Coalbed Methane Recovery Research Articles

Evolution law of pulsating seepage and thermal deformation by injecting high‐temperature steam into coal for thermal coalbed methane recovery

AbstractChinese coal reservoirs are characterized by low pressure and low permeability, which need to be enhanced so as to increase production. However, conventional methods for permeability enhancement can only increase the permeability in fractures, but not the ultra‐low permeability in coal matrices. Attempts to enhance such impermeable structures lead to rapid attenuation of gas production, especially in the late stage of gas extraction. Thermal stimulation by injecting high‐temperature steam is a promising method to increase gas production. The critical scientific challenges that still hinder its widespread application are related to the evolution law of permeability of high‐temperature steam in coal and the thermal deformation of coal. In this study, an experimental approach is developed to explore the high‐temperature steam seepage coupled with the thermal deformation in coal under triaxial stress. The tests were conducted using cylindrical coal specimens of ϕ50 mm × 100 mm. The permeability and thermal strain in coal were investigated when high‐temperature steam was injected at 151.11, 183.20, 213.65, and 239.76°C. The experimental results reveal for the first time that as the amount of injected fluid increases, the steam permeability shows periodic pulsation changes. This paper introduces and explains the main traits of this discovery that may shed more light on the seepage phenomenon. When the injected steam temperature increases, the amplitude of pulsating permeability decreases, whereas the frequency increases; meanwhile, the period becomes shorter, the pulsation peak appears earlier, and the stabilization time becomes longer. The average peak permeability shows a “U‐shaped” trend, decreasing first and then increasing as the steam temperature increases. Meanwhile, with the extension of steam injection time, the axial, radial, and volumetric strains of coal show a stage‐wise expansion characteristic at different temperatures of steam injection, except for the radial strains at 151.11°C. A two‐phase flow theory of gas–liquid is adopted to elucidate the mechanism of pulsating seepage of steam. Moreover, the influencing mechanism of inward and outward thermal expansion on the permeability of coal is interpreted. The results presented in this paper provide new insight into the feasibility of thermal gas recovery by steam injection.

Modelling of flue gas injection and collaborative optimization of multi-injection parameters for efficient coal-based carbon sequestration combined with BP neural network parallel genetic algorithms

Cooperative equalization among the injection parameters can control the economic objective function to ensure the efficiency of gas-mixture-enhanced coalbed methane recovery (GM-ECBM). This study first proposed and validated a refined thermal-hydro-mechanical-chemical (THMC) coupling model with a convenient permeability model. Based on GM-ECBM numerical calculation results under different combinations of injection parameters, different types of cost-income objective functions, including different costs and incomes, were optimized by parallelly applying a genetic algorithm and backpropagation neural network (GA-BP). Using the recovery rate as the index, a small inter-well distance and a large injection pressure can increase the optimal CO2 proportion. The effectiveness of enhancing the injection temperature was significantly correlated with both inter-well distance and the injection pressure. Cooperative equalization among the injection parameters can explain different viewpoints of different scholars on the temperature effect. Large Henry’s law constants resulted in low carbon sequestration and coalbed methane (CH4) production but did not affect the optimal CO2 proportion. High carbon sequestration and CH4 prices corresponded to small inter-well distances and large injection pressure. Based on the objective function, the optimal inter-well distance and the injection temperature were 175–220 m and 305.5–311.5 K, respectively. The volumetric adsorption-induced expansion coefficient (VAEC) of CO2 determined the optimal CO2 proportion, the optimization feasibility of the injection scheme, and the applicability of GM-ECBM.

Migration characteristics of constant elements in the process of coal dissolution by liquid CO2

The effect of liquid CO2 on coal dissolution plays a key role in improving coal bed methane (CBM) recovery and CO2 geological storage. In order to study the effect of liquid CO2–H2O reaction on the migration of mineral constant elements in coal, three kinds of coal samples (lignite, bituminous coal, and anthracite) with different degrees of metamorphism were selected as the research objects. The one-factor experiments of dissolution of liquid CO2 and water-bearing coal samples were carried out by simulating the temperature and pressure of the stratum. X-ray fluorescence spectroscopy (XRF) was used to test the changes in the relative content of constant elements in coal samples after liquid CO2 injection under different pressure conditions. Scanning electron microscopy (SEM) was utilized to observe the evolution pattern of the surface features of the coal before and after the dissolution of liquid CO2. A quantitative analysis of coal pore development characteristics was conducted based on low-temperature N2 adsorption/desorption experiments, and isothermal adsorption experiments were carried out before and after etching the coal samples to understand the adsorption characteristics of CH4 and CO2 by coal under different pressure conditions. The research results indicated that the migration ability of constant elements in coal showed a trend of first decreasing and then increasing with the increasing degree of coal metamorphism. Among the three selected coal samples, the migration ability of constant elements was found to be strongest in anthracite, followed by lignite and bituminous coal. Most of the element migration in coal was carried out through chemical reactions (hydrolysis, carbonation, redox), while some elements were primarily transported through physical means (such as the low-temperature impact of liquid CO2). The dissolution process expands the original pore space of coal and generates new pores, greatly increasing the coal's capacity for CO2 adsorption. These findings deepen our understanding of mineral dissolution in coal by liquid CO2 and provide important insights for achieving efficient and long-term coalbed CO2 geological storage and enhanced methane recovery techniques.

Decoding wettability in coal-water-CO2 system for enhanced sequestration security

The injection of CO2 into deep unminable coal seam is a most promising carbon storage method that can simultaneously achieve the dual objectives of mitigating CO2 emission and enhancing coalbed methane recovery. In this context, the wettability of the coal-water-CO2 system plays an important role in the CO2 injection rate, storage capacity, and sequestration security. However, the factors affecting wettability alternation in the coal-water-CO2 system are still unclear until now. In this study, the sessile drop method was used to measure the contact angle (CA) in the coal-water-CO2 system under different pressures (3 – 8 MPa) and temperatures of (40–70 °C) with four different rank coals. Results indicate that with increasing pressure, the CA shows a steady increase below 5 MPa followed by a rapid increase at 5 – 8 MPa. The CA decreases with increasing temperature and coal rank. The CA is negatively correlated with the mes- and macro-pores, but positively correlated with micropores. It was found that these relationships are attributed to the CO2 density and CO2 adsorption capacity of coal. As the CO2 density increases, the coal-CO2 interaction force intensifies, leading to a tendency towards CO2 wetting for the coal-water-CO2 system. The adsorption capacity illustrates the strength of the coal-CO2 interaction, where the affinity of polar adsorption sites for CO2 molecules exceeds that of nonpolar adsorption sites. Finally, we conducted a comprehensive assessment of the wettability of the coal-water-CO2 system as it varies with burial depth by developing an integrated model that considers four influential factors, including pressure, temperature, coal rank, and pore structure. The findings of this study can be utilized to determine the optimal CO2 injection pressure in CO2-ECBM projects and enhance sequestration safety.

Experimental simulation of water-coal interactions during liquid CO2 injection into coal beds

Injection of liquid CO2 (LCO2) into coal reservoirs is an extremely effective way to enhance coalbed methane recovery and storage. This study aimed to investigate the changes in mineral composition and content during the chemical reaction between coal samples and weakly acidic fluids dissolved in LCO2. Therefore, in this study, simulating the formation temperature (30 °C), three types of coal samples with different metamorphic degrees (lignite, anthracite, and bituminous coal) were selected for CO2–H2O-coal interaction leaching experiments under various pressure conditions (1 MPa, 3 MPa, 5 MPa). X-ray diffraction analysis (XRD) was used to test coal samples' mineral composition and content before and after LCO2 injection under different pressure conditions. Scanning Electron Microscope (SEM) was used to observe the evolution pattern of surface characteristics before and after the dissolution of the coal body by LCO2. The results showed that minerals such as kaolinite, illite, quartz, and potassium feldspar in the three coal samples underwent mineral transformation during the reaction process at different dissolution pressures, and the content changed significantly in the early stage of the reaction. The initial content of kaolinite in the bituminous coal (16.5%) increased to 23.8%, 26.7%, and 25.2% respectively under different leaching pressures of 1 MPa, 3 MPa, and 5 MPa. Carbonate minerals dissolved rapidly in the initial stages of the reaction, the initial content of calcite, a carbonate mineral in the anthracite (9.8%), decreased to 4.2%, 3.8%, and 2.4% respectively under different leaching pressures of 1 MPa, 3 MPa, and 5 MPa. Similarly, the initial content of siderite decreased from 6.8% to 2.8%, 2.3%, and 1.6% respectively. LCO2 pressure had a significant influence on the reaction. These results advance our understanding of LCO2 dissolution of minerals in coal.

High-Pressure adsorption of supercritical methane and carbon dioxide on Coal: Analysis of adsorbed phase density

The occurrence of supercritical CH4 and CO2 in coal is significant for both coalbed methane recovery and CO2 storage. Adsorption isotherms of CH4 and CO2 on two coals have been measured at three temperatures up to pressures of 25 MPa. Three modified supercritical adsorption models (SL-V, SBET-V, and SDR-V) were used to describe the excess adsorption behavior, with the pressure-independent adsorbed phase volume being considered. The adsorbed phase density (APD) and absolute adsorption amount were calculated based on the modified models and compared with those estimated by previous models. The results indicate that SDR-V is the most suitable for CH4 adsorption due to the dominant role of filling of micropores by CH4, while SBET-V is the most appropriate model for CO2 adsorption because of multilayer adsorption of CO2 in both micropores and meso-macropores. The APD increases with pressure until reaching a maximum value but decreases as temperature increases following a Langmuir-style trend. The previous models, which use a fixed APD, seriously underestimate the absolute adsorption, the extent of which increases with increasing pressure and temperature, leading to significant errors in deep formations with high temperature and pressure conditions. Furthermore, as burial depth increases, the adsorption process can be divided into three stages based on changes in APD and free phase density (FPD). These findings contribute to a comprehensive understanding of the behavior and occurrence of CH4 and CO2 within deep coal seams, enhancing the applicability of CO2-ECBM (CO2 Geological Storage Enhanced Coalbed Methane Recovery).

Macromolecular insight into the adsorption and migration properties of CH4/CO2/N2 in bituminous coal matrix under uniaxial strain loading

Gas adsorption–migration in coal is of crucial importance for coalbed methane (CBM) recovery; however, the effect of coal deformation on it is not yet very clear, especially at the molecular level. In this study, the effects of uniaxial tension–compression strains on the CH4/CO2/N2 adsorption–migration characteristics in bituminous coal matrix were investigated by integrating the grand canonical Monte Carlo and molecular dynamics methods. The results show that the dual-mode equation fits the isothermal adsorption results, and the adsorption concentration and Langmuir volume are positively correlated with strain. Tension strain has a small effect on a thermodynamic factor but a large effect on Henry constant. In addition, the swelling resistance of coal matrix is positively correlated with tension strain which has a greater impact on the shear resistance of coal matrix containing CO2. The average mass density of the gas is linearly positively correlated with strain that has a large impact on N2 stability. More significantly, the self-diffusion coefficient (Ds) of CH4 is larger than that of CO2/N2, and the relationship between Fick diffusion coefficient and strain is roughly similar to that between Ds and strain. Also, the mass transfer of CO2 permeation is more significant compared to N2, especially for tension strain. These research results provide a basis for the optimization design of CBM recovery in deformed coal reservoirs.

Modeling and coupling analysis of enhanced coalbed methane recovery by gas injection

AbstractEnhanced coalbed methane (ECBM) recovery by gas injection is regarded as a feasible method for ECBM recovery. To investigate the mechanism of CH4 displacement by N2 injection, a series of physical experiments were conducted in the laboratory under different N2 injection pressures. The experimental results showed a continuous increase in the N2 volume fraction and a decrease in the CH4 volume fraction with the N2 injection pressure. The CH4 displacement efficiency increases rapidly in the initial stage and then gradually stabilizes. Given the effect of matrix shrinkage and effective stress on coal permeability, a dynamic multi‐field coupling model of ECBM recovery by N2 injection (N2‐ECBM) was proposed in this work. Then, numerical simulations were implemented by the coupling model to analyze the key factors affecting coal permeability, N2 injection pressure and CH4 pressure during the N2–ECBM process. Furthermore, the Response Surface Methodology (RSM) was used to investigate the interactions of multiple factors, the results reveal that an increase in one factor would weaken the influence of another factor. In addition, a RSM regression model was obtained and verified by the experimental data, with a well‐fitting outcomes. Therefore, the RSM model can be used in practical engineering applications to optimize specific extraction parameters for ECBM recovery at minimum cost in a limited extraction period.

Influence of Imbibition Fracturing Fluid on the Original Water and Methane Occurrence in Actual Coalbed Methane Reservoirs Using the Integrated Device of Displacement and Low-Field Nuclear Magnetic Resonance.

The original water in the coal rock pores plays a controlling role in the occurrence of gas. Furthermore, during the hydraulic fracturing process, pressurized fracturing fluid with a higher pressure than the original pore pressure in the fractures drives the fracturing fluid to infiltrate into the coal rock pores, thereby altering the occurrence pattern of gas and water in the original pores. However, due to the limitations of the indoor simulation device, a systematic conclusion on the impact of the original pore water and imbibition fracturing fluid on coalbed methane reservoirs has not yet been formed. In this paper, an integrated device combining displacement and low-field nuclear magnetic resonance was employed using underground cylindrical coal rock samples as experimental subjects. Experimental conditions were maintained at a temperature of 30 °C, a confining pressure of 23 MPa, and an approximate reservoir pressure of 15 MPa. The initial water saturation levels were altered to 0, 27.88, and 42.18% to replicate the conditions of a coalbed methane reservoir at a depth of approximately 1200 m. Fracturing fluid with a pressure of 18 MPa was injected into the experimental samples to simulate the impact of the fracturing fluid on the original reservoir during hydraulic fracturing. This allowed for a realistic assessment of the influence of initial water saturation and fracturing fluid absorption on the coalbed methane recovery rate in the reservoir. The experimental results indicate that the imbibition process promotes the desorption of adsorbed gas, and the desorption amount of adsorbed gas increases with the increase in the original water saturation. This will result in an increase in the gas pressure within the pore system. The conditions of this experiment, in comparison to the previous ones, more closely resemble real reservoir conditions. This enables a realistic assessment of how the presence of the original water content and the absorption of the fracturing fluid affect gas occurrence within the reservoir.

Effects of CO2 injection pressure and confining pressure on CO2-enhanced coalbed methane recovery: Experimental observations at various simulated geological conditions

Systematic understanding of the characteristics of fluid transport and occurrence in conventional Coalbed Methane (CBM) recovery and Injecting CO2 enhancing CBM recovery (CO2-ECBM) engineering plays an essential role in improving the recovery rate of CBM and mitigating the greenhouse effect. In this study, the displacement adsorption time, fluid flow rate and cumulative fluid flow rate of different coal rank samples under conventional and CO2 injection conditions were obtained. The efficiency of exchange adsorption was evaluated based on sweep efficiency and displaced volume. It is found that: (a) In conventional CBM recovery, there is no good correlation between the CBM recovery amount and the gas adsorption capacity of different coal rank samples, but CO2 injection can effectively improve the CBM recovery amount of coal reservoir. (b) In CO2-ECBM, the overall flow rate of the mixed gas decreases rapidly in the initial stage, and then when CO2 is detected at the end, the flow rate of the mixed gas gradually increases and becomes stable until the displacement is completed. (c) Due to the fluid velocity sensitivity effect of coal reservoirs, excessive CO2 injection pressure will have a negative effect on sweep efficiency, but confining pressure will weaken this negative effect. (d) Confining pressure changes the pore-fracture structure of coal reservoirs, strongly influencing conventional CBM recovery. However, it does not change the gas occurrence mechanism in the coal reservoir, it only causes a larger number of gas molecules in the coal matrix instead of the pores, which has little influence on the effectiveness parameters of CO2-ECBM. This research is of great significance for the systematic understanding of the occurrence mechanism of multiple fluids in coal reservoirs, the safe and efficient development of CBM resources, and the realization of carbon neutrality.

Microwave irradiation-induced alterations in physicochemical properties and methane adsorption capability of coals: An experimental study using carbon molecular sieve

In order to comprehend the applicability of microwave irradiation for recovering coalbed methane, it is necessary to evaluate the microwave irradiation-induced alterations in coals with varying levels of metamorphism. In this work, the carbon molecular sieve combined with KMnO4 oxidation was selected to fabricate carbon molecular sieve with diverse oxidation degrees, which can serve as model substances toward coals. Afterwards, the microwave irradiation dependences of pores, functional groups, and high-pressure methane adsorption characteristics of model substances were studied. The results indicated that microwave irradiation causes rearrangement of oxygen-containing functional groups, which could block the micropores with a size of 0.40–0.60 nm in carbon molecular sieve; meanwhile, naphthalene and phenanthrene generated by macro-molecular structure pyrolysis due to microwave irradiation could block the micropores with a size of 0.70–0.90 nm. These alterations in micropore structure weaken the saturated methane adsorption capacity of oxidized carbon molecular sieve by 2.91%–23.28%, suggesting that microwave irradiation could promote methane desorption. Moreover, the increased mesopores found for oxidized carbon molecular sieve after microwave irradiation could benefit CH4 diffusion. In summary, the oxidized carbon molecular sieve can act as model substances toward coals with different ranks. Additionally, microwave irradiation is a promising technology to enhance coalbed methane recovery.

Dynamic gas liberation from water-immersed anthracite coal with varying wetting states under heating conditions: Unveiling the gas breakthrough phenomena

During coalbed methane recovery, the effective extraction of gas trapped in narrow pore throats encounters challenges due to the water blocking effect. To shed light on this phenomenon during thermal recovery of coalbed methane, this study investigated the breakthrough behaviors of CO2 traversing through a 0.2 mm diameter hole in water-immersed anthracite coal at varying temperatures (23 °C, 40 °C, and 60 °C). The measurements of breakthrough pressure (defined as the pressure at which the bubble achieves a semi-spherical shape with a minimum curvature radius), growth characteristics of CO2 bubbles, and coal wettability were conducted under varying thermal conditions and water immersion durations. The results showed that the breakthrough pressure initially increased continuously as water immersed into the coal and then gradually stabilized. During this process, the coal's water wettability increased, leading to a decrease in the diameter of the bubble's three-phase contact line, which in turn affected the breakthrough pressure. Moreover, higher temperatures accelerated the rate of water immersion, augmenting the coal's hydrophilicity. The elevated temperature also resulted in a decrease in water surface tension, consequently contributing to a lower breakthrough pressure. Interestingly, compared to CO2, He exhibited a faster increase in breakthrough pressure during water immersion. This disparity can be attributed to He's superior diffusion capacity and lower viscosity, enabling a swifter transformation of the coal's wetting state during water imbibition. This study revealed the dual mechanism of heating to reduce gas breakthrough pressure, as well as the effects of surface water content and gas properties. These findings highlight potential benefits of thermal treatment on coalbed methane recovery and provide valuable insights for its exploitation under different geological conditions.

Nonlinear Seepage Mechanism and Evolution Law of CO2 Enhancing Coalbed Methane Recovery

China’s coal seam permeability is low, and the original coal seam gas extraction is difficult. CO2 displacement of coal seam CH4 technology is an effective gas extraction technology. CO2 is injected into the coal seam under pressure, and competitive adsorption occurs with CH4 in the pores. The gas composition is nonuniformly distributed, and its viscosity μ is the dynamic parameter. As the gas is compressible, the pressure drops, and migration distance does not satisfy a linear relationship. Therefore, the gas transport does not conform to Darcy’s law. The mass transfer process and a multicomponent gas competitive adsorption were investigated theoretically and experimentally. The adsorption characteristics and gas compressibility determine the distribution of the gas components in pores and change the gas dynamic viscosity in different regions. The change in the gas dynamic viscosity in the channel is the direct reason for the nonlinear pressure gradient and gas flow curve. The permeability and gas component affect the degree of nonlinear deviation of the gas flow and pressure gradient curve. This affects the nonlinear deviation degree of the curve by changing the gas dynamic viscosity in the pore channel during displacement. The reasonable displacement pressure is the critical pressure (PO) through experimental and theoretical analysis.

Sustainability evaluation of a PEMFC system for coalbed methane recovery based on life cycle assessment and emergy analysis

To promote the sustainable development of clean energy, a novel integrated system coupled coalbed methane recovery and proton exchange membrane fuel cell (PEMFC) is developed. Life cycle assessment (LCA) and emergy analysis model are established to analyze sustainability of the proposed system. The parametric analysis is performed to assess the effects of the reforming temperature, steam carbon ratio and current density on the emergy performance. The LCA results indicate that the construction phase has the most significant impact on system sustainability, accounting for 51.65%. Reducing the use of stainless steel and copper in the construction phase and improving the recycling process in the recovery phase can help improve the sustainability performance. The emergy analysis results show that the total emergy consumption of the system is 8.53E+16, the use phase accounted for 55.8%, the construction phase accounted for 43.8%, and the recovery phase only accounted for 0.4%. Parametric analysis shows that the emergy savings ratio increases by 7.11% as the reforming temperature is 800 °C. The emergy sustainability index ranges from 3.04 to 4.45 with great sustainability performance, as the increase of steam carbon ratio. The system has low environmental load and high sustainability when the current density is close to 1. This research will help improve the sustainability evaluation system of the energy system and promote the sustainable development of clean energy.

N2 injection to enhance gas drainage in low-permeability coal seam: A field test and the application of deep learning algorithms

N2 injection to enhance coal seam gas drainage is an effective technology for coalbed methane recovery. Nevertheless, there is a limited body of research addressing the application of ECBM technology for gas management in low permeability coal seams within underground coal mines, and the effect is uncertain. Additionally, numerical simulators have been challenged to accurately predict methane emissions during gas injection and replacement. In this study, firstly, an underground field trials of N2 injection replacement in a coal mine with low-permeability coal seams in China were conducted, and a comparative analysis of “N2 injection to enhance gas drainage” and “conventional drainage” technique was performed. The result show that injecting pressurized N2 into a low-permeability coal seam could increase the pressure gradient to promote the directional flow of free gas from the coal seam cracks to the gas-production boreholes. After N2 injection, the mixed flow rate and CH4 flow rate significantly increased. Additionally, the gas content in the coal seam in the experimental area significantly decreased. Secondly, the lag-effect was discussed. Upon discontinuation of N2 injection, the gas-producing mixed flow initially increased slightly, then gradually decreased, and eventually settled at a high level. Despite the attenuation of N2 injection volume, the CH4 flow rate continued to increase during intermittent injection and remained high after gas injection discontinuation. Finally, three deep learning algorithms (BP, LSTM, and TCN) were employed to predict the dynamic change of gas drainage in coal seams displaced by N2 injection, based on the results of the field test. The results indicated that deep learning algorithms exhibited superior prediction performance. The TCN model demonstrated the lowest approximation error rate, displaying optimal performance in predicting the CH4 flow rate during nitrogen injection for enhanced gas drainage. Additionally, it exhibited good applicability to other similar field test results.

Modeling of methane and carbon dioxide sorption capacity in tight reservoirs using Machine learning techniques

The viability of enhanced coalbed methane recovery (ECBM) and enhanced shale gas recovery (ESGR) are abundantly explored in various studies since they present a solution for ongoing energy demand and environmental crisis. As a matter of challenge, the prediction of the gas sorption profile poses a significant obstacle in the development of such resources. In this regard, mathematical models, numerical simulations, empirical correlations, and experimental measurements suffer from over-simplification, computationally extensive calculations, time-consuming, and costly processes. This work examines different machine learning methods, from shallow to deep learning, to investigate their capability to model 3804 data points of methane (CH4) and/or carbon dioxide (CO2) sorption capacity in shale and coal at different thermodynamic conditions. Percentage of CO2 in injection gas, rock type, total organic carbon (TOC), moisture, temperature, and pressure were taken as input. Hyperparameter tuning was executed by Optuna optimizer. According to the results, the random forest (RF) was the most proficient predictor for both test subsets of CH4 (MAE = 0.0864, MSE = 0.0231, RMSE = 0.1520) and CO2 (MAE = 0.0529, MSE = 0.0533, RMSE = 0.2308) sorption capacity. Based on the trend prediction simulation, RF predictors were able to properly capture the single and binary sorption capacities. More importantly, they successfully predict the abnormal descending behavior of CO2 sorption in high pressures. In addition, a sensitivity analysis was carried out to acquire the importance of input features and model hyperparameters in the training process. Input feature impacts were consistent with technical expectations of geology and reservoir engineering aspects. Both models are capable of being applied to lab scale and further developed for their application in reservoir scale simulators.

Permeability evolution of deep-buried coal based on NMR analysis: CO2 adsorption and water content effects

Permeability evolution of deep-buried coal plays a crucial role in CO2 geological storage and coalbed methane (CBM) recovery. In this study, permeability and nuclear magnetic resonance (NMR) tests were conducted on coal specimens under triaxial conditions. Based on the evolution of relaxation time (T2), the effects of CO2 adsorption and water content on permeability, pore structure, and mechanical properties of coal were discussed. Experimental results show that CO2 injection causes adsorption-induced swelling, inhibits flow in the early stage, causes the “expansion” and “complexity” of pore structure, and generates new channels for fluid transport. The presence of water in coal inhibits the flow process, resulting in an overall reduction of permeability by 2 orders of magnitude. Softening occurs in coal specimens, as evidenced by plasticity and low brittle failure and an average strength loss of 29.3 %. Additionally, a complex CO2–H2O coupling effect in coal is observed, causing the dissolution of certain minerals and organic matter, which further amplifies the “weakening effect” of water. Finally, permeability evolution characteristics of coal affected by CO2 and H2O from multiple perspectives were discussed in consideration of NMR fractal analysis. This work provides valuable insights into deep CO2 geological sequestration and CBM recovery.

Exergy, economic, exergoeconomic and environmental (4E) analyses and multi-objective optimization of a PEMFC system for coalbed methane recovery

Exergy, economic, exergoeconomic and environmental (4E) analyses and multi-objective optimization of a PEMFC system for coalbed methane recovery

Investigation of the smashing characteristics induced by energy distribution of CO2 BLEVE for coalbed methane recovery

Failure in the near field of coal by liquid CO2 phase transition blasting (LCO2-PB) is the major reason for fracturing performance and enhancing coalbed methane (ECBM) recovery. Features to clarify this failure are of significant importance for the field projects. Some studies have revealed that the energy of LCO2 releasing can determine the damage feature to some extent. This study was therefore initiated to investigate the effect of BLEVE energy on the fracturing performance of LCO2-PB in coal. A series of LCO2-PB fracturing tests was carried out on hard and soft coal to examine the effect of CO2 BLEVE energy on fracture morphology. It was obtained that, compared with fractal dimension of hard coal under lower import energy (623.48 kJ) is around 2.17, the higher import energy (831.36 kJ) provides a larger fractal dimension (2.32), especially for high rupture pressure (95 MPa), which make fragments smash into a smaller radial. Although higher input energy favours a large superfluous energy density for any coal types, soft coal represents a stronger tendency to fracture in the stress drop stage. Lower input energy in hard coal seam products a longer main fracture, and excellent fracturing in soft coal prefers the higher import energy.

Experimental investigation of gas diffusion kinetics and pore-structure characteristics during coalbed methane desorption within a coal seam

The desorption-diffusion properties of coalbed methane (CBM) are not only the theoretical basis for investigating gas outburst hazards in a coal mine, but also impose a non-negligible impact on CBM recovery performance. In this paper, the pore structure of coal with five different metamorphism degrees was qualitatively and quantitatively characterized with the scanning electron microscopy (SEM) and low-temperature nitrogen gas adsorption (LTNGA) measurements. The isothermal methane ad/desorption experiments were performed with four initial gas desorption pressure scales. Subsequently, the matching degree between eight empirical correlations (ECs) and the measured methane desorption data was determined, and the methane diffusion coefficient (Dfg) was numerically calculated combining with an FGDG (free gas density gradient) diffusion model. Importantly, we evaluated and discussed the sensitivity of pore structure parameters, initial gas desorption pressure, and volatile fraction to Dfg. The results show that pore density distribution differs among coal samples and the pore structure, especially the micropores, is developed better in high-rank coals than in low- and medium-rank ones. Initial gas release velocity increases with an increase in coal rank and decreases negatively with the increasing particle size in an exponential manner. Among the eight ECs, EC-VIII can be applied to more accurately describe gas desorption process during the whole time scale, and its correlation coefficient with the measured data is larger than 0.9900. Dfg increases with an increase in pore volume and specific surface area (SSA), and it is negatively correlated with the average pore diameter. Additionally, Dfg exhibits an asymmetric U-shaped pattern with an increase in the volatile fraction, which is mainly related to the switch between the dominant roles of mesopores and micropores during coal metamorphism. At a lower volatile fraction, the diffusion coefficient is more sensitive to micropores, while, at a higher volatile fraction, mesopores contribute more to the diffusion coefficient.