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Review

A Review of Supercritical CO2 Fracturing Technology in Shale Gas Reservoirs

by
Zhaokai Hou
1,*,
Yuan Yuan
2,
Ye Chen
3,
Jinyu Feng
1,
Huaishan Wang
1 and
Xu Zhang
1
1
Sanya Offshore Oil & Gas Research Institute, Northeast Petroleum University, Sanya 572025, China
2
Test Team of No.1 Oil Provide Factory, Daqing Oilfield Limited Company, Daqing 163000, China
3
Engineering Technology Research Institute, PetroChina Southwest Oil & Gasfield Company, Chengdu 610017, China
*
Author to whom correspondence should be addressed.
Processes 2024, 12(6), 1238; https://doi.org/10.3390/pr12061238
Submission received: 13 May 2024 / Revised: 4 June 2024 / Accepted: 14 June 2024 / Published: 16 June 2024
(This article belongs to the Section Particle Processes)
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Abstract

:
Shale gas reservoirs generally exhibit characteristics such as low porosity, permeability, and pore throat radius, with high airflow resistance. Currently, hydraulic fracturing is a commonly used method for commercial shale gas extraction; however, the hydraulic fracturing method has exhibited a series of issues, including water sensitivity and reservoir pollution in shale reservoirs. Therefore, the development of anhydrous fracturing technology suitable for shale gas reservoirs has become an urgent requirement. The supercritical carbon dioxide fracturing technique has the merits of reducing reservoir damage, improving recovery and backflow rates, and saving water resources. Moreover, this technique has broad application prospects and can achieve the effective extraction of shale gas. To enhance the understanding of the supercritical carbon dioxide fracturing technique, this review summarizes the progress of current research on this technique. Furthermore, this study analyzes the stage control technology of supercritical carbon dioxide during the fracturing process, the interaction characteristics between supercritical carbon dioxide and rocks, and the laws of rock initiation and crack growth in supercritical carbon dioxide fracturing. The outcomes indicate that after SC-CO2 enters the reservoir, CO2 water–rock interaction occurs, which alters the mineral composition and pore throat framework, weakens the mechanical characteristics of shale, reduces the rock fracturing pressure, and increases the complexity of the fracturing network. This article provides a reference for research related to supercritical carbon dioxide fracturing technology and is greatly significant for the development of shale gas reservoirs.

1. Introduction

In order to meet the growing energy demand, the vigorous development of shale gas resources with abundant reserves has become a reliable approach to fill the future global energy supply and demand gap and ensure energy security [1] (as shown in Figure 1). Hydraulic fracturing technology is currently recognized as the most effective way to develop shale gas resources [2]. However, hydraulic fracturing technology still faces many unavoidable problems in terms of reservoir and environmental protection [3]. Firstly, shale reservoirs have a high clay content, and water-based fracturing fluids can cause damage to the reservoir; secondly, the scarcity of water resources in the areas where most shale gas is located limits the application of large-scale hydraulic fracturing technology; and thirdly, the chemical additives contained in fracturing fluid can easily cause serious pollution to groundwater resources. The above issues have constrained the growth and application of shale gas. Therefore, the development of an anhydrous fracturing technique suitable for shale gas reservoirs has become urgent.
In recent years, many researchers have proposed the technical idea of SC-CO2 fracturing [4]. Supercritical CO2 fracturing technology is a novel kind of anhydrous fracturing technology using supercritical CO2 instead of water. In general, CO2 mainly exists in the form of gas. As a result of changes in environmental conditions, CO2 occurs in three phases: solid, liquid, and gaseous. In the case of an ambient temperature above 31.1 °C and a pressure value above 7.38 MPa, carbon dioxide reaches a supercritical state. A diagram showing the conditions for CO2 phase change is shown in Figure 2 [5].
Supercritical CO2 fluid is different from both liquid and gas, with many distinct physical and chemical characteristics. Supercritical CO2 shows a density close to that of liquid, a viscosity close to that of gas, a high diffusion parameter, and a surface tension close to zero, with great mobility and good heat and mass transfer efficiency [6]. Transforming unconventional reservoirs with supercritical CO2 as a fracturing fluid has many advantages: supercritical CO2, as an anhydrous working fluid, can slow down clay expansion and avoid reservoir pollution [7]; supercritical CO2 easily enters reservoir microfractures, which can grow the complexity of artificial fractures and improve the fracturing effect. Moreover, the adsorption of supercritical CO2 on the rock surface is stronger than that of methane, which can improve production and recovery by replacing methane molecules adsorbed in shale [8,9]. After fracturing, supercritical CO2 easily flows back, has little impact on shallow water and the surface environment, and can reduce the cost of decontamination [10]. Therefore, supercritical CO2 fracturing technology has wide application potential and can achieve the effective exploitation of shale gas.
Recently, researchers have conducted relevant studies of the initiation and propagation law of supercritical CO2 fracturing of shale. However, the content of research is relatively scattered and its considerations are not comprehensive; thus, the existing research cannot effectively guide development in this field. Therefore, in order to further promote the research of supercritical CO2 fracturing technology and provide a reference for scholars in this direction in the future, this study summarizes the research progress of supercritical CO2 fracturing technology from the aspects of supercritical CO2 phase control technology in fractures, the influence of supercritical CO2 on shale mineral composition and pore framework, and the initiation and growth law of supercritical CO2 fractures.

2. Supercritical CO2 Phase Control Technology

Accurately determining the pressure and temperature of CO2 in the fractured wellbore and fracture is the key to CO2 phase control. The study of wellbore flow and heat transfer problems began in the 1950s and mainly resulted in the formation of analytical and numerical research methods. Ramey et al. [11] first proposed an analytical model of wellbore heat transfer under injection conditions, which can be solved explicitly and has high accuracy for wellbore temperature calculation of incompressible fluid or low-pressure gas. Since then, many researchers, such as Holmes [12], Romero [13], Fontanilla [14], and Gu [15] have proposed analytical models of wellbore heat transfer suitable for different working conditions. In addition to the analytical numerical method, there are also many scholars focusing on the development of numerical methods for the wellbore temperature field. Raymond et al. [16] first proposed a numerical model of the wellbore temperature under drilling conditions. Subsequently, Eickmeier et al. [17] discretized the wellbore in the radial and axial directions (as shown in Figure 3) with the explicit finite difference approach. On the basis of Eickmeier’s research, You [18] and Dong [19] used numerical methods to solve the unsteady wellbore heat transfer model. With the deepening of research, Alves [20] and Sun [21] combined the wellbore heat transfer and steady-state flow control equations and proposed a quasi-steady-state analytical equation of wellbore temperature under injection conditions. Hasan [22] and Kabir [23] successively established pseudo-steady-state and unsteady-state wellbore two-phase flow and heat transfer models and extended them to the solution of wellbore temperature distribution under different working conditions during drilling and completion.
Compared with water-based fluids, pressure and temperature have significant effects on physical parameters such as the density and viscosity of carbon dioxide. Therefore, on the basis of the previous flow and heat transfer models, scholars have combined the physical characteristics of CO2 to analyze the pressure and temperature fields in the CO2 fracturing wellbore. In early studies, the Peng–Robinson equation of state [24] was widely used to calculate the density of carbon dioxide due to its simple form and strong applicability. However, the accuracy of the equation is poor, and the influence of formation water intrusion and CO2 physical parameter changes on the wellbore flow law during the flow process was not considered. In order to calculate the physical parameters of CO2 more accurately, Wu Xiaodong [25] proposed that the combination of P-R and EXP-RK state equations can exhibit relatively great precision. Then, the wellbore temperature field model of vertical well CO2 flooding was established by combining the optimized cubic state equation with the quasi-steady wellbore temperature field numerical model. At the same time, Span and Wagner [26] compiled available data and established a calculation model for the thermodynamic characteristics of carbon dioxide. Subsequently, the equation has been widely used in wellbore flow and heat transfer calculation under various conditions such as CO2 drilling, fracturing, and geological storage. Li [27] and Dou [28] analyzed the wellbore temperature and pressure allocation of vertical wells during supercritical CO2 drilling by combining the Span–Wagner model with the pseudo-steady-state wellbore temperature field numerical model and the steady-state mass and momentum equations. With the deepening of research, Singhe [29] and Guo [30] studied the wellbore flow and heat transfer of CO2 injection by considering the unsteady heat transfer in the wellbore and introduced the frictional heat generation term and the coke soup effect term in the numerical model. The above wellbore temperature field models are mostly one-dimensional quasi-steady-state heat transfer equations, which have excellent usage effects under low-speed injection circumstances. Nevertheless, due to the steady-state heat transfer assumption adopted in the fluid energy equation, it is not applicable to short-term and fast injection procedures, while the transient wellbore temperature field model can effectively solve such issues. Therefore, some scholars have begun to pay attention to the dynamic change process of CO2 wellbore flow. For example, Wang [31], Yang [32], and Wu [33] established unsteady CO2 fracturing wellbore heat transfer models. In addition, many scholars have used CFD software (the version number is 19.2)to establish two- and three-dimensional models to analyze the heat transfer law of CO2 in the wellbore. Among them, Ruan et al. [34] set up a two-dimensional axisymmetric wellbore heat transfer model for low-speed injection processes by using CFD software(the version number is 19.2), and explored the heat transfer system. Jiang et al. [35] also described the heat transfer of a vertical wellbore on the basis of Ruan et al. with a two-dimensional axisymmetric model and developed a porous medium flow model of the generation to couple the wellbore and generation in flow.
Compared with the flow and heat transfer of CO2 in the wellbore, there are relatively few studies on the flow and heat transfer of CO2 in fractures. Among them, Kamphluss et al. [36] considered the heat conduction and convection in the generation process and the thermal convection along the fracture direction. A numerical solution method for the fracture temperature field considering the fracture, filtration zone, and reservoir temperature distribution (K-D-R method) was proposed, which provides a relatively perfect algorithm for solving the fracture temperature field. Recently, the usage of nontraditional fracturing fluids has been greatly developed. Therefore, researchers have carried out a significant amount of research on the flow and heat transfer law of unconventional fracturing fluids in fractures. Among them, Li [37], Wu [38], and Wang [39] considered the influence of different factors and successively set up the calculation model of the temperature field in SC-CO2 fractures, which provided a theoretical foundation for SC-CO2 fracturing design. Wang et al. [40] introduced the wellbore temperature field model, established the wellbore fracture temperature field model of carbon dioxide fracturing, and studied the phase-change procedure of carbon dioxide from the wellhead to the bottom of the well and finally to the crack tip. In the meantime, Friehauf et al. [41] developed a two-dimensional fracture simulator suitable for energy-increasing fluids including carbon dioxide. The simulator takes into account fluid compressibility and temperature changes and can simulate the dynamic expansion of fractures, fluid temperature, and pressure changes in fractures. Ribeiro et al. [42] extended the two-dimensional fracture simulation to a three-dimensional fracture simulation and considered a more reasonable fracture propagation model.

3. The System of Rock Initiation and Fracture Propagation in Supercritical CO2 Fracturing

3.1. Effect of Supercritical CO2 on Rock’s Physical Properties

Shale contains a variety of complex mineral components such as carbonate, clay, quartz, and pyrite. Among them, clay minerals mainly include illite, montmorillonite, and chlorite [43]. Under the conditions of formation temperature and pressure, SC-CO2 dissolves in formation water to form carbonic acid, which dissolves dolomite, calcite, and other carbonate minerals under reservoir pressure and temperature conditions. Wu Di [44] and Luo [45] found that mineral elements such as Ca, Mg, Na, K, and Al in shale change under the action of SC-CO2. However, shale clay minerals do not readily react in a short time frame at room temperature and low pressure, but they dissolve under a high temperature and the long-term action of SC-CO2. Edlmann [46], Yu [47], and Shiraki [48] found that minerals including calcite, dolomite, and potassium feldspar in shale dissolve in SC-CO2 under high-temperature and high-pressure conditions. In the meantime, Zhou et al. [49] found that as pressure increases, the content of quartz in shale grows while the content of carbonate and clay minerals declines. In addition, supercritical CO2 also affects the organic matter in shale. Angeli et al. [50] found that the organic matter in shale was decomposed in the environment of supercritical CO2 when studying the mechanism of supercritical CO2 permeability in cap rock. Allawzi et al. [51] observed that supercritical CO2 acted on kerogen and led to the decomposition of organic fragments when they used supercritical fluid extraction to extract oil from oil shale. Xu [52] and Babatunde [53] also observed the decomposition of kerogen under the action of SC-CO2. Table 1 shows the geochemical reactions related to the CO2H2O–shale interaction [54].
Supercritical CO2–water–rock interaction not only dissolves rock minerals but also causes damage to the rock microstructure. Cheng [55], Ao [56], Yin [57], and Zou [58] showed that the specific surface area of shale after SC-CO2 action generally decreases, while the average pore size increases significantly. At the same time, the damage to rock microstructure is also affected by temperature, pressure, and soaking time. Jiang [59] and other studies have shown that the clay minerals of shale are dehydrated after SC-CO2 action, and that micron-scale pore volume increases with an increase in soaking time and pressure. Masoudian [60] and Du [61] have shown that the permeability of rock can be improved under the action of the supercritical CO2–water–rock interaction, and that permeability is positively correlated with the experimental temperature and pressure. Pan [62] and others showed that after supercritical CO2 treatment, the micropore and mesopore framework coefficients of marine shale samples declined greatly as macropore framework coefficients grew, while the continental shale samples showed the opposite trend.
After the interaction of supercritical CO2–water–rock, the mechanical characteristics of rock usually change due to the change in the mineral composition and pore size distribution of rock. Rani et al. [63] showed that water and supercritical CO2 reduced the uniaxial compressive strength of coal by about 17% and 10%, respectively, and reduced the elastic modulus by 8% and 16%, respectively. Li [64], Delle [65], and Rathnaweera [66] found that the interaction between supercritical CO2 and water-saturated sandstone leads to a decrease in the fracture toughness, tensile strength, uniaxial compressive strength, and elastic modulus of rock. The change trend of some parameters is shown in Figure 4 [67]. Li [68] and De [69] also tested the mechanical characteristics of shale under supercritical CO2 saturation and pointed out that under the action of supercritical CO2, all mechanical strength of shale decreases. Researchers have also analyzed the major elements influencing the mechanical strength of rock under the action of supercritical CO2. Roy et al. [70] found that the tensile strength of basalt and shale core samples decreased as saturation time grew. Qin et al. [71] found that compared with subcritical CO2, SC-CO2 has a higher adsorption capacity, greater reduction in coal rock strength, and more cracks after failure. Guo et al. [72] tested the change in rock strength after the shale core was soaked in supercritical carbon dioxide fluid. As soaking time increases, the compressive strength of shale decreases rapidly and then tends to be gentle. As the soaking temperature increases, the compressive strength of shale decreases. Ni et al. [73] found that the mechanical characteristics of shale under supercritical CO2 are not sensitive to pressure changes but are greatly affected by temperature.

3.2. Cracking Law of Supercritical CO2 Fracturing of Rock

One of the main merits of the CO2 fracturing of shale reservoirs is its low initiation pressure. Zhang [74], Lu [75], and Verdon [76] carried out supercritical CO2 fracturing experiments on shale and sandstone. It was found that not only can SC-CO2 fracturing achieve the same effect as hydraulic fracturing, but it can also significantly reduce the initiation pressure required for fracturing (as shown in Figure 5). Wang et al. [77] analyzed the system of the SC-CO2 fracturing of rock from the perspective of the rock failure mechanism. They pointed out that compared with traditional fracturing fluid, SC-CO2 fluid has the features of high density, high diffusivity, and low viscosity. When injecting SC-CO2 into the rock reservoir, SC-CO2 can enter the micropores and microcracks of the rock, establishing a fluid pressure system of different sizes inside the rock, which is more likely to cause tensile and shear failure of the rock. Subsequently, scholars at home and abroad analyzed the main factors affecting the fracture initiation pressure of SC-CO2 fracturing. Yan [78] and Zhang [79] explored the effects of temperature, injection rate, and in situ stress on the fracture initiation of the supercritical CO2 fracturing of coal rock. The study shows that the impact of fracturing fluid temperature and fracturing fluid injection rate on fracture initiation pressure is less than that of in situ stress. Jiang et al. [80] found that the growth of the original rock stress causes the growth of the crack initiation pressure, and the prefabricated crack affects the direction of crack propagation.
The system of reservoir initiation is the starting point and the key point for the study of the fundamental theory of supercritical CO2 fracturing. The study of reservoir initiation mechanisms can be traced back to the 1950s. Based on the triaxial compression experiment, Hubbert et al. [81] put forward a stress model near the wellbore affected by wellbore pressure, namely the famous Hubbert–Willis model, but the model did not consider the impact of radial seepage. While introducing the seepage term into the wellbore stress model, Haimson et al. [82] derived the formulas for calculating the initiation pressure and fracture width. Following Hubbert and Haimson’s research, Hossian [83], Ma [84], Gao [85], and Zhu Haiyan [86] improved and supplemented the hydraulic fracture initiation model from different angles. However, when supercritical CO2 is adopted as a fracturing fluid, its high mobility and interaction with rock greatly affect the stress state around the well. The existing theoretical model cannot accurately predict the initiation pressure of supercritical CO2. Therefore, scholars have established supercritical CO2 fracturing initiation pressure models according to different main controlling factors. Considering the viscosity of supercritical CO2, fluid compressibility, and the pressurization rate, Chen et al. [87] set up a prediction model of supercritical CO2 fracturing initiation pressure. Zhong et al. [88] set up a heat–fluid–solid coupling model, taking into account the temperature and pressure field of the wellbore and the stress field around the wellbore. While coupling the wellbore flow equation, the wellbore pressurization rate, and the initiation pressure equation, Xiao et al. [89] put forward a CO2 fracturing initiation model taking into account the real bottom-hole temperature and pressure circumstances and provided the best injection displacement range. Ma et al. [90] considered the influence of near-well generation temperature and pore pressure variations caused by CO2 intrusion on the tangential stress of reservoir rock and established a thermal–fluid–solid coupling supercritical CO2 fracturing initiation pressure model.

3.3. Crack Growth Law of Supercritical CO2 Fracturing

At present, the technical means to research the law of CO2 fracture propagation are numerical simulation and fracturing physical simulation experiments. In terms of experimental research, at present, the fracture morphology of fracturing is mainly studied via large-scale true triaxial physical experiments at home and abroad. Among them, Daneshy et al. [91] used the true triaxial device to carry out the sandstone crack extension experiment earlier and used transparent organic glass as a material to prepare samples to visually observe the crack morphology. Recently, as unconventional oil and gas resources develop, several scholars have tried to explore the propagation law of the supercritical CO2 fracturing of cracks, providing theoretical guidance for the application of this technology. Ye Liang [92], Liu Guojun [93], Ranjith [94], and Wang [95] carried out laboratory experiments on the supercritical CO2 fracturing of tight sandstone, coal, and shale. The outcomes of these studies revealed that SC-CO2 fracturing demonstrates higher complexity than liquid CO2 and water-based fracturing fluid. Liang [96] and Li [97] analyzed the reasons for the generation of complicated fracture networks in SC-CO2. Studies have shown that at the moment in which supercritical CO2 enters the fracture, because of the Joule–Thomson effect, the fluid temperature drops sharply and produces a temperature difference, which causes a change in the supercritical CO2 fluid phase, thus obtaining a higher fracture growth speed and driving the generation of complicated fracture networks. During the instantaneous low-pressure period of rock crack initiation, if the heat at the crack tip rapidly diffuses into the low-temperature fluid, the thermal stress generated at the crack tip significantly expands the damage and failure of the rock, which promotes further expansion of the crack, thus forming a complex crack network. Bennour [98] and Chen [99] analyzed the reasons for the formation of complex fractures from a macro perspective through laboratory tests. Studies have shown that fractures triggered by supercritical CO2 fracturing mostly propagate along the boundary of mineral particles, and fractures in samples fractured by water and oil tend to penetrate mineral particles.
Researchers have also analyzed the major elements influencing the fracture morphology of supercritical CO2 fracturing of rock. Wang [100] and other studies have found that natural fractures with high cementation strength almost do not affect the fracture propagation path, while natural fractures with low cementation strength or an original opening have a greater impact on fracture propagation. Zhang et al. [101] showed that the fracture pressure of salt rock is higher than that of inter-salt shale. Deng et al. [102] carried out fracturing simulation experiments and found that under high-level stress differences, the opening of the original weak surface may lead to shear failure. Shear failure affects the propagation of cracks and induces shear cracks at the crack tip to produce oblique cracks. When the rock is fractured, how to effectively obtain and characterize the fracture characteristics is key to analyzing the experimental outcomes. At present, the most common fracture feature analysis methods include CT scanning, acoustic emission monitoring, surface profile (morphology) scanning, and artificial optical measurement. Guo [103], Liu [104], and Shafloot [105] evaluated the complexity of the fracture morphology of shale and glutenite after true triaxial fracturing by means of computed tomography (CT) scanning technology. Zhou [106] and Shi [107] studied the propagation mode of shale cracks during SC-CO2 fracturing using acoustic emission monitoring technology. Jia [108] and Zhao [109] studied the crack propagation behavior of supercritical CO2 fracturing of shale and scanned the fracture section after fracturing by using laser three-dimensional scanning. Zou [110] and Hu [111] obtained fracture characteristics and parameters through artificial optical observation and fracture images.
At present, the common numerical simulation methods of hydraulic fracturing are the finite element method (FEM), extended finite element method (XFEM), discrete element method (DEM), and boundary element method (BEM).
As a traditional classical numerical calculation approach, the finite element method (FEM) has merits in settling nonlinear mechanical issues and complicated stress–strain issues. The FEM simulates the propagation of cracks by making the crack border conform to the border of the mesh element and using the mesh reconstruction method. The FEM has been extensively adopted in the numerical simulation of hydraulic fracturing. Chen [112], Liu [113], Wang [114], and Carrier [115] established numerical models of CO2 fracturing based on the finite element approach.
However, the conventional finite element approach of simulating the hydraulic fracture propagation needs to constantly re-divide the grid and encrypt the grid near the crack, and the computational complexity is large. Therefore, to solve this issue, the extended finite element method was developed. The extended finite element approach adopts the level set approach to deal with the existence of discontinuities. This method does not need to take the crack as a geometric entity, the grid is independent of the discontinuity surface, and the crack propagation does not need to re-divide the grid, which can simulate random branch cracks and intersecting cracks. Taleghani [116] studied the interplay between hydraulic fractures and natural fractures with the extended finite element approach and pointed out that when the tensile stress at the tip of the hydraulic fracture is large enough, the natural fracture can be opened and the fracture propagation path can be deflected. Shi et al. [117] analyzed the interplay between hydraulic fractures and natural fractures on the basis of the extended finite element approach, considering the fluid flow and pressure drop in the fracture, and using the improved Renshaw–Pollard criterion to determine whether the hydraulic fracture can pass through the friction interface. Gordeliy et al. [118] proposed an expanded finite element approach for three-dimensional hydraulic fracture growth. This method introduces the asymptotic solution of the crack tip to the expansion shape function and solves the fracture border with the implicit level set approach. Yan [119], Feng [120], and Mohammadnejad [121] also studied the fracture process of supercritical CO2 fracturing with the extended finite element approach.
The discrete element method is a discontinuous medium dynamic solution based on Newton’s second law, which is suitable for discontinuous bodies. The discrete element method has strong advantages for the hydraulic fracturing of natural fracture development strata and can be roughly divided into two categories based on the element type: particle-based discrete element and block discrete element. Nagel et al. [122] simulated three-dimensional hydraulic fracturing fracture propagation with a discrete element approach. Bao [123], Al-Busaidi [124], and Yoon [125] used the particle-based discrete element approach (PFC2D) to simulate the hydraulic fracturing process. On the basis of the discrete element numerical simulation method, Eshiet et al. [126] simulated the generation and distribution of cracks after CO2 injection.
The boundary element method expresses the solution’s problem as a boundary integral equation and discretizes it on the boundary of the computational domain to obtain an approximate solution. Compared with the finite element approach, the extended finite element approach, and the discrete element approach, the boundary element approach can reduce the spatial computational domain by one dimension. Therefore, the boundary element approach has the merits of a small data processing workload and great computational efficiency. The typical representatives of the boundary element method are Schlumberger’s UFM simulator [127] and FrackOptima developed by Long [128]. The UFM simulator uses the displacement discontinuity method (DDM) to determine the rock deformation and calculates the crack propagation in terms of height and length based on the quasi-three-dimensional model (as shown in Figure 6). FrackOptima uses the boundary element approach to work out the rock deformation and considers the stress interference problem of multi-fracture propagation. It is a full three-dimensional multi-fracture propagation simulator. In addition to UFM and FrackOptima, Peirce et al. [129] developed a more accurate boundary element numerical method based on the implicit level set algorithm.

4. Discussion

The United States, Canada, and China have successively carried out a wide range of research on supercritical CO2 fracturing technology. This technology has become a powerful tool for shale oil development, with good application prospects and great development potential; however, it also possesses some scientific problems and drawbacks that need to be addressed:
(1) The sand-carrying capacity of CO2 fracturing fluid is weak, and the sand carried in the process of flowing in the wellbore and fracture easily settles and accumulates, resulting in sand blockage at the bottom of the well and the end of the fracture, which is extremely unfavorable to shale gas exploitation.
(2) A property of supercritical CO2 is that it is extremely unstable, and improper operation in the high-pressure transmission process causes large-scale leakage leading to casualties.
(3) CO2 is an acidic gas, and carbonic acid solution formed in a water environment corrodes drill pipes and pipes. Furthermore, underground storage of CO2 induces earthquake disasters to a certain extent.
(4) CO2 leakage during fracturing causes damage to vegetation, soil, and other ecosystems in the buried area. Large amounts of CO2 leak into the air in some countries, which can lead to dizziness and the suffocation of humans and wildlife in the surrounding areas.

5. Conclusions and Future Prospects

  • Shale contains a variety of complex mineral components such as carbonate minerals, clay, quartz, and pyrite. Under reservoir conditions, the injected CO2 dissolves in formation water to form an acidic solution, which reacts geochemically with shale minerals, causing changes in the mineral composition and microstructure, thus weakening the mechanical properties of shale.
  • Based on the chemical reaction between SC-CO2 and shale, the low viscosity of SC-CO2, and the thermophysical properties of CO2, SC-CO2 fracturing can decrease the initiation pressure and result in the formation of a more complicated fracture network.
  • Although much research has been conducted on the initiation and growth of supercritical CO2 fracturing, it has focused only on the observation and analysis of surface phenomena. As a result, the interaction law of flow, temperature, and rock mechanical parameters in the process of supercritical CO2 fracturing is still unclear. In future research, it is necessary to use extended finite element, boundary element, or more advanced simulation methods to track the multi-field coupling effects during crack initiation and propagation, supplemented by experimental methods to deeply understand and reveal the mechanisms of crack initiation and propagation.

Author Contributions

Writing—review and editing, Y.C.; writing—original draft preparation, Z.H.; conceptualization, H.W.; investigation, X.Z.; visualization, J.F. and Y.Y. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by the specific research fund of The Innovation Platform for Academicians of Hainan Province, grant number YSPTZX202301, and the National Natural Science Foundation of China, grant number 52004064.

Conflicts of Interest

Author Yuan Yuan was employed by the company Test Team of No.1 Oil Provide Factory, Daqing Oilfield. Author Ye Chen was employed by the company Engineering Technology Research Institute, PetroChina Southwest Oil & Gasfield. The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest. The Daqing Oilfield Limited Company and PetroChina Southwest Oil & Gasfield Company had no role in the design of the study; in the collection, analyses, or interpretation of data; in the writing of the manuscript, or in the decision to publish the results.

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Figure 1. Evaluation of the distribution of shale oil and gas resources.
Figure 1. Evaluation of the distribution of shale oil and gas resources.
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Figure 2. CO2 phase diagram.
Figure 2. CO2 phase diagram.
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Figure 3. Diagram of the Eickmeier wellbore structure physical model and grid division [17].
Figure 3. Diagram of the Eickmeier wellbore structure physical model and grid division [17].
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Figure 4. Axial stress and elastic modulus of shale under different CO2 phases and different saturation times [67].
Figure 4. Axial stress and elastic modulus of shale under different CO2 phases and different saturation times [67].
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Figure 5. SC-CO2 fracturing significantly reduces fracture pressure [75].
Figure 5. SC-CO2 fracturing significantly reduces fracture pressure [75].
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Figure 6. Fracture geometry calculated by using the UFM simulator [128].
Figure 6. Fracture geometry calculated by using the UFM simulator [128].
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Table 1. Geochemical reaction table of minerals and CO2 in shale.
Table 1. Geochemical reaction table of minerals and CO2 in shale.
MineralsEquation
CalciteCaCO3 + H+ ⇌ Ca2+ + HCO3−
DolomiteCaMg(CO3)2 + 2H+ ⇌ Ca2+ +Mg2+ +2HCO3−
KaoliniteAl2Si2O5(OH)4 + 6H+ ⇌ 2Al3 + +2SiO2 + 5H2O
IlliteKAl2(OH)2AlSiO10 + 10H+ ⇌ 2K+ +3Al3+ +3SiO2 + 6H2O
Potassium feldspar2KAlSi3O8 + 2H+ + H2O ⇌ 2K+ + Al2Si2O5(OH)4 + 4SiO2
Sodium feldspar2NaAlSi3O8 + CO2 + 11H2O ⇌ 2Na+ +2HCO3− + 2H4SiO4 + Al2Si2O5(OH)4
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Hou, Z.; Yuan, Y.; Chen, Y.; Feng, J.; Wang, H.; Zhang, X. A Review of Supercritical CO2 Fracturing Technology in Shale Gas Reservoirs. Processes 2024, 12, 1238. https://doi.org/10.3390/pr12061238

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Hou Z, Yuan Y, Chen Y, Feng J, Wang H, Zhang X. A Review of Supercritical CO2 Fracturing Technology in Shale Gas Reservoirs. Processes. 2024; 12(6):1238. https://doi.org/10.3390/pr12061238

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Hou, Zhaokai, Yuan Yuan, Ye Chen, Jinyu Feng, Huaishan Wang, and Xu Zhang. 2024. "A Review of Supercritical CO2 Fracturing Technology in Shale Gas Reservoirs" Processes 12, no. 6: 1238. https://doi.org/10.3390/pr12061238

APA Style

Hou, Z., Yuan, Y., Chen, Y., Feng, J., Wang, H., & Zhang, X. (2024). A Review of Supercritical CO2 Fracturing Technology in Shale Gas Reservoirs. Processes, 12(6), 1238. https://doi.org/10.3390/pr12061238

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