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Chen, Liwei, Mingzhen Zhao, Xiaohua Li, and Yuan Liu. "Impact research of CH4 replacement with CO2 in hydrous coal under high pressure injection." Mining of Mineral Deposits 16, no. 1 (March 30, 2022): 121–26. http://dx.doi.org/10.33271/mining16.01.121.
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Purpose. Based on high-pressure gas injection technology that enhances coal seam gas drainage, the effect of CH4 replacement with CO2 in aquiferous coal has been studied. Methods. Using the laboratory experimental method and the self-built high-pressure gas injection experimental device, high-pressure CO2 is injected into coal with different moisture contents to replace CH4 under different adsorption equilibrium pressures. Findings. With an increase in coal moisture content, the adsorption capacity of coal for CH4 and CO2 gradually weakens, the adsorption capacity for CO2 is always greater than that of CH4, and the CH4 replacement rate and the CO2 injection ratio gradually decrease. It is concluded that the CH4 replacement rate and the CO2 injection ratio are negatively correlated with the water content of coal. With an increase of the pre-adsorption equilibrium CH4 pressure (0.5, 0.75, 1.0, 1.3 and 2.0 MPa), the CH4 replacement rate and the CO2 injection ratio first sharply and then slowly increase. The transition point is 1.3 MPa (pre-adsorption equilibrium pressure of CH4). Originality. Based on the adsorption characteristics of coal seam gas injection, the influence of coal water content and gas injection pressure on CH4 replacement rate and CO2 injection ratio is analyzed, and the mechanism is studied. Practical implications. The experimental results have important guiding significance for selecting reasonable gas injection pressure and the source of gas to drive its injection into underground coal seam.
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Vermesse, J., D. Vidal, and P. Malbrunot. "Gas Adsorption on Zeolites at High Pressure." Langmuir 12, no. 17 (January 1996): 4190–96. http://dx.doi.org/10.1021/la950283m.
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Giacobbe, F. W. "A high‐pressure volumetric gas adsorption system." Review of Scientific Instruments 62, no. 9 (September 1991): 2186–92. http://dx.doi.org/10.1063/1.1142336.
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Jia, Bao, Jyun-Syung Tsau, and Reza Barati. "Different Flow Behaviors of Low-Pressure and High-Pressure Carbon Dioxide in Shales." SPE Journal 23, no. 04 (May 30, 2018): 1452–68. http://dx.doi.org/10.2118/191121-pa.
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Summary Understanding carbon dioxide (CO2) storage capacity and flow behavior in shale reservoirs is important for the performance of both CO2-related improved oil recovery (IOR) and enhanced gas recovery (EGR) and of carbon sequestration. However, the literature lacks sufficient experimental data and a deep understanding of CO2 permeability and storage capacity in shale reservoirs under a wide range of pressure. In this study, we aimed to fill this gap by investigating and comparing CO2-transport mechanisms in shale reservoirs under low- and high-pressure conditions. Nearly 40 pressure-pulse-transmission tests were performed with CO2, helium (He), and nitrogen (N2) for comparison. Tests were conducted under constant effective stress with multistage increased pore pressures (0 to 2,000 psi) and constant temperature. The gas-adsorption capacity for CO2 and N2 was measured in terms of both Gibbs and absolute adsorption. Afterward, the gas apparent permeability was calculated incorporating various flow mechanisms before the adsorption-free permeability was estimated to evaluate the adsorption contribution to the gas-transport efficiency. The results indicate that He permeability is the highest among the three types of gas, and the characteristic of CO2 petrophysical properties differs from the other two types of gas in shale reservoirs. CO2 apparent porosity and apparent permeability both decline sharply across the phase-change region. The adsorbed phase significantly increases the apparent porosity, which is directly measured from the pulse-decay experiment; it contributes positively to the low-pressure CO2 permeability but negatively to the high-pressure CO2 permeability.
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Ekundayo, Jamiu M., Reza Rezaee, and Chunyan Fan. "Measurement of gas contents in shale reservoirs – impact of gas density and implications for gas resource estimates." APPEA Journal 61, no. 2 (2021): 606. http://dx.doi.org/10.1071/aj20177.
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Gas shale reservoirs pose unique measurement challenges due to their ultra-low petrophysical properties and complicated pore structures. A small variation in an experimental parameter, under high-pressure conditions, may result in huge discrepancies in gas contents and the resource estimates derived from such data. This study illustrates the impact of the equation of state on the gas content determined for a shale sample. The gas content was determined from laboratory-measured high-pressure methane adsorption isotherms and theoretically described by a hybrid type model. The modelling involved the use of the Dubinin–Radushkevich isotherm to obtain the adsorbed phase density followed by the Langmuir isotherm to describe the resultant absolute adsorptions. Significant variations were observed in measured adsorption isotherms due to the variations in gas densities calculated from different equations of states. The model parameters and the gas in-place volumes estimated from those parameters also varied significantly.
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Hu, Ke, and Helmut Mischo. "Absolute adsorption and adsorbed volume modeling for supercritical methane adsorption on shale." Adsorption 28, no. 1-2 (February 2022): 27–39. http://dx.doi.org/10.1007/s10450-021-00350-8.
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AbstractAdsorbed methane significantly affects shale gas reservoir estimates and shale gas transport in shale formations. Hence, a practical model for accurately representing methane adsorption behavior at high-pressure and high-temperature in shale is imperative. In this study, a reliable mathematical framework that estimates the absolute adsorption directly from low-pressure excess adsorption data is applied to describe the excess methane adsorption data in literature. This method provides detailed information on the volume and density of adsorbed methane. The obtained results indicate that the extensively used supercritical Dubinin-Radushkevich model with constant adsorbed phase density underestimates absolute adsorption at high pressure. The adsorbed methane volume increases both the pressure and expands with the temperature. The adsorbed methane density reduces above 10 MPa, and approaches a steady value at high pressure. This study provides a novel method for estimating adsorbed shale gas, which is expected improve the prediction of shale gas in place and gas production.
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Liu, Zhen, Qingbo Gu, He Yang, Jiangwei Liu, Guoliang Luan, Peng Hu, and Zehan Yu. "Gas–Water Two-Phase Displacement Mechanism in Coal Fractal Structures Based on a Low-Field Nuclear Magnetic Resonance Experiment." Sustainability 15, no. 21 (October 30, 2023): 15440. http://dx.doi.org/10.3390/su152115440.
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In this paper, the gas–water two-phase seepage process under a real mechanical environment is restored by a nuclear magnetic resonance experiment, and the gas–water two-phase distribution state and displacement efficiency in coal with different porosity under different gas injection pressures are accurately characterized. The fractal dimension of liquid phase distribution under different gas injection pressures was obtained through experiments, and the gas–water two-phase migration law is inverted according to it. Finally, the gas–water two-phase migration mechanism inside the fractal structure of coal was obtained. The results are as follows: 1. Gas will first pass through the dominant pathway (the composition of the dominant pathway is affected by porosity) and it will continue to penetrate other pathways only when the gas injection pressure is high. When the gas injection pressure is low, the displacement occurs mainly in the percolation pores. With the increase in gas injection pressure, the focus of displacement gradually shifts to the adsorption pore. 2. As the gas injection pressure increases, the displacement efficiency growth rate is relatively uniform for the high-porosity coal samples, while the low-porosity coal samples show a trend of first fast and then slow growth rates. When the gas injection pressure reaches 7 MPa, the displacement efficiency of high-porosity coal samples exceeds that of low-porosity coal samples. 3. With the increase in gas injection pressure, the fractal dimension of the adsorption pore section and the seepage pore section shows an increasing trend, but the fractal dimension of the adsorption pore section changes faster, indicating that with the increase in gas injection pressure, gas–water two-phase displacement mainly occurs in the adsorption pore section.
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Wynnyk, Kyle G., Behnaz Hojjati, Payman Pirzadeh, and Robert A. Marriott. "High-pressure sour gas adsorption on zeolite 4A." Adsorption 23, no. 1 (November 18, 2016): 149–62. http://dx.doi.org/10.1007/s10450-016-9841-6.
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Guo, Wenjing, Jie Liu, Fan Dong, Ru Chen, Jayanti Das, Weigong Ge, Xiaoming Xu, and Huixiao Hong. "Deep Learning Models for Predicting Gas Adsorption Capacity of Nanomaterials." Nanomaterials 12, no. 19 (September 27, 2022): 3376. http://dx.doi.org/10.3390/nano12193376.
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Metal–organic frameworks (MOFs), a class of porous nanomaterials, have been widely used in gas adsorption-based applications due to their high porosities and chemical tunability. To facilitate the discovery of high-performance MOFs for different applications, a variety of machine learning models have been developed to predict the gas adsorption capacities of MOFs. Most of the predictive models are developed using traditional machine learning algorithms. However, the continuously increasing sizes of MOF datasets and the complicated relationships between MOFs and their gas adsorption capacities make deep learning a suitable candidate to handle such big data with increased computational power and accuracy. In this study, we developed models for predicting gas adsorption capacities of MOFs using two deep learning algorithms, multilayer perceptron (MLP) and long short-term memory (LSTM) networks, with a hypothetical set of about 130,000 structures of MOFs with methane and carbon dioxide adsorption data at different pressures. The models were evaluated using 10 iterations of 10-fold cross validations and 100 holdout validations. The MLP and LSTM models performed similarly with high prediction accuracy. The models for predicting gas adsorption at a higher pressure outperformed the models for predicting gas adsorption at a lower pressure. The deep learning models are more accurate than the random forest models reported in the literature, especially for predicting gas adsorption capacities at low pressures. Our results demonstrated that deep learning algorithms have a great potential to generate models that can accurately predict the gas adsorption capacities of MOFs.
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Cheng, De Zhu, Ai Ling Du, and Ai Qin Du. "The Influence of Coal Adsorbing Methane and Carbon Dioxide on Gas Outburst." Advanced Materials Research 1049-1050 (October 2014): 101–4. http://dx.doi.org/10.4028/www.scientific.net/amr.1049-1050.101.
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Methane and carbon dioxide of different pressures were absorbed by the anthracite coal for 5 hours in high pressure reactor. When adsorption experiment was completed, pressure is reduced quickly. The content of pulverized coal which was produced by releasing gas quickly, was used to reflect capacity of gas adsorption. The result showed that the content of pulverized coal which was produced by adsorbing CH4 was higher than that was produced by adsorbing CO2 on the same coal under the same pressure. Langmuir isotherm and Freundlich isothermal can describe coal methane adsorption. Freundlich isothermal can be a good description of coal carbon dioxide adsorption.
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Kasuya, F., and T. Tsuji. "High purity CO gas separation by pressure swing adsorption." Gas Separation & Purification 5, no. 4 (December 1991): 242–46. http://dx.doi.org/10.1016/0950-4214(91)80031-y.
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Cai, Hailiang, Peichao Li, Zhixin Ge, Yuxi Xian, and Detang Lu. "A new method to determine varying adsorbed density based on Gibbs isotherm of supercritical gas adsorption." Adsorption Science & Technology 36, no. 9-10 (October 9, 2018): 1687–99. http://dx.doi.org/10.1177/0263617418802665.
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In the calculation of the absolute adsorption of supercritical gas adsorbed on the microporous materials, most existing methods regard the adsorbed density as a constant, which is very unreasonable. In this study, an extended pressure point method combined with Langmuir adsorption model is proposed in which the varying adsorbed density under different pressures is considered at the same time. The utility of the proposed method to correlate accurately the experimental data for supercritical gas adsorption system is demonstrated by high-pressure methane adsorption measurements on two groups of shale samples. Taking advantage of the proposed method, we can obtain the adsorbed density and the adsorbed volume corresponding to different pressures. Compared with the conventional methods under the assumption of fixed and parameterized adsorbed density, the proposed method yields better fitting results with the experimental data. Our work should provide important fundamental understandings and insights into the supercritical gas adsorption system.
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Jing, Tongling, Chuanqi Tao, Yanbin Wang, Huan Miao, Mingyu Xi, Xingchen Zhao, and Haiyang Fu. "Energy Variation Features during the Isothermal Adsorption of Coal under High-Temperature and High-Pressure Conditions." Processes 11, no. 9 (August 23, 2023): 2524. http://dx.doi.org/10.3390/pr11092524.
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This paper aims to describe methane adsorption in coal under the conditions of high temperature and high pressure, as well as quantitatively decipher the change rule of energy in the isothermal adsorption process. The isothermal adsorption test was carried out with four groups of middle-rank coals from the Linxing area with different degrees of metamorphism. The impacts of the degree of deterioration of coal, temperature, and pressure on adsorption were analyzed with regard to the adsorption amount, adsorption potential, and adsorption space. Additionally, the energy change during the adsorption of methane by the coal was considered. The results show that the coal adsorption capacity hinges on the degree of deterioration of the coal, as well as the pressure and temperature. Additionally, the impact of temperature upon coal methane adsorption under depth conditions is highlighted. Like the adsorption space, the adsorption potential is an important parameter used to quantitatively characterize the adsorption ease and adsorption capacity; furthermore, the adsorption potential of millipores exceeds that of mesopores, as they are capable of offering a larger specific surface area for adsorption. The total decrease in the surface free energy during adsorption increases as the pressure increases; simultaneously, the increase rate is fast and then slow. The total decrease in the above-described free energy diminishes as the temperature escalates. Under the same pressure, the total decrease in the aforementioned free energy increases as the reflectance of the specular body of the coal increases. The decrease in the aforementioned free energy at each point of pressure lessens as the pressure grows; notably, when the pressure is comparatively low, the reduction is very fast. As the pressure escalates continuously, the decrease speed is slow. Regarding the effect of pressure and temperature upon adsorption, the adsorption gas volume of coal exists in a conversion depth from 1200 m to 1500 m; at the same time, the impact of pressure upon adsorption is dominant up to this depth. Additionally, beyond this depth, temperature gradually comes to have the greatest impact on adsorption.
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Wu, Xukun, Guangming Zhao, Youlin Xu, Xiangrui Meng, and Xiang Cheng. "Research on Adsorption and Desorption Characteristics of Gas in Coal Rock Based on Nuclear Magnetic Resonance Technology." Geofluids 2022 (May 16, 2022): 1–13. http://dx.doi.org/10.1155/2022/1277973.
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In order to explore the change characteristics of the adsorption and desorption performance of coal under high gas pressure, low-field nuclear magnetic resonance (LFNMR) technology was used to conduct experimental research on coal adsorption and desorption. The results show that (1) the T 2 spectrum distribution diagram shows adsorption peaks ( T 2 = 0.01 ms ~ 1 ms ) and free peaks ( T 2 = 5 ms ~ 1000 ms ); (2) with the increase of equilibrium pressure, the peak area of adsorbed methane gradually increased at first and then tended to equilibrium. The initial increase rate of free methane was slower than that of adsorbed methane, and the increase rate of free methane was faster in the later stage; (3) the relationship between the amount of adsorbed gas in the adsorption state of coal and the gas pressure conforms to the Langmuir equation. Taking the equilibrium pressure P = 8.7 MPa as the critical hysteresis pressure, it can be divided into two stages which are higher gas pressure (0.5~8.7 MPa) and high gas pressure (8.7~10.33 MPa); the amount of adsorbed gas in the free state has a linear relationship with the gas pressure, and there is no obvious hysteresis; (4) comparative analysis under the same experimental conditions, the mass of the adsorbed gas in the desorption process is greater than the mass of the adsorbed gas in the adsorption process, and there is basically no difference in the mass of the free gas.
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Salmachi, Alireza, and Manouchehr Haghighi. "Temperature effect on methane sorption and diffusion in coal: application for thermal recovery from coal seam gas reservoirs." APPEA Journal 52, no. 1 (2012): 291. http://dx.doi.org/10.1071/aj11021.
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Investigating the effects of in situ thermal treatment on coal seams requires adequate knowledge of gas sorption and its kinetics in coal at various temperatures. Methane sorption onto two Australian coal samples (high-volatile bituminous) at dry state and different temperatures was measured. Methane adsorption isotherms were measured at pressures up to 7 MPa by the gas adsorption manometric method. Adsorption isotherms data at two temperatures were used to investigate the effects of in situ thermal treatment on critical desorption pressure, ultimate gas recovery and the diffusion coefficient in coal. An increase of experimental temperature from 308 to 348 K resulted in a 50% reduction in the adsorption affinity of the coal sample and an insignificant reduction in the saturation capacity of the isotherms. At higher experimental temperatures, Langmuir isotherms exhibit downward shift with the initial gas content of the coal seam being constant, resulting in critical gas desorption pressure increase. According to the measured Langmuir isotherms at different temperatures, an increase in reservoir temperature by 1 K leads to a 2% and 1.2% increase in total recovery for the tested coal seams. Gas left in the coal seam at the abandonment pressure can only be recovered at a higher reservoir temperature. Diffusion coefficients of coal seam samples were calculated for different experimental temperatures. Fractional uptakes of the first coal sample show a good agreement with the results obtained using the unipore diffusion model with the diffusion coefficient to be 4.7 × 10–12 m2/s at 348 K. For the second coal sample, the unipore diffusion model fairly matches the uptake data. A bidisperse diffusion model was also applied to measure the adsorption kinetics of the second coal sample, resulting in an improved agreement with the experimental uptake data. Both coal samples exhibited a reduction of the diffusion coefficient with an increase in equilibrium pressure; this effect was more pronounced at equilibrium pressures below 0.045 MPa. It was observed that the diffusion coefficient change with pressure becomes flat at high pressures, with the pressure effect diminishing much faster at lower temperatures.
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Huang, Shijun, Yonghui Wu, Linsong Cheng, Hongjun Liu, Yongchao Xue, and Guanyang Ding. "Apparent Permeability Model for Shale Gas Reservoirs Considering Multiple Transport Mechanisms." Geofluids 2018 (June 4, 2018): 1–18. http://dx.doi.org/10.1155/2018/2186194.
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Shale formation is featured in nanopores and much gas adsorptions. Gas flow in the shale matrix is not a singular viscous flow, but a combination of multiple mechanisms. Much work has been carried out to analyze apparent permeability of shale, but little attention has been paid to the effect of unique gas behavior in nanopores at high pressure and adsorbed layer on apparent permeability. This work presents a new model considering multiple transport mechanisms including viscous flow (without slip), slip flow, Knudsen diffusion, and surface diffusion in the adsorption layer. Pore diameter and mean free path of gas molecules are corrected by considering the adsorption layer and dense gas effect, respectively. Then the effects of desorption layer, surface diffusion, and gas behavior on gas apparent permeability in nanopores of shale are analyzed. The results show that surface diffusion is the dominant flow mechanism in pores with small diameter at low pressure and that the effect of adsorbed layer and dense gas on apparent permeability is strongly affected by pressure and pore diameter. From the analysis results, the permeability value calculated with the new apparent permeability model is lower than in the other model under high pressure and higher than in the other model under high pressure, so the gas production calculated using the new permeability model will be lower than using the other model at early stage and higher than using the other model at late stage.
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Aprianti, Tine, Harrini Mutiara Hapsari, Debby Yulinar Permata, Selvia Aprilyanti, Justin Sobey, Kallan Pham, Srinivasan Kandadai, and Hui Tong Chua. "Experimental study of gas adsorption using high-performance activated carbon: Propane adsorption isotherm." Teknomekanik 7, no. 1 (June 10, 2024): 62–73. http://dx.doi.org/10.24036/teknomekanik.v7i1.28672.
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Activated carbon is widely used for its diverse adsorptive abilities, with a vast range of current and emerging uses. This study developed a data set for high-performing activated carbon, its adsorption abilities with differing adsorbents, and an understanding of what deviations are present compared to the widely used adsorption models. This study included the construction of Tóth isotherms in varying conditions. Building a strong isotherm correlation is desired, with an understanding of the relationship between the pores of the activated carbon sample, operating parameters, and the adsorbent. The present data could complement efforts in designing adsorbed natural gas storage systems. Experimental data was collected using a Constant Volume Variable Pressure (CVVP) apparatus, consisting of a temperature-regulated vessel containing the activated carbon sample dosed with varying adsorbents through a controlled dosing vessel. Analysis of the derived data gave a well-fitted Tóth adsorption isotherm, giving the maximum specific adsorption capacity of the activated carbon to be 2.28 g of propane per gram of activated carbon with a standard error of regression
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Qu, Lina, Zhenzhen Wang, and Long Liu. "Molecular Simulation Study Based on Adsorption of Gas (CO2,O2,CH4) on Coal." Fire 6, no. 9 (September 11, 2023): 355. http://dx.doi.org/10.3390/fire6090355.
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This study aimed to further explore the adsorption properties of different gases (CO2, O2, and CH4) on the coking coal surface by establishing a molecular model. Changes in the absolute adsorption capacity and the isosteric heat of adsorption of gases under different temperatures, pressures, and compositions were simulated using grand canonical Monte Carlo (GCMC) and molecular dynamics simulations. Interaction energy and energy distribution were used to analyze the adsorption behavior of gases, and the diffusion properties were investigated using the diffusion coefficient and diffusion activation energy. The absolute adsorption results fit well with the Langmuir–Freundlich model. The absolute adsorption capacity had a significant positive correlation with pressure and the corresponding mole fraction, and a significant negative correlation with temperature. The competitiveness, based on binary adsorption selectivity, was in the order of CO2 > O2 > CH4. The isosteric heat of adsorption of CH4 was slightly higher than that of O2, and that of CO2 was 1.49–1.64 times that of O2 and CH4. The isosteric heat of the adsorption of gases was also barely influenced by temperature and pressure. The interaction energy between CO2 and coal was greater than that of O2 or CH4, but the high pressure and high content were not conducive to the adsorption of O2 by CO2. The preferred adsorption site for CO2 was stronger than that for O2 and CH4, and its peak value negatively correlated with the molar fraction. The diffusion coefficient for single component gases initially increased and then decreased with increased pressure, showing a positive correlation with temperature. A close inverse correlation existed between diffusion activation energy and pressure. These results revealed the microscopic adsorption and diffusion regularities of CO2, O2, and CH4 in the coal model, indicating great significance in accurately predicting coal fires.
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Li, Jing, Keliu Wu, Zhangxin Chen, Kun Wang, Jia Luo, Jinze Xu, Ran Li, Renjie Yu, and Xiangfang Li. "On the Negative Excess Isotherms for Methane Adsorption at High Pressure: Modeling and Experiment." SPE Journal 24, no. 06 (August 5, 2019): 2504–25. http://dx.doi.org/10.2118/197045-pa.
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Summary An excess adsorption amount obtained in experiments is always determined by mass balance with a void volume measured by helium (He) –expansion tests. However, He, with a small kinetic diameter, can penetrate into narrow pores in porous media that are inaccessible to adsorbate gases [e.g., methane (CH4)]. Thus, the actual accessible volume for a specific adsorbate is always overestimated by an He–based void volume; such overestimation directly leads to errors in the determination of excess isotherms in the laboratory, such as “negative isotherms” for gas adsorption at high pressures, which further affects an accurate description of total gas in place (GIP) for shale–gas reservoirs. In this work, the mass balance for determining the adsorbed amount is rewritten, and two particular concepts, an “apparent excess adsorption” and an “actual excess adsorption,” are considered. Apparent adsorption is directly determined by an He–based volume, corresponding to the traditional treatment in experimental conditions, whereas actual adsorption is determined by an adsorbate–accessible volume, where pore–wall potential is always nonpositive (i.e., an attractive molecule/pore–wall interaction). Results show the following: The apparent excess isotherm determined by the He–based volume gradually becomes negative at high pressures, but the actual one determined by the adsorbate–accessible volume always remains positive.The negative adsorption phenomenon in the apparent excess isotherm is a result of the overestimation in the adsorbate–accessible volume, and a larger overestimation leads to an earlier appearance of this negative adsorption.The positive amount in the actual excess isotherm indicates that the adsorbed phase is always denser than the bulk gas because of the molecule/pore–wall attraction aiding the compression of the adsorbed molecules. Practically, an overestimation in pore volume (PV) is only 3.74% for our studied sample, but it leads to an underestimation reaching up to 22.1% in the actual excess amount at geologic conditions (i.e., approximately 47 MPa and approximately 384 K). Such an overestimation in PV also underestimates the proportions of the adsorbed–gas amount to the free–gas amount and to the total GIP. Therefore, our present work underlines the importance of a void volume in the determination of adsorption isotherms; moreover, we establish a path for a more–accurate evaluation of gas storage in geologic shale reservoirs with high pressure.
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Shasha, Si, Wang Zhaofeng, Zhang Wenhao, and Dai Juhua. "Study on Adsorption Model of Deep Coking Coal Based on Adsorption Potential Theory." Adsorption Science & Technology 2022 (August 8, 2022): 1–13. http://dx.doi.org/10.1155/2022/9596874.
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With the exhaustion of coal resources in shallow coal seams, many mining areas have moved to deep mining, and the coal storage environment is obviously affected by the mining depth, mainly manifested as the increase of gas pressure and temperature, which makes the adsorption characteristics of deep coal seam gas much more complicated than shallow coal seam. Based on this, this paper chooses Pingdingshan coking coal as the research object, using Hsorb-2600 high-temperature and high-pressure gas adsorption instrument to carry on isothermal adsorption experiment. According to the adsorption theory and the uniqueness of the adsorption characteristics cure, the adsorption model was analyzed and studied. The results show that the predicted curve of coal seam gas adsorption isotherm is in good agreement with the measured curve, the relative error is less than 10%, and the adsorption characteristic curve is logarithmic. At the same time, the model is used to study the variation of adsorbed gas amount with mining depth. The results show that the adsorbed gas amount increases first and then decreases with coal burial depth.
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Deng, Jia, Qi Zhang, Lan Zhang, Zijian Lyu, Yan Rong, and Hongqing Song. "Investigation on the adsorption properties and adsorption layer thickness during CH4 flow driven by pressure gradient in nano-slits." Physics of Fluids 35, no. 1 (January 2023): 016104. http://dx.doi.org/10.1063/5.0134419.
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In shale gas exploration, gas adsorbed on the surface of porous medium results in a change in pore size, which is closely relevant to permeability, flow rate, and production capacity of shale gas reservoirs, especially for the reservoir containing large numbers of pores and slits. Thus, the present work investigates the adsorption mechanism and adsorption layer thickness during CH4 flow driven by the pressure gradient in nano-slits by using molecular dynamics simulation. Herein, a slit-pore model in terms of gas storage and grapheme pore is developed, implemented, and verified. The effects of the pressure, temperature, pressure gradient, and pore size on adsorption properties and adsorption layer thickness of CH4 are also examined. Results show that the relative adsorption capacity is positively correlated with the pressure gradient and pore size and negatively correlated with the system pressure, whereas unaffected by temperature. Moreover, the adsorption layer thickness decreases with the pressure and is almost unaffected by the pore size under the small pore size, whereas increasing with the pressure gradient and temperature. The descending order of sensibility to the adsorption layer thickness is temperature, pressure gradient, pore size, and system pressure. Hence, based on those findings, a new formula for calculating the adsorption layer thickness is proposed for the quantitative determination of the effective pore size of porous medium when gas flows in slits, thereby contributing to shale gas high-efficient exploration.
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Xu, Wenjie, Xigui Zheng, Cancan Liu, Peng Li, Boyang Li, Kundai Michael Shayanowako, Jiyu Wang, Xiaowei Guo, and Guowei Lai. "Numerical Simulation Study of High-Pressure Air Injection to Promote Gas Drainage." Sustainability 14, no. 21 (October 22, 2022): 13699. http://dx.doi.org/10.3390/su142113699.
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Coal-accompanying gas is an essential resource, with numerous mining methods. The practice has proved that injecting high-pressure air into the coal seam can replace and flush the gas in the coal seam, effectively solving the problem of inadequate single gas drainage in soft and low permeability coal seams. This paper uses the finite element method to solve the model, simulate and study the gas drainage by high-pressure air injection in the bedding drilling, and establish a fluid-structure coupling model for gas drainage by high-pressure air injection. The competitive adsorption of N2, O2, and CH4, diffusion and migration of CH4 in coal matrix and fissure, matrix deformation caused by CH4 adsorption, and desorption and control of coal deformation by applied stress are considered in the model. When the fixed extraction time is 600 days (d), the optimal spacing between the extraction hole and injection hole is 12.5 m. The safe extraction effect and minimum drilling amount can be ensured. It provides a basis for guiding gas drainage by injecting high-pressure air on-site.
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Agarwal, R. K., K. A. G. Amankwah, and J. A. Schwarz. "Analysis of adsorption entropies of high pressure gas adsorption data on activated carbon." Carbon 28, no. 1 (1990): 169–74. http://dx.doi.org/10.1016/0008-6223(90)90110-k.
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Chang, Cheng, Jian Zhang, Haoran Hu, Deliang Zhang, and Yulong Zhao. "Molecular Simulation of Adsorption in Deep Marine Shale Gas Reservoirs." Energies 15, no. 3 (January 27, 2022): 944. http://dx.doi.org/10.3390/en15030944.
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Deep marine shale gas reservoirs are extremely rich in the Sichuan basin in China. However, due to the in situ conditions with high temperature and high pressure (HTHP), in particular reservoir pressure being usually much higher than the test pressure, it is difficult to accurately clarify the adsorption behavior, as seepage theory plays an important role in shale gas reserves evaluation. Therefore, three kinds of sorbent, including illite, quartz and kerogen, and two simulation methods, containing the grand canonical ensemble Monte Carlo method and molecular dynamics method, are synthetically used to determine the methane adsorption behavior under HTHP. The results show that both absolute adsorption and excess adsorption decrease with the increase of temperature. When the pressure increases, the absolute adsorption increases quickly and then slowly, and the excess adsorption first increases and then decreases. The superposition of wall potential energy is strongest in a circular hole, second in a square hole, and weakest in a narrow slit. The effect of pore size increases with the decrease of the pore diameter. Under HTHP, multi-layer adsorption can occur in shale, but the timing and number of layers are related to the sorbent type.
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Deyko, Gregory S., Valery N. Zakharov, Lev M. Glukhov, Dmitry O. Charkin, Dmitry Yu Kultin, Vladimir V. Chernyshev, Leonid A. Aslanov, and Leonid M. Kustov. "High-Pressure Gas Adsorption on Covalent Organic Framework CTF-1." Crystals 14, no. 12 (December 10, 2024): 1066. https://doi.org/10.3390/cryst14121066.
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Triazine-based covalent organic framework CTF-1 was synthesized via polymerization of 1,4-dicyanobenzene in the presence of zinc chloride. Two different methods of the post-synthesis treatment of the obtained material were compared. It was demonstrated that ultrasonication effectively removes impurities from CTF-1. Adsorption of hydrocarbon gases (methane and ethane) and carbon dioxide was measured at 298 K in a wide pressure range for the first time. Ideal selectivity and IAST values for methane/ethane and methane/CO2 pairs were calculated from the obtained isotherms.
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Kostroski, Kyle P., and Phillip C. Wankat. "High Recovery Cycles for Gas Separations by Pressure-Swing Adsorption." Industrial & Engineering Chemistry Research 45, no. 24 (November 2006): 8117–33. http://dx.doi.org/10.1021/ie060566h.
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Kinigoma, B. S., and G. O. Ani. "Comparison of gas dehydration methods based on energy consumption." Journal of Applied Sciences and Environmental Management 20, no. 2 (July 25, 2016): 253–58. http://dx.doi.org/10.4314/jasem.v20i2.4.
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This study compares three conventional methods of natural gas (Associated Natural Gas) dehydration to carry out the dehydration process and suitability of use on the basis of energy requirement. These methods are Triethylene Glycol (TEG) absorption, solid desiccant adsorption and condensation. Analyses performed were based on dehydration of Natural Gas saturated with 103Nm3/h water content at a temperature range of -10O C to 30oC, and gas pressure variation between 7MPa and 20MPa. This analysis and study showed that energy required for all three processes decreases with increase in pressure, but condensation dehydration requires the least energy at high pressures. Results obtained shows that, both at high pressures and low pressures, TEG dehydration is most suitable and in cases where very low Tdew is required, solid desiccant adsorption is preferable. In conclusion, the findings in this paper will aid natural gas process design engineers to decide on what method to use base on energy consumption and on the physical and chemical properties of the final products.Keywords: Dehydration, Absorption, Desiccant, Condensation, Triethylene Glycol (TEG)
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Yue, Jiwei, Zhaofeng Wang, and Jinsheng Chen. "Dynamic response characteristics of water and methane during isobaric imbibition process in remolded coal containing methane." Energy Exploration & Exploitation 37, no. 1 (September 13, 2018): 83–101. http://dx.doi.org/10.1177/0144598718798083.
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Addition of water to the coal is actually an isobaric imbibition process. To study the dynamic response characteristics of water and methane, the isobaric imbibition process was stimulated by a self-designed experimental device which can eliminate the reabsorbing phenomenon. The results indicate that adding water can displace absorbed gas. The displacement mechanism is attributed to the capillary effect and competitive adsorption during isobaric imbibition process. A competitive adsorption phenomenon exists between gas molecules and water molecules. Since oxygen-containing functional groups in coal and the hydrogen bond of water, water can easily occupy high-energy sites and only the low-energy sites are available for methane. The imbibition quantity increases with increasing water content or adsorption equilibrium pressure. Moreover, the imbibition quantity would reach a maximum value. The relationship between water content and maximum imbibition quantity or the maximum imbibition rate can be described by a Langmuir function under the same adsorption equilibrium pressure. The maximum imbibition quantity increases with increasing adsorption equilibrium pressure under the same water content, which also can be described by a Langmuir function. However, the maximum imbibition rate decreases with increasing adsorption equilibrium pressures under the same water content, which can be described by an exponential function. Compared to the adsorption equilibrium pressure, the water content has a greater effect on the imbibition quantity and imbibition rate. This study revealed the mechanisms of the dynamic response characteristics of water and methane during isobaric imbibition process based on the transformation form of Hagen–Poiseuille equation, adsorption force of coal and gas and adsorption force of coal and water, which can provide a new method to control gas in deep coal seams.
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Chen, Xuexi, Wenxuan Shan, Ruibang Sun, and Liang Zhang. "Methane displacement characteristic of coal and its pore change in water injection." Energy Exploration & Exploitation 38, no. 5 (July 2, 2020): 1647–63. http://dx.doi.org/10.1177/0144598720934052.
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Coalbed methane as one type of clean energy has become an important gas resource recently. High-pressure water injection in coal seams is an effective approach for improving gas extraction efficiency, which is determined by the gas displacement characteristic and pore structure of coal. To investigate the gas displacement characteristics in coal and its pore response and influential factors, gas adsorption and water injection experiments were conducted under different conditions. The results show that the gas displacement caused by the water injection undergoes three stages: rapid increase, slow increase, and almost constant. The wetting process in water injection includes three processes: wetting, soaking, and spreading, and the wettability of coking coal is best, followed by lean coal and anthracite. The amount of gas driven by the water increases with increasing water injection pressure, and it is more favorable to increase the injection pressure to improve the gas displacement effect under the relatively low injection pressure. The lower the coal rank, the better the gas displacement effect due to the higher porosity of the coal, and the longer the early gas displacement stage. The high adsorption equilibrium pressure can improve the gas displacement effect; for the relatively high adsorption equilibrium pressure, the gas displacement effect is better. After water injection in coal, the large fractures and pores dramatically increase in size, especially for the low metamorphic coals coking coal, contributing to the majority of the increase in porosity. The results of this study can provide a theoretical foundation for the wide application of water injection technology for efficient gas drainage in coal mines.
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Kalman, Viktor, Johannes Voigt, Christian Jordan, and Michael Harasek. "Hydrogen Purification by Pressure Swing Adsorption: High-Pressure PSA Performance in Recovery from Seasonal Storage." Sustainability 14, no. 21 (October 28, 2022): 14037. http://dx.doi.org/10.3390/su142114037.
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Hydrogen storage in a depleted gas field is a promising solution to the seasonal storage of renewable energy, a key question in Europe’s green transition. The gas composition and pressure in the month-long storage and recovery phase can vary substantially; meanwhile, the recovered H2 has to be pure, especially for fuel cell applications. Pressure swing adsorption can be used for the purification of the recovered gas. A lab-scale, four-bed PSA unit was built to investigate its applicability by separating different H2-CH4 mixtures. The feed parameters in the experiments are based on a depleted gas reservoir with a pressure range of 25–60 bar and methane contamination between 0 and 35%. The change in the feed properties is modeled by four distinct stages and the twelve-step cycle is tailored to each stage. The high pressure did not have any irreversible effects on the process. A hydrogen purity of 99.95% was achieved in all stages with the average hydrogen recovery ranging from 60 to 80%. The experiments revealed the challenges of a cycle design when the feed parameters are not constant, but an adequate separation performance was shown, which supports the applicability of the PSA in seasonal storage and confirms the need for further investigation with multicomponent contaminants and large-scale projects.
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Zhang, Yongchun, Aiguo Hu, Pei Xiong, Hao Zhang, and Zhonghua Liu. "Experimental Study of Temperature Effect on Methane Adsorption Dynamic and Isotherm." Energies 15, no. 14 (July 11, 2022): 5047. http://dx.doi.org/10.3390/en15145047.
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Knowing the methane adsorption dynamic is of great importance for evaluating shale gas reserves and predicting gas well production. Many experiments have been carried out to explore the influence of many aspects on the adsorption dynamic of methane on shale rock. However, the temperature effect on the adsorption dynamic as a potential enhanced shale gas recovery has not been well addressed in the publications. To explore the temperature effect on the adsorption dynamic of methane on gas shale rock, we conducted experimental measurement by using the volumetric method. We characterized the adsorption dynamic of methane on gas shale powders and found that the curves of pressure response at different pressure steps and temperatures all have the same tendency to decrease fast at first, then slowly in the middle and remain stable at last, indicating the methane molecules are mainly adsorbed in the initial stage. Methane adsorption dynamic and isotherm can be well fitted by the Bangham model and the Freundlich model, respectively. The constant z of the Bangham model first decreases and then increases with equilibrium pressure increasing at each temperature, and it decreases with temperature increasing at the same pressure. The adsorption rate, constant k of the Bangham model, is linearly positively correlated with the natural log of the equilibrium pressure, and it decreases with temperature increasing at the same pressure. Constant K and n of the Freundlich model all decrease with temperature increasing, indicating that low temperatures are favorable for methane adsorption on shale powders, and high temperatures can obviously reduce constant K and n of the Freundlich model. Finally, we calculated isosteric enthalpy and found that isosteric enthalpy is linearly positively correlated with the adsorption amount. These results will be profoundly meaningful for understanding the mechanism of methane adsorption dynamic on shale powders and provide a potential pathway to enhance shale gas recovery.
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Cai, Feng, Jingwen Yin, and Juqiang Feng. "Effect of Methane Adsorption on Mechanical Performance of Coal." Applied Sciences 12, no. 13 (June 29, 2022): 6597. http://dx.doi.org/10.3390/app12136597.
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Understanding the influence of methane adsorption on coal mechanical properties is an important prerequisite for preventing coal mining and gas mining disasters. In the present research, meager coal and gas coal samples were obtained from Huaneng Yunnan Diandong Energy Co., Ltd. The triaxial compression tests were carried out under different methane adsorption equilibrium pressures and confining pressures. The influence laws of different factors on the mechanical properties of coal were analyzed. The results show that the triaxial stress-strain curve of adsorbed methane coal has similar morphology with that of non-adsorbed coal. Under the same confining pressure, the stress-strain curve morphology of coal before and after adsorbing methane is basically the same but the compressive strength of coal after adsorbing methane decreases. The greater the adsorption equilibrium pressure of methane, the smaller the compressive strength of coal. The change in the mechanical properties (compressive strength and elastic modulus) of coal caused by methane adsorption can be described by the Langmuir curve and the correlation coefficient is more than 0.99. Under any stress environment, high-rank coal shows greater strength and lower elastic modulus than low-rank coal, which is mainly due to the existence of a developed cleat system in high-rank coal that provides more conditions for methane adsorption. The research results provide important data-based support for the prevention of coal and gas outbursts.
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Liu, Zhenjian, Zhenyu Zhang, Xiaoqian Liu, Tengfei Wu, and Xidong Du. "Supercritical CO2 Exposure-Induced Surface Property, Pore Structure, and Adsorption Capacity Alterations in Various Rank Coals." Energies 12, no. 17 (August 27, 2019): 3294. http://dx.doi.org/10.3390/en12173294.
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Carbon dioxide (CO2) has been used to replace coal seam gas for recovery enhancement and carbon sequestration. To better understand the alternations of coal seam in response to CO2 sequestration, the properties of four different coals before and after supercritical CO2 (ScCO2) exposure at 40 °C and 16 MPa were analyzed with Fourier Transform infrared spectroscopy (FTIR), low-pressure nitrogen, and CO2 adsorption methods. Further, high-pressure CO2 adsorption isotherms were performed at 40 °C using a gravimetric method. The results indicate that the density of functional groups and mineral matters on coal surface decreased after ScCO2 exposure, especially for low-rank coal. With ScCO2 exposure, only minimal changes in pore shape were observed for various rank coals. However, the micropore specific surface area (SSA) and pore volume increased while the values for mesopore decreased as determined by low-pressure N2 and CO2 adsorption. The combined effects of surface property and pore structure alterations lead to a higher CO2 adsorption capacity at lower pressures but lower CO2 adsorption capacity at higher pressures. Langmuir model fitting shows a decreasing trend in monolayer capacity after ScCO2 exposure, indicating an elimination of the adsorption sites. The results provide new insights for the long-term safety for the evaluation of CO2-enhanced coal seam gas recovery.
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Ekundayo, Jamiu M., and Reza Rezaee. "Numerical Simulation of Gas Production from Gas Shale Reservoirs—Influence of Gas Sorption Hysteresis." Energies 12, no. 18 (September 4, 2019): 3405. http://dx.doi.org/10.3390/en12183405.
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The true contribution of gas desorption to shale gas production is often overshadowed by the use of adsorption isotherms for desorbed gas calculations on the assumption that both processes are identical under high pressure, high temperature conditions. In this study, three shale samples were used to study the adsorption and desorption isotherms of methane at a temperature of 80 °C, using volumetric method. The resulting isotherms were modeled using the Langmuir model, following the conversion of measured excess amounts to absolute values. All three samples exhibited significant hysteresis between the sorption processes and the desorption isotherms gave lower Langmuir parameters than the corresponding adsorption isotherms. Langmuir volume showed positive correlation with total organic carbon (TOC) content for both sorption processes. A compositional three-dimensional (3D), dual-porosity model was then developed in GEM® (a product of the Computer Modelling Group (CMG) Ltd., Calgary, AB, Canada) to test the effect of the observed hysteresis on shale gas production. For each sample, a base scenario, corresponding to a “no-sorption” case was compared against two other cases; one with adsorption Langmuir parameters (adsorption case) and the other with desorption Langmuir parameters (desorption case). The simulation results showed that while gas production can be significantly under-predicted if gas sorption is not considered, the use of adsorption isotherms in lieu of desorption can lead to over-prediction of gas production performances.
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Tang, Songlei, Hongbo Zhai, Hong Tang, and Feng Yang. "Isothermal Desorption Hysteretic Model for Deep Coalbed Methane Development." Geofluids 2022 (January 25, 2022): 1–9. http://dx.doi.org/10.1155/2022/5259115.
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The adsorption/desorption mechanism of coalbed methane is significant for gas control and coalbed methane exploitation; scholars have done a lot of research on it and generally have confidence in that temperature, pressure, and moisture are central factors affecting the adsorption of coalbed methane. Considering the reduction of recovery efficiency caused by desorption hysteresis in deep coalbed methane drainage, the effects of high reservoir pressure, high gas content, and low permeability on the hysteresis index were analyzed. A desorption hysteresis model based on the combination of dual-porosity media and traditional Langmuir adsorption theory was proposed. By comparing with the four experimental data of Ma et al., the advantages of the new model in fitting desorption data were investigated. Based on the new desorption hysteresis model, the hysteresis index was calculated from the adsorption capacity and desorption capacity under the abandonment pressure. The hysteresis index under different coal sizes and adsorption pressure were calculated, and a good linear relationship was found between the adsorption pressure and the hysteresis index. Through a large number of field production data analysis, the following conclusions are drawn: as the adsorption pressure increases, the hysteresis index enhances; when the coal sample size increases, the hysteresis index also increases. Finally, by comparing experimental data from deep and shallow coal samples, the influence of desorption hysteresis on deep coalbed methane mining was explored. This paper draws the conclusion that although the gas content in deep coalbed methane is considerable, its hysteresis index is also enhanced, which makes coalbed methane development more difficult. The findings of this study can provide theoretical support for coal bed gas control and coal bed methane heat injection mining.
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Ni, X. M., Q. F. Jia, and Y. B. Wang. "Characterization of Permeability Changes in Coal of High Rank during the CH4-CO2 Replacement Process." Geofluids 2018 (November 12, 2018): 1–8. http://dx.doi.org/10.1155/2018/8321974.
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The influences of coal matrix expansion/contraction and effective stress on the permeability of coal with different thermal maturities are different during the CH4-CO2 replacement process due to different mechanical properties and gas adsorption capacities. To accurately predict the variation law of coal permeability during the CH4-CO2 replacement process, it is critical to understand how the matrix expansion/contraction and effective stress affect the permeability of coal at different thermal maturities during the CH4-CO2 replacement. In this study, the permeability of two coal specimens with anthracite and high-rank bituminous coal during the CH4-CO2 replacement process under different confining and injection pressures was tested using a CBM replacement testing machine. The results demonstrate that with decreasing gas injection pressure, the permeability of the two coal specimens exhibited a U-shaped correlation under different confining pressures. Under the same gas injection pressure, with increasing effective stress, the permeability presented a negative exponential decrease and the permeability of the anthracite decreased more significantly. Moreover, under the same confining pressure, with increasing gas injection pressure, the decreasing permeability agreed with Langmuir curve and the permeability of high-rank bituminous coal was more significantly reduced.
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Zhou, Juan, Shiwang Gao, Lianbo Liu, Tieya Jing, Qian Mao, Mingyu Zhu, Wentao Zhao, Bingxiao Du, Xu Zhang, and Yuling Shen. "Investigating the Influence of Pore Shape on Shale Gas Recovery with CO2 Injection Using Molecular Simulation." Energies 16, no. 3 (February 3, 2023): 1529. http://dx.doi.org/10.3390/en16031529.
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Carbon-dioxide-enhanced shale gas recovery technology has significant potential for large-scale emissions reduction and can help achieve carbon neutrality targets. Previous theoretical studies mainly focused on gas adsorption in one-dimensional pores without considering the influence from the pore geometry. This study evaluates the effects of pore shape on shale gas adsorption. The pure and competitive gas adsorption processes of CO2 and CH4 in nanopores were investigated using molecular simulations to improve the prediction of shale gas recovery efficiency. Meanwhile, quantitative analysis was conducted on the effects of the pore shape on the CO2-EGR efficiency. The results indicate that the density of the adsorption layer in pores is equally distributed in the axial direction when the cone angle is zero; however, when the cone angle is greater than zero, the density of the adsorption layer decreases. Smaller cone-angle pores have stronger gas adsorption affinities, making it challenging to recover the adsorbed CH4 during the pressure drawdown process. Concurrently, this makes the CO2 injection method, based on competitive adsorption, efficient. For pores with larger cone angles, the volume occupied by the free gas is larger; thus, the pressure drawdown method displays relatively high recovery efficiency.
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De Wireld, Guy, Youssef Belmabkhout, and Marc Frère. "Buoyancy effect correction on high pressure pure gas adsorption gravimetric measurements." Annales de Chimie Science des Matériaux 30, no. 4 (August 28, 2005): 411–23. http://dx.doi.org/10.3166/acsm.30.411-423.
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Chilev, Ch, F. Darkrim Lamari, E. Kirilova, and I. Pentchev. "Comparison of gas excess adsorption models and high pressure experimental validation." Chemical Engineering Research and Design 90, no. 11 (November 2012): 2002–12. http://dx.doi.org/10.1016/j.cherd.2012.03.012.
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Rouquerol, Jean, Françoise Rouquerol, Phillip Llewellyn, and Renaud Denoyel. "Surface excess amounts in high-pressure gas adsorption: Issues and benefits." Colloids and Surfaces A: Physicochemical and Engineering Aspects 496 (May 2016): 3–12. http://dx.doi.org/10.1016/j.colsurfa.2015.10.045.
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Raza, Syed Shabbar, Julie Pearce, Pradeep Shukla, Phil Hayes, and Victor Rudolph. "Characterisation of Surat Basin Walloon interburden and overlying Springbok Sandstone: a focus on methane adsorption isotherms, permeability and gas content." APPEA Journal 60, no. 2 (2020): 748. http://dx.doi.org/10.1071/aj19078.
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The Surat Basin in Queensland is one of the world’s premier producers of natural gas from coal seams. We investigate the potential for clay-rich Walloon Coal interburden and the overlying Springbok Sandstone to hold or produce gas. Seventeen core samples were analysed from two wells from intervals within the Walloon Upper Juandah Coal Measures interburden and the Springbok Sandstone. Samples were characterised using high-pressure methane adsorption isotherms, canister gas desorption tests, moisture contents, ash contents, carbon contents, scanning electron microscopy/energy dispersive X-ray spectrometry, X-ray quantitative clay analysis, permeability, helium pycnometry and mercury intrusion porosimetry. Methane adsorption was conducted at 30°C with up to 8 MPa pressure on dried crushed samples. The adsorption capacity of methane at 8 MPa varied from 3 cc/g (calcite-cemented) up to 25 cc/g (standard temperature and pressure equivalent) (coal). Clay-rich interburden samples adsorbed ~5–14 cc/g (dry). The measured isotherms and methane content from canister desorption tests show that appreciable volumes of gas are contained within some portions of interburden and in the overlying Springbok Sandstone. Gas within the interburden likely represents a large volumetric resource, albeit in low permeability rock that restricts direct productivity. The gas adsorption and gas content results for the Springbok Sandstone help to explain field observations of high gas content in some landholder water wells.
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Gao, Jian Liang, and Yu Wang. "Research on the Relationship between the Drilling Cutting Gas Desorption Index △h2 and Parameters of Gas Occurrence." Applied Mechanics and Materials 99-100 (September 2011): 1312–18. http://dx.doi.org/10.4028/www.scientific.net/amm.99-100.1312.
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The drilling cutting gas desorption index △h2is one of the most important indexes for the prediction of coal and gas outburst. Based on the mathematical and physical model of the gas diffusion of coal particles, the analytical solution of △h2was deduced. The relationship between the drilling cutting gas desorption index △h2and parameters of gas occurrence such as the gas diffusion coefficient, adsorption constants (a and b), gas pressure, and gaSubscript textSubscript texts content were studied. The results show that △h2increases and gas diffusion resistance decreases with the gas diffusion coefficient. The drilling cutting gas desorption index △h2increases with the adsorption constant a, and the two meet the linear relationship. △h2increases with the adsorption constant b and the raising rate gets lower gradually. And, △h2increases with the gas pressure, and the two meet the power relationship with very high correlation coefficient.△h2and gas content are in linear relationship.
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Li, De-Yang, Dong-Mei Liu, Hong-Kui Hu, Hui-Feng Bo, and Zhan-Xin Zhang. "Molecular Simulation of Adsorption and Diffusion of Methane and Ethane in Kaolinite Clay under Supercritical Conditions: Effects of Water and Temperature." Minerals 13, no. 10 (September 28, 2023): 1269. http://dx.doi.org/10.3390/min13101269.
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Grand Canonical Monte Carlo (GCMC) simulation and Molecular Dynamics (MD) simulations were used to study the effects of temperature (310 K to 400 K), pressure (≤30 MPa) and water content (0 molecule/nm3 to 9 molecule/nm3) on the adsorption and diffusion behavior of CH4 and C2H6 in 3 nm kaolinite slit under supercritical conditions. The obtained adsorption capacity, isosteric adsorption heat, concentration distribution and diffusion coefficient were analyzed and compared. The simulation results show that the adsorption capacity of C2H6 is higher under low pressure conditions, and the adsorption capacity of CH4 is higher under high pressure conditions due to the small molecular radius and increased adsorption space. The addition of water molecules and the increase in temperature will reduce the adsorption capacity and isosteric adsorption heat of the two gases. We analyzed the changes in Langmuir volume and Langmuir pressure of the two gases under different temperature and water content conditions. The addition of water molecules and the increase in temperature will reduce the saturation adsorption capacity (which has a greater effect on C2H6) and the adsorption rate of the two gases in the kaolinite slit. The water molecules occupy the adsorption site of the gas molecules (limiting the diffusion of the gas molecules), which reduces the interaction between gas molecules and the wall surface, thus altering the distribution of the two gases in the slit. The increase in temperature will accelerate the oscillation of the gas molecules, increasing diffusion, and also leads to a reduction in the peak value of the adsorption peaks of the two gases.
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Damasceno Borges, Daiane, and Douglas S. Galvao. "Schwarzites for Natural Gas Storage: A Grand-Canonical Monte Carlo Study." MRS Advances 3, no. 1-2 (2018): 115–20. http://dx.doi.org/10.1557/adv.2018.190.
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ABSTRACTThe 3D porous carbon-based structures called Schwarzites have been recently a subject of renewed interest due to the possibility of being synthesized in the near future. These structures exhibit negatively curvature topologies with tuneable porous sizes and shapes, which make them natural candidates for applications such as CO2 capture, gas storage and separation. Nevertheless, the adsorption properties of these materials have not been fully investigated. Following this motivation, we have carried out Grand-Canonical Monte Carlo simulations to study the adsorption of small molecules such as CO2, CO, CH4, N2 and H2, in a series of Schwarzites structures. Here, we present our preliminary results on natural gas adsorptive capacity in association with analyses of the guest-host interaction strengths. Our results show that Schwarzites P7par, P8bal and IWPg are the most promising structures with very high CO2 and CH4 adsorption capacity and low saturation pressure (<1bar) at ambient temperature. The P688 is interesting for H2 storage due to its exceptional high H2 adsorption enthalpy value of -19kJ/mol.
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Abou Alfa, Khaled, Diana C. Meza-Sepulveda, Cyril Vaulot, Jean-Marc Le Meins, Camelia Matei Ghimbeu, Louise Tonini, Janneth A. Cubillos, et al. "Cocoa Pod Husk Carbon Family for Biogas Upgrading: Preliminary Assessment Using the Approximate Adsorption Performance Indicator." C 10, no. 4 (November 29, 2024): 100. http://dx.doi.org/10.3390/c10040100.
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The preliminary selection of adsorbents for the separation of a gas mixture based on pure gas adsorption remains a critical challenge; thus, an approximate adsorption performance indicator (AAPI) was proposed for the initial evaluation of the adsorbents to separate the biogas main constituents (carbon dioxide/methane (CO2/CH4)) by studying their pure gas adsorption. Three samples derived from cocoa pod husk (CPH), namely Cabosse-500 (pyrolyzed at 500 °C), Cabosse-700 (pyrolyzed at 700 °C), and Cabosse-A-700 (activated with CO2 at 700 °C), were synthesized, characterized, and evaluated for the pure gases adsorption. This study presents an AAPI evaluation, which takes into account adsorption capacity, approximate selectivity, and heat of adsorption. Adsorption isotherms indicate the ability of the CPH family to selectively capture CO2 over CH4, as they have a high approximate selectivity (>1) thanks to their physical properties. Changing the pyrolysis temperature, activation methods, and varying the pressure can significantly change the choice of the most effective adsorbent; Cabosse-A-700 showed better performance than the other two in the low and high pressure range owing to its presence of micropores and mesopores, which enhances the CO2 adsorption and therefore the AAPI.
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Tan, Xiaohua, Xinjian Ma, Xiaoping Li, and Yilong Li. "An Adsorption Model Considering Fictitious Stress." Fractal and Fractional 9, no. 1 (December 30, 2024): 17. https://doi.org/10.3390/fractalfract9010017.
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The adsorption of coalbed methane alters the pore structure of reservoirs, subsequently affecting the coal seam’s gas adsorption capacity. However, traditional gas adsorption models often neglect this crucial aspect. In this article, we introduce a fractal capillary bundle model that accounts for the expansion of coal seam adsorption. We utilize curvature fractal dimension and capillary fractal dimension to characterize the complexity of the coal seam’s pore structure. By incorporating the concept of fictitious stress, we have described the relationship between gas adsorption, matrix porosity, and permeability changes. We have developed a model that describes the changes in matrix porosity and permeability during the gas adsorption process. After fitting this model to experimental data, it demonstrated high accuracy in predictions. Furthermore, our investigation into how factors such as curvature fractal dimension, capillary fractal dimension, and fictitious stress influence gas adsorption capacity reveals several key findings. Firstly, the specific surface area within the pore structure of coal seams is the primary factor controlling gas adsorption capacity. Secondly, the virtual stress generated during the gas adsorption process alters the coal seam’s maximum gas adsorption capacity, a factor that cannot be overlooked. Lastly, we found that gas adsorption primarily affects the gas migration process, while under high-pressure conditions, gas desorption does not cause significant changes in the matrix porosity and permeability.
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Jia, Tianrang, Cao Liu, Guoying Wei, Jiangwei Yan, Qinghao Zhang, Lifei Niu, Xiaolei Liu, Mingjie Zhang, Yiwen Ju, and Yongjun Zhang. "Micro-Nanostructure of Coal and Adsorption-Diffusion Characteristics of Methane." Journal of Nanoscience and Nanotechnology 21, no. 1 (January 1, 2021): 422–30. http://dx.doi.org/10.1166/jnn.2021.18733.
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The adsorption and diffusion characteristics of coal are important parameters for coalbed methane (CBM) extraction and mine gas control. However, the adsorption test can only obtain the apparent adsorption amount, and it cannot obtain the actual adsorption amount, which leads to a large error during the calculation of the coal diffusion coefficient. Taking the anthracite coal in the Jiulishan Mine as the research object, the micro-nanostructure and instantaneous apparent methane adsorption isotherms of the primary structure coal and tectonic coal were determined by low-temperature CO2 adsorption, mercury intrusion and methane diffusion kinetics tests, and the instantaneous apparent adsorption isotherms of methane were corrected to the instantaneous actual adsorption isotherm by the Langmuir model. The results demonstrate that the micro-nanopore, Density Function Theory (DFT) pore volume and specific surface area values below 1–2 nm in tectonic coal are larger than those in the primary structure coal, which is the fundamental reason why the ultimate adsorption capacity of tectonic coal is larger than that of the primary structure coal. The apparent adsorption amounts of the tectonic coal and the primary structure coal reach the maximum at 8 MPa and 10 MPa, respectively. Thereafter, the instantaneous isotherms of the apparent adsorption amount decrease with increasing of gas pressure. However, the instantaneous isotherms of the actual adsorption amount tend to be stable. The diffusion coefficient undergoes a rapid decay with time under low gas pressure, and undergoes a slow decay with under the high gas pressure.
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Zhang, Guofang, Taoping Chen, Fuping Wang, Boyu Sun, Yong Wang, and Dali Hou. "Experimental determination of deviation factor of natural gas in natural gas reservoir with high CO2 content." E3S Web of Conferences 245 (2021): 01045. http://dx.doi.org/10.1051/e3sconf/202124501045.
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The deviation factor of natural gas is a coefficient to quantitatively describe the deviation degree between real gas (natural gas) and ideal gas. Generally, the deviation factor of natural gas is measured in PVT cell without considering porous media. However, when natural gas is in underground porous media reservoir, due to the adsorption of porous media, the deviation factor of natural gas in porous media deviates from that measured in conventional PVT cell. Moreover, compared with other gases, CO2 has stronger adsorption capacity. Therefore, in porous media, the deviation factor of natural gas considering the adsorption of porous media is quite different from that measured in conventional PVT cell. In this paper, simulating the isothermal mining conditions in gas reservoir,the deviation factor of natural gas with different CO2 content considering the influence of porous media under different pressure isothermal conditions is studied by using the test of designed sand filled long slim tube in series. And under the same conditions, the deviation factor is compared with that of conventional PVT. The experimental results show that under the same conditions, due to the adsorption of porous media, the deviation factor measured in porous media is smaller than that measured by PVT cell without considering porous media.
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Öztan, Hazal, and Duygu Uysal. "Determination of adsorption capacities of N2 and CO2 on commercial activated carbon and adsorption isotherm models." E3S Web of Conferences 433 (2023): 01004. http://dx.doi.org/10.1051/e3sconf/202343301004.
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In today’s technologies of gas purification systems, adsorption processes offer more advantages than traditional processes (amine absorption and cryogenic distillation). Thanks to advantages such as high efficiency, low energy consumption and ease of operation, the adsorption process plays an important role in today’s natural gas purification and carbon capturing processes. In order to bring natural gas to the usage standards and to ensure carbon capture in the emission sources (coal mines, landfills, agricultural activities, etc.) that emit CO2-CH4 as a result of human activities, it is extremely important to purify impurities such as CO2 and N2, which are highly present in the gas mixture. In the study, the adsorption of N2 and CO2 gases on activated carbon and the effect of pressure and temperature on adsorption were examined. The operating conditions pressure range was 1-6 bar and temperatures below room temperature. Experimental studies were carried out in laboratory scale adsorption cell system. As a result of the studies, it was determined that the adsorption capacity of activated carbon N2 and CO2 increased with pressure. N2 adsorption capacities were determined between 0.4-7.8 mmol/g and CO2 adsorption capacities were determined in the range of 2.7-7.4 mmol/g. In addition, Langmuir and Freundlich isotherm models were created, model parameters were examined and the adsorption behaviour of activated carbon for CO2 and N2 gases was obtained.
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Ao, Xiang, Baobao Wang, Yuxi Rao, Lang Zhang, Yu Wang, and Hongkun Tang. "Effect of CO2 Corrosion and Adsorption-Induced Strain on Permeability of Oil Shale: Numerical Simulation." Energies 16, no. 2 (January 9, 2023): 780. http://dx.doi.org/10.3390/en16020780.
Full textAbstract:
Permeability is a crucial parameter for enhancing shale oil recovery through CO2 injection in oil-bearing shale. After CO2 is injected into the shale reservoir, CO2 corrosion and adsorption-induced strain can change the permeability of the oil shale, affecting the recovery of shale oil. This study aimed to explore the influence of CO2 corrosion and adsorption-induced strain on the permeability of oil shale. The deformation of the internal pore diameter of oil shale induced by CO2 corrosion under different pressures was measured by low-pressure nitrogen gas adsorption in the laboratory, and the corrosion model was fitted using the experimental data. Following the basic definitions of permeability and porosity, a dynamic mathematical model of porosity and permeability was obtained, and a fluid–solid coupling mathematical model of CO2-containing oil shale was established according to the basic theory of fluid–solid coupling. Then the effects of adsorption expansion strain and corrosion compression strain on permeability evolution were considered to improve the accuracy of the oil shale permeability model. The numerical simulation results showed that adsorption expansion strain, corrosion compression strain, and confining pressure are the important factors controlling the permeability evolution of oil shale. In addition, adsorption expansion strain and corrosion compression strain have different effects under different fluid pressures. In the low-pressure zone, the adsorption expansion strain decreases the permeability of oil shale with increasing pressure. In the high-pressure zone, the increase in pressure decreases the influence of expansion strain while permeability gradually recovers. The compressive strain increases slowly with increasing pressure in the low-pressure zone, slowly increasing oil shale permeability. However, in the high-pressure area, the increase in pressure gradually weakens the influence of corrosion compressive strain, and the permeability of oil shale gradually recovers.