Development and Characterization of Clean Fracturing Fluid Based on Gemini Surfactant for Coalbed Methane Extraction

Abstract

Addressing the issues of low permeability, stress sensitivity in CBM reservoirs, and severe reservoir damage from traditional fracturing fluids, we prepared a Gemini surfactant (designated GEM-CBM) for CBM development using ethanolamine, epichlorohydrin, and alkylamidopropyl dimethylamine as feedstocks. On this basis, we further developed a clean fracturing fluid system. The synthesis process of GEM-CBM was optimized via single-factor and orthogonal experiments. The surface activity of GEM-CBM was assessed through surface tension measurements, whereas the sand-carrying capacity, the rheological properties, gel-breaking performance, and reservoir compatibility were comprehensively examined. The optimal conditions for GEM-CBM are listed as follows: the molar ratio of intermediate to alkylamidopropyl dimethylamine being 1:2.2, reacted at 80 °C for 20 h, with a conversion rate of 96.5%. FTIR verified the existence of characteristic functional groups, and EA results matched the theoretical molecular composition. GEM-CBM has good performance, with a critical micelle concentration (CMC) of 19.0 μmol/L and a surface tension at CMC (γCMC) of 37.44 mN/m. The optimized clean fracturing fluid (formulation: 2.3% GEM-CBM + 0.3% Tween-80 + simulated formation water with 150,000 mg/L mineralization) exhibited a viscosity of 82 mPa·s (66.7% viscosity retention rate) after being subjected to 100 min of shearing at 90 °C and 170 s⁻¹. At 90 °C, the proppant settlement velocity was less than 0.15 mm/s, and complete gel breaking was achieved within 30 min without residues. For coal cores from the Qinshui Basin, the permeability recovery rate reached 78.6%. The permeability recovery rate of coal cores from the Qinshui Basin reached 78.6%. This fracturing fluid realizes viscosity enhancement and sand carrying via the worm-like micellar network formed by GEM-CBM, inducing minimal damage to CBM reservoirs and offering technical support for efficient CBM extraction.

1. Introduction

Coalbed methane is deposited in coal seams by ancient plants during the process of coal formation. It not only serves as a high-grade clean energy but also contributes to reducing methane emissions (a potent greenhouse gas) and mitigating gas-related safety hazards in coal mining, thus possessing notable energy and environmental value [1,2,3]. China possesses abundant CBM resources, yet its main development blocks (such as the Qinshui Basin and Ordos Basin) are primarily low-permeability formations, with an average permeability of below 5 × 10⁻³ μm² [4]. Most coal seams exhibit extremely low permeability, hindering the natural flow of gas—hydraulic fracturing effectively improves gas flow channels and efficiency by creating dense crack networks in coal seams [5,6]. Therefore, developing a clean and low damage fracturing fluid system is crucial for improving coalbed methane recovery rate.

CBM reservoirs possess distinct geological characteristics that pose considerable challenges to conventional fracturing fluids: high stress sensitivity—a 0.1 MPa increase in confining pressure can reduce reservoir permeability by over 30% due to coal matrix shrinkage and pore blockage. Intense water-blocking effect: coal is inherently hydrophilic, and fracturing fluid invasion can occupy pore spaces, impeding CBM desorption and seepage. Third, harsh downhole conditions—medium-deep CBM reservoirs (1500–2000 m deep) have temperatures of 80–100 °C and formation water mineralization over 100,000 mg/L, which readily degrade fracturing fluid performance [7].

Traditional fracturing fluids cannot meet these requirements: cross-linked guar gum-based polymer fluids leave 800–1000 mg/L of solid residues after gel breaking, which permanently clog coal pores. While conventional viscoelastic surfactant (VES) fluids are residue-free, they tend to break down micelles at temperatures above 80 °C or in high-salinity (mineralization > 100,000 mg/L) formation water, causing rapid viscosity loss [8,9,10]. These properties make Gemini surfactants ideal for developing clean fracturing fluids tailored to CBM reservoirs [11,12]. Therefore, developing a Gemini surfactant-based clean fracturing fluid with low reservoir damage, temperature resistance, and salt tolerance is crucial for breaking through the bottleneck of CBM development [13,14,15].

In recent years, various new systems adapted to different geological conditions have emerged in the study of coalbed methane fracturing fluids. In terms of surfactant selection, early studies focused on cationic Gemini surfactants (e.g., quaternary ammonium salts) due to their excellent thickening ability [16]. However, these surfactants are easily adsorbed on negatively charged coal surfaces, increasing chemical consumption and altering coal wettability to exacerbate water-blocking [17]. Subsequent studies introduced hydrophilic groups (e.g., hydroxyl and amide) to reduce adsorption—for instance, a study reported an amide-containing Gemini surfactant that achieved a fracturing fluid viscosity of 100 mPa·s at a 1% concentration, but its salt tolerance was limited to mineralization below 100,000 mg/L, restricting application in high-salinity reservoirs [18,19].

In terms of fluid performance optimization, most studies enhance salt resistance by compounding salt-tolerant additives (e.g., organic acids, nanoparticles) [20]. While this approach improves performance, it increases the complexity of on-site preparation and introduces potential reservoir damage risks (e.g., nanoparticle aggregation blocking micropores) [21,22,23]. Additionally, most studies focus on basic performance evaluations (rheology, gel breaking) and lack in-depth research on reservoir compatibility—for example, few studies evaluate fluid loss performance based on coal pore structure or verify the stability of permeability recovery through long-term core soaking experiments [24,25,26,27,28,29]. This disconnect between laboratory results and field application leads to poor performance of some fracturing fluids in practical CBM development [30,31,32].

In summary, current Gemini surfactant-based clean fracturing fluids for CBM still face challenges such as insufficient salt tolerance, weak reservoir targeting, and complex compound formulations [33,34]. There is an urgent need to develop a single-component Gemini surfactant that can adapt to medium-deep CBM reservoir conditions (80–100 °C, mineralization 100,000–200,000 mg/L) and systematically verify the reservoir adaptability of its corresponding fracturing fluid [35,36,37]. The gel breaker is a functional additive used only to regulate gel-breaking time, without participating in the thickening mechanism. The core thickening component remains the single-component GEM-CBM.

This study seeks to develop a clean fracturing fluid applicable to CBM reservoirs, with three key research components: first, synthesis and structural characterization of the Gemini surfactant GEM-CBM. Utilizing ethanolamine, epichlorohydrin, and alkylamidopropyl dimethylamine as raw materials, single-factor experiments and orthogonal experiments were performed to optimize the synthesis process. FTIR and EA were employed to verify the molecular structure and functional groups, while surface tension measurements were carried out to analyze surface activity. Second, optimization of the clean fracturing fluid formulation and performance assessment. With GEM-CBM as the thickening agent, the surfactant concentration, gel breaker type, and dosage were optimized. The fluid’s performance under CBM reservoir conditions was assessed, including rheological properties, sand-carrying capacity, gel-breaking performance (gel-breaking time, residue content), and fluid loss performance (fluid loss coefficient, initial fluid loss). Third, verification of fracturing fluid reservoir compatibility. Using coal cores from the Qinshui Basin, the permeability recovery rate was tested via core flow experiments. Polarizing Optical Microscopy (POM) and Dynamic Light Scattering were employed to observe the adsorption behavior and morphological variations in micelles on rock cores, and the reservoir damage mechanism was analyzed.

2. Experimental Section

2.1. Materials and Instruments

2.1.1. Materials

Raw materials: Ethanolamine (analytical reagent, AR, Beijing InnoChem Science & Technology Co., Ltd., Beijing, China), epichlorohydrin (analytical reagent, Tianjin Fuyu Fine Chemical Co., Ltd., Tianjin, China), palmitamidopropyl dimethylamine, and stearamidopropyl dimethylamine (both industrial grade, Guangzhou Tinci Materials Technology Co., Ltd., Guangzhou, China). Additives: Tween-80 and OP-10 (both analytical reagents, Shanghai Macklin Biochemical Co., Ltd., Shanghai, China), simulated formation water (prepared based on the mineralization of CBM reservoir water in the Qinshui Basin, with a mass ratio of NaCl:KCl:CaCl₂:MgCl₂ at 10:3:1:0.8 and a mineralization degree of 150,000 mg/L). Coal samples obtained from the No. 3 coal seam were made into cylindrical cores (Φ30 mm × L60 mm). After vacuum drying, the average porosity was found to be 7.5%, and the average permeability was tested as 3.8 × 10⁻³ μm². Proppant: Ceramic proppant (particle size range 0.45–0.8 mm, bulk density of 1.55 g/cm³, and compressive strength no less than 52 MPa). The purity of analytical reagent-grade raw materials (ethanolamine, epichlorohydrin) was determined by gas chromatography (Agilent 7890A, Santa Clara, CA, USA) [5]. For industrial-grade surfactants (palmitamidopropyl dimethylamine, stearamidopropyl dimethylamine), composition and main component content were verified via HPLC [12], ensuring compliance with experimental requirements.

2.1.2. Instruments

Structural characterization instruments: Bruker VERTEX 70 Fourier Transform Infrared (FTIR) Spectrometer (Bruker, Karlsruhe, Germany, wavenumber range 4000–500 cm⁻¹), Elementar Vario EL Ⅲ Elemental Analyzer (Elementar, Langenselbold, Germany, for C, H, N content determination). Surface activity testing instrument: Biolin Scientific SIGMA700 Automatic Surface Tensiometer (Biolin Scientific, Västra Frölunda, Sweden, ring method, test temperature 25 °C). Performance evaluation instruments: Haake MARS60 Complex Fluid Rheometer (Haake, Vreden, Germany, temperature range 25–150 °C, shear rate range 0.1–1000 s⁻¹), ZNN-D6 Six-Speed Rotational Viscometer (Shandong Meike Instrument, Qingdao, China, for routine viscosity measurement), High-Temperature High-Pressure Fluid Loss Meter (Shanghai Kence Instrument, Shanghai, China, temperature range 30–120 °C, pressure range 0–10 MPa), CoreLab Core Flow Testing System (CoreLab, Houston, TX, USA, for permeability recovery rate measurement). Microscopic observation instruments: Leica DM2700P Polarizing Optical Microscope (POM, Leica, Wetzlar, Germany, magnification 100–400×), Malvern Zetasizer Nano ZS90 Dynamic Light Scattering (DLS) Instrument (Malvern Panalytical, Malvern, UK, for micelle size measurement, test temperature 25 °C).

2.2. Synthesis Process

The synthesis of GEM-CBM consists of two steps: intermediate preparation and target product synthesis, with the detailed procedure as follows: preparation of hydroxyl-containing amine intermediate [9]: ethanolamine (3.0 g, 0.05 mol) and 45 mL of anhydrous methanol were added into a 250 mL single-necked flask, which was then positioned at 0 °C and stirred for 10 min. Epichlorohydrin (10.8 g, 0.117 mol) was slowly added in drops via a constant-pressure funnel over 50 min to prevent side reactions caused by local overheating. After the dropwise addition, the temperature was raised to room temperature, and stirring was sustained for 12 h. Methanol was eliminated using a rotary evaporator (60 °C, 0.08 MPa) to obtain a pale yellow viscous intermediate, with a yield of 91.2%.

Synthesis of target product GEM-CBM: The intermediate (0.02 mol), palmitamidopropyl dimethylamine (0.044 mol), and 60 mL of anhydrous ethanol (serving as solvent) were put into a 500 mL three-neck flask, and the mixture was stirred until all raw materials were completely dissolved—achieving a 60% reactant mass concentration. After assembling a reflux device, the system was heated to 80 °C, and the reaction was maintained for 20 h. Post-reaction, the crude product was rinsed three times with a dichloromethane-petroleum ether mixture (volume ratio 1:10) to eliminate unreacted raw materials. The product was then dried via rotary evaporation (70 °C, 0.08 MPa) to obtain light brown viscous GEM-CBM. After purification by recrystallization (ethanol/water = 3:1, v/v) and vacuum drying (60 °C, 4 h), the actual yield of GEM-CBM was 11.0 g, corresponding to a total yield of 86.2% (theoretical yield: 12.8 g, calculated based on 15.0 g of C16 fatty acid chloride as the limiting reagent). The conversion rate was determined by the N element content measured by EA (compared with the theoretical value), reaching 96.5% under optimal conditions, and the reaction formula is presented in Scheme 1.

Single-factor experiments were performed to explore the effects of raw material molar ratio (intermediate: alkylamidopropyl dimethylamine = 1:2.0, 1:2.2, 1:2.4), reaction temperature (75 °C, 80 °C, 85 °C), and reaction time (16 h, 20 h, 24 h) on the conversion rate. A three-factor, three-level orthogonal experiment was further carried out to ascertain the optimal process. The results indicated that the raw material molar ratio had the most prominent impact on the conversion rate, with reaction temperature being the next, and reaction time had minimal influence. The optimal combination was intermediate: palmitamidopropyl dimethylamine = 1:2.2, 80 °C, and 20 h.

2.3. Structural Characterization

2.3.1. Fourier Transform Infrared Spectroscopy (FTIR) Analysis

GEM-CBM was mixed with KBr, and pressed into a transparent tablet. A VERTEX 70 spectrometer (4 cm⁻¹ resolution, 32 scans) was utilized to acquire the FTIR spectrum.

2.3.2. Elemental Analysis (EA)

We weighed precisely 2 mg of GEM-CBM and measured its C, H, and N contents using a Vario EL Ⅲ elemental analyzer (calibrated with acetanilide).

2.4. Surface Activity Testing

A Biolin Scientific SIGMA700 Automatic Surface Tensiometer (ring method) was used to measure the surface tension of aqueous solutions of GEM-CBM, C12-APB, C16-2-16, SDBS, and CAPHS at different concentrations (0.001–1 mmol/L) in a constant temperature water bath at 25 ± 0.1 °C. Each concentration was tested in parallel three times, with a relative standard deviation (RSD) required to be <2%. The critical micelle concentration (CMC) was determined from the inflection point of the surface tension-log concentration curve. The maximum surface excess concentration (Γₘₐₓ) and minimum molecular area at the interface (Aₘᵢₙ) were calculated using the formulas Γₘₐₓ = −(dγ/dlog₁₀C)T,P/2.303nRT and Aₘᵢₙ = 1/(NₐΓₘₐₓ) (where R = 8.314 J/(mol·K), T = 298 K, n = 3, Nₐ = 6.02 × 10²³ mol⁻¹).

2.5. Analysis of Coal Reservoir Physical Properties

2.5.1. Pore Structure Analysis

A Micromeritics AutoPore V 9500 Mercury Intrusion Porosimeter (Micromeritics Instrument Corporation, Norcross, GA, USA) was used to test the pore structure parameters of Qinshui Basin coal cores (Φ30 mm × L60 mm) within a pressure range of 0.001–414 MPa. Mercury saturation, displacement pressure, and average pore throat radius were calculated, and pore type distribution was analyzed through mercury intrusion curves.

2.5.2. Stress Sensitivity Testing

A CoreLab Triaxial Stress Permeability System (CoreLab, Houston, TX, USA) was used, with nitrogen as the displacement medium (pressure difference of 0.5 MPa). The confining pressure was gradually increased within the range of 0–6 MPa (each confining pressure was stabilized for 30 min), and the permeability of coal cores under different confining pressures was measured. The permeability damage rate was calculated using the following formula: (K₀ − K)/K₀ × 100% (K₀ is the permeability at a confining pressure of 0.1 MPa).

2.6. Performance Evaluation Methods of Clean Fracturing Fluid

2.6.1. Rheological Property Testing

In line with the principle of “matching coal reservoir properties while balancing performance and cost,” the fundamental composition of the fracturing fluid (GEM-CBM + gel breaker + simulated formation water) was optimized:

Optimization of GEM-CBM concentration: The viscosity of GEM-CBM solutions with concentrations of 1.5%, 2.0%, 2.3%, and 2.5% (mass ratio) was determined at 25 °C using a ZNN-D6 viscometer (170 s⁻¹). The findings indicated that as the concentration rose from 1.5% to 2.3%, the viscosity increased notably. When the concentration surpassed 2.3%, the viscosity only rose to 112 mPa·s with decreasing marginal gains. Hence, the optimal concentration of GEM-CBM was identified as 2.3%.

Optimization of gel breaker type and dosage: The performance of two non-ionic gel breakers (Tween-80 and OP-10) at concentrations of 0.2%, 0.3%, and 0.4% was evaluated. The results demonstrated that 0.3% Tween-80 decreased the viscosity to 3.5 mPa·s within 30 min, realizing complete gel breaking without residues. OP-10 required a concentration of 0.4% to attain similar outcomes, and the gel-broken fluid was slightly turbid. Consequently, 0.3% Tween-80 was chosen as the gel breaker.

To mimic CBM reservoir environments, we employed a MARS60 rheometer (Haake, Vreden, Germany; cone-plate configuration: 50 mm diameter, 1° angle). The test protocol included: heating the fluid from 25 °C to 90 °C at 3 °C/min, applying continuous shear at 90 °C and 170 s⁻¹ for 100 min, and recording viscosity data at 5 min intervals. In addition, viscoelasticity testing was carried out to further assess the fluid’s shear resistance and proppant-carrying capability: stress sweep was implemented at 90 °C, 1 Hz, and a stress range of 0.01–100 Pa for identifying the Linear Viscoelastic Region (LVR) where storage modulus (G′, elastic contribution) and loss modulus (G″, viscous contribution) remain stable. Frequency sweep was subsequently conducted at 90 °C, a stress of 1 Pa (within LVR), and a frequency range of 0.1–100 Hz to record changes in G′ and G″.

2.6.2. Sand-Carrying Capacity Testing

The proppant-carrying capability at varying temperatures was assessed via static sedimentation. Ceramic proppants (30% volume fraction, 0.45–0.8 mm particle size) were blended with fracturing fluid in a 100 mL graduated cylinder (10 cm scaled height), then immersed in 30 °C/60 °C/90 °C thermostatic water baths sequentially. Proppant settling time (top to bottom) was recorded, settling velocity calculated as (height/time). Triplicate tests per temperature, average values adopted.

2.6.3. Fluid Loss Property Testing

A high-temperature, high-pressure fluid loss meter (90 °C, 3 MPa) was used, with coal cores as the filtration medium. The fluid loss volume was recorded within 0–30 min, and the fluid loss coefficient (C) and initial fluid loss (V₀) were calculated according to API standards using the following formulas: C = 0.005 k/A and V₀ = 11.92 b/A, where k is the slope, A denotes core cross-sectional area, and b is the intercept of the fluid loss curve.

2.6.4. Reservoir Damage Testing

A CoreLab core flow system was employed: initially, the K₀ (initial permeability) of the coal core was determined through nitrogen displacement. Subsequently, the core was flushed with simulated formation water until the effluent was clear, and the recovered permeability (K_r) was measured. The permeability recovery rate was calculated using the formula: Permeability recovery rate = (K_r/K₀) × 100%.

The adaptability of fracturing fluid in high salinity formation water was evaluated using mineralization sensitivity testing. Simulated formation water with mineralization levels of 100,000, 150,000, 200,000, and 250,000 mg/L was prepared to formulate fracturing fluids (2.3% GEM-CBM + 0.3% Tween-80). The viscosity of each fluid was tested at 90 °C and 170 s⁻¹ to analyze the effect of mineralization on fluid viscosity. Meanwhile, to comprehensively assess gel-breaking performance, additional gel breakers (30% volume ratio kerosene and 200% volume ratio tap water) were tested alongside the original 0.3% Tween-80. The gel-breaking time (time for viscosity to decrease to <5 mPa·s), clarity of the broken gel solution, and residue content (detected after centrifugation at 8000 r/min for 10 min) were recorded for each breaker.

3. Results and Discussion

3.1. Correlation Between Structure and Surface Activity of Gemini Surfactant GEM-CBM

3.1.1. Molecular Structure Verification of GEM-CBM

FTIR analysis results (Figure 1) show that GEM-CBM exhibits a strong absorption peak at 3341 cm⁻¹ corresponds to the hydroxyl group derived from the intermediate. The antisymmetric stretching vibration of methyl and the symmetric stretching vibration of methyl are reflected in the absorption peaks located at 2914 cm⁻¹ and 2851 cm⁻¹, the 1654 cm⁻¹ is derived from the C=O amide groups, and the 1052 cm⁻¹ peak arises from C-H bending vibration. These characteristic peaks fully align with the designed molecular structure of GEM-CBM (containing hydroxyl, amide, and long alkyl chains), verifying the successful introduction of target functional groups.

Elemental analysis results showed measured contents of 64.8% (C), 11.1% (H), and 6.2% (N)—these values deviate by less than 0.5% from the theoretical contents (65.1% C, 11.3% H, 6.5% N) calculated from the molecular formula C₄₆H₉₂N₄O₄. This indicates that the molecular composition of the synthesized product is consistent with the design requirements, and no significant impurities were detected.

FTIR, EA characterizations confirmed that GEM-CBM has the target structure of “dual hydrophilic heads (hydroxyl + amide)—dual hydrophobic tails (palmitic acid chains)—spacer group.” Its surface activity advantage stems from the synergistic effect of the molecular structure: the dual hydrophobic tails enhance intermolecular hydrophobic interactions, promoting rapid micelle formation (resulting in a low CMC of 19.0 μmol/L). The hydrophilic heads (hydroxyl and amide groups) form a thick hydration layer, which not only reduces surface tension (γCMC = 37.44 mN/m) but also lays the foundation for the salt resistance of the subsequent fracturing fluid—the hydration layer can prevent salt ions from compressing the micelle electric double layer, reducing micelle aggregation.

POM observations showed that worm-like micelles (length 200–450 nm) were formed in the 2.3% GEM-CBM solution (Figure 2). The thickening effect of fracturing fluid originates from the dynamic three-dimensional network structure formed by the entanglement between micelles. This structure is the core mechanism that endows and maintains the required viscoelasticity of the system.

3.1.2. Surface Activity Performance of GEM-CBM

The surface tension-log concentration curve of GEM-CBM (Figure 3) shows that when the concentration is below 19.0 μmol/L, the surface tension decreases rapidly with increasing concentration; when the concentration exceeds 19.0 μmol/L, the surface tension stabilizes. This inflection point is the CMC (19.0 μmol/L), and the corresponding surface tension (γCMC) is 37.44 mN/m.

Further calculations yield Γₘₐₓ = 4.21 × 10⁻⁶ mol/m² and Aₘᵢₙ = 0.40 nm²/molecule: Γₘₐₓ is higher than that of the traditional single-chain surfactant CTAB (2.85 × 10⁻⁶ mol/m²), indicating that GEM-CBM has a higher adsorption capacity at the gas–liquid interface; Aₘᵢₙ is smaller than that of CTAB (0.58 nm²/molecule), proving that the synergistic effect of dual hydrophobic chains promotes the close arrangement of molecules and reduces interfacial gaps.

Compared with other surfactants, GEM-CBM has a significantly lower CMC than SDBS (56.2 μmol/L) and C16-2-16 (28.5 μmol/L), and its γCMC is also lower than those of the above two surfactants (38.5 mN/m, 40.2 mN/m). This indicates that it can effectively reduce surface tension at low concentrations—a characteristic that can reduce the dosage of surfactant in fracturing fluid and lower on-site application costs [10].

3.2. Constraint Mechanism of Coal Reservoir Properties on Fracturing Fluid

3.2.1. Pore Structure Constraints of Coal Reservoirs

Mercury intrusion porosimetry results (Figure 4) show that the Qinshui Basin coal cores have a maximum mercury saturation of 82.3%, a displacement pressure range of 0.025–0.088 MPa, and an average pore throat radius of 1.2–28.5 μm. The pore system is dominated by a ‘fracture-micropore’ dual structure, where fractures account for more than 65% of the total pore volume and serve as the main seepage channels for CBM.

This structure imposes clear requirements on fracturing fluid: low fluid loss performance—to avoid excessive infiltration of fracturing fluid into micropores leading to water blocking (pore clogging); sufficient viscosity—to ensure proppant carrying in fractures and prevent proppant settlement from clogging fractures. The subsequently optimized fracturing fluid (2.3% GEM-CBM + 0.3% Tween-80) forms a dense filter cake through micelles, controlling the fluid loss coefficient at 3.2 × 10⁻⁴ m/min^1/2, which exactly matches the requirements of this pore structure.

3.2.2. Stress Sensitivity Constraints of Coal Reservoirs

Stress sensitivity testing results (Figure 5) indicate that when the confining pressure increases from 0.1 MPa to 0.15 MPa, the coal core permeability decreases from 3.8 × 10⁻³ μm² to 2.5 × 10⁻³ μm², with a permeability damage rate of 34.2%; when the confining pressure rises to 5 MPa, the permeability is only 0.45 × 10⁻³ μm², with a damage rate as high as 88.2%, confirming the strong stress sensitivity of CBM reservoirs.

This requires the fracturing fluid to have rapid shear recovery capability: during construction, the fracturing fluid must quickly rebuild viscosity after being sheared by the formation (the fluid in this study recovers 85% of its initial viscosity within 5 min after shearing) to support fractures and avoid closure; meanwhile, proppants must stably suspend in the fracturing fluid (settlement velocity < 0.15 mm/s at 90 °C) to prevent proppant failure after fracture closure caused by increased confining pressure.

The “fracture-micropore” structure and strong stress sensitivity of CBM reservoirs impose clear constraints on fracturing fluid performance: pore structure constraint—the fracture-dominated seepage channels easily lead to fracturing fluid loss. Tests showed that the optimized fracturing fluid had a fluid loss coefficient C = 3.2 × 10⁻⁴ m/min^1/2 and an initial fluid loss V₀ = 0.98 × 10⁻³ m³/m², significantly lower than that of conventional VES fracturing fluids (C ≈ 6.5 × 10⁻⁴ m/min^1/2). This is attributed to the dense filter cake formed by GEM-CBM micelles on the fracture surface—the micellar network can block fluid infiltration into micropores while not clogging the main fractures, balancing fluid loss control and fracture conductivity.

Increased confining pressure leads to fracture closure, requiring the fracturing fluid to maintain sufficient viscosity after shearing to support proppants. Rheological tests on the GEM-CBM-based fluid demonstrated it maintains robust performance: after shearing, it retains a viscosity of 82 mPa·s (viscosity retention rate 66.7%). This stability originates from the dynamic behavior of GEM-CBM’s worm-like micelles: they temporarily disentangle under shear stress but quickly rearrange via intermolecular forces to rebuild a three-dimensional network once shearing ceases—enabling efficient viscosity recovery (e.g., regaining 85% of the initial value within 5 min after shear cessation). Viscoelasticity tests further confirmed this adaptability: within the stress range of 0.1–50 Pa, the storage modulus (G′) and loss modulus (G″) stayed steady, indicating structural resistance to formation shear. When frequency > 0.5 Hz, G′ (15–32 Pa) was consistently greater than G″ (8–18 Pa), meaning elasticity dominated-this elastic network “wraps” proppants to reduce settlement, addressing the risk of fracture closure from reservoir stress changes.

To further verify the GEM-CBM-based fluid’s superiority over traditional surfactant systems, rheological tests of three clean fracturing fluids (GEM-CBM-based, CTAB-based, EAPB-based) were conducted under the same conditions (90 °C, 170 s⁻¹ shear rate, 100 min duration, simulated formation water with 150,000 mg/L mineralization), and results are shown in Figure 6a. As observed, the three fluids exhibited distinct viscosity variation trends: CTAB-based and EAPB-based fluids showed continuous, rapid viscosity decline throughout the experiment, while the GEM-CBM-based fluid first displayed a slight viscosity increase in the initial stage (due to enhanced entanglement of worm-like micelles under low-temperature shear) before stabilizing at a high level. At the end of the test, the GEM-CBM-based fluid maintained a viscosity of 82 mPa·s (retention rate 66.7%)-far higher than the final viscosities of CTAB-based and EAPB-based fluids, and well above the 50 mPa·s minimum viscosity required for effective proppant carrying in CBM reservoirs. This comparison confirms that the GEM-CBM-based system has more reliable shear resistance to cope with reservoir stress sensitivity, which is critical for preventing fracture closure by confining pressure and ensuring stable proppant placement in artificial fractures.

To determine the structural stability of the GEM-CBM-based fluid against formation shear stress, stress sweep tests were conducted on three clean fracturing fluid systems (GEM-CBM-based, CTAB-based, EAPB-based) at 90 °C and 1 Hz, with results shown in Figure 6b.

As observed in Figure 6b, the G′ and G″ of the three fluids exhibit non-linear changes with increasing stress: all moduli first increase slightly and then decrease significantly. Within the 0.1–48 Pa stress range, the G′ and G″ of the three fluids remain relatively stable—this interval is defined as their Linear Viscoelastic Region (LVR), where the micellar reticular structure is not destroyed by shear stress. To avoid damaging the micelle structure during subsequent frequency sweep tests, the selected stress value should be far from the end of the LVR platform. Thus, 1 Pa was determined as the stress for the frequency sweep. For the GEM-CBM-based fluid, its LVR (0.1–48 Pa) is slightly wider than that of CTAB-based (0.1–45 Pa) and EAPB-based (0.1–42 Pa) fluids, indicating that it has a stronger ability to adapt to fluctuations in formation shear stress-a key advantage for coping with the stress sensitivity of CBM reservoirs.

3.3. Performance Advantages and Reservoir Adaptability of Clean Fracturing Fluid

3.3.1. Temperature/Salt Resistance and Sand-Carrying Capacity

Within the temperature window of 80–100 °C, after constant shear, the apparent viscosity of the system can still maintain a relatively high level of 60 mPa·s, indicating that its initial structure has not been significantly disrupted (Figure 7). Through mineralization sensitivity tests, we found that viscosity maintained 55 mPa·s (over 80% viscosity retention ratio), even when the formation water mineralization reached 250,000 mg/L. In contrast, CTAB-based fracturing fluid had a viscosity below 40 mPa·s at 200,000 mg/L [10]. The reason for this superior salt tolerance lies in the thick hydration layer generated by the hydroxyl groups in GEM-CBM, which resists the compression of micellar double layers by salt ions.

To further verify the salt tolerance advantage of GEM-CBM over other conventional surfactants, the viscosity changes in GEM-CBM, C12-APB (cationic), C16-2-16 (cationic Gemini), SDBS (anionic), and CAPHS (amphoteric) solutions with varying NaCl mass fractions (0~26%) were measured at 90 °C (simulating medium-deep CBM reservoir temperature), and the results are shown in Figure 8a.

In Figure 8a, all five surfactants exhibit a “first increase then decrease” viscosity trend with increasing NaCl mass fraction: when the NaCl mass fraction is <8%, the viscosity of all solutions increases slightly (due to the compression of micellar electric double layers promoting micelle entanglement). However, when the NaCl mass fraction exceeds 12%, the viscosity of C12-APB, C16-2-16, SDBS, and CAPHS decreases sharply (e.g., SDBS viscosity drops by >60% at 16% NaCl) [20], while GEM-CBM maintains a viscosity retention rate of >70% even at 20% NaCl. This difference is attributed to the thick hydration layer formed by the hydroxyl groups in GEM-CBM, which effectively resists the compression of micellar double layers by Na⁺ and Cl⁻, thus maintaining the stability of the worm-like micellar network.

Sand-carrying capacity tests under different temperatures showed that the proppant settlement velocity of GEM-CBM fracturing fluid increased slowly with temperature: 30 °C with 0.08 mm/s, 60 °C with 0.11 mm/s, and 90 °C with 0.14 mm/s. This velocity is much lower than that of water (9.5 mm/s) and conventional surfactants (CTAB: 0.32 mm/s at 90 °C. EAPB: 0.25 mm/s at 90 °C), and no significant stratification of proppants was observed after standing in the solution for 2 h. The worm-like micelles hinder proppant settlement through “wrapping-entanglement,” ensuring proppant transport to target fractures.

3.3.2. Gel-Breaking Performance and Reservoir Damage Control

We carried out gel-breaking experiments with three types of breakers: tap water at a 200% volume ratio broke the gel most rapidly (10 min), 0.3% Tween-80 required 30 min, and kerosene at a 30% volume ratio took 70 min. All results met industry criteria (gel-breaking time < 120 min), and the viscosity of the broken gel fluid was consistently 3.5 mPa·s across all breaker types. No residues were detected after centrifugation (content < 0.1 mg/L), avoiding pore blockage by solid residues. The gel-breaking mechanism is rooted in the hydrophilic groups within breakers (e.g., components of Tween-80 and tap water) inserting into the worm-like micelles of GEM-CBM, disrupting the micellar entanglement. The micelles then dissociate into single molecules or small aggregates that are easily soluble in formation water, resulting in no solid residues (Figure 9).

Permeability recovery experiments demonstrated that the coal core permeability recovery rate reached 78.6% (Figure 10), far exceeding that of polymer fracturing fluids (usually <50%). Microscopically, POM observations revealed that after the fracturing fluid interacted with the coal core, micelles only formed a thin adsorption layer (thickness < 50 nm) on the coal surface without entering micropores. DLS tests showed no significant change in micelle size (365 nm → 372 nm) in simulated formation water (Figure 11), confirming that salt ions did not induce micelle aggregation and further explaining its stable performance in high-salinity environments.

4. Conclusions

We succeeded in synthesizing a Gemini surfactant (GEM-CBM) tailored for CBM reservoirs. FTIR and EA characterizations verified that GEM-CBM’s molecular structure includes the intended functional groups, such as hydroxyl and amide. GEM-CBM exhibits excellent surface activity (CMC = 19.0 μmol/L, γCMC = 37.44 mN/m, Γₘₐₓ = 4.21 × 10⁻⁶ mol/m², Aₘᵢₙ = 0.40 nm²/molecule) and can form a stable worm-like micellar network.

The optimized GEM-CBM-based clean fracturing fluid (formulation: 2.3% GEM-CBM + 0.3% Tween-80 + simulated formation water with 150,000 mg/L mineralization) demonstrates good adaptability to CBM reservoir traits: after 100 min of shearing at 90 °C and 170 s⁻¹, its viscosity retention rate reaches 65.4%, and even when formation water mineralization hits 250,000 mg/L, the viscosity retention rate still stays above 80%. The proppant settlement velocity is 0.08–0.14 mm/s within 30–90 °C, showing excellent sand-carrying capacity. It has a fluid loss coefficient of 3.2 × 10⁻⁴ m/min^1/2, and with different breakers (tap water, Tween-80, kerosene), it achieves complete gel breaking within 10–70 min without residues.

The fracturing fluid induces minimal damage to CBM reservoirs, as evidenced by a 78.6% permeability recovery rate in Qinshui Basin coal cores. Its performance strengths come from two key factors: the stable network structure and low adsorption of GEM-CBM micelles, and the strong temperature and salt resistance enabled by the hydration layer of hydroxyl groups. These properties provide comprehensive technical support for efficient CBM development.

Future research can focus on optimizing the industrial synthesis process of GEM-CBM to reduce production costs and verifying its practical application effect through field fracturing experiments.