umbrella-shaped structure with evenly developed fractures. The findings also demonstrate that the discrete element method (DEM) effectively reproduces the dynamic fracture network expansion at each stage of fracturing, providing a basis for studying the CO2 directional rock cracking mechanism.

Fracture Evolution during CO2 Fracturing in Unconventional Formations: A Simulation Study Using the Phase Field Method

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.

Analysis of Fracturing Expansion Law of Shale Reservoir by Supercritical CO2 Fracturing and Mechanism Revealing

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.

A molecular dynamics investigation into the polymer tackifiers in supercritical CO2 fracturing fluids under wellbore conditions

SC-CO2 fracturing technology is a feasible method for green extraction of unconventional oil and gas reservoirs. However, due to a series of problems such as sand transportation during SC-CO2 fracturing, CO2 thickening has become the focus of current research. Polymer thickeners have been widely used in oilfields. Due to the macroscopic nature and limitations of laboratory experiments, we have not been able to elucidate the microscopic mechanism of polymer thickening CO2 and the viscosity change of the CO2 fracturing fluid system downhole after polymer addition. In this study, we used all-atom modeling and molecular simulation of the COMPASSII force field. We selected nine polymers to study their microscopic properties and the factors affecting their effects. Finally, we simulated the viscosity change of the CO2 system after the addition of polymer tackifiers in the wellbore under the CO2 fracturing construction conditions by combining the data from one well in the oilfield.

Study on the Thermal Expansion Characteristics of Coal during CO2 Adsorption

The adsorption of CO2 fracturing fluid into coal reservoirs causes the expansion of the coal matrix volume, resulting in changes in the fracture opening, which alters the permeability of the coal reservoir. However, it is not yet clear whether thermal expansion during CO2 adsorption on coal is the main cause of coal adsorption expansion. Therefore, by testing the thermal properties, expansion coefficient, and adsorption heat of the three coal samples, the adsorption thermal expansion characteristics of coal and their impact on the permeability of coal reservoirs are clarified. The results reveal the following: (1) Under the same conditions, the adsorption heat increases with increasing pressure, while it decreases with increasing temperature. The relationship between adsorption heat and pressure conforms to the Langmuir equation before 40 °C, and it follows a second-order equation beyond 40 °C. At 100 °C, the adsorption heat of coal samples to CO2 is primarily determined by temperature. (2) The maximum temperature variation in coal samples from Xinjiang, Liulin, and Zhaozhuang during CO2 adsorption is 95.767 °C, 87.463 °C, and 97.8 °C, respectively. The maximum thermal expansion rates are 12.66%, 5.74%, and 14.37%, and the maximum permeability loss rates are 16.16%, 7.51%, and 18.24%, respectively, indicating that thermal expansion is the main reason for coal adsorption expansion. (3) This research can elucidate the impact of CO2 fracturing fluid on coal reservoirs and its potential application value, thus providing theoretical support for coalbed methane development and CO2 geological storage.

Study on Microscopic Characteristics and Rock Mechanical Properties of Tight Sandstone after Acidification–Supercritical CO2 Composite Action: Case Study from Xujiahe Formation, China

Acidified CO2 fracturing is a viable method for increasing production in deep, tight sandstone reservoirs. However, the potential mechanism of changes in pore structure and mechanical properties of sandstone under acidified CO2 supercritical composite is not clear. Understanding this mechanism is important for the study of crack initiation and extension in tight sandstone reservoirs. This study utilizes sandstone samples from the Xujiahe Formation reservoir in Rongchang District as experimental specimens. The primary focus is to analyze the changes in pore structure and mechanical properties of these samples after acidification–supercritical CO2 composite action. Nuclear magnetic resonance (NMR) and uniaxial compression tests are employed as the main investigative techniques. The results show that there was a physicochemical synergy between the acidification–supercritical CO2 composite effect; the crack initial stress, damage stress, and peak stress of the sandstone after 16 MPa supercritical CO2 acidification treatment were reduced by 20%, 49.5%, and 49.8%, respectively; the crack volumetric strain accelerated and the sandstone evolved from brittle to ductile damage; and the larger pore space and microcracks of the sandstone increased significantly after the treatment, which can be attributed to the gradual dissolution of intergranular cement leading to the formation of new pores connected to the existing pore network. The change mechanism of sandstone after acidification–supercritical CO2 compound treatment is also proposed.

Effects of natural fracture reopening on proppant transport in supercritical CO2 fracturing: A CFD-DEM study

The reopening of natural fractures reshapes the proppant beds in hydraulic fractures, especially at fracture intersections, critically influencing subsequent proppant migration. However, studies on the effects of proppant bed shapes on post-reopening proppant migration are limited. To address this gap, a moving wall boundary technique is integrated into a Computational Fluid Dynamics–Discrete Element Method (CFD-DEM) framework to model natural fracture reopening, enabling an in-depth analysis of how proppant bed reshaping impacts subsequent proppant migration during supercritical CO2 fracturing. Results reveal that proppant migration into natural fractures is governed by both drag force-induced and gravity-induced rolling mechanisms, with the latter exerting a more significant effect. The gravity-induced rolling mechanism is enhanced by five key factors: (a) the generation of a well-developed proppant pack in proximity to the intersection; (b) the inadequately filled V-shaped gully; (c) the increased proppant transport capacity within the natural fracture; (d) the reduced bypassing of proppants at the intersection; and (e) the improved ability of proppants to enter the natural fracture. The enhanced gravity-induced rolling mechanism significantly increases the proppants flowing into natural fractures: by 35.6% between the central and rearward section cases, 168.9% from mild to severe plugging cases, 39.1% with a wider natural fracture width (1.5 mm–2.5 mm), 20.3% with decreased hydraulic fracture flow rate (0.35 m/s to 0.25 m/s), and 33% with reduced fluid temperature (160 °C–40 °C). These findings underscore the impact of natural fracture reopening on subsequent proppant migration, offering valuable insights for optimizing fracturing designs.

Preparation and Application of CO2-Resistant Latex in Shale Reservoir Cementing

With the application of CO2 fracturing, CO2 huff and puff, CO2 flooding, and other stimulation technologies in shale reservoirs, a large amount of CO2 remained in the formation, which also lead to the serious corrosion problem of CO2 in shale reservoirs. In order to solve the harm caused by CO2 corrosion, it is necessary to curb CO2 corrosion from the cementing cement ring to ensure the long-term stable exploitation of shale oil. Therefore, a new latex was created using liquid polybutadiene, styrene, 2-acrylamide-2-methylpropanesulfonic acid, and maleic anhydride to increase the cement ring’s resistance to CO2 corrosion. The latex’s structure and characteristics were then confirmed using infrared, particle size analyzer, thermogravimetric analysis, and transmission electron microscopy. The major size distribution of latex is between 160 and 220 nm, with a solid content of 32.2% and an apparent viscosity of 36.8 mPa·s. And it had good physical properties and stability. Latex can effectively improve the properties of cement slurry and cement composite. When the amount of latex was 8%, the fluidity index of cement slurry was 0.76, the consistency index was 0.5363, the free liquid content was only 0.1%, and the water loss was reduced to 108 mL. At the same time, latex has a certain retarding ability. With 8% latex, the cement slurry has a specific retarding ability, is 0.76 and 0.5363, has a free liquid content of just 0.1%, and reduces water loss to 108 mL. Moreover, latex had certain retarding properties. The compressive strength and flexural strength of the latex cement composite were increased by 13.47% and 33.64% compared with the blank cement composite. A long-term CO2 corrosion experiment also showed that latex significantly increased the cement composite’s resilience to corrosion, lowering the blank cement composite’s growth rate of permeability from 46.88% to 19.41% and its compressive strength drop rate from 27.39% to 11.74%. Through the use of XRD and SEM, the latex’s anti-corrosion mechanism, hydration products, and microstructure were examined. In addition to forming a continuous network structure with the hydrated calcium silicate and other gels, the latex can form a latex film to attach and fill the hydration products. This slows down the rate of CO2 corrosion of the hydration products, enhancing the cement composite’s resistance to corrosion. CO2-resistant toughened latex can effectively solve the CO2 corrosion problem of the cementing cement ring in shale reservoirs.

In-situ laboratory study on influencing factors of pre-SC-CO2 hybrid fracturing effect in shale oil reservoirs

Supercritical CO2 (SC-CO2) fracturing, being a waterless fracturing technology, has garnered increasing attention in the shale oil reservoir exploitation industry. Recently, a novel pre-SC-CO2 hybrid fracturing method has been proposed, which combines the advantages of SC-CO2 fracturing and hydraulic fracturing. However, the specific impacts of different pre–SC-CO2 injection conditions on the physical parameters, mechanical properties, and crack propagation behavior of shale reservoirs remain unclear. In this study, we utilize a newly developed “pre-SC-CO2 injection → water-based fracturing” integrated experimental device. Through experimentation under in-situ conditions, the impact of pre-SC-CO2 injection displacement and volume on the shale mineral composition, mechanical parameters, and fracture propagation behavior are investigated. The findings of the study demonstrate that the pre-injection SC-CO2 leads to a reduction in clay and carbonate mineral content, while increasing the quartz content. The correlation between quartz content and SC-CO2 injection volume is positive, while a negative correlation is observed with injection displacement. The elastic modulus and compressive strength exhibit a declining trend, while Poisson's ratio shows an increasing trend. The weakening of shale mechanics caused by pre-injection of SC-CO2 is positively correlated with the injection displacement and volume. Additionally, pre-injection of SC-CO2 enhances the plastic deformation behavior of shale, and its breakdown pressure is 16.6% lower than that of hydraulic fracturing. The breakdown pressure demonstrates a non-linear downward trend with the gradual increase of pre-SC-CO2 injection parameters. Unlike hydraulic fracturing, which typically generates primary fractures along the direction of the maximum principal stress, pre-SC-CO2 hybrid fracturing leads to a more complex fracture network. With increasing pre-SC-CO2 injection displacement, intersecting double Y-shaped complex fractures are formed along the vertical axis. On the other hand, increasing the injection rate generates secondary fractures along the direction of non-principal stress. The insights gained from this study are valuable for guiding the design of preSC-CO2 hybrid fracturing in shale oil reservoirs.

Evolution of shale wetting properties under long-term CO2/brine/shale interaction: Implications for CO2 storage in shale reservoirs

In the case of Carbon Geological Storage (CGS), the wettability is one of the main parameters controlling the CO2 injection capacity and CO2 plume movement, which affects the safety of long-term CO2 storage. A full evaluation of this parameter is essential for risk evaluation and storage capacity estimation. The objective of this study was to investigate the wettability changes of shales from the Chang 7 Formation in the Ordos Basin by exposing the samples to ScCO2/brine for 10/20/30/and 60 days. The mineral composition, pore structure, chemical functional groups, and surface morphology changes of the shale were analyzed using x-ray diffractometer (XRD), low-temperature nitrogen adsorption (LN-N2), infrared spectroscopy (FTIR), and scanning electron microscopy (SEM). In addition, the solid-drop method was used to measure the contact angle of shale samples at different times of ScCO2 soaking. The results show that after 60 days of continuous ScCO2 soaking, the shale water contact angle and chemical group peak spectrum generally show an increasing trend, which is caused by the reduction of carbonate and clay mineral content. The prolonged time of ScCO2 soaking weakens the shale's water wettability and reduces the water-locking effect (water has a sealing effect in the pore channel of the reservoir), capillary force, and the height of CO2 sequestration columns, which is favorable for shale gas extraction (a method of extracting natural gas from shale rock by CO2 fracturing), but it may increase the CO2 geological leakage risk. The results have important implications for regulating the change of shale water wettability, and this study can also better provide theoretical references for Carbon Geological Storage programs.

Further Investigation of CO2 Quasi-Dry Fracturing in Shale Reservoirs—An Experimental Study

The physical properties of shale reservoirs are typically poor, necessitating the use of fracturing technology for effective development. However, the high clay content prevalent in shale formations poses significant challenges for conventional hydraulic fracturing methods. To address this issue, CO2-based fracturing fluid has been proposed as an alternative to mitigate the damage caused by water-based fracturing fluids. In this paper, the applicability of quasi-dry CO2 fracturing in shale reservoirs is examined from three key perspectives: the viscosity of CO2 fracturing fluid, the fracture characteristics induced by the CO2 fracture fluid, and the potential reservoir damage caused by the fracturing fluid. Firstly, the viscosity of CO2 fracturing fluid was determined by a rheological experiment. Rheological tests revealed that the viscosity of CO2 fracturing fluid was significantly influenced by the water–carbon ratio. Specifically, when the water–carbon ratio was 30:70, the maximum viscosity observed could reach 104 mPa·s. Moreover, increasing reservoir temperature resulted in decreased fracturing fluid viscosity, with a 40 °C temperature rise causing a 20% viscosity reduction. Secondly, matrix permeability tests were conducted to investigate permeability alteration during CO2 fracturing fluid invasion. Due to the weak acidity of CO2-based fracturing fluid, the permeability reduction induced by clay hydration was inhibited, and an increase in permeability was observed after a 3-day duration. However, the matrix permeability tends to decrease as the interaction time is prolonged, which means prolonged soaking time can still cause formation damage. Finally, triaxial fracturing experiments facilitated by a three-axis servo pressure device were conducted. The fracture properties were characterized using computed tomography (CT), and 3D reconstruction of fractured samples was conducted based on the CT data. The results demonstrate that CO2 fracturing fluid effectively activates weak cementation surfaces in the rock, promoting the formation of larger and more complex fractures. Hence, CO2 quasi-dry fracturing technology emerges as a method with significant potential, capable of efficiently stimulating shale reservoirs, although a reasonable soaking time is necessary to maximize hydrocarbon production.

Investigation of creep and transport mechanisms of CO2 fracturing within natural gas hydrates

Natural gas hydrates (NGH) are considered as a potential energy resource in the future because of its dramatic energy reserves. NGH formation owns the characteristic of viscoelasticity, to some extent behaves both like liquid and solid. Ignoring the viscoelastic properties of NGH can lead to inaccurate prediction of related characteristics. In 2020, horizontal-well drilling technology was adopted to improve the stimulation performance of NGH reservoirs in the Shenhu area of China. This indicates that it is possible to apply hydraulic fracturing or CO2 fracturing in the reservoir reconstruction of NGH. CO2 fracturing can generate more fracture networks and connect micro fractures. Additionally, CO2 can be stored geologically and integrated with injection, production, and storage. This study provides a relatively detailed demonstration of the formation and basic mechanical properties of NGH. Then, a comprehensive overview of potential NGH production enhancement methods is conducted. Finally, an evaluation method for dual conductivity considering creep effect is proposed, and the results show that the creep effect of NGH can reduce the conductivity of fractures and matrices. Thus, it is of great importance to investigate the viscoelastic properties of NGH formation, for the long-term prediction of the geo-mechanical response to gas extraction.