Recent Progress on Fracturing Fluid for Coalbed Methane in China ()
1. Introduction
China’s coalbed methane (CBM) reserves are estimated at 36.8 trillion cubic meters in coalbeds at depths of up to 2,000 meters. Resources at depths exceeding 1000 meters account for 61.2% of total reserves, indicating enormous development potential [1] [2]. As CBM development progresses, efforts are gradually shifting toward deeper reservoirs. Compared to shallow coalbeds, deep coalbeds typically exhibit low permeabilit y, low saturation, and high gas content. Coal fines production, fracture closure, and the inherently low permeability of deep coalbeds result in low production rates and rapid decline in CBM wells [3] [4]. Therefore, stimulation measures are required to enhance recovery from CBM wells, which will help promote China’s CBM development [5]. According to reports, among more than 10,000 CBM wells in the United States, 90% achieved production enhancement targets through hydraulic fracturing [6]. Currently, hydraulic fracturing is also the most widely used stimulation technology for CBM development in China. However, because geological conditions vary significantly across regions, using incompatible fracturing fluids can directly impair fracturing effectiveness and cause formation damage [7].
Therefore, China’s coalbeds are characterized by high gas content, low permeability, high salinity, and high in-situ stress. Additionally, CBM wells typically produce large volumes of high salinity flowback fluid that is difficult to reuse. Consequently, there is an urgent need for fracturing fluid systems that are highly efficient, environmentally friendly, low-cost, minimally damaging, easy to formulate, salt-tolerant, and reusable. Recognizing the critical role of fracturing fluids in CBM development, this paper systematically reviews various fracturing fluid systems currently employed, analyzes their limitations, and explores their compatibility with CBM reservoirs. Finally, it offers an outlook on future development trends for CBM fracturing fluids.
All reference cited and referenced in this paper was sourced from authoritative databases such as China National Knowledge Infrastructure (CNKI) and Web of Science. Keywords included “fracturing fluid,” “coalbed methane,” and “China,” with the time range spanning from 1990 to 2024. After identifying relevant literature, appropriate references were selected based on an assessment of their main content aligned with the topic of this paper.
2. Common Fracturing Fluid Systems Used in Coalbed
Methane Applications
In China, coalbeds are characterized by low permeability and high in-situ stress, which result in high fracturing pressures, difficulties in fracture propagation, and a high risk of reservoir damage. Consequently, fracturing fluids must exhibit high friction reduction, excellent proppant transport capability, low cost, and low damage potential. According to their primary compositions, fracturing fluid systems currently employed in CBM development can be broadly categorized as active water, cross-linked gel, clean, and foam fracturing fluids [8].
To systematically compare the suitability, advantages, and disadvantages of different fracturing fluid systems, this study primarily compares their performance in terms of sand-carrying capacity, flowback performance, temperature resistance, reservoir damage, cost, and technical maturity, thereby enabling a better evaluation and comparison of the various fracturing fluid systems. The performance comparisons and evaluation criteria are presented in Table 1.
Table 1. Key points for comparing fracturing fluid properties.
Fracturing Fluid
Properties |
Core Characteristics |
Key Evaluation Criteria |
Proppant transport |
The fluid’s ability to carry and distribute proppants |
Viscosity-shear relationship, sand suspension stability, placement
efficiency |
Flowback
efficiency |
Post-pressurization discharge rate and completeness |
Gel-breaking performance, surface tension, risk of formation water lock |
Temperature tolerance |
Stability of performance in high-temperature reservoirs |
Upper temperature limit, thermal degradation characteristics,
crosslinking stability |
Reservoir
damage |
Degree of damage to reservoir permeability |
Filtration loss, residue content, clay swelling inhibition |
Cost |
Economic feasibility |
Material cost, construction cost, overall cost-benefit ratio |
Field maturity |
Degree of field validation of the technology |
Number of field application cases, success rate |
Proppant transport |
The fluid’s ability to carry and distribute proppants |
Viscosity-shear relationship, sand suspension stability, placement
efficiency |
2.1. Active Water Fracturing Fluid
Active water fracturing fluid consists primarily of clean water with additives such as anti-swelling agents and surfactants. It is widely used because of its low viscosity, high flowback efficiency, low formation damage, and low cost. Research and application of active water fracturing fluid began in the 1970s, with international researchers taking the lead [9]. A field test comparing active water and cross-linked gel fracturing fluids was conducted in the Black Warrior Basin, United States, using CBM wells with over 1.5 years of production history [10]. The test results showed that active water fracturing fluid outperformed cross-linked gel fracturing fluid: daily production rates were 3256.5 m3/d and 2265.4 m3/d, respectively [10].
Parallel progress has been made in China’s research on active water fracturing fluids. To develop a fracturing fluid suitable for Jurassic CBM reservoirs in the Jiaoping mining area, Fan et al. [11] selected 1.0% KCl as an anti-swelling agent and 0.05% fluorocarbon surfactant as a friction reducer and proposed an active water fracturing fluid system for the target block. Geng et al. [12] optimized fracturing fluid formulations in the laboratory based on coal core properties of the target block. The resulting active water fracturing fluid comprised water, 2% FH-2, and 0.2% JX-D friction reducer (by mass), which was successfully validated through field fracturing tests.
The imbibition of fracturing fluid into the coal seam matrix can significantly reduce matrix permeability, ultimately affecting stimulation effectiveness. Therefore, researchers have investigated permeability reduction caused by active water fracturing fluid retention in coal seams. Zhang et al. [13] developed an active water fracturing fluid tailored to CBM reservoir geology, comprising an anti-swelling agent, a coal fines dispersant, a friction reducer, and a flowback aid. This formulation caused only a 17.2% reduction in coal matrix permeability and minimally affected propped fracture conductivity. Zhang et al. [14] optimized active water fracturing fluid formulations for CBM wells in the Fukang mining area by evaluating viscosity, proppant transport capability, and formation damage potential. To mitigate residue-induced pore clogging and production decline, Li et al. [15] investigated the effects of polyacrylamide-containing active water fracturing fluid on two coal samples with different gas adsorption properties. They found that methane adsorption capacity correlates with pore structure: samples with greater pore volume, higher internal surface roughness, and more complex network structures exhibited stronger adsorption. Liu et al. [16] developed a novel active water fracturing fluid for CBM wells, which caused less than 15% permeability reduction in coal cores. Field application in five CBM wells yielded daily gas production exceeding 1,000 m3/d per well, demonstrating effective stimulation.
Figure 1 presents typical formulations of active water fracturing fluids and the mechanisms of their retention in coal matrix. Although these fluids provide simple formulation, low damage potential, and low cost, they exhibit low viscosity and poor proppant transport capability. Consequently, proppant bridging may occur during operations, and controlling fracture geometry remains challenging. In coalbeds with low permeability and poorly developed natural fractures, active water fracturing fluids are prone to water blocking and pore plugging due to capillary retention, limiting their applicability.
Figure 1. Comparison of typical active water fracturing fluid formulations, the retention and adsorption mechanisms of active water.
2.2. Cross-Linked Gel Fracturing Fluid
Cross-linked gel fracturing fluids typically comprise gelling agents, cross-linkers, breakers, anti-swelling agents, friction reducers, and biocides [17]. Borate-cross-linked hydroxypropyl guar gel fracturing fluids are commonly used in the San Juan and Black Warrior basins, United States. Average daily production of treated CBM wells ranges from 2832.0 to 7079.3 m3/d [18]. Based on compatibility studies with various Indian coal samples, Choudhary et al. [19] concluded that linear gel fracturing fluid systems with viscosities of 11 - 20 mPa·s are optimal for CBM fracturing in Indian reservoirs.
Hydroxypropyl guar gum is the most widely used modified guar gum product due to its stable performance and relatively low cost. Gan et al. [20] prepared a novel organoboron crosslinking agent, BX-Y, using borate and the organic ligand D-fructose. Crosslinking this agent with hydroxypropyl guar gum yielded a BX-Y crosslinked fracturing fluid with a gel-breaking viscosity of only 5 mPa·s. This fracturing fluid exhibited a permeability recovery rate of over 85% and demonstrated good reservoir protection performance. Kun Xu et al. [21] developed a hydroxypropyl guar gel fracturing fluid crosslinking agent, GJ-1. Performance studies on a fracturing fluid system prepared with 0.15% modified hydroxypropyl guar gum and 0.3% GJ-1 showed that the crosslinking rate was fast, the damage rate was low, and the residue content after gel breakdown was 33 mg/L, effectively reducing damage to fracture flow capacity. Similarly, Zhang [22] optimized a fracturing fluid system consisting of 0.3% guar gum, 0.5% clay stabilizer, 0.5% KCl, 0.3% foaming agent, 0.3% flow-enhancing agent, 0.1% biocide, and 0.5% water-lock damage treatment agent, and conducted field fracturing operations in coalbed methane wells, achieving good fracturing results.
To minimize fluid loss from fracturing fluids and reduce water-locking damage to reservoirs caused by external fluids, Fan et al. [23] investigated the solubility of guar gum, hydroxypropyl guar gum, and carboxymethyl hydroxypropyl guar gum in ethanol at different volume fractions. They prepared alcohol-crosslinked fracturing fluids using sodium tetraborate as the crosslinking agent and evaluated their performance. The results showed that the crosslinking time of the fracturing fluid first increased and then decreased with increasing ethanol volume fraction, whereas the addition of ethanol significantly improved the temperature resistance of the fracturing fluid. Furthermore, Huang et al. [24] studied the main components, rheological properties, and friction characteristics of guar gum-based fracturing fluids, concluding that highly effectiv e gum-breaking agents are of great significance for advancing guar gum fracturing fluid technology.
In response to the low reservoir temperatures characteristic of coalbed methane, Xu et al. [25] conducted laboratory-scale optimization of additives and established the following low-temperature fracturing fluid formulation: 1.5% KCl, 0.3% thickener XD-02, 0.3% flow enhancer DB-80, 0.1% biocide SJ, 0.15% crosslinking agent TCB-2, 0.15% ammonium persulfate, and 0.1% low-temperature activator HY-02. Performance evaluation results showed that the low-temperature fracturing fluid system exhibited excellent temperature and shear resistance, thorough gel breakdown, low fluid loss, and low residue content. Field applications indicated that the low-temperature fracturing fluid exhibited good proppant-carrying capacity and thorough gel breakdown, achieving favorable stimulation results.
In contrast to plant-based crosslinked gel fracturing fluids, non-plant-based crosslinked gel fracturing fluids have also attracted the attention of researchers. Dai et al. [26] developed a zirconium gel fracturing fluid; laboratory test results indicated that this gel fracturing fluid offered advantages such as ease of preparation, low cost, high shear resistance, low filtration coefficient, rapid gel breakdown, no post-breakdown residue, and ease of recovery. Similarly, based on an analysis of factors affecting the performance of zirconium gel fracturing fluids, Zhao et al. [27] optimized a nonionic polyacrylamide-zirconium gel fracturing fluid (0.4% PAM + 0.035% ZrOCl2) through laboratory testing. Performance evaluation results indicated that this fracturing fluid broke down easily, left no residue, caused minimal damage to coal seams, and was easily recovered, making it suitable for use in low-temperature coal seam fracturing. To address the issue of structural instability in polyacrylamide-zirconium gel fracturing fluids, Xu et al. [28] employed a two-stage temperature-controlled radical polymerization method in aqueous solution to investigate the influence of synthesis conditions on polyacrylamide (PAM) performance. The results showed that by optimizing reaction conditions, a gel with good viscoelasticity could be synthesized that cross-linked with zirconium salts at room temperature. The low concentration of the gelling base significantly reduced the cost of the fracturing fluid.
Crosslinked gel fracturing fluid systems can be broadly categorized into plant-based crosslinked gel fracturing fluids and non-plant-based crosslinked gel fracturing fluids. A summary of the main crosslinked gel fracturing fluid systems is provided in Table 2. Compared with aqueous fracturing fluids, crosslinked gel fracturing fluids exhibit higher viscosity and offer advantages such as excellent temperature and shear resistance, strong proppant-carrying capacity, and low fluid loss. These properties facilitate proppant transport into fractures and enhance fracture propagation, making them suitable for most coal seams, particularly those with stringent temperature requirements for fracturing fluids. However, crosslinked gel fracturing fluids still face challenges such as incomplete gel breakdown, flowback difficulties, tendency to clog coal seam pores and fractures, and potential formation damage. Future developments should focus on achieving complete gel breakdown, improved flowback efficiency, and reduced reservoir damage.
Table 2. Summary of cross-linked gel fracturing fluid systems.
Type |
Key Ingredients |
Key Performance |
Ref. |
Plant-based gel fracturing
fluids
(primarily
hydroxypropyl guar gum) |
Organic boron crosslinking agent BX-Y + hydroxypropyl guar gum |
The viscosity of the de-gelling
solution is 5 mPa·s; the recovery rate of permeability is >85%. |
[20] |
Crosslinking agent GJ-1 + 0.15% modified hydroxypropyl guar gum |
Fast cross-linking speed and low damage rate |
[21] |
Plant-based gel fracturing fluids (primarily hydroxypropyl guar gum) |
0.3% guar gum + 0.5% clay
stabilizer + 0.5% KCl + 0.3% foaming agent + 0.3% drainage aid + 0.1% biocide + 0.5%
water-locking agent |
Excellent heat and shear
resistance; thorough rubber
breakdown |
[22] |
Various types of guar gum + sodium tetraborate + ethanol at different volume fractions |
The crosslinking time first
increases and then decreases with the ethanol content |
[23] |
1.5% KCl + 0.3% thickener + 0.3% drainage aid + 0.1%
biocide + 0.15% cross-linking agent + 0.15% ammonium
persulfate + 0.1%
low-temperature activator |
Excellent temperature and shear resistance, thorough gel
breakdown, low fluid loss, and low residue |
[25] |
Plant-based gel fracturing fluids
(primarily
hydroxypropyl guar gum) |
Zirconia gel fracturing fluid |
Easy to prepare, low-cost, high shear resistance, and low filtration coefficient |
[26] |
Non-ionic polyacrylamide
zirconium gel |
Easily breaks down, leaves no
residue, causes minimal damage to coal seams, and is easy to flush out |
[27] |
Synthesis of structured PAM via dual-temperature control |
PAM cross-links with zirconium salts at room temperature,
exhibiting good viscoelasticity. |
[28] |
2.3. Clean Fracturing Fluid
Clean fracturing fluids are a type of fracturing fluid composed of viscoelastic surfactants (VES). Through self-assembly in aqueous solution, these surfactants form wormlike micelles that entangle to create a reversible three-dimensional network structure, significantly increasing the solution viscosity and imparting distinctive rheological properties. The mechanism of action of VES fracturing fluids is illustrated in Figure 2 [29]. Clean fracturing fluids were first developed by Schlumberger in the 1990s and successfu lly applied to hydraulic fracturing, which has led to increased attention from researchers.
Dong et al. [30] developed a viscoelastic surfactant fracturing fluid tailored to the characteristics of coal seams in the Jincheng region. Experimental results showed that the system exhibited good viscoelasticity, low viscosity after gel breakdown, and a high recovery rate, with a permeability recovery rate of 78% for the coal sample. Qin et al. [31] developed a clean fracturing fluid system tailored to the characteristics of a specific coalbed methane block in the Qinshui Basin, using two viscoelastic surfactants as the main agents and co-surfactants and KCl as auxiliary agents. Laboratory test results showed that this fracturing fluid system exhibited excellent temperature and shear resistance and viscoelastic properties, demonstrated low formation damage characteristics, and yielded a permeability damage rate of only 7.27% for coal cores.
Figure 2. Mechanism of action of ves fracturing fluid and reservoir enhancement effects.
Depending on the surfactants used, clean fracturing fluids can be broadly classified into cationic, anionic, amphoteri c, and nonionic types. Wang [32] prepared a VES-18 clean fracturing fluid by blending cationic quaternary ammonium salts and organic salts and investigated its key properties. The results showed that the VES-18 fracturing fluid exhibited good proppant-carrying capacity, complete gel breakdown within 4 hours, a post-breakdown viscosity of less than 3 mPa·s, and good compatibility with the formation. Wang et al. [33] optimized the composition and gel-breaking strategy of the clean fracturing fluid. The optimized fracturing fluid consisted of 4% cetyltrimethylammonium bromide (CTAB), 2% sodium salicylate, and 2% KCl. A mixture with a water-to-lubricant volume ratio of 25:1 served as an ideal gel-breaking agent; the residual content of the fracturing fluid after treatment with this agent was 0.05 g/L. Similarly, Wang et al. [34] synthesized a diamide cationic surfactant using erucic acid, N,N-dimethyl-1,3-propanediamine, and epichlorohydrin as raw materials under acidic conditions. By mixing it with a KCl solution, they prepared a clean fracturing fluid system. Relevant performance tests indicated that this product offered advantages such as good shear stability, low viscosity, low filtrate loss, and excellent gel-breaking performance. To investigate the effects of surfactant composition and fracturing fluid formulation on the performance of the fracturing fluid system, Yang et al. [35] analyzed the effects of cationic surfactant hydrocarbon chain length on water loss, wettability, viscosity, and temperature resistance. They found that stearyl trimethyl ammonium chloride (STAC) was more effective than cetyltrimethylammonium chloride (CTAC) in reducing fluid loss during the fracturing process. An appropriate amount of cocoyl amide propyl betaine (CAB) could improve the viscosity and temperature resistance of the fracturing fluid.
To address issues such as the adsorption of cationic surfactant fracturing fluids in the formation and the resulting secondary damage to the reservoir, Yu et al. [36] synthesized a long-chain tertiary amine (OADA) using oleylamine as the raw material. Using OADA as the main agent and acetic acid as an additive, they formulated a clean fracturing fluid system by blending the mixture with a KCl solution. An evaluation of the fracturing fluid’s performance revealed that it exhibited good temperature and shear resistance and was easy to demulsify. The surface and interfacial tensions of the demulsified fluid were low, and the permeability damage rate to coal cores was only 5.82%, which was beneficial for reservoir protection. Yin et al. [37] developed a pH-responsive clean fracturing fluid based on the interaction between oleamide propyl dimethylamine and butane tetracarboxylic acid under specific pH conditions. Performance evaluation results indicated that by adjusting the pH, the zero-shear viscosity of the fracturing fluid could exceed 240 mPa·s. After 60 minutes of shearing at 90˚C and 170 s−1, the viscosity remained above 200 mPa·s. The gel broke completely within 1 hour, leaving no residue.
Compared with crosslinked gel fracturing fluids, clean fracturing fluids exhibit superior gel-breaking performance; however, the issue of gel breaking in clean fracturing fluids still warrants attention. Huang et al. [38] conducted laboratory studies to investigate the effects of gel-breaking agent type, temperature, dosage, and pH on gel-breaking performance. They identified four gel-breaking agents suitable for coalbed methane wells at different fracturing depths. The study found that with a dosage of 0.02% - 0.03%, the gel-breaking time could be controlled within 0.5 - 5 hours, the viscosity of the broken gel fluid was less than 3 mPa·s, and the residue content was below 0.1%, resulting in minimal damage to the coal seam. Similarly, Ma et al. [39] developed a low-temperature, controllable, invisible gel-breaking clean fracturing fluid with the following formulation: 0.35% octadecyltrimethylammonium chloride, 0.15% sodium salicylate, 0.06% KCl, 0.06% synergist, and 0.08% anti-residue agent, which demonstrated excellent results in field tests at the Fanzhuang block in the Qinshui Basin, showing great application potential.
To better analyze the effects of coal reservoir modification, Changwei Wang et al. [40] conducted immersion experiments using clean fracturing fluids with varying ultrasonic exposure times. The results indicated that, under ultrasonic irradiation, the fracturing fluid reacted chemically with mineral impurities, improving pore structure characteristics and pore connectivity; the combined effect of ultrasonic irradiation and the fracturing fluid increased the aromaticity of the coal, facilitating methane desorption. Lu et al. [41] experimentally investigated the effects of viscoelastic surfactant fracturing fluids on the composition, pore structure, and gas permeability of coal samples from different burial depths. They found that viscoelastic surfactant fracturing fluids reduced the content of clay minerals in coal that tend to clog pores and fractures; compared to water, the use of viscoelastic surfactant fracturing fluids reduced blockage of migration pathways and improved gas flow. Comparative permeability tests on coal samples treated with viscoelastic surfactant fracturing fluids and water showed that the former increased permeability by 178%. Furthermore, a comparison of the core permeability loss rates for different fracturing fluid systems is shown in Figure 3. VES fracturing fluids exhibited the lowest core permeability loss rates, followed by active water fracturing fluids, while crosslinked gel fracturing fluids exhibited the highest core permeability loss rates.
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Figure 3. Comparison of permeability and porosity in core samples.
Compared with active water fracturing fluids, viscoelastic surfactant fracturing fluids exhibit higher proppant-carrying capacity and can effectively transport proppants into fractures. Compared with crosslinked gel fracturing fluids, they break down more easily and contain less residue, resulting in less damage to coal reservoirs. However, ionic surfactants are incompatible with formation water, leading to precipitation that can block coal seam pores and exacerbate reservoir damage. Furthermore, the relatively high application cost of clean fracturing fluids limits their widespread adoption.
2.4. Foam Fracturing Fluid
Foam fracturing fluid is a stable mixture of gas and liquid phases. It primarily consists of a base fluid, gas, foaming agent, and foam stabilizer, and is characterized by easy recovery, low damage potential, and strong proppant-carrying capacity [42]. The gas used is typically N2 or CO2; a comparison of the properties of these two gases is shown in Figure 4.
As shown in Figure 4, N2 and CO2 foam fracturing fluids each have their own advantages and limitations; therefore, both types have been extensively studied. Wu et al. [43] conducted field trials of the N2 foam fracturing process in the Daning-Jixian area, considering the geological characteristics of the coal seam. Field operations demonstrated that N2 foam fracturing technology could increase the proppant-to-fluid ratio, effectively reduce fluid loss, and minimize damage to coal reservoirs caused by the fracturing fluid. Liu [44] selected N2 as the gas phase for the foam fracturing fluid, screened suitable foaming agents and foam stabilizers, and prepared a foam fracturing fluid system characterized by large bubble size, long half-life, good proppant-carrying capacity, and low fluid loss. The damage rate to coal cores was comparable to that of active water fracturing fluids. Mao et al. [45] developed the following N2 foam fracturing fluid formulation: 0.2% foaming agent SK-1, 0.3% foaming agent SK-2, 0.2% foam stabilizer WWP-11, and 2.0% KCl. Coalbed methane wells treated with this foam fracturing fluid system experienced a significantly shorter time to initial gas production and a marked increase in daily gas production.
![]()
Figure 4. Comparison of the physical properties of CO2 and N2.
In contrast to N2 foam fracturing fluids, CO2 foam fracturing fluids have also been extensively studied. Based on the characteristics of coal seam reservoirs, Gong et al. [46] proposed a CO2 foam fracturing process for deep coal seams, which is characterized by low fluid loss, strong proppant-carrying capacity, and good fluid recovery. Liu et al. [47] investigated the effect of CO2 foam fracturing fluid on coal permeability and found that after 8 hours of immersion in either water or CO2 foam fracturing fluid, the proportion of micropores smaller than 10 nm in the coal samples decreased, and the specific surface area of the pores also decreased. Notably, immersion in CO2 foam fracturing fluid promoted methane desorption from the coal samples.
CO2 purification is difficult and costly, and N2 does not promote methane desorption. To address these challenges, Liu [48] formulated a mixed-gas foam fracturing fluid based on novel foaming agents and foam stabilizers: 1% QSL-1 surfactant, 0.5% modified nanoparticles, 0.7% NH4Cl, and mixed gas (CO2/N2, volume ratio 5:1). Performance studies revealed that the foam quality reached 81%, with a half-life exceeding 1 hour, effectively resolving issues such as low foam quality, single-gas composition, and poor stability. Lü et al. [49] used SiO2 nanoparticles as a novel intensifier for CO2 foam fracturing fluids and investigated the performance of the enhanced foam. The results indicated that SiO2 nanoparticles increased the roughness of the gas-liquid interface, enhanced the resilience of the foam film after deformation, and significantly improved foam stability under high-temperature and high-pressure conditions. A comparison of the performance of different foam fracturing fluid systems is shown in Figure 5, an equally weighted relative comparison method was adopted. On a 1 - 5 point scale, 3 points represent the average level for similar systems, 5 points indicate clearly superior performance, and 1 point indicates clearly inferior performance; the 0 - 100-point scale is normalized to a percentage-based system. All dimensions are given equal weight to avoid subjective bias in weighting, subsequent similar data would be processed according to the aforementioned method. The mixed-gas foam fracturing fluid exhibits the best overall performance.
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Figure 5. Comparison of the performance of different foam fracturing fluid systems (Relative Comparison Based on reference [43]-[53]).
Once foam fracturing fluid enters a coal reservoir, the gases in the fracturing fluid system expand under reservoir conditions; therefore, it is necessary to study the effects of foam fracturing fluid on methane diffusion and flow in coal reservoirs. Yang et al. [50] used molecular simulation software to study the effects of foam fracturing fluid additives on methane diffusion in coal seams. The results indicated that foaming agent molecules significantly impeded methane diffusion, while foam stabilizers further exacerbated damage to the coal seam. They recommended optimizing the structure of foaming agents and reducing their dosage to minimize adverse effects on methane diffusion in coal seams, while maintaining the performance of the fracturing fluid. Huang et al. [51] analyzed the effects of two types of fracturing fluids—active water fracturing fluid and foam fracturing fluid—on methane flow in coal seams. The study found that an increase in fracturing fluid concentration exacerbated damage to methane flow in the coal seam, while lower viscosity of the foam fluid resulted in less damage to methane adsorption, desorption, and coal seam permeability.
To develop a foam fracturing fluid that causes minimal damage to coal seams, Song et al. [52] proposed preparing CO2 foam under non-sealed conditions and using a composite foam stabilizer to create a low-damage foam fracturing fluid system. Performance test results indicated that this system exhibited excellent temperature and shear resistance, good coal powder dispersion, and anti-swelling properties. Simulation of coalbed methane extraction methods demonstrated that this fracturing fluid caused minimal damage to coal seams. Similarly, Xu [53] developed a low-damage, desorption-promoting foam fracturing fluid for low-water-content coal seams. Performance tests revealed that this fluid exhibited good proppant-carrying capacity, strong coal powder dispersion capability, and a negative permeability damage rate for coal cores. After immersion in the foam fracturing fluid, the adsorption of methane by coal powder was reduced, indicating that this fluid promoted the desorption of methane from the coal seam.
Foam fracturing fluids are characterized by high viscosity, low fluid loss, strong proppant-carrying capacity, and ease of recovery, thereby significantly reducing fluid retention in the reservoir and minimizing reservoir damage. They are commonly used for reservoir enhancement in shallow coal seam reservoirs. However, for fracturing operations in medium- to deep-depth wells and high-temperature and high-pressure wells, the foam stability of these systems needs improvement. Additionally, they suffer from drawbacks such as high operational costs and long preparation times, which require further investigation.
2.5. Comparison of the Properties of Different Fracturing Fluids
Currently, the fracturing fluids commonly used in coalbed methane reservoir enhancement include active water fracturing fluids, crosslinked gel fracturing fluids, clean fracturing fluids, and foam fracturing fluids. The primary cause of core damage associated with active water fracturing fluids is the low volume of fluid returned after pressure drops, which can easily lead to water-locking damage and pore plugging. Due to issues such as incomplete gel breakdown and flowback difficulties, crosslinked gel fracturing fluids are prone to blocking coal seam pores, thereby causing damage to coal reservoirs. Clean fracturing fluids break down easily, have low residue content, and cause less damage to coal reservoirs; however, they may be incompatible with formation water, leading to precipitation that blocks coal seam pores and exacerbates reservoir damage. Foam fracturing fluids contain compressible gas; when the gas is released, it rapidly expands, facilitating rapid fluid return. This significantly reduces the fluid’s residence time in the reservoir, thereby minimizing reservoir damage. These fracturing fluids each have their own advantages and disadvantages and are subject to certain limitations in practical applications. A comparison of the performance of several fracturing fluids commonly used in coalbed methane development is shown in Table 3.
Table 3. Performance comparison of different fracturing fluid systems.
Types of
Fracturing Fluids |
Main Ingredients |
Key Benefits |
Main Drawbacks |
Active water fracturing fluid |
Surfactant/
Anti-foaming agent |
Low impact/Low cost/Simple process |
Low sand-carrying
capacity/Difficult to control cracking
patterns/High
construction pressure |
Cross-linked gel fracturing fluid |
Thickening agent/Cross-linking agent/Dispersing agent |
High sand-carrying
capacity/Low filtrate loss/Temperature and shear resistance |
Resistant to gel
breakdown/Difficult to reverse flush/High risk of reservoir
damage |
Clean fracturing fluid |
Viscoelastic
surfactants |
Low irritation/Minimal leaching/Good
viscoelasticity/Leaves
no residue |
Not
heat-resistant/High cost |
Foam fracturing fluid |
Base fluid/Foaming agent/Vapor phase |
High sand-carrying
capacity/Easy
backflushing/Low
damage |
High cost/Stringent requirements for
fracturing operations |
3. Novel Fracturing Fluid
Coal seam fracturing operations should be based on geological characteristics, with the goal of creating complex artificial fractures that provide effective support, high fracture conductivity, and sufficient length. To achieve coal seam fracturing objectives such as “long fractures, sustained support, high fracture conductivity, and minimal damage,” researchers have developed an increasing number of novel fracturing fluid systems, including liquid gas fracturing fluids, energy-enhancing fracturing fluids, nano-fracturing fluids, supramolecular fracturing fluids, and viscosity-modifying fracturing fluids.
3.1. Liquid Gas Fracturing Fluid
To avoid problems associated with water-based fracturing fluids—such as incomplete gel breakdown, flowback difficulties, and water-locking damage—a liquid-gas fracturing fluid has been developed that causes no damage to the reservoir. The liquid gas used is typically liquid N2 or liquid CO2. Upon contact with the coal seam, the liquid gas causes the temperature to drop sharply, causing the coal matrix to contract. This, in turn, causes pore water to freeze and expand, while thermal contraction of the coal matrix occurs, fracturing the reservoir and forming a complex fracture network.
After conducting a comprehensive review of the application of liquid N2 fracturing fluids in coalbed methane development, Longinos et al. [54] concluded that cryogenic fracturing can serve as an effective method for creating complex fracture networks in coal seams. Liquid N2 fracturing fluids can widen existing fractures and generate new ones, thereby enhancing the permeability of coal reservoirs. Wen et al. [55] investigated the flow and heat transfer characteristics of N2 during liquid N2 fracturing in CBM reservoirs. They established a three-dimensional unsteady fluid flow and heat transfer model for liquid N2 fracturing in CBM reservoirs. This model accounts for the phase change of N2, variations in the thermal properties of coal, and heat transfer between N2 and the formation, thereby elucidating the distribution of N2 and its impact on fracture generation.
Yang et al. [56] investigated the performance of a composite fracturing technique combining hydraulic fracturing and liquid N2 fracturing. Compared with pure liquid N2 fracturing, the average fracture aperture, number of fractures, and total fracture volume increased by 28%, 10%, and 34%, respectively. Compared with hydraulic fracturing, the average fracture aperture in composite fracturing decreased, but the number of fractures and total fracture volume increased by 55% and 42%, respectively, thereby forming a more complex fracture network. The enhancement effect of liquid N2 composite fracturing is shown in Figure 6.
Figure 6. Enhanced fracturing effects of liquid nitrogen composite fracturing.
Wen et al. [57] compared the fracture pressures and fracture morphologies of several different fracturing methods. The results indicated that thermal damage caused by the freezing of liquid N2 was the primary factor contributing to the complex fracture morphology observed in cryogenic fracturing, and they concluded that liquid N2 composite fracturing technology held greater potential for practical application.
While there has been extensive research on liquid N2 fracturing fluids, liquid CO2 fracturing fluids have also garnered research attention. Xu et al. [58] proposed a multi-cycle liquid CO2 fracturing technique and investigated the feasibility of using liquid CO2 to induce low-temperature effects on the crack evolution in five different coal cores under loading conditions. Their findings indicated that the low-temperature effects of liquid CO2 could significantly improve pore connectivity and markedly increase coal seam permeability. Addressing the limitations of traditional coal seam fracture simulation methods in improving methane desorption and permeability, Kang et al. [59] employed theoretical analysis, numerical simulation, and field experiments to investigate the application of liquid CO2 in coal seam fracturing and its impact on methane desorption. Their study indicated that the maximum pressure generated by the rapid thermal expansion of liquid CO2 could induce the initiation and propagation of cracks and fractures in coal. Liu et al. [60] further determined the effective damage radius of liquid CO2 fracturing by continuously monitoring gas flow rates in different observation boreholes. They also explored methods to further optimize methane drainage through liquid CO2 fracturing under varying coal seam thicknesses and geological conditions. The results indicated that the application of liquid CO2 fracturing technology in coalbed methane wells was effective.
During injection, the liquid-gas fracturing fluid remains in liquid form, but it completely vaporizes during the flowback process, leaving no liquid residues or harmful substances in the formation. It causes no damage to the reservoir and facilitates the formation of complex fracture networks. However, its application costs are prohibitively high, and it requires sophisticated infrastructure, making large-scale implementation difficult.
3.2. Energy-Enhanced Fluid Fracturing Fluid
Energized fracturing fluids are a new type of fracturing fluid developed from foam fracturing fluids. Inert gases or foam are typically selected as the energy-enhanced fluid. The main difference between energy-enhanced fluid fracturing fluids and foam fracturing fluids lies in the gas content: the gas content in energy-enhanced fluid fracturing fluids is less than 52%. When the gas content exceeds 52%, the system is classified as a foam fracturing fluid [61].
Energy-enhanced fluid fracturing fluids can automatically generate heat, produce gas, and increase pressure through internal chemical reactions alone, subsequently forming foam within the reservoir and ultimately achieving effects similar to those of foam fracturing fluids. Based on this, He [62] developed a self-heating foam-enhanced fracturing fluid. It was found that this fracturing fluid system could generate a large amount of thermal energy and gas within the formation. Once foam is formed, it preferentially occupies rock pores to reduce fluid loss, and the large amount of gas produced exerts an automatic gas lift effect, significantly improving the fluid recovery rate. Field tests indicated that self-heating foam-enhanced fracturing fluids effectively reduced fluid loss from the reservoir while improving post-fracturing production gains. Similarly, Zhang et al. [63] developed a self-generating gas-type foam-enhanced fracturing fluid and evaluated its performance. The results showed that this system possessed excellent temperature and shear resistance as well as rheological properties, with low fluid loss and minimal reservoir damage, fully meeting the fracturing process requirements for proppant loading and fluid recovery.
To promote rapid fluid return and gel breakdown, Cai et al. [64] incorporated the exothermic reaction between NH4Cl and NaNO2 into the fracturing fluid system, creating a novel foam-like energy-enhanced fracturing fluid. Laboratory test results indicated that this fracturing fluid system offered advantages such as rapid fluid return, high self-spouting return rates, residue-free operation, and low damage potential. It has been successfully applied in field fracturing operations, yielding good production enhancement results. Through laboratory studies, Chen [65] found that foam-like energy-enhanced fracturing fluids possessed excellent proppant-carrying capacity, reduced fluid loss, and low-damage properties. After conducting 14 fracturing operations in the Ling 72 well area, the fracturing process achieved a success rate of 92.3% and a treatment effectiveness rate of 71.4%, resulting in favorable reservoir enhancement effects. Building upon existing fracturing fluid systems, Zhang et al. [66] proposed a novel in-situ heated energy-enhanced fracturing fluid system. They conducted systematic optimization through laboratory experiments based on performance evaluation criteria for water-based fracturing fluids. Compared with traditional fracturing fluid systems, the in-situ heated energy-enhanced fracturing fluid system generates a large amount of inert gas and forms a foamy fracturing fluid. This system reduces fluid loss, enhances proppant transport capacity and gel-breaking performance, improves fracture flow capacity, leaves no gel residue, and produces a clean, non-toxic post-breakdown fluid, thereby demonstrating greater application potential.
A comparison of the performance characteristics of energy-enhanced fluid fracturing fluids and foam fracturing fluids is shown in Figure 7. As shown in Figure 7, energy-enhanced fluid fracturing fluids exhibit excellent proppant-carrying capacity, reduced fluid loss, and enhanced fluid drainage, combining the technical advantages of both conventional water-based fracturing fluids and foam fracturing fluids. However, during fluid recovery, energy-enhanced fluid fracturing fluids are prone to causing coal dust migration due to excessive flow rates, which can block CBM permeation pathways. Subsequent research should focus on preventing reservoir blockage damage caused by fracturing fluid recovery.
3.3. Fracturing Fluid Modified with Nanomaterials
Due to the unique physicochemical properties—including high permeability, strong electrical conductivity, and significant reinforcement effects—nanomaterials are widely used in various fields and stages of oil and gas field development, such as in fracturing fluids, drilling fluids, profile control in water injection wells, and wastewater treatment. The modification of key additives in fracturing fluids using nanotechnology and nanomaterials to effectively enhance their performance represents a relatively new research field [67].
Figure 7. Comparison of the performance of energy-enhanced fluid fracturing fluids and foam fracturing fluids (Relative Comparison Based on reference [61]-[66]).
To improve the temperature resistance of clean fracturing fluids, Gurluk et al. [68] investigated the effects of nano-MgO and ZnO particles on the viscoelasticity and temperature resistance of fracturing fluids. The results showed that the addition of nanoparticles effectively improved the thermal stability of the micellar structure in clean fracturing fluids, extending the maximum applicable temperature to 135˚C. The fracturing fluid system also exhibited good viscoelasticity under various shear rates. Zhou et al. [69] systematically investigated the morphology, thermal stability, shear resistance, apparent viscosity, viscoelasticity, proppant-carrying capacity, gel-breaking performance, and core damage rate of clean fracturing fluids containing nano-TiO2 compared to corresponding clean fracturing fluids without nano-TiO2. The study found that the addition of nano-TiO2 enhanced the strength of the clean fracturing fluid, increased temperature resistance from 81˚C to 100˚C, and significantly improved viscoelasticity.
Similarly, Raj et al. [70] investigated the effects of nanoparticles at different concentrations on the rheological and structural properties of clean fracturing fluids, examining SiO2, Fe2O3, MgO, and ZnO. The results showed that MgO and Fe2O3 had a more pronounced effect on enhancing the viscosity of the fracturing fluid, with MgO being more effective than SiO2 in improving the rheological properties of the fracturing fluid. Compared with the absence of nanoparticles, the micelle structure in the clean fracturing fluid was more compact in the presence of nanoparticles. To investigate the proppant-carrying behavior of nanoparticle-enhanced clean fracturing fluids in complex fractures and its influencing factors, Han et al. [71] established a proppant transport model that accounts for proppant collisions, wall friction and blockage, fracturing fluid loss, and fracture branching angles. The results indicated that the proppant-carrying performance of nanoparticle-enhanced clean fracturing fluids was superior to that of conventional water-based fracturing fluids, and that the fluid-structure interaction model for nanoparticle-enhanced clean fracturing fluids could accurately characterize the proppant-carrying behavior of these fluids, providing a research basis for optimizing the parameters of high-efficiency proppant-carrying fracturing fluids in CBM reservoir fracturing operations.
Building on the development of a nanoparticle-modified clean fracturing fluid system, Zuo et al. [72] investigated the mechanism by which nanoparticle-modified fracturing fluids influence the adsorption and desorption characteristics of methane. Using laboratory experiments and molecular simulation methods, they examined the effects of nanoparticle-modified fracturing fluid treatment on the adsorption, desorption, and diffusion capabilities of methane in coal samples. The experimental results indicated that, compared with coal samples treated with clean fracturing fluid, those treated with nanoparticle-modified clean fracturing fluid exhibited significant improvement in both methane adsorption and desorption capacities. The construction of methane adsorption systems with different pore sizes and the calculation of isothermal adsorption enthalpy indicated that the interaction forces between methane and coal molecules were weaker after treatment with nanoparticle-modified clean fracturing fluid, which facilitated methane desorption. Furthermore, nanoparticle-modified clean fracturing fluid could mitigate the detrimental effects of clean fracturing fluid on the desorption and diffusion capabilities of coal reservoirs.
In addition to incorporating nanoparticles into clean fracturing fluid systems, researchers have also attempted to incorporate them into other fracturing fluid systems. Yang et al. [73] investigated the effect of nano-SiO2 particles on the performance of foamed fracturing fluids. Experimental results showed that foamed fracturing fluids containing nano-SiO2 particles offered advantages such as simple formulation, low cost, and high-temperature resistance, with a temperature tolerance of up to 120˚C. Their half-life at 90˚C was approximately 80 minutes, and the performance of the fracturing fluid containing nanoparticles was significantly improved. Similarly, Zheng et al. [74] used a foam scanner and an interfacial rheometer to investigate the mechanism by which nano-SiO2 particles stabilize CO2 foam and their effect on fracturing fluid runoff at different reservoir temperatures. They found that the addition of nano-SiO2 particles reduced the foam volume of the SDS solution but significantly increased the foam half-life; the adsorption of nano-SiO2 particles at the gas-liquid interface enhanced the foam’s resistance to external disturbances.
Unlike conventional viscoelastic surfactant-based clean fracturing fluids, Duan et al. [75] developed a clean fracturing fluid system composed of hydrophobic associative polymers and nano-ZnO. Laboratory performance evaluations showed that this system exhibited superior temperature resistance, filtrate reduction, viscoelasticity, and proppant-carrying capacity, with a permeability damage rate of only 9.3% after gel breakdown. To provide a theoretical foundation for the development of functional fracturing fluids, Liu et al. [76] introduced the nanomaterials SiO2, SiO2-C8, and SiO2-QAS into polymer-based clean fracturing fluids and evaluated the comprehensive performance of the fluids after nanomaterial incorporation. The results showed that all three nanomaterials exhibited good dispersion stability in the fracturing fluids, and that the fluids demonstrated excellent temperature and shear resistance. Furthermore, the addition of SiO2-C8 and SiO2-QAS improved the oil displacement efficiency of the fracturing fluids.
Although the addition of nanomaterials to certain fracturing fluid systems can effectively enhance the performance of the fracturing fluid, there are significant differences in the performance of fracturing fluids modified with different nanomaterials, as shown in Figure 8. At the same time, due to the high cost of nanomaterials, the large-scale adoption of nanoparticle-modified fracturing fluids remains fraught with challenges. Further development of low-cost nanomaterials is needed to advance the research and application of nanoparticle-modified fracturing fluids.
Figure 8. Comparison of the properties of fracturing fluids modified with different nanomaterials (Relative Comparison Based on reference [68]-[76]).
3.4. Supramolecular Fracturing Fluid
Supramolecular fracturing fluids are systems based on supramolecular interactions and resulting from the integration of supramolecular chemistry and polymer chemistry, it contains not only viscoelastic surfactants but also polymers, and supramolecular interactions occur between the two. Due to their supramolecular properties, they are classified as “reversible structure” fracturing fluids and have garnered significant attention from researchers [77].
Yang et al. [78] conducted a detailed study of a novel supramolecular fracturing fluid based on hydrophobic associative polymers and viscoelastic surfactants. Through experimental design, they optimized the supramolecular fluid system and found that the fluid remained shear-stable for 1 hour at high temperatures. The dynamic rheological properties of the supramolecular fluid exhibited high viscoelasticity. Proppant transport tests conducted in a large-scale fracture simulator indicated that the fracturing fluid possessed excellent proppant-carrying capacity, while the formation damage rate of this fluid was 50% lower than that of traditional guar gum fracturing fluid. Based on hydrophobic associative polymers and viscoelastic surfactants as well, Pu et al. [79] prepared a hydrophobic associative polymer-viscoelastic surfactant supramolecular fracturing fluid and evaluated its performance. The results showed that this supramolecular fracturing fluid exhibited various supramolecular behaviors and high viscoelasticity, as well as good temperature resistance, shear resistance, and proppant-carrying capacity.
Unlike previous approaches based on hydrophobic associative polymers and viscoelastic surfactants, Cao et al. [80] prepared a supramolecular fracturing fluid using the cationic surfactant dodecyl (trimethyl)azetidinium chloride (DCTAC) and the strongly hydrophobic compound 3-hydroxynaphthalene-2-carboxylate (SHNC). A 1:2 molar ratio of SHNC/DCTAC formed highly stable wormlike micelles, whose viscosity remained stable at temperatures as high as 130˚C, demonstrating excellent thermal stability and making it a potential candidate for fracturing fluids in high-temperature reservoirs.
Taking advantage of the self-assembly properties of supramolecular materials, Yu et al. [81] prepared supramolecular units using isocyanurate and tetramethylammonium chloride, among other compounds. After modifying these units with functional groups, they produced a supramolecular phase-change fracturing fluid. Performance evaluation results indicated that as the temperature rose, the molecules in the fracturing fluid underwent self-assembly and a phase transition to form a solid, and that the phase-transition solid exhibited excellent flow conductivity at various proppant loading concentrations, effectively preventing sand plugging issues associated with solid-phase proppants. Through molecular self-assembly to thicken alkanes, Wei et al. [82] used alkylamines and diisocyanates as raw materials to prepare dialkylurea thickeners. They studied the rheological properties and temperature resistance of thickened hydrocarbon fracturing fluid systems and found that both improved with increasing carbon number of the alkanes and mass fraction of the thickener. However, this fracturing fluid system completely loses its sand-carrying capacity at temperatures exceeding 80˚C, making it suitable for fracturing operations in medium- and low-temperature reservoirs.
Figure 9 compares the temperature resistance of different supramolecular fracturing fluid systems. It shows that existing supramolecular fracturing fluid systems generally meet the temperature resistance requirements for conventional high-temperature thresholds (100˚C), but there is still a significant gap for ultrahigh-temperature thresholds (150˚C). Currently, extensive laboratory research on supramolecular fracturing fluids has been conducted, and performance evaluations have demonstrated their excellent properties. However, the practical application of supramolecular fracturing fluids in high-temperature reservoirs remains limited. Future research should focus on accelerating the development of supramolecular fracturing fluid systems that are cost-effective, have simple application processes, and are easily scalable for widespread use.
Figure 9. Comparison of temperature resistance among different systems.
3.5. Variable Viscosity/Integrated Fracturing Fluid
Variable Viscosity fluid is a new type of hydraulic fracturing fluid. Its key feature is the ability to achieve real-time, controllable changes in fluid viscosity by adjusting the concentration of friction reducers or introducing crosslinking agents, thereby reducing frictional resistance at low viscosity, and enhancing proppant-carrying capacity at high viscosity during operations. This system typically employs hydrophobic associative polymers or nanoemulsions to form reversible physical cross-linked structures in the aqueous phase, causing the fluid to exhibit different viscosities under varying shear rates and concentrations [83].
To address issues such as poor flexibility and limited functionality in existing fracturing fluids for coalbed methane, Xu et al. [84] developed integrated thickeners and investigated the performance of integrated fracturing fluids in combination with other additives. Laboratory performance evaluations indicated that the viscosity of the integrated fracturing fluid could be adjusted within the range of 3 - 200 mPa·s, and that a 1.0% solution exhibited a viscosity greater than 100 mPa·s at 60˚C and 100 s−1. Additionally, drag reduction and swelling inhibition rates both exceeded 70%. This fluid integrates the properties of slickwater, linear gel, and crosslinked gel fracturing fluid systems, and has been successfully applied in field fracturing operations for coalbed methane, shale gas, and tight sandstone gas wells along the eastern margin of the Ordos Basin.
Based on the geological characteristics of Coal Seam No. 9 in the Taiyuan Formation of the Upper Carboniferous System in the Ningwu Basin, Wang et al. [85] conducted laboratory studies and ultimately developed a real-time variable-viscosity fracturing fluid system. This system offers advantages such as controllable viscosity, online blending, low-temperature gel breakdown, and low residue content. While improving fracturing efficiency and proppant-carrying capacity, it reduces the damage caused by the fracturing fluid’s gel breakdown to the reservoir. Field application results indicated that this variable-viscosity fracturing fluid system fully met fracturing operation requirements and had the potential for large-scale implementation.
Given that existing variable-viscosity fracturing fluid systems use oil-in-water reverse-phase drag reducers as their primary component, which suffer from issues such as high cost, environmental damage caused by the oil phase, and poor salt tolerance, Yu et al. [86] [87] have developed a water-in-water nano-friction reducer. Utilizing a water-in-water synthesis method that eliminates the oil phase during production, this formulation reduces costs while protecting both the reservoir and the environment. It meets the technical requirements for integrated friction reduction and proppant transport in fracturing operations, thereby contributing to cost reduction and efficiency improvement.
Although viscosity-modifiable/integrated fracturing fluids offer unique advantages such as controllable viscosity, in-situ blending, and simplified fracturing operations, there are still relatively few practical applications of these fluids in coalbed methane fracturing compared to shale gas development. This is primarily due to significant differences in the physical properties and structures between coal reservoirs and shale reservoirs. Therefore, further research is warranted on the compatibility of variable-viscosity/integrated fracturing fluid systems with coal reservoirs to enhance their applicability in different reservoir types.
4. Compatibility of Fracturing Fluids with Reservoirs
Due to the low permeability and low porosity of coal seams, a series of phenomena—such as fluid incompatibility, residual gel-breaking fluid, and clay swelling—are more likely to occur when fracturing fluid meets the coal seam. These phenomena can cause damage to the reservoir and impair fracturing effectiveness. Therefore, research on the compatibility between fracturing fluid and reservoir is of great significance for protecting coalbed methane reservoirs and ensuring the efficient and sustainable development of coalbed methane resources.
For the same coal reservoir, different fracturing fluids have varying performance characteristics and thus exert different effects on fracturing efficiency. Figure 10 illustrates the use of different fracturing fluids for reservoir enhancement in various basins across the United States. Through an analysis of CPG production operations in the United States, Palmer et al. [88] noted that among the three fracturing methods used in CPG reservoirs in the San Juan and Black Warrior basins—crosslinked gel fracturing, water fracturing, and sandless water fracturing—water fracturing yielded better results than crosslinked gel fracturing, and its cost was only half that of crosslinked gel fracturing. Meanwhile, sand-free water-based fracturing fluid was even more cost-effective, at one-third the cost of sand-laden water-based fracturing fluid. Additionally, Amoco Corporation in the U.S. compared the fracturing performance of different fracturing fluids. The results showed that in the southern San Juan Basin, nitrogen foam fracturing fluid performed best, while linear gel fracturing fluid performed worst. In the Acoma Basin, water-based fracturing fluids outperformed foam fracturing fluids and were less expensive. In the Black Warrior Basin, sand-enhanced water-based fracturing fluids performed better than sand-free water-based fracturing fluids and offered greater economic efficiency [89].
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Figure 10. Comparison of fracturing fluid performance across different basins in the united states (Relative Comparison Based on reference [88] [89]).
In response to the need for production enhancement retrofits in the Qinnan Panhe coalbed methane vertical wells, Sun et al. [90] conducted a study on the fracturing effects of four different fracturing methods. The results indicated that the increase in anthracite coalbed methane production, from highest to lowest, was as follows: nitrogen foam fracturing, active water fracturing, and clean water + nitrogen fracturing or clean water fracturing. The specific average gas production rates are shown in Figure 11. Under normal fracturing conditions, higher pre-injection fluid volumes, higher sand injection rates, and a total fluid volume exceeding 400 m3 yield better fracturing results.
Figure 11. Comparison of stimulation effects of different fracturing fluids for coalbed methane in Panhe, Qinnan.
Due to significant differences in the physical properties of different reservoirs, the same fracturing fluid may exert varying effects on different reservoirs; therefore, the selection of fracturing fluid should follow the principle of compatibility with the physical properties of the target reservoir. After analyzing and evaluating the fracturing effects of different fracturing techniques on CBM wells in various production areas of the Qinnan Block, Zhang et al. [91] concluded that the fracturing fluids suitable for CBM fracturing operations in the Qinnan Block are active water fracturing fluid and active water with nitrogen co-injection. The primary purpose of gas co-injection is to increase formation energy. From an economic perspective, active water fracturing fluid i s recommended as the injection fluid; however, when formation pressure is low, the use of active water with nitrogen injection is more recommended. When using active water fracturing fluid, the volume of fluid injected into the well must be appropriately increased to ensure post-fracturing CBM production.
In coal reservoirs with a high brittleness index, the inherent fragility and susceptibility to collapse, combined with the intrusion of external fluids, result in large amounts of coal fines that block fractures and cleavages. This causes the fractures to close, leading to a decrease in the permeability of the coal seam. Luo et al. [92] developed a coal powder suspending agent for the Hancheng Block, evaluated its performance, and designed a field fracturing plan. Laboratory test results indicated that the coal powder suspending agent solution effectively stabilized and suspended coal powder in fractures and the wellbore, thereby increasing the fluid recovery efficiency during fracturing. The field fracturing application also achieved the expected results. Using a self-developed experimental apparatus for fracturing fluid flowback testing, Jiang et al. [93] studied the migration patterns of coal powder within fractures. The results indicated that the coal powder suspending agent effectively wetted the coal powder, making it easier to flow out with the fracturing fluid. The higher the coal powder content, the lower the outflow rate; however, the outflow rate could be increased during fracturing by adjusting the flow rate.
China is rich in coalbed methane (CBM) resources, which are distributed across five major gas-bearing regions: the Qinghai-Xizang Plateau, Northeast China, Southern China, Northwest China, and North China. Given the significant differences in CBM reservoirs across these regions, it is difficult to achieve fracturing and production enhancement in reservoirs with varying physical properties using a single type of fracturing fluid. During the fracturing fluid design phase, in addition to evaluating the fluid’s performance, it is essential to consider its compatibility with the reservoir and to optimize the formulation based on reservoir characteristics to ensure the efficient development of coalbed methane resources.
5. Issues with Coal Seam Fracturing Fluids and Proposed
Improvements
5.1. Issues
Based on the advantages and disadvantages of the various fracturing fluids discussed above, the following issues with current CBM well fracturing fluids can be summarized:
a. Domestic CBM fracturing primarily relies on active water fracturing fluids. These fluids have poor proppant-carrying capacity and require high operating pressures, which severely limit the scale of operations and hinder the formation of complex fracture networks. In coalbeds with low permeability and poorly developed natural fractures, they are prone to causing water-locking damage and pore blockage.
b. For low-permeability reservoirs, crosslinked gel fracturing fluids present challenges such as difficulty in gel breakdown, high residue content, poor anti-swelling performance, and flowback difficulties. The residues from these fracturing fluids cause significant damage to coal reservoirs.
c. The preparation process for clean fracturing fluids is complex and costly. These fluids do not automatically break down during the CBM fracturing process, and the residual fluid is difficult to degrade, making it prone to causing environmental pollution.
d. The supporting processes and facilities for foam fracturing fluids remain underdeveloped and are relatively costly, making large-scale application in production operations currently unfeasible.
5.2. Suggested Improvements
In response to the existing issues, the following improvement measures are proposed:
a. The high structural stress in the coal seam and the plastic characteristics of the coal and rock severely limit the formation and propagation of primary fractures. Fracturing operations typically address this by increasing proppant injection intensity and flow rate, requiring the fracturing fluid to have low friction resistance and be cost-effective. Friction reducers should be added to active water-based fracturing fluids to reduce operational friction, thereby achieving effective proppant placement that creates long fractures and provides extended support. The addition of flow enhancers minimizes damage to the coal seam, while the optimization of fracturing fluid systems and the development of high-performance, low-cost single-component additives reduce overall fracturing fluid costs.
b. The high in-situ stress in coal seams significantly reduces reservoir permeability. Extremely low permeability and low porosity require the fracturing fluid to possess excellent gel-breaking and flowback properties to minimize reservoir damage caused by fluid retention. High-efficiency gel-breaking systems suitable for different reservoir temperatures should be developed, and in-depth research should be conducted on reservoir damage mechanisms and the gel-breaking mechanisms of fracturing fluids—for example, the practical application effects of chlorine dioxide as a gel-breaking agent should be studied. Fracturing fluid formulations and gel-breaking systems should be optimized based on different reservoir conditions, which is particularly important for crosslinked gel fracturing fluids.
c. Due to the deep burial of coal seams, high in-situ stress, and the difficulty of proppant injection, multiple fracturing operations with increased fluid volume and higher proppant injection rates can achieve effects such as the creation of multiple fractures, long-distance fracture propagation, and high-strength proppant placement. These factors increase the volume of fluid injected into the formation and require the fracturing fluid to possess good gel-breaking performance and a high recovery rate after fracturing operations are completed. For clean fracturing fluids, further optimization of the synthesis methods and processes for viscoelastic surfactants is needed to reduce production costs and promote their widespread application. To address the issue of fracturing fluid recovery, research should be conducted on gel-breaking agents suitable for clean fracturing fluids—such as bio-based gel-breaking agents—to minimize the dosage of gel-breaking agents used and protect the environment. In-depth research into recycling and reusing fracturing fluid recovery fluids will help reduce costs and improve efficiency in fracturing operations.
d. The high-temperature, high-pressure environment of coal seams imposes stricter requirements on the performance of fracturing fluids and the supporting process facilities for fracturing operations. Research should be conducted on supporting processes and operational equipment suitable for foam fracturing fluids, and new foaming agents and foam stabilizers should be developed to improve foam stability. Additionally, the crosslinking conditions of foam fracturing fluids need to be optimized to facilitate their widespread application.
e. Currently, commonly used fracturing fluid systems cannot fully meet the reservoir modification requirements for CBM fracturing operations; therefore, research on new fracturing fluid systems remains necessary. Research on new fracturing fluids can be approached from the following aspects: 1) By integrating the physical properties of CBM reservoirs and conducting studies on the compatibility between fracturing fluids and reservoirs, fracturing fluid systems best suited for specific CBM reservoirs should be identified; 2) The primary components of the fracturing fluid should be optimized to enhance its performance while minimizing reservoir damage, reducing operational costs, and improving competitiveness, thereby further promoting its field application; 3) The advantages of existing fracturing fluid systems should be fully leveraged by combining multiple systems. For example, while active water fracturing fluids cause minimal reservoir damage and are low-cost but have poor proppant-carrying capacity, and clean fracturing fluids have strong proppant-carrying capacity but are high-cost, a combined “active water fracturing fluid + clean fracturing fluid” system can be tested based on the actual physical properties of the reservoir. This approach achieves effective proppant transport, efficient fracture creation, cost reduction, and minimized reservoir damage.
6. Conclusions
a. This study summarizes the current research status of fracturing fluid systems commonly used for coalbed methane reservoir stimulation, identifies their respective advantages and disadvantages, and proposes corresponding improvement measures.
b. The development of new fracturing fluids is summarized. High-efficiency, environmentally friendly, low-cost, and low-damage fracturing fluid technologies represent important development directions, goals that can be achieved through the development of new fracturing fluid systems or by improving existing ones.
c. Studies on the compatibility of fracturing fluids with CBM reservoirs indicate that further research is needed on the mechanisms of reservoir damage caused by fracturing fluids and on the compatibility between fracturing fluids and reservoirs. Such research will enhance fracturing fluid performance while improving compatibility with the reservoir, thereby protecting CBM reservoirs.
d. Based on the characteristics of CBM reservoirs and a thorough understanding of the reservoir, fracturing fluid formulations should be optimized, and appropriate fracturing procedures should be selected to achieve optimal reservoir enhancement while minimizing reservoir damage, thereby enabling the efficient and sustainable development of CBM resources.