CO₂, used as an environmentally friendly fracturing fluid, has encountered a bottleneck in development in recent years. Despite great efforts in research work, limited progress has been made in field applications. In this study, an extensive literature review of research work and field cases was performed to summarize the technical issues and challenges of CO₂ fracturing. The key issues of CO₂ fracturing were analyzed to reveal the gap between fundamental research and field operations. The effects of CO₂ properties on fracture creation and proppant transport were synthetically analyzed to extract new common research orientations, with the aim of improving the efficiency of CO₂ injection. The hydraulic parameters of CO₂ fracturing were compared with those of water-based fracturing fluids, which revealed a theory-practice gap. By studying the developing trends and successful experiences of conventional fluids, new strategies for CO₂ fracturing were proposed. We identified that the major theory-practice gap in CO₂ fracturing exists in pump rate and operation scale. Consequently, the friction reducer, effects of flow loss (due to leak-off) and distribution (within fracture networks), and shear viscosity of thickened CO₂ are key factors in improving both fracture propagation and proppant transport. By increasing the scale of injected CO₂, the CO₂ fracturing technique can be enhanced, making it an essential option for carbon capture, utilization, and storage (CCUS) to reduce carbon emissions and mitigate climate change.

1 Introduction

Carbon capture, utilization, and storage (CCUS) is an essential technique for achieving the goals set forth in the Paris Agreement, particularly the target of limiting global warming to 1.5°C (Zheng et al., 2022a; Shen et al., 2022; Zhao et al., 2022; Zhu et al., 2022). It plays a crucial role in mitigating greenhouse gas emissions and reducing the concentration of carbon dioxide (CO₂) in the atmosphere (Lab, 2022; Hou et al., 2024a). CCUS enables the capture of CO₂ emissions from various industrial processes, such as power generation, cement production, and steel manufacturing, and then stores the CO₂ underground or utilizes it in other applications (Sharifzadeh et al., 2019; Zhang et al., 2020). This allows for the continued utilization of these traditional assets while simultaneously reducing their carbon footprint. Among all the approaches to carbon sinks, geological storage of CO₂ can permanently remove the largest amount of carbon in a short time compared to other methods such as afforestation, agricultural practices, and chemical applications, among others (Busch et al., 2008; Tao and Clarens, 2013; Godec et al., 2014; Levine et al., 2016).

The ideal underground reservoirs for CO₂ storage primarily include oil and gas reservoirs, saline formations, and salt caverns (Rutqvist et al., 2008; Gilfillan et al., 2009; Jia et al., 2019). In this study, we specifically focus on oil and gas reservoirs due to their well-known geological conditions and well-constructed infrastructures. These factors significantly improve the efficiency, economy, and safety of CO₂ injection and storage (Tayari et al., 2015). The utilization of CO₂ in oil fields has a long history, particularly in the context of enhanced oil recovery (EOR) techniques since the 1950s (Crawford et al., 1963; Lillies and King, 1982). The injection of CO₂ drives and displaces in situ oil and gas, especially the heavier components, by reducing their viscosity and increasing their mobility. This process enhances the ultimate recovery of oil and gas. The remarkable performance of CO₂ injection in both the oil and gas industry and as a carbon sink has drawn worldwide attention. Currently, approximately 80% of the CCUS projects worldwide inject CO₂ into oil and gas formations for EOR, as illustrated in Table 1 (Institute, 2021).

TABLE 1

TABLE 1. Representative CCUS projects worldwide.

However, CCUS in oil fields is facing several technical and environmental challenges. One of the most significant issues is the efficiency of CO₂ storage through the EOR process, which has been reported as low as 20% in previous studies (Zhang R.-H. et al., 2021). In other words, approximately 80% of the injected CO₂ is reproduced along with the extracted oil and gas, necessitating the separation and reinjection of CO₂. Additionally, the migration of CO₂ over geological timescales is currently difficult to predict. Extensive monitoring devices are installed from the surface to track the movement of injected CO₂ in representative CCUS sites, such as the Weyburn project. The continuous movement of CO₂ is monitored over time and injections. This is primarily due to the interconnected pore system in the rock matrix, which provides a pathway through which the mature oil and gas migrate from the source rock into the geological structure, reflecting the nature of a conventional oil and gas reservoir (Goodman et al., 2020).

The CO₂ fracturing technique is an alternative approach to CO₂ storage, distinct from EOR, and is typically employed in unconventional formations characterized by extremely low permeability and water sensitivity (Hou et al., 2024b). As a relatively new technique, CO₂ has demonstrated its efficiency as a working fluid in reducing the breakdown pressure of the formation and increasing the stimulated volume following hydraulic injection (Hou et al., 2021). Extensive laboratory research has been conducted to elucidate the rock-mechanical and flow-dynamical characteristics of CO₂ fracturing (Xiangzeng et al., 2014; Wang H. et al., 2019). Corresponding chemical additives have also been developed to enhance the performance of CO₂. Field trials have indicated that the flowback rate of CO₂ after hydraulic injection is significantly lower compared to that after EOR (Yiyu et al., 2021; Honglei et al., 2022). However, the CO₂ fracturing technique is still in the field-trial stage compared to CO₂ EOR. It injects CO₂ at much higher pressures and rates than in EOR injections, resulting in increased investment and challenges (Jing et al., 2022). Furthermore, there exists a gap between previous laboratory-scale efforts and practical field applications at a larger scale.

This study focuses on identifying the disparity and deficiencies between the theory and practice of CO₂ fracturing, with the aim of bridging this gap. Firstly, CO₂ fracturing is redefined and limited to supercritical CO₂ (SC-CO₂) fracturing, which presents a more environmentally friendly solution for CCUS in the oil and gas industry. Secondly, an extensive literature review is carried out to summarize the performances of fracture creation and proppant transport by CO₂—the major tasks of a hydraulic fracturing fluid. By conducting a systematic analysis of research findings and field trials related to CO₂ fracturing, we propose several promising research directions that can advance the field and enhance the efficiency of CO₂ fracturing in practical applications. Through these efforts, we anticipate the CO₂ fracturing technique to become an essential supplement and approach for CCUS in oil and gas reservoirs.

2 History and restricted definition of CO₂ fracturing

The history of CO₂ fracturing can be traced back to the 1970s when it was first experimented with as a method for enhancing oil recovery. Initial trials focused on using CO₂ as a miscible fluid to displace oil from reservoirs, with CO₂ being injected as a liquid from the wellhead. In order to enhance the performance of CO₂ fracturing and flooding, CO₂ was combined with foam-based fracturing techniques, leading to the development of CO₂ foam fracturing in the early 2000s (Martin and Taber, 1992; Yost et al., 1993). The use of foam in CO₂ fracturing offers several advantages over traditional hydraulic fracturing methods. Firstly, the foam acts as a carrier for the CO₂, reducing the amount of CO₂ required to achieve the desired fracturing effect. Secondly, the viscosity of CO₂ foam is significantly improved, enhancing the transport capacity of proppants (Lv et al., 2017). However, the behavior and stability of CO₂ foam under formation conditions present challenges due to the phase change of CO₂ from a gaseous to a supercritical phase. The quality of the foam plays a crucial role in fracture generation, propagation, and production enhancement. Moreover, the use of water in CO₂ foam is inevitable, which can lead to permeability and conductivity losses in water-sensitive formations.

With the revolution of unconventional oil and gas, a more specific definition of CO₂ fracturing has emerged - supercritical CO₂ (SC-CO₂) fracturing, also known as water-free fracturing (Middleton et al., 2015; Sanguinito et al., 2018; Wang et al., 2019). This technique utilizes 100% CO₂ as the primary fracturing fluid to prevent damage caused by water in unconventional formations. In reservoirs buried approximately 800 m deeper, the injected CO₂ undergoes a transition into a supercritical phase state, characterized by temperatures and pressures above the critical point (7.3 MPa, 31°C). The phase state transition of CO₂ (from supercritical state to liquid state) has been observed and illustrated in Figure 1. In the process of supercritical CO₂ fracturing, CO₂ is initially pressurized and heated to reach its supercritical state at the surface. This supercritical CO₂ is then mixed with proppant and injected into the wellbore to fracture the targeted reservoir zone. Supercritical CO₂ exhibits high density, low viscosity, low surface tension, high diffusion coefficient, and excellent heat and mass transfer properties (Hou et al., 2021). As a fracturing fluid, it does not harm the reservoir, effectively avoiding near-wellbore formation damage, protecting the oil and gas reservoir, improving reservoir permeability, and facilitating easy flowback, compared with the traditional water-based fracturing fluids. Moreover, supercritical CO₂ fracturing fluid can dehydrate tight clay formations, open up sandstone pore channels, and reduce the skin factor of the wellbore.

FIGURE 1

FIGURE 1. CO₂ phase transitions (from the supercritical state to CO₂ liquid) observed through a pressure-resistent window during a depressurization and cooling process, from 8.10 MPa to 42.5°C (I) to 5.80 MPa and 12.6°C (IV).

In this study, we adopt a specific definition of CO₂ fracturing, specifically referring to supercritical CO₂ (SC-CO₂) fracturing, which is distinct from other forms of CO₂ fracturing such as CO₂ foam. For one reason, the focus on supercritical CO₂ fracturing is justified by its similarity to the process of CO₂ storage, as it eliminates the use of water and demonstrates higher efficiency in CO₂ storage (Hou et al., 2020; Hou and Elsworth, 2021). The flowback rate of fracturing injected CO₂ is lower than other forms of CO₂ storage, for instance, CO₂-EOR (Hou et al., 2024b). This indicates a higher efficiency of permanent CO₂ storage. This approach presents a more environmentally friendly solution for CCUS in the oil and gas field. For the other reason, CO₂ fracturing represents one of the most promising approaches to large-scale carbon sinks. If water-based fracturing operations could be replaced by CO₂ fracturing, one single horizontal well may store more than ten thousand tons of CO₂. Considering that thousands of wells may be fractured in a single oil or gas field, the CO₂ storage capacity by CO₂ fracturing shows enormous potential. Therefore, the promotion of CO₂ fracturing for CCUS represents a critical approach to carbon sinks and carbon neutrality.

3 Results

3.1 Fracture creation by CO₂

Fractures formed through supercritical CO₂ fracturing exhibit distinct characteristics that are influenced by the properties of supercritical CO₂. One notable effect is the reduction in the breakdown pressure of the formation, allowing for easier penetration into the rock matrix due to its low viscosity, high diffusivity, and absence of surface tension. Supercritical CO₂ exhibits a lower viscosity (three magnitudes or even smaller) compared to alternative fracturing fluids like water-based fluids (Kuang et al., 2023). This attribute allows for smoother flow through minuscule pores and fractures within the reservoir rock, enabling deeper penetration into the rock matrix and generating fractures with enhanced tortuosity. This characteristic allows the injected fluid to effectively access the pre-existing fracture, and as the induced fracture propagates along its path, there is a significant reduction (∼50%) in breakdown pressure (Zhang et al., 2017a; Li et al., 2019; Zhang et al., 2021; Feng and Firoozabadi, 2023), as summarized in Table 2.

TABLE 2

TABLE 2. Comparisons between the fractures created by SC-CO₂ and water-based fluids (Zhang et al., 2017a; Li et al., 2019; Zhang et al., 2021; Feng and Firoozabadi, 2023).

Laboratory tests have indicated that fractures created by CO₂ have higher tortuosity, as illustrated in Figure 2 (Song et al., 2019). Tortuosity pertains to the extent of deviation from a linear trajectory observed in fractures. The higher degree of fracture tortuosity indicates that CO₂ follow intricate routes within the reservoir rock, thereby augmenting their interaction surface. Additionally, CO₂ fracturing holds the potential to generate a more intricate network of interconnected fractures within the reservoir, surpassing the complexity of fractures induced by water-based fluids (Wang and Sharma, 2023). This characteristic enhances the fracture surface area and the volume of the reservoir that is stimulated. The increased fracture surface area provides more flowing pathways for in situ hydrocarbons during production operations, thus improving well productivity and enhanced recovery rates from unconventional formations.

FIGURE 2

FIGURE 2. The fracture morphology created by CO₂ and fracturing fluids. Reproduced with permission from Ref. Song et al. (2019), copyright (2019) Elsevier.

However, a significant challenge associated with CO₂-created fractures is their underdeveloped width, primarily due to the high rate of CO₂ leak-off and the net stress loss within the fracture. This loss of driving force leads to narrower and shorter fractures (Zhou and Burbey, 2014; Wang et al., 2017; Ranjith et al., 2019). The average fracture aperture of water, N₂, L-CO₂ and SC-CO₂ shows relatively small variances falling in the range between 0.304 mm and 0.317 mm, as presented in Figure 3. However, the largest standard deviation (0.201) of the aperture formed by SC-CO₂ fracturing is obtained, followed by water fracturing (0.171), L-CO₂ fracturing (0.123), and N₂ fracturing (0.091). This suggests the maximum roughness of the fractures created by SC-CO₂ (Yang et al., 2021). Furthermore, given the higher complexity and tortuosity of CO₂-created fractures, the injection of proppants afterward becomes more challenging, resulting in elevated operation wellhead pressures. More careful planning and innovative solutions tailored specifically for CO₂ fracturing techniques are essential to overcome these challenges posed by narrow and short CO₂-created fractures with complex geometries.

FIGURE 3

FIGURE 3. The distribution of fracture apertures induced by CO₂ and fracturing fluids. Reproduced with permission from Ref. Yang et al. (2021), copyright (2022) Elsevier.

3.2 Proppant transport by CO₂

In addition to the more challenging conditions for proppant transport, a significant hurdle in CO₂ fracturing is the low viscosity of supercritical CO₂, which is similar to gaseous CO₂. As a result, proppant particles settle rapidly, leading to the formation of accumulations known as dunes (Hou et al., 2015). These dunes vary in shape and size as continuous injections progress. Within fractures, the proppant is then transported in the form of these dunes, creating a dynamic and complex process, unlike water-based high-viscosity fluids that evenly suspend the proppant (Hou et al., 2022a; Hou et al., 2022b). When the mass flow remains constant, altering the injection temperature to a higher value or reducing the injection pressure will lead to a decrease in both viscosity and density of supercritical CO₂, resulting in evolutions of equilibrium height and distance for dune transport, as presented in Figure 4 (Zheng et al., 2022b).

FIGURE 4

FIGURE 4. Effects of injection temperature and pressure on dune equilibrium height and length based on experiments. Reproduced with permission from Ref. Zheng et al. (2022b), copyright (2022) Elsevier.

Furthermore, the high leak-off of CO₂ and the distribution of the injected fluid in complex fracture networks exacerbate proppant accumulation and can even cause sand screen-out due to the loss of the carrying fluid. Previous studies have demonstrated the influence of supercritical CO₂ on the settling, restarting, and flowing behaviors of proppants (Hou et al., 2017a; Chen and Sun, 2023). It has been observed that the high density of CO₂, which is similar to liquid CO₂, contributes to an enhanced capacity for proppant transport in supercritical CO₂, as depicted in Figure 5. Each black point (P1, P2, P3, P4 and P5) represents a proppant particle captured by the high-speed camera. The dashed lines derived from the black points represent the moving trajectory of the proppant particles, which are plotted automatically by the image analysis software. The terminal settling velocity of proppants in CO₂ is slightly higher, within the same magnitude, compared to settling velocities in water (Hou et al., 2015). Additionally, the slippage between the particles and the carrying CO₂ can be eliminated by increasing the flow rate of the slurry (Hou et al., 2017b). Restarting the movement of particles in CO₂ is even easier than in water due to the absence of interfacial tension and the generation of additional Magnus force through high-speed spinning, facilitating the restarting process (Hou et al., 2019).

FIGURE 5

FIGURE 5. Proppant particle movements (trajectories in colorized dashes), from the right side to the left side, in supercritical CO₂ captured by the high-speed camera.

3.3 Improving the research work on CO₂ fracturing

The primary objectives of a fracturing fluid are to create fractures and transport proppants. However, CO₂ fracturing faces significant challenges in both areas, as outlined in Figure 6. In terms of fracture creation, there are several approaches that can be employed to improve performance. These include reducing the leakage of CO₂ into the rock matrix and natural fractures, establishing net stress within the fractures, and then enhancing the propagation of fracture networks. On the other hand, the capacity of CO₂ to carry proppants can be enhanced by addressing issues such as particle settling, eliminating slippage between the particles and CO₂, and improving proppant transport within complex fracture networks.

FIGURE 6

FIGURE 6. Synthetical analyses of fracture creation and proppant transport regarding CO₂ fracturing.

In order to address these challenges, various solutions have been analyzed and summarized in Figure 6. One common approach is the use of CO₂ thickeners, which increase the viscosity of the fluid. This serves to reduce both proppant settling and CO₂ leak-off (Enick et al., 2012; Al Hinai et al., 2018). Additionally, it has been observed through numerical and experimental simulations that fracture width and particle slippage are influenced by the CO₂ pump rate. Higher pump rates facilitate fracture growth and help eliminate slippage (Lei et al., 2016). CO₂ leak-off is another prevalent issue that hampers fracture propagation and proppant transport. Therefore, promising research directions for improving CO₂ as a fracturing fluid include the development of friction reducers, investigating the effects of flow loss (caused by leak-off) and distribution (within fracture networks), as well as studying the shear viscosity of thickened CO₂ (the performance of the thickener under high pump-rate condition).

4 Discussion

4.1 Case study of CO₂ fracturing

The CO₂ fracturing technique is mainly applied in unconventional formations that have extremely tight rock matrix and nano-Darcy permeability (decreasing the leak-off of CO₂). Three representative cases of CO₂ fracturing in tight oil, shale gas, and shale oil formations are summarized in Table 3 (Meng et al., 2016; Yiyu et al., 2021; Jing et al., 2022). Case A uses pure CO₂ for cracking fractures and carrying proppant. Two types of additives are tested to increase the viscosity of CO₂ and its proppant-carrying capacity. Cases B and C only use CO₂ to crack the formation and create complex fracture networks. The high-viscosity gel is applied afterward to further develop the networks and carry the proppant. Generally, both the fracturing scale and pump rate are relatively small for CO₂ fracturing compared with those for water-based fracturing.

TABLE 3

TABLE 3. Summary of CO₂ fracturing cases.

Approximately ∼300 m³ of CO₂ is injected in each well or stage, with approximately ∼180 m³ of CO₂ injected in each stage of the horizontal well in Case C. The pump rate may be restricted by the high friction encountered along the wellbore when using CO₂, resulting in a high wellhead pressure of approximately ∼65 MPa, as indicated in Table 3. The sand ratio in Case A is around 5.6%, which is less than half of the sand ratio typically used in water-based fracturing. The efficiency of CO₂ fracturing in field trials is relatively low due to the limited scale of fracturing (both proppant and CO₂ volumes), low sand ratio, restricted pump rate, and comparatively high injection pressure. This could be one of the main reasons, as well as the high cost of CO₂ additives, why recent tests have opted for a hybrid approach that combines CO₂ injection with water-based fracturing, as illustrated in Cases B and C.

4.2 Potential of CO₂ fracturing for CCUS

Most of the current CO₂ fracturing field cases are reported along with the development of shale oil in China (Hou et al., 2024a). The field engineers injected CO₂ as a pre-fracturing process, aiming to create more complex fracture networks. The following injected conventional water-based fluids continuously develop the fracture dimensions and transport the proppant into fractures (Yang et al., 2022). Therefore, the usage of CO₂ (several hundred scales for each fracturing stage) is significantly smaller than the water-based fluids for the main fracturing operation, as listed in Table 3. However, the flowback rate of fracturing injected CO₂ is approximately one order of magnitude lower than other forms of CO₂ storage (as shown in Figure 7), indicating a higher efficiency of permanent CO₂ storage (Louk et al., 2017; Hou et al., 2024a). The usage of CO₂ may be improved by increasing its proportion in the total fracturing fluids. A possible approach is using CO₂ to share the proppant injection task, for instance, carrying the fine proppant (100 mesh) (Hou et al., 2017a; Hou et al., 2017b). Meanwhile, the developments of the carbon market and carbon capture techniques may reduce the cost of CO₂ sources. The policy incentives are also essential to encourage the operators to promote the usage of CO₂, for instance, the tax preference applied in the United States (Ren et al., 2022). The increasing proportion and decreasing cost may significantly promote the potential and contribution of CO₂ fracturing to CCUS, considering the huge consumption of fracturing fluids.

FIGURE 7

FIGURE 7. Recovery of CO₂ after injections in (A) CO₂ huff-and-puff case and (B) CO₂ fracturing case. Reproduced with permission from Ref. Hou et al. (2024a), copyright (2024) Elsevier.

The other challenge of CO₂ fracturing for CCUS is the mismatch between CO₂ sources and fracturing sites (Munkejord et al., 2016), for instance, transporting the captured CO₂ from power plants to oil and gas fields. Pipelines may be necessary for the continuous transport of CO₂ for huff-and-puff, EOR or direct storage in relatively fixed sites (Onyebuchi et al., 2018). Trucks may be essential for fracturing operations to transport CO₂ from one site to another (Gao et al., 2011). Both pipelines and trucks will increase the investments in construction and equipment, as well as the potential for extra CO₂ emissions. Therefore, CO₂ transport has become a common issue for all kinds of CO₂ storage because of the geographical distance between CO₂ sources and storage sites. For CO₂ fracturing, a hybrid transport system may be a solution to improve the flexibility of CO₂ transport from site to site.

4.3 Gap between theory and practice

Although fundamental research has highlighted the advantages and feasibility of CO₂ fracturing, field trials have encountered significant challenges, as summarized in Table 3. To reveal the disparity between the theory and practice of CO₂ fracturing, we compared key injection parameters recorded during field operations using different fracturing fluids, as presented in Figure 8. Initially, in conventional reservoirs, guar gel (referred to as the first generation of fracturing fluid) was used to create large bi-wing fractures with a high concentration of large proppants. Subsequently, slickwater (with lower viscosity) was employed at a much higher pump rate to carry smaller proppants at lower concentrations, achieving a balance between fracturing efficiency and investment-production ratio (Barati and Liang, 2014; Zhang et al., 2017b). CO₂ fracturing, known as the third generation of fracturing fluid, is considered environmentally friendly. Pump rates and injection scales are both reduced for CO₂ fracturing, reflecting its status as a developing technique.

FIGURE 8

FIGURE 8. Comparison of hydraulic parameters for field operations among the three generations of fracturing fluid.

Compared to conventional fluids, the disparity between fundamental research and field application primarily lies in pump rate and operation scale, as depicted in Figure 8. Current efforts to thicken CO₂ may draw inspiration from the success of first-generation fluids, characterized by high viscosity gel. However, the second-generation fluid (represented by low-viscosity slickwater) compensates for the low-viscosity drawback with a high pump rate, which offers valuable insights. Therefore, the utilization of friction reducers becomes another crucial technique for CO₂ fracturing. Correspondingly, the performance of CO₂ thickener (enhanced CO₂ viscosity after the high-pump-rate shear) becomes an essential criterion for the relevant research, which currently is barely reported. Other valuable insights include enhancing fracturing scales through the development of low-cost additives, increasing the proportion of fine proppant, and adopting hybrid approaches that incorporate water-based fluids (inspired by Cases B and C).

The relatively low pump rate may represent one of the most significant gaps between the theory and practice of CO₂ fracturing. Firstly, the proppant usually settles down rapidly in low-viscosity fluids (CO₂ and slickwater). The horizontal transport distance of the proppant before its settlement reduces under a low pump rate condition due to the lower horizontal dragging force (Hou et al., 2017b; Hou et al., 2019). This significantly constrains the proppant transport capability of supercritical CO₂, and then the scale of proppant injection in fields (Table 3). Secondly, the high diffusion feature of supercritical CO₂ induces a high leak-off of fluid from fractures into the formation. The low pump rate may weaken the supplementary fluid in fractures, thus constraining the propagation of fracture networks. Meanwhile, the relatively low fracturing scale further deteriorates the development of underground fractures. Correspondingly, the stimulated reservoir volume is restricted for enhancing oil/gas production. Regarding the CO₂ storage concern, the low fracturing scale reduces the usage of CO₂ during fracturing operations. The limited artificial fracture volume will further decrease the inventory capacity of CO₂ storage in unconventional reservoirs, because the artificial fracture may contribute most to the capacity of CO₂ storage (Hou et al., 2024a; Hou et al., 2024b). Therefore, the relatively low fracturing scale may represent the other critical gap between the theory and practice of CO₂ fracturing in accordance with the aforementioned rationale.

5 Conclusion

(1) The primary disparity between theory and practice in CO₂ fracturing lies in pump rate and operation scale.

(2) New research directions for improving both fracture propagation and proppant transport in CO₂ fracturing include the use of friction reducers, addressing flow loss caused by leak-off and distribution in fracture networks, and enhancing the shear viscosity of thickened CO₂.

(3) Field operations of CO₂ fracturing can be optimized by enhancing scales through the incorporation of low-cost additives, increasing the proportion of fine proppant, and utilizing a hybrid approach that integrates conventional fluids.

Author contributions

LH: Conceptualization, Funding acquisition, Methodology, Writing–original draft, Writing–review and editing. JL: Writing–review and editing. PG: Data curation, Methodology, Writing–review and editing. YJ: Conceptualization, Investigation, Writing–review and editing. LZ: Data curation, Investigation, Writing–review and editing.

Funding

The authors declare that financial support was received for the research, authorship, and/or publication of this article. This research is funded by the National Natural Science Foundation of China under the grant 42377138.

Conflict of interest

Author PG was employed by Shengli Oilfield Service Corporation.

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.

Publisher’s note

All claims expressed in this article are solely those of the authors and do not necessarily represent those of their affiliated organizations, or those of the publisher, the editors and the reviewers. Any product that may be evaluated in this article, or claim that may be made by its manufacturer, is not guaranteed or endorsed by the publisher.

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