CO₂-ECBM from a Full-Chain Perspective: Mechanism Elucidation, Demonstration Practices, and Future Outlook

Abstract

CO₂-enhanced coalbed methane recovery (CO₂-ECBM) represents a promising pathway within carbon capture, utilization, and storage (CCUS) technologies, offering dual benefits of methane production and long-term CO₂ sequestration. This review provides a comprehensive analysis of CO₂-ECBM from a full-chain perspective (Mechanism, Practices, and Outlook), covering fundamental mechanisms and key engineering practices. It highlights the complex multi-physics processes involved, including competitive adsorption–desorption, diffusion and seepage, thermal effects, stress responses, and geochemical interactions. Recent progress in laboratory experiments, capacity assessments, site evaluations, monitoring techniques, and numerical simulations are systematically reviewed. Field studies indicate that CO₂-ECBM performance is strongly influenced by reservoir pressure, temperature, injection rate, and coal seam properties. Structural conditions and multi-field coupling further affect storage efficiency and long-term security. This work also addresses major technical challenges such as real-time monitoring limitations, environmental risks, injection-induced seismicity, and economic constraints. Future research directions emphasize the need to deepen understanding of coupling mechanisms, improve monitoring frameworks, and advance integrated engineering optimization. By synthesizing recent advances and identifying research priorities, this review aims to provide theoretical support and practical guidance for the scalable deployment of CO₂-ECBM, contributing to global energy transition and carbon neutrality goals.

1. Introduction

Global climate change represents one of the most critical challenges facing modern human society, with greenhouse gas emissions—particularly CO₂—widely recognized as a primary driver of global warming [1,2,3,4]. In light of the progress of international climate agreements, such as the Paris Agreement, achieving net-zero CO₂ emissions and global carbon neutrality has emerged as a widely shared consensus among the global community [5,6,7]. Against this backdrop, the central challenge facing countries worldwide is how to effectively control carbon emissions while ensuring the security of energy supply.

CCUS is regarded as a key pathway for facilitating the low-carbon transition of energy systems. CCUS enables the efficient capture of CO₂ from industrial sources and achieves significant emission reductions through secure geological storage or resource utilization [8,9,10,11,12,13] (Figure 1). CO₂-ECBM represents a synergistic pathway within the broader framework of CCUS, simultaneously targeting enhanced coalbed methane recovery and long-term CO₂ geological storage. This technology involves injecting CO₂ into coal seams, where it preferentially adsorbs onto the coal matrix due to its stronger affinity compared with methane. This competitive adsorption mechanism displaces the adsorbed CH₄, enabling its extraction, while securely storing CO₂ within the coal structure. As a result, CO₂-ECBM offers the dual benefits of energy production and greenhouse gas mitigation [14,15,16]. Compared with conventional coalbed methane extraction methods, CO₂-ECBM offers multiple advantages. It causes minimal disruption to the geological formation, enables efficient methane release, and exhibits strong environmental compatibility and long-term storage stability. These characteristics make CO₂-ECBM a promising technological bridge between energy development and climate mitigation. Globally, many coal-bearing regions are characterized by low permeability, complex pore structures, and limited methane desorption capacity, which often result in low recovery rates using traditional CBM extraction techniques—hindering their commercial viability [17,18,19]. In such contexts, CO₂-ECBM demonstrates clear technical and economic advantages, particularly in deep and complex coal seams where conventional methods fall short. This approach not only provides a sustainable pathway for CBM resource development but also offers reliable geological space for CO₂ sequestration.

In recent years, CCUS technologies have witnessed rapid advancement, with CO₂-ECBM emerging as a focal point of interest across both academia and industry. Research on this technology spans multiple scales, ranging from the fundamental mechanisms of gas adsorption and the dynamics of diffusion and seepage to field experiments and engineering demonstrations (Figure 2) [20,21,22]. CO₂-ECBM is currently transitioning from foundational studies to pilot-scale implementations, and is poised to move toward large-scale deployment. Nevertheless, this technology still faces numerous scientific and engineering challenges. This paper begins with a review of the fundamental mechanisms of CO₂-ECBM, and, drawing on the recent research conducted by our team, systematically summarizes the current progress and practical developments. It further explores global engineering demonstrations, key influencing factors, and potential future trends. The objective is to provide a comprehensive reference for the ongoing optimization and implementation of CO₂-ECBM, and to lay a solid foundation for its eventual large-scale application.

2. Mechanisms of CO₂-Enhanced Coalbed Methane Recovery

CO₂-ECBM enhances methane recovery and enables carbon sequestration by injecting carbon dioxide into coal seams. The core mechanisms primarily involve two interrelated processes: adsorption–desorption behavior and diffusion–seepage transport. A schematic diagram of the CO₂-ECBM mechanisms is shown in Figure 3.

The adsorption–desorption mechanism is fundamental to CO₂-ECBM. Coal exhibits a stronger adsorption affinity for CO₂ than for CH₄. Upon CO₂ injection, a distinct competitive adsorption effect occurs—CO₂ displaces CH₄ previously adsorbed on the coal surface, thereby enhancing CH₄ desorption. Concurrently, the increase in CO₂ concentration and the decrease in CH₄ concentration within the free gas phase disrupt the original adsorption–desorption equilibrium, further promoting CH₄ release. To quantitatively describe this competitive adsorption behavior, the Ideal Adsorbed Solution Theory (IAST) is widely adopted. IAST provides a thermodynamic framework for predicting the multicomponent adsorption equilibrium based on pure-component isotherms, assuming the adsorbed phase behaves as an ideal solution. This approach enables accurate estimation of CO₂ and CH₄ uptake under varying pressure and composition conditions without requiring extensive multicomponent experiments. By incorporating IAST into gas adsorption modeling, researchers can more effectively characterize selective adsorption phenomena and optimize injection strategies. The extended Langmuir model is a theoretical framework for describing the competitive adsorption of multicomponent gases on solid surfaces. It modifies the classic Langmuir single-component model to account for the complexity of gas mixtures, where each component competes for the same adsorption sites. Adsorption is influenced by both the component’s own properties and the presence of other gases, with the model incorporating partial pressures and adsorption affinities to capture these interactions. This approach enables accurate prediction of gas adsorption behavior in porous media under complex conditions, such as CO₂ sequestration and methane recovery in coal seams. Overall, this process not only facilitates methane desorption and recovery, but also results in the sequestration of CO₂ in an adsorbed state within the coal matrix, establishing a synergistic “displacement–sequestration” mechanism [23,24,25].

In addition, the diffusion–seepage process governs the transport pathways and migration efficiency of desorbed methane and injected CO₂. The desorbed CH₄ molecules must diffuse through micropores into the cleat and fracture system, and then migrate via seepage flow toward the production wells to enable effective extraction. During this process, injected CO₂ not only functions as a displacement agent but also establishes a localized pressure gradient that helps overcome the intrinsic low permeability of coal seams, thereby improving gas mobility. Notably, the common phenomenon of “compaction-induced permeability reduction” during conventional methane extraction can be mitigated under continuous CO₂ injection. The sustained pressure around the wellbore helps preserve coal structure integrity, prevents pore closure, and ultimately enhances both permeability and flow capacity [26,27].

In summary, the CO₂-ECBM process integrates coupled mechanisms of adsorption–desorption and diffusion–seepage: adsorption–desorption enables selective gas separation and long-term CO₂ sequestration, while diffusion–seepage promotes CH₄ displacement and recovery. This synergistic mechanism typically enhances methane production by around 20–30% compared with conventional CBM methods, with CO₂ retention efficiencies after 10 years generally ranging from approximately 70% to 90%, depending on reservoir conditions.

3. Current Development of CO₂-ECBM Technology

3.1. Experimental Research Progress on CO₂-ECBM

Experimental research on CO₂-ECBM aims to elucidate the adsorption, desorption, diffusion, and seepage mechanisms of CO₂ within coal seam media at both microscopic and macroscopic scales, thereby assessing its effectiveness in enhancing coalbed methane recovery and carbon sequestration capacity. Current experimental efforts mainly focus on the characterization of reservoir properties in coal seams and surrounding rocks, simulation of CO₂ sequestration mechanisms, and the evaluation of permeability and injectivity during the injection process [28,29,30].

Representative coal and surrounding rock samples are used to perform comprehensive rock mechanics and petrophysical property tests. With the aid of triaxial loading apparatuses, low-field nuclear magnetic resonance (LF-NMR) instruments, various gas adsorption analyzers, mercury intrusion porosimeters, and scanning electron microscopes (SEMs), key mechanical parameters such as elastic modulus, shear modulus, and Poisson’s ratio, along with physical properties including density, porosity, permeability, specific surface area, pore size distribution, pore volume, and CO₂ adsorption capacity, can be quantitatively determined. Figure 4 presents mercury intrusion porosimetry results to characterize the pore size distribution of coal samples—an effective method for evaluating pore structure. These experiments are crucial for understanding the heterogeneity of reservoir properties across different geological formations and their influence on CO₂ migration behavior.

In terms of sequestration mechanisms, experimental studies are typically conducted under simulated reservoir conditions (e.g., temperature, pressure, and water saturation) to investigate three types of physical simulation experiments: adsorption-based, dissolution-based, and mineralization-based CO₂ sequestration. Adsorption experiments employ high-pressure gas adsorption/desorption systems to evaluate the adsorption capacity and characteristics of CO₂ on coal or rock surfaces and within pores. Dissolution experiments are conducted using CO₂–water–rock reaction vessels to examine the dissolution behavior of CO₂ in pore water and its subsequent reactions with minerals. Mineralization experiments focus on observing the formation, transformation, and stability of newly generated minerals after reactions, in order to assess the long-term sequestration potential.

Moreover, to evaluate the injectivity and evolution characteristics of CO₂ in coal seams, particular attention must be paid to geochemical effects and volumetric stress–strain responses [31,32,33]. For instance, CO₂ injection simulation systems are used to monitor volumetric strain, fracture development, and permeability changes in rock samples during the injection process. These observations, combined with analytical techniques such as X-ray diffraction (XRD) and inductively coupled plasma optical emission spectrometry (ICP-OES), allow for detailed analysis of changes in fluid composition and provide a comprehensive understanding of the geochemical and mechanical responses induced by CO₂ injection. Figure 5 presents the modifications in ion concentrations and trace element compositions that are observed across different samples following geochemical interactions. The data indicate that notable alterations in both major ion concentrations and trace element profiles do occur, suggesting that geochemical interactions have a definitive impact on the chemical properties of the samples.

In summary, these experimental studies not only elucidate the multiscale physicochemical behavior of CO₂ within coal seams, but also offer robust experimental support for the assessment of CO₂ storage capacity, suitability evaluation of CO₂-ECBM, numerical simulation research, and injectivity analysis.

3.2. Current Research on CO₂-ECBM Storage Capacity Assessment and Suitability Evaluation

In recent years, extensive research has been conducted by scholars to evaluate the storage capacity of CO₂-ECBM, leading to the development of assessment models that encompass three primary sequestration states: adsorbed, dissolved, and free-phase. These models quantitatively describe the geological sequestration potential of CO₂ in coal seams through theoretical calculations and calibration with experimental data. According to widely accepted approaches from previous studies, CO₂ sequestration in coal seams predominantly occurs in the adsorbed phase, followed by dissolved and free phases, with the adsorbed phase typically accounting for the largest proportion [34,35,36,37,38]. Specifically, the assessment models are generally expressed in the following form [39]:

$$M_{car}=S_{car}{\rho }_{car}{M}_{coal}\left(m_{ab}+m_d+m_f\right)$$

(1)

where M_car is the CO₂ storage capacity in t; S_car is the CO₂ storage coefficient in the coal reservoir; ρ_car is the CO₂ density under standard conditions (101.325 kPa, 273.15 K), equal to 1.977 kg/m³; M_coal is the proven coal reserves in t; m_ab is the amount of CO₂ stored in the adsorbed state per unit mass of coal in m³/t; m_d is the amount of CO₂ stored in the dissolved state per unit mass of coal in m³/t; and m_f is the amount of CO₂ stored in the free state per unit mass of coal in m³/t.

For a unit mass of coal, the CO₂ sequestration potential in the adsorbed state within the reservoir can be expressed as [37,38,39]:

$$m_{\mathrm{a}\mathrm{b}}={\displaystyle \frac{m_{\mathrm{e}\mathrm{x}}}{1-\frac{p{T}_{\mathrm{c}}}{8Z{p}_{\mathrm{c}}T}}}$$

(2)

where p is the pressure of the deep coal reservoir, corresponding to the CO₂ adsorption pressure in MPa; T_c is the critical temperature of CO₂, 304.21 K; Z is the compressibility factor of CO₂ (dimensionless), which can be estimated through multiparameter interpolation; p_c is the critical pressure of CO₂, 7.383 MPa; T is the temperature of the deep coal reservoir, also the CO₂ adsorption temperature in K; and m_ex is the excess adsorption capacity of CO₂ per unit mass of coal in m³/t, which can be calculated using the Dubinin–Radushkevich (D–R) adsorption model [37,38,39]:

$$m_{\mathrm{e}\mathrm{x}}=m_0\left(1-{\displaystyle \frac{{\rho }_{\mathrm{f}}}{{\rho }_{\mathrm{a}}}}\right){\mathrm{e}}^{-D{\left[\ln \left({\displaystyle \frac{{\rho }_{\mathrm{a}}}{{\rho }_{\mathrm{f}}}}\right)\right]}^2}+k{\rho }_{\mathrm{f}}$$

(3)

where m₀ is the maximum CO₂ adsorption capacity per unit mass of coal determined from adsorption experiments in m³/t; ρ_f and ρ_a are the densities of free-phase and adsorbed-phase CO₂ under the actual pressure and temperature conditions of the coal reservoir in kg/m³; D is the adsorption constant (dimensionless); and k is a constant related to Henry’s law (dimensionless).

The CO₂ density in the coal reservoir is a function of pressure and temperature, expressed as ρ_g = f(p, T), and can be further expressed as [37,38,39]:

$${\rho }_g={\displaystyle \frac{p}{\left(1+\delta {\varphi }_{\delta }^{\tau }\right)RT}}$$

(4)

where δ = ρ_c/ρ_f is the reduced density of CO₂ (dimensionless), with ρ_c being the critical density of CO₂ (0.45 × 10⁻³ kg/m³); and τ = T_c/T is the reduced temperature (dimensionless). ϕ(δ,τ) denotes the Helmholtz free energy, which is governed by both temperature and density [37,38,39]:

$$\varphi \left(\delta ,\tau \right)={\varphi }^0\left(\delta ,\tau \right)+{\varphi }^1\left(\delta ,\tau \right)$$

(5)

where ϕ⁰(δ, τ) represents the Helmholtz free energy of the ideal fluid; and ϕ¹(δ, τ) denotes the residual Helmholtz free energy of the real fluid.

In coal reservoirs, the solubility-based CO₂ storage potential per unit mass of coal is a function of the coal seam porosity, water saturation, coal density, and the solubility of CO₂ in water, and can be expressed as [37,38,39]:

$$m_{\mathrm{d}}={\displaystyle \frac{\phi S_{\mathrm{w}}{S}_{\mathrm{c}\mathrm{a}\mathrm{r}}}{{\rho }_{\mathrm{c}\mathrm{o}\mathrm{a}\mathrm{l}}}}$$

(6)

where φ is the coal porosity in %; S_w is the water saturation of the coal seam in %; S_car is the solubility of CO₂ in coal seam water in mol/cm³; and ρ_coal is the coal density in kg/m³.

According to Boyle–Mariotte’s law, and taking into account the gas saturation of the coal seam, the free-phase CO₂ storage potential per unit mass of coal in the reservoir can be expressed as [37,38,39]:

$$m_{\mathrm{f}}={\displaystyle \frac{\phi S_{\mathrm{g}}p{T}_0}{{\rho }_{\mathrm{v}\mathrm{i}\mathrm{s}\mathrm{u}\mathrm{a}\mathrm{l}}Z{p}_{0}T}}$$

(7)

where S_g is the gas saturation of the coal seam in %; p₀ is the standard atmospheric pressure; T₀ is the temperature under standard conditions; and ρ_visual is the apparent density of coal in kg/m³.

To address the issue of CO₂ geological storage suitability, researchers generally advocate for the establishment of a comprehensive evaluation index system that integrates multiple dimensions and hierarchical levels [40,41,42,43,44,45]. This system should fully consider key factors such as reservoir security, storage capacity potential, and socio-economic acceptability. Reservoir security serves as the foundation for the sustainable operation of storage projects, and is primarily determined by regional crustal stability and caprock integrity. For crustal stability, assessments typically involve evaluating peak ground acceleration, historical seismic activity intensity, and the spatial distribution of active faults to determine the overall structural stability of the area. Caprock conditions, including lithology, thickness, continuity, and burial depth, directly affect the sealing performance and migration risk of CO₂. In terms of storage capacity, the scale of the structural unit, reservoir physical properties, and theoretical storage potential are the core evaluation components. The area and thickness of the structural unit define the spatial boundary conditions of the storage site. Reservoir development conditions—such as thickness, porosity, and permeability—determine the CO₂ injectivity and effective storage capacity. Storage potential usually refers to the estimated geological storage volume and storage capacity per unit area, reflecting the resource base of CO₂ geological storage in a given region.

In addition, the feasibility of CO₂-ECBM must also consider socio-economic conditions, particularly carbon source distribution and public acceptance. Economically, proximity to large-scale CO₂ emission sources helps reduce transportation costs and project complexity. Meanwhile, the level of public acceptance may influence the implementation and sustainability of engineering operations. Therefore, when constructing a CO₂-ECBM suitability evaluation framework, it is essential to integrate technical, geological, and economic factors into a unified system. Figure 6 illustrates the suitability evaluation index system for CO₂-ECBM constructed by the authors.

In practical suitability analyses, researchers often adopt a combination of the Analytic Hierarchy Process (AHP) and Fuzzy Comprehensive Evaluation (FCE). This approach enables the construction of a multi-level hierarchical model consisting of a target layer, a criterion layer, and an index layer. Expert judgment matrices are used to determine the weight of each indicator. Coupled with regional geological data, monitoring records, and sampling results, this method provides a quantified, comprehensive evaluation to offer a scientific basis for CO₂-ECBM suitability assessments.

3.3. Monitoring Technologies and Regulatory Frameworks for CO₂-ECBM

In response to the urgent need for CO₂ leakage and migration surveillance, numerous researchers have conducted in-depth investigations into surface deformation and environmental changes induced by CO₂ injection [46,47,48,49,50,51,52]. At present, a widely recognized strategy among Chinese scholars involves an integrated air–space–surface–downhole remote sensing-based monitoring system [53] (Figure 7).

Within the air and space segment, large-scale monitoring relies on optical and radar satellite platforms to acquire long-term, high-resolution InSAR datasets. These datasets enable all-weather tracking of surface micro-deformation and vegetation-related environmental dynamics, thereby revealing CO₂ migration patterns and their potential ecological impacts. Simultaneously, unmanned aerial vehicles (UAVs) equipped with optical and thermal infrared sensors are employed for targeted, rapid surveillance of the injection zone. These systems can acquire surface models and high-resolution imagery, while also detecting potential leakage hotspots and anomalous reactions in a timely manner, ensuring real-time and accurate monitoring. The integration of satellite-based remote sensing and UAV observations provides both macro and micro perspectives on the CO₂ storage site, forming a critical technological foundation for continuous and dynamic monitoring of CO₂ migration and environmental responses at the regional scale.

For surface-based monitoring, long-term surveillance of production well arrays combined with passive seismic-based surveillance of near-surface dynamics enables the effective detection of fracture propagation and surface deformation induced by CO₂ injection. With the aid of advanced passive seismic fracture tomography, subsurface rupture events and the evolution of CO₂ plume fronts can be directly visualized. This provides crucial empirical data for understanding fluid behaviors and fault activation during the storage process. This technique also overcomes the limitations of traditional surface monitoring in terms of signal-to-noise ratio and resolution, significantly enhancing the ability to identify and provide early warnings of CO₂ leakage risks.

In the downhole monitoring system, long-term deployment of fiber-optic sensors along high-angle wells allows for real-time, stratified gas–water sampling and precise tracking of temperature and pressure changes. Additionally, a multi-azimuth multicomponent time-lapse VSP analysis technique is introduced to quantify subsurface fluid dynamics and structural deformation responses. This system not only provides real-time feedback on the in-well CO₂ storage status, but also—through the interpretation of time-lapse datasets—helps reveal the spatial distribution and evolution of CO₂ migration under multi-physics coupling conditions. Together, these insights offer robust data support and scientific guidance for the optimization of CO₂-ECBM deployment strategies.

In parallel with technological advancements, many countries, including China, the United States, and Australia, have progressively improved their policy support and management frameworks to promote the safe and orderly implementation of CO₂-ECBM. These frameworks generally emphasize the importance of long-term environmental monitoring, risk prevention and control, and accountability mechanisms throughout the project lifecycle. In China, relevant departments have begun to explore coordinated regulatory approaches that integrate environmental supervision, project approval, and data reporting, aiming to enhance oversight efficiency and project transparency. The integration of advanced monitoring technologies with a sound governance structure plays a key role in improving risk management, fostering public trust, and facilitating the sustainable and large-scale development of CO₂-ECBM projects.

3.4. Advances in Numerical Simulation of CO₂-ECBM

Coal seams are characterized by strong heterogeneity and generally low permeability, making efficient CO₂ injection and enhanced CH₄ recovery the key technical challenges of CO₂-ECBM. Numerical simulation has become a powerful tool to reproduce the production history of coalbed methane wells, quantitatively assess the potential of CO₂-ECBM, and support the optimization of engineering schemes and evaluation of CH₄ enhancement strategies. Due to its low cost and short research cycle, numerical modeling has attracted extensive attention in recent years. Research efforts have increasingly focused on developing and improving multi-physics coupled models to accurately describe the complex processes occurring within coal reservoirs, including gas adsorption, diffusion, seepage, heat transfer, geomechanical evolution, and geochemical reactions [54,55,56,57,58,59]. Early commercial simulators were primarily based on partial differential equations governing adsorption and flow fields. These models could effectively simulate isothermal adsorption and diffusion of gases within the coal matrix, as well as fluid flow in the fracture network. However, they often neglected the coupled effects of temperature fields, geostress variations, and mineral dissolution/precipitation reactions, thus limiting their applicability under the complex conditions of deep coal seams.

To address these limitations, our research team has recently developed a fully coupled adsorption–hydro–thermo–mechanical–chemical (AHTMC) model [57,58,59,60]. This type of model integrates equations of energy conservation, fluid dynamics, and geomechanics to comprehensively capture the interactions among multiple physical fields during the CO₂-ECBM process [60]. In the AHTMC framework, adsorption behavior is typically described using a modified Langmuir isotherm, while gas diffusion within the coal matrix is governed by Fick’s law. Fluid transport in the fracture system is modeled using a combination of Darcy’s law and gas slippage effects. To characterize thermal responses driven by temperature fluctuations, the model incorporates terms for thermal conduction and convection, alongside thermodynamic effects such as adsorption heat release, dissolution exothermicity, and endothermic deformation of coal rock. The geomechanical response is modeled using the theory of poroelasticity, fully considering reservoir deformation resulting from changes in fluid pressure, temperature, and adsorption-induced strain. Some advanced models further integrate the dynamic dissolution of CO₂ and CH₄ in formation water to refine the representation of CO₂ storage mechanisms in water-bearing coal seams.

Currently, finite element platforms such as COMSOL (Comsol multiphysics 6.2) multi-physics have emerged as important tools for simulating fully coupled CO₂-ECBM processes. Their modular and flexible multi-physics environment allows researchers to construct and solve highly complex models with ease. In parallel, advancements in finite difference and open-source simulation platforms are providing new pathways for tackling multiscale and multi-physics coupling challenges. Overall, the scope of numerical simulation in this field has evolved from single-field representations to multi-physics coupling, while the application frontier has expanded to include the quantitative evaluation of key performance indicators—such as CH₄ recovery efficiency and CO₂ adsorption capacity These efforts offer substantial data support for engineering design and risk assessment in real-world projects. Despite these advances, numerical simulation in CO₂-ECBM still faces major challenges, including high model complexity, intensive computational demands, and difficulties in obtaining accurate reservoir parameters. Future research should aim to further optimize model architecture, reduce computational costs, and validate simulations through field data, thereby enhancing their utility in guiding the engineering deployment and large-scale application of CO₂-ECBM technology.

4. Global Demonstration Projects of CO₂-ECBM

Overall, CO₂-ECBM technology remains in the exploratory engineering stage both internationally and in China. A number of pilot projects have been carried out globally, which have, to some extent, demonstrated the technical feasibility of CO₂-ECBM for both long-term CO₂ sequestration and enhanced coalbed methane recovery [61,62,63,64,65,66,67] (Table 1). Although research in this field began earlier in several countries, and some projects have progressed to pilot-scale or limited commercial operation, the majority are still in the field-testing phase.

As early as 1995–2001, the United States initiated the first CO₂-ECBM field trial at the Allison Unit in the San Juan Basin. The project employed multi-well co-production techniques and successfully enhanced CBM recovery. This large-scale trial covered an area of approximately 1.295 × 10⁶ m², with four CO₂ injection wells and 16 production wells, and a cumulative CO₂ injection volume of 336,000 t [68,69]. Another prominent effort in the San Juan Basin, located in New Mexico, targeted the Upper Cretaceous Fruitland Formation, which has an average depth of approximately 900 m [70]. This test, initiated in 1995, aimed to assess the carbon sequestration potential of the Fruitland coal seams. The reservoir was categorized into four distinct subregions based on geological and production characteristics. The pilot area was located in a high-pressure, high-yield CBM zone. In addition to the San Juan Basin, other demonstration projects in the United States have been conducted in the Illinois and Appalachian Basins. These projects involved unmineable coal seams and lignite blocks, as well as the application of advanced technologies such as horizontal drilling and pre-fracturing, thereby contributing valuable field data and engineering experience to the development of CO₂-ECBM.

China’s research and engineering application of CO₂-ECBM started relatively late, but has developed rapidly in recent years with the support of national key scientific and technological programs. Since 2013, several pilot tests have been carried out under the leadership of China United Coalbed Methane Co., Ltd., focusing on both shallow and deep coal seams, ranging from single-well trials to multi-well group operations in the Qinshui Basin (Figure 8) and the Ordos Basin. China’s first pilot project was implemented in the Qinshui Basin between 2002 and 2006 through a joint initiative with the Canadian government. The trial involved intermittent CO₂ injection and production in No. 3 coal seam, where a total of 192.8 t of liquid CO₂ was injected, resulting in a significant increase in CBM recovery. From 2011 to 2012, a single-well injection-production test was conducted in a 560 m deep coal seam in Liulin, Shanxi Province, with a total CO₂ injection of 460 t. Subsequently, during 2013–2015, a deeper coal seam test at a depth of 900 m achieved a cumulative CO₂ injection of 4491 tonnes [71].

These pilot projects illustrate the evolution of China’s CO₂-ECBM development from shallow, single-well tests to deep, multi-well group experiments. The technical maturity has steadily improved, confirming the feasibility of CO₂-ECBM and revealing its promising potential for commercial-scale deployment. At the same time, these efforts have also highlighted the engineering challenges that must be overcome for widespread implementation of this technology.

Table 1. Major CO₂-ECBM projects worldwide [71].

Country	Project Location	Injection Period	CO2 Injected (t)
USA	Allison Field, San Juan Basin	April 1995–August 2001	336,000
USA	Pump Canyon, San Juan Basin	July 2008–August 2009	16,699.00
USA	Tanquary Farm, Illinois Basin	2008	92.3
USA	Virginia, Central Appalachian Basin	January 2009–February 2009	~900.00
USA	Lignite Block, Williston Basin	2009	90
USA	Black Warrior Basin	June 2010–August 2010	225
USA	Marshall, Northern Appalachian Basin	September 2009–December 2013	4500.00
USA	Buchanan, Central Appalachian Basin	July 2015–August 2015	1470.00
China	Shizhuang South Block, Qinshui Basin	April 2004–June 2004	192.8
China	Shizhuang North Block, Qinshui Basin	April 2010–May 2010	233.6
China	Liulin Block, Eastern Ordos Basin	September 2011–March 2012	460
China	Shizhuang North Block, Qinshui Basin	2013–2015	4491.00
China	Shizhuang South Block, Qinshui Basin	June 2020–June 2021	2001.04
Canada	Fenn Big Valley, Alberta	1998	201
Canada	Alder Flats, Alberta	June 2006	Unknown
Poland	Kaniow, Silesian Basin	August 2004–May 2005	760
Japan	Ishikari Basin, Hokkaido	July 2004–September 2007	~800.00

Table 1. Major CO₂-ECBM projects worldwide [71].

Country	Project Location	Injection Period	CO2 Injected (t)
USA	Allison Field, San Juan Basin	April 1995–August 2001	336,000
USA	Pump Canyon, San Juan Basin	July 2008–August 2009	16,699.00
USA	Tanquary Farm, Illinois Basin	2008	92.3
USA	Virginia, Central Appalachian Basin	January 2009–February 2009	~900.00
USA	Lignite Block, Williston Basin	2009	90
USA	Black Warrior Basin	June 2010–August 2010	225
USA	Marshall, Northern Appalachian Basin	September 2009–December 2013	4500.00
USA	Buchanan, Central Appalachian Basin	July 2015–August 2015	1470.00
China	Shizhuang South Block, Qinshui Basin	April 2004–June 2004	192.8
China	Shizhuang North Block, Qinshui Basin	April 2010–May 2010	233.6
China	Liulin Block, Eastern Ordos Basin	September 2011–March 2012	460
China	Shizhuang North Block, Qinshui Basin	2013–2015	4491.00
China	Shizhuang South Block, Qinshui Basin	June 2020–June 2021	2001.04
Canada	Fenn Big Valley, Alberta	1998	201
Canada	Alder Flats, Alberta	June 2006	Unknown
Poland	Kaniow, Silesian Basin	August 2004–May 2005	760
Japan	Ishikari Basin, Hokkaido	July 2004–September 2007	~800.00

5. Influencing Factors of CO₂-ECBM

As previously discussed, coalbed methane, as a self-sourced and self-stored unconventional natural gas within coal seams, is not only a clean energy resource but also plays a vital role in mine safety and gas explosion prevention. Its rational development can generate substantial economic benefits. Against this backdrop, CO₂-ECBM, which simultaneously enables long-term CO₂ sequestration and enhanced methane recovery, holds significant theoretical and practical value. Investigating its influencing factors is essential for optimizing production strategies and improving recovery efficiency.

During CO₂-ECBM, methane mainly exists in an adsorbed state within the micropores of the coal matrix, and the adsorption–desorption behavior is primarily controlled by gas partial pressure and temperature. After CO₂ injection, due to its stronger adsorption affinity for coal than methane, CO₂ is preferentially adsorbed onto the internal surfaces of the coal, displacing the adsorbed methane. This displacement effect significantly reduces the partial pressure of methane, promoting its desorption. The released free methane then migrates through the fracture and pore network under the pressure differential between injection and production wells, thereby enhancing the overall recovery rate [72,73,74,75]. In practical conditions, reservoir pressure, formation temperature, and CO₂ injection rate all exert significant influence on this process. Lower pressures help break the adsorption equilibrium, facilitating greater methane desorption and production. Suitable temperatures provide gas molecules with sufficient thermal energy to accelerate the desorption process. In addition, higher CO₂ injection rates can rapidly enhance the desorption rate and shorten the desorption time, playing a crucial role in improving methane recovery efficiency.

Geological conditions of the reservoir are fundamental to the feasibility and efficiency of CO₂-ECBM implementation. Optimal coal seams should possess favorable continuity and structural integrity to ensure uniform CO₂ distribution and effective contact with adsorbed methane. Specifically, laterally continuous coal seams facilitate homogeneous CO₂ migration, enhancing the overall displacement efficiency while reducing the likelihood of preferential flow paths and uneven sweep. In contrast, structurally complex formations—such as those with intense faulting or folding—can compromise sealing capacity and introduce high-permeability conduits that serve as potential leakage pathways. These not only limit the interaction between injected CO₂ and CH₄ but also elevate the risk of CO₂ escape, posing both environmental and operational safety concerns. Therefore, geologically stable, laterally extensive, and structurally simple coal reservoirs with low fault density and effective caprock integrity are considered the most suitable targets for CO₂-ECBM, as they support both enhanced methane recovery and secure long-term CO₂ storage [76,77,78]. In addition, permeability is a key parameter affecting injection efficiency, with higher permeability facilitating smoother fluid flow. Methane-saturated coal seams typically demonstrate better recovery outcomes, providing important guidance for the site selection and technical design of regional CO₂-ECBM projects.

Overall, the CO₂-ECBM process is governed by coupled multi-physical effects—including adsorption–desorption, diffusion and seepage, heat transfer, geomechanical evolution, and geochemical reactions—that collectively determine methane recovery and long-term CO₂ sequestration performance. These factors are not independent; rather, they interact through energy exchange, mass transport, and structural deformation in a highly complex manner. Therefore, future research should focus on elucidating the interaction mechanisms among these variables. A comprehensive understanding of these interactions is essential for revealing the fundamental nature of the CO₂-ECBM process, improving injection–production strategies, and achieving optimal technical and economic performance.

6. Discussion

6.1. Challenges in CO₂-ECBM

Although CO₂-ECBM has achieved a series of pilot-scale successes globally, numerous scientific and engineering challenges remain unresolved in practical applications. One critical issue is the development of efficient monitoring, measurement, and verification (MMV) technologies to accurately assess CO₂ migration, leakage risk, and storage capacity during sequestration, thereby ensuring long-term subsurface storage security. Despite considerable progress internationally—particularly in the United States—risk control remains at the core of CO₂-ECBM research. However, growing attention has been directed toward the associated environmental risks and sequestration costs.

One frequently discussed concern is the potential for injection-induced geomechanical responses. CO₂ injection alters the stress–pressure balance in the reservoir, potentially leading to surface uplift due to increased pore pressure and coal matrix swelling, or, conversely, surface subsidence from long-term compaction or pressure decline. Field evidence from the In Salah Krechba gas field in Algeria (Figure 9) demonstrates that sustained CO₂ injection can cause measurable surface deformation—primarily uplift—highlighting the sensitivity of overburden to subsurface pressure changes. In addition, pressure perturbations may activate pre-existing faults and induce microseismicity, posing risks to both storage security and operational safety. These deformation responses underscore the importance of geomechanical assessment, integrated monitoring, and adaptive risk management strategies during large-scale CO₂ geological sequestration [79]. Preventive measures such as optimizing injection rates, selecting structurally stable reservoirs, and implementing real-time pressure and deformation monitoring can significantly reduce the likelihood of leakage. In the event of leakage, which poses a significant safety risk during large-scale field implementations, remediation techniques—such as pressure relief through extraction wells or sealing of leakage pathways using sealants or cement—can help contain and mitigate its impact. While microfractures induced by injection may enhance reservoir permeability, they also raise concerns about seismic hazards and the integrity of geological storage.

In addition, the potential environmental impacts of CO₂ geological sequestration have attracted widespread attention. Once injected into coal seams, CO₂ may react with chemical constituents in groundwater, forming acidic compounds that promote the dissolution or precipitation of minerals such as carbonates and pyrite. These geochemical reactions may alter the chemical properties of soil, vegetation, and aquifers, potentially degrading the local ecosystem. Furthermore, such reactions could adversely affect the pore structure of coal, leading to reduced gas recovery efficiency and compromised reservoir stability.

Economic cost remains another major barrier to the large-scale deployment of CO₂-ECBM. The current implementation process requires CO₂ capture, compression, and purification prior to its injection in liquid form into coal seams. The associated equipment investment and energy consumption result in high overall project costs. Although some studies propose using flue gas compression to reduce costs—while leveraging N₂ in flue gas to improve coal permeability—this approach still entails additional expenses for separation and purification at later stages. Striking a balance between technical performance and economic feasibility is a critical challenge for future development.

Another key issue is the alteration of coal seam physical properties caused by CO₂ injection. During the process, coal matrices undergo significant swelling and shrinkage, as CO₂ exhibits a much stronger adsorption capacity than CH₄. This leads to notable volumetric changes during desorption, affecting reservoir porosity and permeability, and ultimately reducing the effectiveness of gas recovery. In parallel, CO₂-induced acid generation and subsequent mineral dissolution and precipitation can further alter the pore structure of coal seams, negatively impacting gas production. Moreover, the plasticizing effect of supercritical CO₂ on coal becomes increasingly pronounced, leading to the softening of the coal’s physical and mechanical properties. Significant reductions in elastic modulus and compressive strength increase the likelihood of reservoir fracturing and leakage during injection and production operations.

6.2. Development Trends of CO₂-ECBM Technology

The future development of CO₂-ECBM technology will primarily focus on in-depth investigations of multi-physics coupling mechanisms, comprehensive upgrades of monitoring technologies, and the large-scale deployment of engineering application models. Firstly, as the decline in coal reservoir permeability after CO₂ injection becomes increasingly significant, the effects of various injection parameters—such as injection volume, pressure, and method—on coal swelling and pore structure alteration have yet to be generalized into a universally applicable theoretical framework. Therefore, future research should systematically explore the complex coupling mechanisms among these influencing factors to provide scientific guidance for site selection and the optimization of injection-production schemes, ensuring sustained and stable CO₂ injection as well as efficient methane recovery.

Uncertainties in coal cleat structure remain a key challenge for accurate risk prediction in CO₂-ECBM. As cleats govern fluid flow and pressure responses, variations in their geometry and connectivity can significantly affect model reliability. However, their fine-scale heterogeneity makes precise characterization difficult. Meanwhile, current monitoring, measurement, and verification (MMV) technologies are still inadequate for fully tracking gas transport, leakage, and reservoir dynamics within coal seams. Improving imaging, in situ monitoring, and uncertainty-informed modeling will be essential to enhance risk assessment and ensure storage safety. In addition, there is a lack of large-scale, long-term field tests—particularly in coal seams deeper than 1000 m—leading to limited understanding of optimal operational conditions and engineering control strategies. Future efforts should prioritize the development of high-precision real-time monitoring tools and the implementation of cross-regional demonstration projects to expand data diversity and support the refinement of risk management frameworks for CO₂-ECBM deployment.

Moreover, the industrial application of CO₂-ECBM continues to face challenges related to high implementation costs and insufficient market incentives. Achieving a balance between technical performance and economic viability will be a central challenge in future technological transformation and large-scale deployment. Accordingly, it is urgent for national and regional governments to enhance policies related to coalbed methane development and utilization. Support should be given to the full-process technology chain of CO₂ geological sequestration and utilization, as well as to cluster-based demonstration projects, aiming to establish industrial-scale applications with a capacity exceeding one million tons. Simultaneously, fundamental scientific research into CO₂ geological storage and utilization must be strengthened to uncover the underlying mechanisms of source-sink matching, technology integration, and system optimization under various regional energy, resource, and environmental conditions. These efforts will provide theoretical foundations and practical guidance for the development of advanced and regionally adaptive CO₂-ECBM technology models.

In summary, the future advancement of CO₂-ECBM technology will rely on deeper insights into complex coupling mechanisms, innovations in monitoring technologies, and sustained implementation of large-scale engineering trials. Through policy support and integrated technological solutions, CO₂-ECBM can achieve simultaneous improvements in storage security, methane recovery efficiency, and economic performance, ultimately promoting the healthy and widespread application of this technology on a global scale.

7. Conclusions

This study provides a comprehensive review of the fundamental mechanisms, experimental and numerical research progress, and current status of engineering demonstrations related to CO₂-ECBM technology. It highlights the synergistic advantages of this approach in enhancing coalbed methane recovery while enabling long-term CO₂ sequestration, thereby establishing an effective technological bridge between energy development and carbon emission reduction. Research indicates that the coupled multi-physical processes—including adsorption/desorption, diffusion, and seepage—play a critical role in the CO₂-driven methane displacement process. The preferential adsorption of CO₂ facilitates the displacement of adsorbed CH₄, significantly reducing the partial pressure of CH₄ in the coal matrix, promoting its desorption and migration toward production wells, and ultimately improving recovery efficiency.

Both experimental studies and numerical simulations have demonstrated that reservoir pressure, formation temperature, and CO₂ injection flow rate significantly influence CBM recovery. Meanwhile, reservoir physical properties, structural conditions, and multi-physics coupling effects collectively determine the injection efficiency and long-term storage security of CO₂. These findings provide critical references for assessing the storage capacity and site suitability of CO₂-ECBM projects.

Although a number of pilot tests and demonstration projects have been conducted globally, and some have yielded preliminary successes, CO₂-ECBM technology still faces several pressing challenges. These include insufficient monitoring and verification technologies, the risk of induced seismicity, potential environmental impacts, high economic costs, and changes in coal reservoir properties. These issues require further in-depth investigation. Future development efforts should focus on elucidating the complex multi-physics coupling mechanisms triggered by CO₂ injection, enhancing the accuracy and real-time capabilities of monitoring technologies, and promoting large-scale, long-duration, and cross-regional field demonstrations. Based on integrated technologies and full-process optimization, CO₂-ECBM can achieve coordinated improvements in storage safety, recovery efficiency, and economic viability, thus offering robust technical support for global energy transition and low-carbon development.