A Review of Fracturing and Enhanced Recovery Integration Working Fluids in Tight Reservoirs

Abstract

Tight reservoirs, characterized by low porosity, low permeability, and difficulty in fluid flow, rely on horizontal wells and large-scale hydraulic fracturing for development. During fracturing, a significant volume of fracturing fluid is injected into the reservoir at a rate far exceeding its absorption capacity. This not only serves to create fractures but also impacts the recovery efficiency of tight reservoirs. Therefore, achieving the integration of fracturing and enhanced recovery functions within the working fluid (fracturing-enhanced recovery integration) becomes particularly crucial. This study describes the concept and characteristics of fracturing-enhanced recovery integration and analyzes the types and features of working fluids. We also discuss the challenges and prospects faced by these fluids. Working fluids for fracturing-enhanced recovery integration need to consider the synergistic effects of fracturing and recovery; meet the performance requirements during fracturing stages such as fracture creation, proppant suspension, and flowback; and also address the demand for increased recovery. The main mechanisms include (1) enlarging the effective pore radius, (2) super-hydrophobic effects, and (3) anti-swelling properties. Fracturing fluids are pumped into fractures through pipelines, where they undergo complex flow in multi-scale fractures, ultimately seeping through capillary bundles. Flow resistance is influenced by the external environment, and the sources of flow resistance in fractures of different scales vary. Surfactants with polymerization capabilities, biodegradable and environmentally friendly bio-based surfactants, crosslinking agents, and amino acid-based green surfactants with outstanding properties will unleash their application potential, providing crucial support for the effectiveness of fracturing-enhanced recovery integration working fluids. This article provides important references for the green, efficient, and sustainable development of tight oil reservoirs.

1. Introduction

The rapid development of the economy and society demands more oil and gas resources. In recent years, conventional oil and gas production has declined, coupled with China’s dependency on foreign sources exceeding 70%. Therefore, it is urgent to increase domestic unconventional oil and gas production. Tight reservoir oil and gas reserves have been increasing, becoming some of the most important future resources [1,2]. Typically, tight reservoirs have characteristics such as low permeability, difficulty in flow, large burial depth, and low natural energy [3,4]. Challenges such as the low injection capacity of water injection wells and difficulty in well productivity enhancement have emerged. Hydraulic fracturing technology is one of the key methods of increasing production [5,6,7,8,9,10]. Fracturing fluid plays an important role in fracturing, and its performance directly affects the effectiveness of the transformation. Therefore, research on fracturing fluid performance has been particularly important [11].

To achieve various reservoir stimulation effects, a fracturing fluid must typically be a complex system composed of multiple components. The major component is the solvent (for water-based fracturing fluids, the solvent is water) [12]. To increase viscosity and thickening, polymers are added. To suppress clay swelling, clay stabilizers or anti-swelling agents are added. Proppants are added to support the fracture during and after fracturing. Breakers are added to facilitate fluid flowback. In certain formations, biocides and pH adjusters may also be added to improve fracturing effectiveness. Fracturing fluid transfers energy to formation rocks and initiates and propagates fractures, constituting a dynamic flow process. The fracturing fluid is typically required to have characteristics such as good compatibility, low friction, suspending ability, easy flowback, thermal resistance, shear resistance, low filtration, minimal residue, low reservoir damage, and low cost [13].

After fracturing, the well undergoes shut-in and flowback, followed by the production phase. Therefore, fracturing and drainage operations are closely interconnected in their processes. Surfactants and polymers contained in fracturing fluids have oil displacement efficiency. Polymer molecules entangle in the solution, increasing the viscosity of the polymer solution compared with water-driven systems, thereby enhancing the oil–water mobility ratio. By adsorbing on pore surfaces and capturing residual oil trapped in porous media, the effective permeability of water is reduced, leading to increased sweep volume and recovery rate. Surfactants reduce the interfacial tension between oil and water, promoting the formation of emulsions with crude oil. They exhibit strong residual oil capture capabilities within pores, resulting in improved sweep efficiency and enhanced recovery [14].

Fracturing operations impact subsequent shut-in and flowback processes, thereby influencing the recovery rate. So, fracturing fluids not only meet the performance requirements for fracturing but also consider the need to enhance recovery. Integrated fracturing and enhanced recovery fluids are a future tendency, and the development of multifunctional integrated fluids has been deemed essential. This paper first elaborates on the concept of integrated fracturing and enhanced recovery and summarizes the demand characteristics of integrated fluids, including the operational requirements for fracturing and the requirements for production. Then, it introduces the types and features of integrated fluids and provides prospects for the development of integrated fluids based on this foundation.

2. The Function of Integrated Fracturing and Enhanced Recovery and the Characteristics of Working Fluids

2.1. The Function of Integrated Fracturing and Enhanced Recovery

The applicability of secondary and tertiary oil recovery techniques used in conventional reservoirs faces significant challenges; the aim is to inject hydrocarbon gases into the reservoir and use fracturing fluids containing various additives to complete a single injection during the fracturing stage, benefiting the entire lifecycle of well development. Therefore, the concept of integrated fracturing and enhanced recovery for shale oil reservoirs is proposed as an inevitable development. Its main function lies in integrating the design and procedures of increasing recovery rates during the fracturing process. The approach is to adhere to the concept of integration when designing shale oil fracturing, considering the role of fracturing fluids in replenishing energy and displacement outside the fracture network, and implementing integrated fracturing and enhanced recovery technologies in field operations.

2.2. Characteristics of Integrated Fracturing and Enhanced Recovery Fluid

Tight oil and gas resources are characterized by large geological reserves and wide distribution, possessing tremendous exploitation potential, and have become an important source for increasing oil and gas production [15,16]. Currently, research on tight reservoir oil and gas resources, including theory, technology, and applications, is becoming increasingly important. Along with this, fracturing fluid continues to evolve in response to technological advancements, operational requirements, and reservoir characteristics. During the fracturing process, fracturing fluid plays roles such as transferring energy, carrying proppants, and forming and communicating fractures [17].

Enhancing oil recovery is achieved through well shut-in optimization and flowback control. Well shut-in is conducted after hydraulic fracturing, during which fracturing fluid migrates deeper into a formation through imbibition, alleviating water blockage and enhancing gas flow rates upon well opening. Imbibition in shale formations may further induce new fractures or reopen closed ones, thus increasing matrix permeability and offering a new approach to boosting oil and gas well production and recovery rates [18]. Currently, there are two main types of fracturing fluids that align with the concept of integrated fracturing and recovery: one composed primarily of surfactants, forming a clean fracturing fluid system, and the other involving the addition of imbibition agents to conventional fracturing fluid systems. Both types exhibit lower interfacial tension, allowing them to reside in formation pores and enhance oil imbibition efficiency. The difference lies in their mechanisms of action. Surfactants primarily increase recovery by reducing surface tension and altering wettability, whereas imbibition agents enhance the fracturing fluid’s penetration ability to achieve improved recovery. Integrated fracturing and recovery fluids utilize mechanisms such as interfacial adsorption, wettability alteration, micellar solubilization, and oil–water displacement to induce spontaneous imbibition and enhance crude oil recovery efficiency [19,20,21,22,23,24].

During hydraulic fracturing, it is crucial for fracturing fluids to ensure smooth operations. Once these fluids enter the formation and come into contact with the reservoir, they have an influence on subsequent recovery processes. Therefore, the evaluation of fracturing fluid performance should not be limited to conventional fracturing fluid characteristics but should also focus on recovery performance. Integrated fluids need to meet the requirements of both the initial fracturing and subsequent recovery processes, as shown in

Table 1. Performance characteristics of working fluid in various processes.

Operation Process	Characteristics of Working Fluid
Fracturing	High-temperature resistance, shear resistance, salt resistance, sand-carrying capacity, anti-swelling property, friction reduction, and low fluid loss
Production	Low interfacial tension, anti-swelling property, low residue, moderate return permeability, easy breakage of gel, and low damage

, for the performance demands of each stage. Commonly used polymers, surfactants, and gas-based additives are combined to assess both fracturing and recovery performance, achieving the desired characteristics for integrated fluids. For example, blended surfactants have low surface tension and interfacial tension, forming three-dimensional micelle structures that act to suspend sand and reduce friction. These surfactants exhibit strong shear resistance and salt tolerance. After micelle structure breakdown, they become small molecules that aid in flowback, causing minimal formation damage. They spontaneously infiltrate pores, displacing the oil phase and enhancing oil and gas recovery efficiency. Integrated fluids are a key technology for improving fracturing effectiveness, reducing secondary damage, and enhancing fracture conductivity. They break the constraints of traditional multiple additive applications, reduce construction procedures, and lower costs, making them significant for unconventional oil and gas development.

3. Types and Characteristics of Integrated Fracturing and Enhanced Recovery Fluids

3.1. Polymer-Based Working Fluids

Polymers are one of the most commonly used additives and include both natural and synthetic types. The former type mainly comprises guar gum and its modified forms [25], while the latter primarily consists of polyacrylamide and its modified derivatives [26]. Due to their relatively large molecular weight, polymers form spatial network structures through intra- or intermolecular interactions, resulting in viscosity enhancement, thereby achieving functions such as sand suspension and friction reduction [27,28,29]. To address various reservoir characteristics, technological processes, construction conditions, and encountered issues, a wide range of functional monomers can be selectively synthesized as needed, gradually contributing to the development of multiple synthetic polymer fluid systems [30,31,32,33,34].

Zirconium is one of the most commonly used crosslinking agents in fracturing fluids. The future of this technology lies in synthesizing organozirconium crosslinkers that simultaneously offer high-temperature resistance and controllable crosslinking times. The introduction of temperature-resistant monomers substantially increases the thermal stability of polymers, further enhancing their applications in oilfields [35]. While partially hydrolyzed polyacrylamide is the most commonly used friction reducer, its effectiveness in high-temperature, high-salinity environments is limited by its poor salt resistance and thermal stability. Therefore, there is a need to develop new polymers suitable for harsher conditions [36]. In high-salt formations, conventional polymer chains reduce fluid volume and weaken interactions, leading to decreased polymer system performance. The structure of the hydrophobic association polymer can produce a stable and robust network structure that can effectively resist the harmful effects of salt ions [37].

Unconventional reservoirs such as tight oil and gas typically employ slickwater fracturing fluid to create fractures and reduce friction [38,39]. Novel dopamine hydrochloride-modified hydrophobic association polymers exhibit not only good comprehensive properties based on their porous network structures but also excellent viscosity [40]. Considering the damage to formations caused by residue after fracturing flowback, green and clean nanocomposite friction reducers have been developed, showing excellent properties such as non-toxicity, non-hazardousness, and resistance to salt and temperature [41]. Emulsion-based slickwater fracturing fluids exhibit rapid viscosity buildup, eliminating the need for pre-mixing; exhibit continuous blending units; and offer good viscoelastic properties, thus reducing operational costs. However, their sand-carrying and friction-reducing capabilities typically decrease in temperatures higher than normal, necessitating the preparation of high-temperature emulsion-thickening agents to meet the demands of deep unconventional reservoir transformations. Premature crosslinking can result in frictional pressure loss and the mechanical degradation of the fracturing fluid along the long wellbore [42]. In cases where a single working fluid system cannot meet the technical requirements of fracturing in special low-permeability oil and gas reservoirs, combining polymers with CO₂ foam fracturing fluid systems can maintain stable structure and performance, showing promising applications.

Guar gum is a commonly used fracturing additive due to its wide availability and low cost, and it is still utilized in some oilfields. However, pure guar gum needs improvements in terms of its gel breaking and temperature resistance. Commonly used modification methods include esterification, oxidation, crosslinking, grafting, and etherification [43,44,45,46,47]. A hydrophobic region can be introduced into guar gum through the graft copolymerization of hydrophobic monomers. As illustrated in Figure 1, these graft copolymers form polymer micelles and aggregates in aqueous environments, but the micelles disperse in oil–water mixtures [47].

To address highly insoluble substances and poor temperature resistance in guar gum solutions, various new modifications have been developed. For instance, a new type of anionic guar gum derivative was developed and modified by grafting with maleic anhydride. Compared with the original guar gum, the insoluble content decreased from 13% to 5%, and the decomposition temperature increased from 285 °C to 308 °C [48]. Another example is the preparation of a novel fluorinated hydrophobic cationic guar gum, which exhibits improved heat resistance and shear resistance. This enhancement is beneficial for increasing guar gum’s fracturing and proppant-carrying capacity, resulting in low residual content and minimal damage to formations [49]. By synthesizing fluorinated monomers from di-isocyanates and 1, 2, 3, 4, 4, 4-hexafluoro-1-butanol and using cationic guar gum and fluorinated reactive monomers as raw materials, fluorinated cationic guar gum can be prepared. Various test results indicate the further enhancement of its temperature resistance [50]. Additionally, by employing a potassium bromate–sulfur dioxide–thiourea redox system, acrylamide polymer was grafted onto guar gum, and the prepared polyacrylamide–guar gum graft copolymer was further crosslinked with glutaraldehyde, resulting in a multifunctional modified guar gum material with significantly improved adsorption performance [51].

3.2. Surfactant-Based Fracturing Fluids

Based on their charge, surfactants are classified into cationic, anionic, nonionic, and amphoteric surfactants, with each type possessing unique characteristics [52]. Surfactant fracturing fluids exhibit several advantages such as simple formulation, no need for crosslinkers or breakers, low friction, and low formation damage. Under some conditions, they form various structural micelles that intertwine to create a complex, reversible three-dimensional network, displaying distinctive fluid properties [53,54]. Compared with guar gum and partially hydrolyzed polyacrylamide, clean working fluids offer advantages such as easy breaking, efficient flowback, no residue, and minimal risk of causing secondary formation damage [55,56]. When the surfactant concentration exceeds the critical micelle concentration, supramolecular structures are formed through non-covalent interactions between molecules, resulting in micelles with a certain spatial arrangement. Micelles will aggregate to form microscopic spheres, rods, and plates, which will subsequently form microscopic spheres on the rock surface. This microstructure plays a crucial role in friction reduction and proppant suspension. The unique properties of surfactant working fluids are closely related to their microstructure. By utilizing non-covalent interactions between molecules, it is possible to create large pseudo-polymeric surfactants, forming worm-like micelles. The structure of these micelles is highly influenced by external factors, such as pH. Surfactant working fluids have low viscosity and high leak-off, leading to increased costs. The use of cationic surfactants may lead to the blockage of oil and gas flow channels by altering wettability. Additionally, as depicted in Figure 2 and Figure 3, their thermal stability is inferior compared with polymer-based fluids [57,58,59]. Therefore, surfactants can be combined with nanoparticles to form crosslinked structures, which can enhance filter cake formation and improve thermal stability.

Surfactants can be synthesized using chemical reagents. For instance, carboxymethyl chitosan-based amphoteric surfactants have been synthesized using N,N-dimethyl dodecylamine and sodium chloroacetate as raw materials. This substance has lower interfacial tension and critical micelle concentrations (500 ppm) and can alter the wettability characteristics of rock surfaces [60]. Additionally, natural substances can be used as alternatives to chemical reagents for preparation. Anionic polymer surfactants are prepared using cashew nut shell liquid as a raw material. These surfactants exhibit comparable viscosity to conventional polymers and non-Newtonian shear thinning behavior. They maintain stable performance at 80–120 °C, and the salt in them further enhances the wettability alteration of oil-wet rocks into water-wet rocks [61].

A single surfactant system may not meet the requirements for fracturing operations. Surfactants can be combined with other types of surfactants or polymers and supplemented with additional additives to develop multifunctional surfactant working fluids that possess oil displacement properties, thereby enhancing overall operational efficiency [62,63]. Nanomaterials and nanotechnology are widely used in oilfields, but nanomaterials typically cannot be used alone and require processing through specific physicochemical methods to prepare nanocomposite working fluid systems [63]. For example, hydrophobic nanomaterials modified with C8 and hydrophobic electroneutral nanomaterials modified with quaternary ammonium salts can be used to formulate functional polymer-based cleaning working fluids. These fluids exhibit low damage, low surface tension, high friction reduction rates, and temperature and shear resistance and can also promote oil–water separation to enhance oil displacement performance.

Conventional surfactants are prone to structural degradation or adsorption on rock surfaces under reservoir conditions. Gemini surfactants, also known as dimeric surfactants, have gradually become the focus of researchers due to advantages such as lower critical micelle concentration and excellent water solubility [64]. They connect two or more conventional surfactant molecules together at or near the hydrophilic base through a linking group, forming an effective novel surfactant. They typically consist of at least two hydrophobic chains, two hydrophilic head groups, and one linking group, which strengthens the hydrophobic binding force between carbon chains, enhancing the tendency of hydrophobic chains to escape from water environments while reducing the repulsion between hydrophilic groups. These properties, such as solution and aggregate behavior, make their physicochemical properties more prominent [65,66]. Gemini surfactants are more likely to tightly adsorb on interfaces, converting high interfacial energy into low interfacial energy, thus enhancing wetting. They exhibit good water solubility, high efficiency at low concentrations, excellent solubilization, and lower critical micelle concentration [67,68].

3.3. Foam-Based Working Fluid

Foam fracturing technology is an improvement over conventional hydraulic fracturing techniques. Typically, gas is mixed with liquid to prepare foam. Foam working fluid mainly consists of a liquid phase (external phase), a gas phase (internal phase), a foaming agent, and other additives, forming a multi-interface bubble aggregate separated by liquid films. Generally, the foam proportion should be greater than 52% [69,70]. Due to the flow properties of the two-phase fluid, the working fluid has a higher viscosity (up to hundreds of mPa·s) and lower density, both of which ensure that the foam system has greater proppant-carrying capacity (>85%). The flow pattern of a foam system is shown in Figure 4, and the proppant distribution in foam working fluid is shown in Figure 5. The flow pattern of foam fluid is related to many factors. With the increase in gas flow rate and flow rate, the flow pattern changes. During hydraulic fracturing, it will carry proppant into the formation. The selection of the liquid phase needs to consider reservoir conditions, such as permeability, clay content, and temperature, usually using water, acid, alcohol, or hydrocarbons [71]. Among various foam systems, water-based foam is the most widely used due to its good applicability and lower technical requirements. Selecting foam-type working fluid for fracturing is more effective for reservoirs with low pressure, low permeability, and water sensitivity.

Foam is a thermodynamically unstable system [72]. The stability of foam increases with the concentration of the foaming agent and foam proportion but decreases with increasing temperature [73]. Foam undergoes decay, declining the performance of the fracturing fluid system. During foam production, appropriate foam surfactants must be used to combine the internal and external phases to maintain the stability of the foam during fracturing. In addition, adding certain additives to the foam, such as iodine, hydrogen peroxide, copper sulfate, and zinc bromide, can further enhance the stability of the foam. Therefore, maintaining the stability of foam systems under reservoir conditions is a research hotspot. The stability of foam largely depends on the stabilizer. Different types of surfactants, each with different foaming abilities and advantages, can be selected. For example, the foaming ability of tertiary alkyl amine ethoxylate can be changed into that of a defoamer by lowering the pH of the medium (below about 8), thus decomposing the foam produced.

Nitrogen foam fracturing, compared with conventional hydraulic fracturing, can generate complex and twisted fractures with larger surface areas upon fracturing, and these fractures are distributed throughout the entire sample. This results in the release of more energy, facilitating the secondary extension of the fractures. Foams provide a large contact area between the gas and the liquid, creating a significant platform for mass transfer [74]. Nitrogen foam is stronger than CO₂ foam and possesses good water-blocking capabilities under any pressure condition. Additionally, increasing pressure causes a decrease in the strength of CO₂ foam. Nitrogen foam exhibits better performance, with the correlation between foam and fracturing fluid pressure helping to reduce losses when foam is used appropriately [75].

Foam fracturing offers advantages such as water resource conservation, low damage, minimal fluid loss, environmental friendliness, and accelerated or thorough flowback. It holds strong potential for applications in water-sensitive shale formations with relatively high permeability (10 μD) [76]. However, there are several drawbacks that we should pay attention to. The various liquids, gases, surfactants, and proppants needed for foam system preparation must be stored separately, and the half-life of foam survival is short. Water-based foam induces significant expansion in shale matrixes, greatly reducing pore space for gas migration [77]. Polymer cannot be used as a stabilizer, necessitating the selection of completely degradable foaming agents and surfactants with stable performance [78,79,80]. Moreover, foam fracturing requires specialized equipment and substantial investment in high-level technical and logistical infrastructure.

3.4. Gas-Based Working Fluid

Water-based working fluids are widely used, but they may encounter issues such as water blocking, water sensitivity, incomplete flowback, and water consumption in tight reservoirs, which can diminish fracturing effectiveness. Therefore, gas-based working fluids are considered a future tendency. Nitrogen, liquefied petroleum gas, and carbon dioxide can all serve as fracturing mediums.

Supercritical CO₂ (Sc-CO₂) is a potential fracturing medium for shale gas. Above its critical temperature (304.25 K) and critical pressure (7.39 MPa), carbon dioxide behaves as a supercritical fluid, expanding like a gas to fill its space while maintaining the density of a liquid [81]. Sc-CO₂ offers several advantages, including the increased recovery of permeability, the prevention of clay swelling, and the enhanced desorption of CH₄ from organic matter in shale [82,83,84]. This desorption occurs because CO₂ has a greater adsorption capacity than CH₄, displacing CH₄ and thus increasing the production and recovery rates of CH₄. The use of carbon dioxide aligns with global environmental policies. Sc-CO₂ is one of the most important applications. It has gained significant attention due to its high efficiency [85]. Sc-CO₂, as an effective fracturing fluid, may become a primary section for geological sequestration in shale formations.

Experimental fracturing using CO₂ and water-based fluids has shown that, under the same injection pressure and rate, CO₂ fracturing can achieve comparable fracturing effects. Water and Sc-CO₂ possess entirely different physical properties, leading to variations in fracturing fluid performance [86]. Ishida et al. conducted fracturing experiments on granite using Sc-CO₂ and liquid CO₂, revealing that the fracturing pressures required for Sc-CO₂ and liquid CO₂ fracturing were lower than for hydraulic fracturing with water [87]. Pure CO₂ working fluids have low viscosity and high flow resistance, making them unsuitable for on-site application. They typically need to be combined with thickening agents to enhance their proppant-carrying capabilities. Zhou et al. reported on the current research status of four types of CO₂-thickening agents, including surfactants, hydrocarbon polymers, fluorinated polymers, and siloxane polymers, providing a reference for CO₂ thickening [88]. Compared with conventional hydraulic fracturing, CO₂ fracturing can effectively reduce flow resistance, enhance fracture communication, conserve water resources, facilitate flowback, protect reservoirs, decrease original viscosity, perform in situ energizing, and displace methane, among other enhanced oil recovery characteristics. However, Sc-CO₂ also presents challenges such as causing shale to swell upon interaction, which leads to reduced natural fracture apertures, and it has poor proppant-carrying capabilities [89,90].

4. Fracturing and Enhanced Recovery Integration Fluid: Challenges and Prospects

At present, the conventional methods for improving the recovery rate of low-permeability reservoirs are surfactant flooding and natural gas flooding. The main problem with gas flooding is gas channeling, which leads to inefficient displacement. For surfactant flooding, although it improves oil recovery efficiency, it is also related to issues such as chemical pollution and low oil recovery efficiency. In recent years, many scholars have studied the application of nanofluid flooding to improve the recovery rate of low-permeability reservoirs. The problem faced by gas flooding is that the gravity difference between air and liquid can lead to ineffective displacement in heterogeneous formations. Nanofluids have attracted considerable attention in the oil and gas extraction industry due to their unique surface/interface characteristics.

4.1. Fracturing and Enhanced Recovery Coordination Effect

As oilfield operations develop toward informatization, artificial intelligence, and refinement, it is necessary not only to improve the effectiveness of each operation but also to consider the integration between different operations and their impact on later construction stages. Therefore, in formulating fracturing plans, in addition to considering the requirements for shut-in wells and flowback, the demand for enhanced oil recovery should also be taken into account. Further research can be conducted in the following aspects:

(1)

The development of working fluids with oil displacement, such as cationic surfactant and carboxymethyl hydroxyethyl cellulose composite working fluid systems. Combining the advantages of surfactants and polymers, these have lower surface tension and interfacial tension, altering rock wettability and improving displacement efficiency.

(2)

Microbially enhanced oil recovery is one of the most effective techniques recognized for recovering residual oil and heavy oil reservoirs. Researching endogenous microbial activators and biopolymer emulsifiers compounded with oil displacement agents for specific reservoirs and injecting them into the formation during fracturing operations can activate reservoir microorganisms through processes such as shut-in wells, leading to the degradation and dispersion emulsification of crude oil.

4.2. Nanomaterial Pressure Reduction and Enhanced Injection

Nanoparticle-assisted pressure reduction and injection technology is a method whereby specific nanoparticle materials are carried into a reservoir through a dispersing medium and adsorbed onto the surface of its throats, thereby altering the wettability and microstructure of the pore walls to achieve pressure reduction and injection enhancement. Di et al. [91] proposed the nanoparticle lattice slip effect to explain the reason for the pressure reduction and injection enhancement of nanoparticle fluids. Hydrophobic nanoparticles can replace the hydration layer and form a nanoparticle layer arranged in a lattice on the surfaces of pores, rendering the pore surface superhydrophobic. This prevents injected water from approaching the pore surface, thus inducing a water slippage effect. Additionally, the dense arrangement of nanoparticles on the surface of rock pores reduces the opportunity for the water phase to contact the rock surface, thereby significantly reducing the flow resistance of the water phase. In summary, the mechanism of nanoparticle fluid pressure reduction and injection enhancement can be summarized as three points [92,93]: (a) the enlargement of pore radius and water films, as shown in Figure 6; (b) the superhydrophobic effect; and (c) anti-swelling performance.

(1)

Enlarging the Effective Pore Radius

The surfaces of reservoir pores carry negative charges, exhibiting hydrophilicity. Clay particles on the surface adsorb a certain thickness of water film. When injected water passes through the reservoir pores, it interacts with the water film, increasing flow resistance and causing high injection pressure, making water injection difficult. After injecting nanoparticle fluids into the reservoir, the non-polar substances in the nanoparticle fluid (modified nanoparticles with abundant -CH₃ on the surface) expel the water film, thinning the water film thickness on the reservoir pore surface, effectively enlarging the effective pore radius of the reservoir.

(2)

Superhydrophobic Effect

Nanoparticles and the hydration layer on the pore surface compete for adsorption. The high-energy state of unsaturated bonds and the extremely unstable surface atoms on the surface of hydrophobic nanoparticles give them strong hydrophilicity and binding adsorption capacity. Nanoparticles approach the wall surface through diffusion, convection, sedimentation, etc. They compete for adsorption with the hydration layer on the pore surface and replace the water film, forming a strongly hydrophobic adsorption layer. This further enlarges the pore throat, reverses the wettability of the rock, and induces hydrophobic slippage when injected water flows over the reservoir rock surface, reducing the flow resistance of injected water and selectively increasing the permeability of the water phase.

(3)

Anti-Swelling Performance

Positively charged nanoparticles enter the rock pores and adsorb on the surfaces of the rock pores. This not only effectively enlarges the pore radius, forming a strong hydrophobic layer, but also separates the contact between clay minerals and water, weakening the hydration expansion and diffusion of clay particles. This reduces the probability of particle migration blocking the reservoir pores, thereby reducing the injection pressure and playing a certain role in injection enhancement.

4.3. Fracture–Pore Coupling Frictional Resistance Evolution

The fracturing fluid is pumped into fractures through the fracturing pipeline, where it undergoes complex flow in multi-scale fractures, ultimately seeping through the capillary bundles. The flowback process of the fracturing fluid is the reverse of the aforementioned flow process. The resistance generated during the flow process is influenced by external factors, and there are significant differences in the flow patterns between fractures and pores. Due to the multi-scale nature of fractures, the sources of flow resistance in different-scale fractures vary. In the main fractures and natural fractures/faults, where the width of the fissures is relatively large, providing space for flow, the flow is likely to be in a turbulent state. At this point, additives exert their drag reduction effect through their own transformations. In the branch fractures and micro-fractures, the width of the fractures further decreases, and the influence of fracture surface roughness and fracture curvature on flow intensifies, resulting in slow laminar flow. As shown in Figure 7, solid-phase components and additives in the fracturing fluid settle or adsorb in weakly flowing local areas, altering the original geometric features of the fracture surfaces, and thereby changing the flow resistance.

Pore geometry differs from that of fractures, with capillary diameters being several orders of magnitude smaller than those of fractures. In low-porosity and low-permeability formations, capillary diameters can even approach the nanometer. Consequently, the conductivity of fractures is stronger than that of capillary bundles, and fluid flow in capillary bundles typically occurs through capillary imbibition or seepage. Factors such as rock mineral composition, clay content and type, roughness, geometric dimensions, and the mineralization of capillary walls affect wettability, thereby influencing resistance to imbibition or seepage. Adding components to the fracturing fluid that alter wettability on the capillary wall reduces seepage resistance, as illustrated in Figure 8, where surfactants adsorb on the capillary wall, leading to changes in wettability.

In hydraulic fracturing fluids, surfactants or polymers with surfactant properties are often added. They form a “micellar” interaction network structure within the fractures, achieving the purposes of reducing friction and suspending proppants. Active additives adsorb inside the capillary bundles, altering the original surface wettability, reducing the flow resistance of fracturing fluids, and facilitating fluid infiltration and flowback. Surfactant molecules adsorbed on the capillary wall can enhance in situ, reducing the interfacial tension between oil and water upon contact with crude oil, enhancing their miscibility and improving oil recovery.

The multifunctional surfactant–copolymer nanocomposite additive has emerged as a rapidly developing hydraulic fracturing additive in recent years [94,95]. Its polymeric structure enables both proppant suspension and friction reduction efficiencies. Montmorillonite (MMT), a type of layered aluminosilicate clay mineral, with its cation exchange capacity and adsorption properties, has garnered considerable attention in applications [94,95]. Polymer-layered silicate (PLS) is a widely studied nanocomposite material, resulting from the combination of polymers and layered silicates, forming a continuous phase with dispersed phases [96,97,98]. A novel guar gum–montmorillonite nanocomposite material was prepared using the solution intercalation method [99]. Clay mineral modification with biopolymers is a trend in green chemistry development, as these biopolymers offer biodegradability, environmental friendliness, and renewability [100,101].

4.4. Green and Environmentally Friendly Integrated Fluid

Currently, hydraulic fracturing is being increasingly utilized, leading to a corresponding increase in wastewater and waste solids generated during the fracturing process. Improperly handling these wastes could pose threats to the ecological environment. Additionally, increasingly stringent environmental laws and regulations require fracturing operations to meet safety and environmental protection standards. Therefore, the future development of fracturing fluids will inevitably move toward safety, environmental protection, and green development. It is recommended to deepen research on integrated fracturing–stimulation fluids in the following aspects:

(1)

Fracturing can produce thousands to tens of thousands of cubic meters of fluid, leading to rising costs and imposing a heavy burden on the ecological environment. Therefore, it is necessary to strengthen the recycling of fracturing fluids. The recycling of fracturing wastewater simplifies the treatment process and reduces fracturing costs, and given the special environment of offshore fracturing operations, the urgent need for multiple recycling of fracturing fluids is emphasized.

(2)

“CO₂+”-enhanced fracturing and stimulation (such as CO₂ + solvent, CO₂ + expansion agent, CO₂ + thickening agent, etc.) will play an important role, and the promotion of supercritical CO₂ fracturing will provide an opportunity for the wider use of CO₂. CO₂-responsive microemulsion is a promising solvent.

(3)

Developing high-temperature controllable gelling/breaking CO₂-responsive clean fracturing fluids can overcome the poor temperature resistance of traditional clean fracturing fluids and have advantages such as low reservoir damage and environmental friendliness. The biodegradable, environmentally friendly, and outstanding properties of green biosurfactants, crosslinkers, and amino-acid-based green surfactants will unleash their application potential.

5. Summary

Fracturing fluid, as the working medium for fracturing operations, affects the processes of fracturing and enhances recovery enhancement. Research on fracturing fluids closely follows the trends in oil and gas exploration and development. It becomes increasingly refined based on reservoir characteristics and physical properties. In order to achieve the integration of fracturing and enhanced recovery enhancement, the following conclusions are drawn:

(1)

Fracturing and subsequent production enhancement are related. Fracturing fluids need to meet the performance requirements for stages such as creating fractures, suspending proppants, supporting fracture networks, and flowback. Additionally, they must consider production enhancement requirements. Polymer additives exhibit strong thickening abilities but may have difficulties in complete breaking and may leave large residues. Clean fracturing fluids have low surface–interface tension but weaker mechanical properties and higher costs. Foam-based fluids have low filtration loss and minimal reservoir damage but have poor sand-carrying capabilities. Integrated fracturing fluids should be tailored to specific conditions, integrating the advantages of various additives to complete integrated operations.

(2)

Nano-scale depressurization and injection technology involves carrying specific nanoparticles into a reservoir through a dispersing medium, adsorbing them onto fracture surfaces, and altering surface wettability and microstructures to achieve depressurization and injection enhancement. The main mechanisms include (a) expanding the effective pore radius; (b) the superhydrophobic effect; and (c) anti-swelling performance.

(3)

Injecting fluids with fracturing and oil displacement properties during the fracturing process can expand the fluid filtration range in the reservoir, reduce rock fracturing pressure, increase reservoir elastic energy, and displace crude oil, thereby increasing production. Surfactants with polymerization; biodegradability and the properties of bio-based surface-active agents, crosslinkers, and amino-acid-based green surfactants demonstrate application potential. Polymer-layered silicate nanocomposites with excellent thermal stability and mechanical properties will provide important support for the effectiveness of integrated fracturing and enhanced recovery enhancement fluids.