Coalbed Methane Recovery Processes Research Articles

Kinetic evaluation of hydrate-based coalbed methane recovery process promoted by structure II thermodynamic promoters and amino acids

Coalbed methane recovery is crucial to coal mine safety, greenhouse gas emission reduction and economic benefits. Gas hydrate technology can be employed to separate CH4 from the N2-rich coal mine gas. To enhance hydrate formation kinetics, separation performance and CH4 recovery, we examined the synergistic effect of structure II (sII) hydrate promoters and amino acids on hydrate formation of 30 mol% CH4/70 mol% N2 mixture, involving three thermodynamic promoters (tetrahydrofuran (THF), cyclopentane (CP) and propane) and four amino acids (l-cysteine, l-methionine, l-tryptophan and l-lysine). Amino acids exhibited extraordinary promotion effects on the propane system with over 10 times improvement in kinetics. CP-amino acid systems excelled in separation performance by enriching CH4 content from 30 mol% to 70 mol%. THF-amino acid systems showed moderate performance on kinetics and separation but achieved the highest CH4 recovery up to 50.27%. The impacts of amino acids were system-dependent: they did not alter the hydrate growth pattern of the THF system but completely changed the hydrate morphology of CP and propane systems. Two possible mechanisms were discussed including interfacial tension alteration and hydrophobicity of amino acids. These insights would provide a basis for further optimizing the hydrate process promoted by sII promoters and amino acids for applications including coalbed methane recovery and beyond.

Experimental and numerical model of anisotropic permeability and CO2 injectivity of coal during CO2 enhanced coalbed methane recovery process

Guaranteeing CO2 injectivity has been the precondition for implementing the CO2-enhanced coalbed methane recovery (CO2-ECBM), however, it dramatically decreases during the CO2 injection process because it is influenced by the dynamic change of the anisotropic permeability of coal. To reveal and evaluate the CO2 injectivity of coal, the anisotropic permeability test and the CO2 injectivity simulation test were first conducted, then the corresponding numerical models were established and verified by the experimental data. The results show that the permeability of coal in parallel face cleat direction is the largest, followed by the permeability of coal in parallel butt cleat direction and that in vertical bedding direction is the minimum. The peak value of the instantaneous injectivity rate is enhanced and the injection time is prolonged with the increase of the CO2 injection pressure. The total CO2 injectivity rate is nonlinearly increased from 13.61 to 311.87 cm2/MPa min when the CO2 injection pressure raises from 2 to 10 MPa. The anisotropic permeability model is appropriate to describe the dynamic evolution of permeability under different boundary conditions, the CO2 injectivity prediction model can be used to evaluate the CO2 injectivity during the CO2 injection process. Increasing the CO2 injection pressure may temporarily promote CO2 injectivity, while the CO2 injection increment is limited. The CO2 fracturing by phase transition may be an available reservoir stimulation method for enhancing the CO2 injection and should be focused on in the future.

Coalbed methane accumulation, in-situ stress, and permeability of coal reservoirs in a complex structural region (Fukang area) of the southern Junggar Basin, China

The enrichment of coalbed methane (CBM), in-situ stress field, and permeability are three key factors that are decisive to effective CBM exploration. The southern Junggar Basin is the third large CBM basin in China but is also known for the occurrence of complex geological structures. In this study, we take the Fukang area of the southern Junggar Basin as an example, coalbed methane accumulation and permeability, and their geological controls were analyzed based on the determination of geological structures, in-situ stress, gas content, permeability, hydrology and coal properties. The results indicate that gas contents of the Fukang coal reservoirs are controlled by structural framework and burial depth, and high-to-ultra-high thickness of coals has a slightly positive effect on gas contents. Perennial water flow (e.g., the Baiyanghe River) favors gas accumulation by forming a hydraulic stagnant zone in deep reservoirs, but can also draw down gas contents by persistent transportation of dissolved gases to ground surfaces. Widely developed burnt rocks and sufficient groundwater recharge make microbial gases an important gas source in addition to thermogenic gases. The in-situ stress field of the Fukang area (700–1,500 m) is dominated by a normal stress regime, characterized by vertical stress > maximum horizontal stress > minor horizontal stress. Stress ratios, including lateral stress coefficient, natural stress ratios, and horizontal principal stress ratio are all included in the stress envelopes of China. Permeability in the Fukang area is prominently partitioned into two distinct groups, one group of low permeability (0.001–0.350 mD) and the other group of high permeability (0.988–16.640 mD). The low group of permeability is significantly formulated by depth-dependent stress variations, and the high group of permeability is controlled by the relatively high structural curvatures in the core parts of synclines and the distance to the syncline core. Meanwhile, coal deformation and varying dip angles intensify the heterogeneity and anisotropy of permeability in the Fukang area. These findings will promote the CBM recovery process in China and improve our understanding of the interaction between geological conditions and reservoir parameters and in complex structural regions.

Mechanisms in CO2-enhanced coalbed methane recovery process

Injection of CO2 and subsequent desorption of CH4 is considered to be the most efficient enhanced coalbed methane (ECBM) recovery technique to date. Meanwhile, CO2-ECBM is an excellent option for CO2 geo-sequestration for an extended period. Despite ongoing research efforts and several field applications of this technology, the mechanisms of the process have yet to be fully understood. The coalbed heterogeneity, the fluid interactions with coal, the CO2 induced swelling, and the continuous pressure and composition changes require outright insights for optimal application of the technique. Furthermore, intermolecular interactions of CO2 and CH4, their competitive adsorption on the dry/wet coal surface, and the dispersion and advection processes play an important role in defining the CO2-ECBM recovery process. An attempt has been made here to understand the key mechanisms of CO2-ECBM recovery in coalfields, particularly the adsorption of CO2 in the supercritical state at the recommended sequestration depth. Cited as: Asif, M., Wang, L., Wang, R., Wang, H., Hazlett, R. D. Mechanisms in CO2-enhanced coalbed methane recovery process. Advances in Geo-Energy Research, 2022, 6(6): 531-534 . https://doi.org/10.46690/ager.2022.06.09

Brittleness Evolution of Different Rank Coals under the Effects of Cyclic Liquid CO2 during the Coalbed Methane Recovery Process

Brittleness Evolution of Different Rank Coals under the Effects of Cyclic Liquid CO₂ during the Coalbed Methane Recovery Process

Mechanical responses of coals under the effects of cyclical liquid CO2 during coalbed methane recovery process

Liquid CO2 fracturing technology has been introduced to enhance coalbed methane (CBM) recovery for the decades, under its multiple-effects of phase transition and flooding, by complicating the crack distribution and improving the reservoir permeability. When huge amounts of cryogenic fluids were cyclically injected into the reservoirs, the accompanying effects of temperature shock and adsorption might have some potential impacts on the fracturing results, and their influence degree and the related mechanical deterioration were required to systematically studied. Three different rank coals were chosen and cyclically treated by liquid CO2, and the uniaxial compression behaviors of these affected coals were studied to investigate the destruction patterns, the evolutions of mechanical parameters, and the mechanism of damage failure. Compared to the raw coals, the ones affected by temperature-adsorption coupling effects of liquid CO2 displayed a more complex “separation + spallation” destruction pattern, while the ones treated by the sole effect had a destruction pattern of “spallation” and “separation” respectively. The more complex the destruction pattern, the larger the fractal dimension, and the greater the structure degradation. The affected coals exhibited diverse mechanical responses, for example, the compression strength σc and elastic modulus E had negative correlations with the increasing cyclical parameters, while Poisson’s ratio μ and damage variable Dv positively correlated with the increasing affecting parameters, respectively, which manifested that the accompanying cyclical temperature shock could facilitate the crack growth and the CO2 adsorption aggravated the strength deterioration, finally destroying the coals with the smaller yield strength. A new damage model was established by jointly considering the grain anisotropy from the microscopic aspect and the diversity of mechanical responses from the macroscopic perspective, and the induced unrecoverable deformations greatly weakened the cohesive stress among the grains or matrix skeleton, finally destroying the coal structure by producing amounts of new cracks. Furthermore, the produced new-raw cracks provided amounts of adsorption sites for CO2 molecules, which further decreased the surface energy and accelerated shear failure. The results were helpful to the injection parameters optimization, the low-cost of CO2 injection invests and the potential profit maximization of CBM utilization.

Competitive adsorption characteristics of N2 and CH4 gas mixtures on coal and its geological significance

Coalbed methane (CBM) is an important unconventional natural gas resource and has achieved great advances in recent years. In this study, single and binary component adsorption experiments of N2 and CH4 on dry coal from eastern Yunnan and western Guizhou area were conducted on a high-pressure isothermal adsorption equipment to investigate the competitive adsorption characteristics of N2 and CH4. The results show that absolute adsorption capacity of methane is higher than that of nitrogen for coal samples in this area. Moreover, maximum mixture gas adsorption isotherms lie between the pure N2 isotherms and pure CH4 isotherms. There is an obvious increasing trend for PL as the content of nitrogen increases, it can be ruled out that critical desorption pressure increases along with the increasing nitrogen content in coal seam. This investigation is significative to understand CBM recovery processes considering N2 injection.

Research on the Processes of Injecting CO2 into Coal Seams with CH4 Recovery Using Horizontal Wells

The paper presents a research study on modeling and computer simulation of injecting CO2 into the coal seams of the Upper Silesian Coal Basin, Poland connected with enhanced coal bed methane (ECBM) recovery. In the initial stage of the research activities, a structural parameter model was developed specifically with reference to the coal-bearing formations of the Upper Carboniferous for which basic parameters of coal quality and the distribution of methane content were estimated. In addition, a lithological model of the overall reservoir structure was developed and the reservoir parameters of the storage site were analyzed. In the next stage of the research, the static model was supplemented with detailed reservoir parameters as well as the thermodynamic properties of fluids and complex gases. The paper discusses a series of simulations of an enhanced coalbed methane recovery process with a simultaneous injection of carbon dioxide. The analyses were performed using the ECLIPSE software designed for simulating coal seam processes. The results of the simulations demonstrated that the total volume of CO2 injected to a designated seam in a coal mine during the period of one year equaled 1,954,213 sm3. The total amount of water obtained from the production wells during the whole period of the simulations (6.5 years) was 9867 sm3. At the same time, 15,558,906 sm3 of gas was recovered, out of which 14,445,424 sm3 was methane. The remaining 7% of the extracted gas was carbon dioxide as a result of reverse production of the previously injected CO2. However, taking into consideration the phenomena of coal matrix shrinking and swelling, the total amount of injected CO2 decreased to approximately 625,000 sm3.

Changes in Pore Structure of Coal Caused by CS2 Treatment and Its Methane Adsorption Response

The pore structure and gas adsorption are two key issues that affect the coal bed methane recovery process significantly. To change pore structure and gas adsorption, 5 coals with different ranks were treated by CS2 for 3 h using a Soxhlet extractor under ultrasonic oscillation conditions; the evolutions of pore structure and methane adsorption were examined using a high-pressure mercury intrusion porosimeter (MIP) with an AutoPore IV 9310 series mercury instrument. The results show that the cumulative pore volume and specific surface area (SSA) were increased after CS2 treatment, and the incremental micropore volume and SSA were increased and decreased before and after Ro,max=1.3%, respectively; the incremental big pore (greater than 10 nm in diameter) volumes were increased and SSA was decreased for all coals, and pore connectivity was improved. Methane adsorption capacity on coal before and after Ro,max=1.3% also was increased and decreased, respectively. There is a positive correlation between the changes in the micropore SSA and the Langmuir volume. It confirms that the changes in pore structure and methane adsorption capacity due to CS2 treatment are controlled by the rank, and the change in methane adsorption is impacted by the change of micropore SSA and suggests that the changes in pore structure are better for gas migration; the alteration in methane adsorption capacity is worse and better for methane recovery before and after Ro,max=1.3%. A conceptual mechanism of pore structure is proposed to explain methane adsorption capacity on CS2 treated coal around the Ro,max=1.3%.

Application case study of enhanced coal bed methane recovery process in thar coal fields

Enhanced coal bed methane recovery (ECBM) process is an important developing technology because of its dual advantage, i.e., producing methane gas and sequestering CO2 at the same time. CO2 have been used for enhanced oil recovery (EOR) for more than five decades but available storage sites for EOR are only limited to oil rich countries. Pakistan has one of the largest coal reserves in the world accounting to more than 185 billion tons. In this study, CO2 sequestration in the coalbeds of Thar coal field located in the South of Pakistan is explored from the technical and economical point of view. Potential CO2 storage capacity and methane gas‐in‐place has been calculated for the Thar coal fields. Next, an economic analysis has been performed to evaluate the cost of CO2 storage and to explore any economic benefit from the methane production. Usually, coal reservoirs are saturated with water, hence water production along with methane is inevitable. This study analyzed various water treatment methods and recommended shallow re‐injection technology to be the most suitable for the Thar coal ECBM process. In addition, carbon balance has been investigated to calculate the CO2 avoided during the ECBM process. Finally, a sensitivity analysis has been performed on some of the important design variables in order to analyze their effect on the cost of CO2 storage. © 2017 American Institute of Chemical Engineers Environ Prog, 37: 900–911, 2018

ICM releases new details about showcase biorefinery

Coal bed methane (CBM) has received increasing attentions as a significant energy resource. Numerical modeling of the CBM recovery processes entails simulation of the complex coupled mechanisms, including desorption of methane from the coal matrix surface, diffusion of gas to coal cleats, and gas flow from coal cleats to the wellbore. Beyond these complex flowing mechanisms, it is crucially important to represent coal cleats, structural fractures, and/or hydraulic fractures realistically in CBM simulators as they provide flow channels and dominate CBM flow behaviors. Existing CBM simulators are typically extended from oil and gas reservoir simulators with either black-oil or compositional formulation, and sorption and desorption are usually modeled by the Langmuir isotherms. The concept of shape factor is commonly used to characterize the flow between matrix and cleats (or fractures). When the shape factor is treated as only a function of cleat spacing, the detailed characteristics of actual cleats (or fractures) are missing, including the spatial distribution of cleats and interconnectivity of cleats. In this study, we propose a new workflow to perform a 2-D coal bed methane recovery simulation with discrete fracture model (DFM) in consideration of both structural fractures (large-scale fractures) and cleats (small-scale fractures). There are two key steps in our approach. First, we use a detailed network of discrete fractures characterized from core samples to represent the actual distribution of identified cleats, and calculate the shape factor of the realistic cleated coal sample by running a flow simulation to pseudo-steady state. Second, we apply the shape factor to field-scale simulations in which large-scale fractures are modeled as DFM. For this purpose, we treat gas sorption and desorption as a “chemical reaction”, and we developed an extension to an existing geochemical-reservoir simulator. We implemented both a “pseudo-compositional” and a “full-compositional” module to study the effect of mass exchange between gas and aqueous phases. We validated our new formulation and simulator development from a benchmark case in which our simulation results show close agreement with commercial simulators. We also demonstrated the significance of modeling mass exchange between fluid phases on CBM recovery in some cases, which is commonly missing in most commercial simulators. Finally, we presented our workflow in modeling an enhanced CO2-ECBM recovery process to a complex fractured coal bed with both large-scale tectonic fractures and small-scale cleats.

Gas Transportation and Enhanced Coalbed Methane Recovery Processes in Deep Coal Seams: A Review

Coalbed methane (CBM) is a potential green energy supply for addressing the worldwide energy crisis. However, the recovery of economically viable amounts of methane requires the application of production-enhancement techniques. The greater effectiveness of enhanced coalbed methane (ECBM) recovery compared to traditional pressure depletion and hydraulic stimulation techniques has been identified in terms of higher CBM recovery with minimal pollution risk and the ability to contribute to CO2 sequestration. Gas transport behavior in a coal seam is the governing factor for ECBM recovery, which includes sorption/desorption and diffusion in the matrix and advective flux in cleats. The interactions among sorption, diffusion, and flow indicate the complexity and abstruseness of gas transport in coal. Therefore, the purpose of this paper is to provide comprehensive knowledge of the gas transport process in deep coal seams, particularly in relation to the ECBM process. According to the review, the dual-porosity sys...

Pore Structure and Compressibility of Coal Matrix with Elevated Temperatures by Mercury Intrusion Porosimetry

To gain a better understanding of the effect of heat (e.g., magma intrusion, geothermal fluids and enhanced coal-bed methane recovery process) on coal reservoir properties, the pore structure and compressibility of coal matrix for low rank coal (0.69% Ro, m) with elevated temperatures were investigated by using multiple methods, including thermogravimetry-mass spectrometry (TG-MS), scanning electron microscope (SEM), N2 adsorption/desorption at 77 K and mercury intrusion porosimetry (MIP). The results from TG-MS showed that moisture and partial volatiles were removed from the coal matrix, and pore structure almost remained unchanged during the low heat treatment (25∼200°C). The micropores and transition pores consisted of more than 80% of the total pore volume based on the MIP. The pore structure was slightly changed following the temperature increase to 400°C, and the bound moisture and partial organics in the coal were released and decomposed by the increased heat, respectively. When temperature reached 400°C, organic matter decomposition of the coal released a large amount of hydrocarbon and micromolecule gases. The meso- and macropore in the coal were significantly developed, occupying ∼35% of the total pore volume. Although there was no large change in generated gas composition after 600°C, the pore volume and structures, including pore size distribution, pore volume and pore connectivity, were significantly changed based on the MIP. The pore structure acquired from MIP exhibited a deviation when the mercury intruded pressure reached 10 MPa. A fractal model was introduced to correct the MIP data and acquire the pore compressibility of the coal matrix. The results showed that the pore compressibility decreased with increasing pressure and temperature. Thus, this study provides significant implications of the pore structure evolution of underground coals that encounter heating.

Changes in coal pore structure and permeability during N2 injection

Previous studies on N2-ECBM (N2-enhanced coalbed methane) have focused on experimental investigation or numerical simulation of coalbed methane recovery processes using pure N2 or binary gas (CO2/N2) injection. Experimental studies on the changes in pore structure and permeability during N2 injection have been limited. In this study, N2 injection experiments, mercury intrusion porosimetry and permeability measurements were conducted to investigate the changes in pore structure and permeability caused by N2 injection of semi-anthracite coal from the Lu'an mining area in the Qinshui basin, Shanxi Province, China. The results show that the total pore volume markedly increases during N2 injection, with increases in transition pores, mesopores and macropores of 8.0%, 50.0% and 138.3%, respectively. Nitrogen injection improves the pore size distribution: the incremental pore volume variances of transition pores, mesopores and macropores after treatment are 2.1%, 47.8% and 141.0%, respectively. Porosity and permeability markedly rise during N2 injection, by 22.6% and 29.9%, respectively. These results demonstrate that N2 injection mainly affects macropores, followed by mesopores and transition pores, and reformation of the micropores is limited. Nitrogen injection alters the pore structure of coal, which leads to an increase in the pore volume and improvement of the pore size distribution and connectivity: these changes facilitate the diffusion and transfusion of coalbed methane. The permeability of the coal sample was improved as a result of N2 injection, indicating that N2 injection could be used to enhance the permeability of CBM reservoirs. These findings will lead to a better understanding of the interactions between pores and N2 during N2 injection and hence can be applied to improve CBM recovery for non-productive or low-productivity CBM wells.

A novel approach to model enhanced coal bed methane recovery with discrete fracture characterizations in a geochemical simulator

Abstract Coal bed methane (CBM) has received increasing attentions as a significant energy resource. Numerical modeling of the CBM recovery processes entails simulation of the complex coupled mechanisms, including desorption of methane from the coal matrix surface, diffusion of gas to coal cleats, and gas flow from coal cleats to the wellbore. Beyond these complex flowing mechanisms, it is crucially important to represent coal cleats, structural fractures, and/or hydraulic fractures realistically in CBM simulators as they provide flow channels and dominate CBM flow behaviors. Existing CBM simulators are typically extended from oil and gas reservoir simulators with either black-oil or compositional formulation, and sorption and desorption are usually modeled by the Langmuir isotherms. The concept of shape factor is commonly used to characterize the flow between matrix and cleats (or fractures). When the shape factor is treated as only a function of cleat spacing, the detailed characteristics of actual cleats (or fractures) are missing, including the spatial distribution of cleats and interconnectivity of cleats. In this study, we propose a new workflow to perform a 2-D coal bed methane recovery simulation with discrete fracture model (DFM) in consideration of both structural fractures (large-scale fractures) and cleats (small-scale fractures). There are two key steps in our approach. First, we use a detailed network of discrete fractures characterized from core samples to represent the actual distribution of identified cleats, and calculate the shape factor of the realistic cleated coal sample by running a flow simulation to pseudo-steady state. Second, we apply the shape factor to field-scale simulations in which large-scale fractures are modeled as DFM. For this purpose, we treat gas sorption and desorption as a “chemical reaction”, and we developed an extension to an existing geochemical-reservoir simulator. We implemented both a “pseudo-compositional” and a “full-compositional” module to study the effect of mass exchange between gas and aqueous phases. We validated our new formulation and simulator development from a benchmark case in which our simulation results show close agreement with commercial simulators. We also demonstrated the significance of modeling mass exchange between fluid phases on CBM recovery in some cases, which is commonly missing in most commercial simulators. Finally, we presented our workflow in modeling an enhanced CO 2 -ECBM recovery process to a complex fractured coal bed with both large-scale tectonic fractures and small-scale cleats.

A poromechanical model for coal seams saturated with binary mixtures of CH4 and CO2

Underground coal bed reservoirs naturally contain methane which can be produced. In parallel of the production of this methane, carbon dioxide can be injected, either to enhance the production of methane, or to have this carbon dioxide stored over geological periods of time. As a prerequisite to any simulation of an Enhanced Coal Bed Methane recovery process (ECBM), we need state equations to model the behavior of the seam when cleats are saturated with a miscible mixture of CH4 and CO2. This paper presents a poromechanical model of coal seams exposed to such binary mixtures filling both the cleats in the seam and the porosity of the coal matrix. This model is an extension of a previous work which dealt with pure fluid. Special care is dedicated to keep the model consistent thermodynamically. The model is fully calibrated with a mix of experimental data and numerical data from molecular simulations. Predicting variations of porosity or permeability requires only calibration based on swelling data. With the calibrated state equations, we predict numerically how porosity, permeability, and adsorbed amounts of fluid vary in a representative volume element of coal seam in isochoric or oedometric conditions, as a function of the pressure and of the composition of the fluid in the cleats.

Improved apparent permeability models of gas flow in coal with Klinkenberg effect

Klinkenberg effect is an important phenomenon for gas flow in low permeability reservoirs, and its influence increases with the reduction of gas pressure. Unlike conventional gas reservoirs, coal seam is unique with its high compressibility and sorption-induced-swelling features. During the coalbed methane (CBM) recovery process, coal cleat width varies due to the net effect of effective stress and coal matrix shrinkage, thus the Klinkenberg coefficient cannot be treated as a constant like rock reservoirs. A brief review of previous studies shows that the influence of coal seam characteristics on Klinkenberg effect was ignored by other researchers. By using the bundled matchstick conceptual model of coal, two improved models are proposed in this paper, one is under constant effective stress and the other is under reservoir condition. The former shows that the proportion of permeability change due to Klinkenberg effect is greater than the result from original model, and the Klinkenberg coefficient varies substantially albeit the influence of effective stress is eliminated. The latter links apparent permeability and coal porosity together, and the results show good agreement with field data, especially when the gas pressure is relative low. It can be concluded that apparent permeability model is crucial for explicit prediction of gas permeability changes during CBM recovery process, which may be underestimated without due consideration of Klinkenberg effect. The development of the improved apparent permeability models has significant value in the accurate prediction of CBM production as a result of permeability changes.

Development of a multi-mechanistic, dual-porosity, dual-permeability, numerical flow model for coalbed methane reservoirs

Most existing coalbed methane (CBM) simulators usually treat coal seams as dual-porosity, single-permeability systems ignoring the effects of water presence in the coal matrix. In this study, a compositional dual-porosity, dual-permeability CBM simulator has been developed. The CBM reservoir is treated as a dual-porosity, dual-permeability system consisting of coal matrix and fracture network. The development of the proposed numerical model incorporates the effects of water presence in the coal matrix and the phenomena of coal shrinkage and swelling. The transport of gas follows a multi-mechanistic flow mechanism triggered by pressure and concentration gradients. In addition, the proposed simulator is able to collapse to simpler coal seam representations and was successfully tested against the existing commercial and research CBM simulators for CO2-enhanced CBM recovery process. Successful history matching exercises were performed on pure CO2 injection and flue gas injection tests using the actual field data.

Numerical studies on the effects of water presence in the coal matrix and coal shrinkage and swelling phenomena on CO<SUB align= �right �>2-enhanced coalbed methane recovery process

Conventional coalbed methane (CBM) models are developed using dual-porosity, single-permeability domain characteristics, which ignore the effects of water presence in the coal matrix. Neglecting these effects typically over-predicts gas production. Another phenomenon often disregarded in most CBM models is the coal shrinkage and swelling effects, which cause changes in coal permeability. This study illustrates how the water presence in the coal matrix and coal shrinkage and swelling phenomena affect the CO2-enhanced CBM recovery process. An in-house two-phase, fully-implicit, compositional, dual-porosity, dual-permeability CBM simulator accounting for the effects of water presence in the coal matrix and coal shrinkage and swelling, is used in this analysis. Results demonstrate the water presence in the coal matrix caused an early CO2 breakthrough. A decrease in fracture permeability caused by the dominating effects of coal swelling delays the CO2 breakthrough. Ignoring these effects could provide significant errors of production predictions of enhanced CBM recovery process.

Modelling of anisotropic coal swelling and its impact on permeability behaviour for primary and enhanced coalbed methane recovery

Coal swelling/shrinkage during gas adsorption/desorption is a well-known phenomenon. For some coals the swelling/shrinkage shows strong anisotropy, with more swelling in the direction perpendicular to the bedding than that parallel to the bedding. Experimental measurements performed in this work on an Australian coal found strong anisotropic swelling behaviour in gases including nitrogen, methane and carbon dioxide, with swelling in the direction perpendicular to the bedding almost double that parallel to the bedding. It is proposed here that this anisotropy is caused by anisotropy in the coal's mechanical properties and matrix structure. The Pan and Connell coal swelling model, which applies an energy balance approach where the surface energy change caused by adsorption is equal to the elastic energy change of the coal solid, is further developed to describe the anisotropic swelling behaviour incorporating coal property and structure anisotropy. The developed anisotropic swelling model is able to accurately describe the experimental data mentioned above, with one set of parameters to describe the coal's properties and matrix structure and three gas adsorption isotherms. This developed model is also applied to describe anisotropic swelling measurements from the literature where the model was found to provide excellent agreement with the measurement. The anisotropic coal swelling model is also applied to an anisotropic permeability model to describe permeability behaviour for primary and enhanced coalbed methane recovery. It was found that the permeability calculation applying anisotropic coal swelling differs significantly to the permeability calculated using isotropic volumetric coal swelling strain. This demonstrates that for coals with strong anisotropic swelling, anisotropic swelling and permeability models should be applied to more accurately describe coal permeability behaviour for both primary and enhanced coalbed methane recovery processes.