Molecular Investigation on the Displacement Characteristics of CH4 by CO2, N2 and Their Mixture in a Composite Shale Model

Gong, Liang; Zhang, Yuan; Li, Na; Gu, Ze-Kai; Ding, Bin; Zhu, Chuanyong

doi:10.3390/en14010002

Cited by 11 publications

(8 citation statements)

References 34 publications

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“…For example, with increasing temperature from 313.15 to 343.15 K, the displacement efficiency of CH 4 decreases from 62.12 to 59.09%. This demonstrates that a reasonable temperature (temperature of 313.15–323.15 K) accelerates the diffusion rate of CH 4 , which is conducive to enhancing the efficiency of CH 4 recovery by injecting CO 2 . − …”

Section: Discussionmentioning

confidence: 85%

“…The average diffusion rate of the CH 4 molecule is reduced from 4.4 × 10 –8 to 1.605 × 10 –8 m 2 /s, decreasing by about 1.7 times. Since the amount of CO 2 injected into the pores increases, the intermolecular van der Waals forces, viscosity, and volume expansion become stronger, which hinder the diffusion rate of CO 2 for displacing CH 4 . , In addition, there is a limited specific surface area in micropores. Increasing the injection amount of CO 2 increases the probability of intermolecular collisions and limits the average diffusion rate for intermolecular collisions .…”

Section: Discussionmentioning

confidence: 99%

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Enhancing the Efficiency of Coal Bed Methane Recovery by Injecting Carbon Dioxide Based on an Anthracite Coal Macromolecular Model and Simulation Methods

Shen

Meng

2022

Energy Fuels

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Enhancing the efficiency of coal bed methane (CBM) recovery by injecting carbon dioxide (CO2) is regarded as an effective method to exploit CBM, and CO2 geological sequestration also mitigates greenhouse gas emissions. In this study, 13C nuclear magnetic resonance (13C NMR) spectroscopy, Fourier transform infrared (FTIR) spectroscopy, and X-ray photoelectron spectroscopy (XPS) experiments are employed to construct a two-dimensional (2D) chemical molecular structure. The 2D chemical molecular structure is annealed and geometrically optimized to construct a three-dimensional (3D) anthracite molecular model by molecular simulations. The CH4/CO2 mixed gas competitive adsorption and displacement of CH4 by injecting CO2 in an anthracite coal molecular model is investigated by Grand Canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations. The simulation results show that CO2 is easier to adsorb than CH4, which is conducive for CO2 to have an advantage in competitive adsorption at a temperature of 303.15 K and a pressure of 10 MPa. The total amount of CH4/CO2 mixed gas is higher in small pores than in large pores at a pressure of less than 1 MPa. Simultaneously, the MD simulation result reveals that the displacement efficiency of CH4 recovery by injecting 10 MPa CO2 into a 1 nm pore was enhanced by about 73.08% at the temperature of 303.15 K. These research results will help to realize CO2-enhanced coal bed methane (ECBM) recovery at the microscopic level and geological CO2 sequestration to reduce environmental pollution.

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Section: Discussionmentioning

confidence: 85%

Section: Discussionmentioning

confidence: 99%

Enhancing the Efficiency of Coal Bed Methane Recovery by Injecting Carbon Dioxide Based on an Anthracite Coal Macromolecular Model and Simulation Methods

Shen

Meng

2022

Energy Fuels

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“…Lee et al constructed a composite shale model containing quartz and CNTs regions, in which CNTs and quartz were hydrophobic and hydrophilic, respectively . Gong et al built a composite shale model consisting of two kaolinite layers and two kerogen II-D layers to study the displacement characteristics of CH 4 by CO 2 , as shown in Figure . It was found that the increase of formation temperature and pore size could improve the displacement efficiency of CH 4 .…”

Section: Molecular Models Of Shalementioning

confidence: 99%

A Review of Molecular Models for Gas Adsorption in Shale Nanopores and Experimental Characterization of Shale Properties

Zhang

Xin

et al. 2023

ACS Omega

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Shale gas, as a promising alternative energy source, has received considerable attention because of its broad resource base and wide distribution. The establishment of shale models that can accurately describe the composition and structure of shale is essential to perform molecular simulations of gas adsorption in shale reservoirs. This Review provides an overview of shale models, which include organic matter models, inorganic mineral models, and composite shale models. Molecular simulations of gas adsorption performed on these models are also reviewed to provide a more comprehensive understanding of the behaviors and mechanisms of gas adsorption on shales. To accurately understand the gas adsorption behaviors in shale reservoirs, it is necessary to be aware of the pore structure characteristics of shale reservoirs. Thus, we also present experimental studies on shale microstructure analysis, including direct imaging methods and indirect measurements. The advantages, disadvantages, and applications of these methods are also well summarized. This Review is useful for understanding molecular models of gas adsorption in shales and provides guidance for selecting experimental characterization of shale structure and composition.

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“…Shale gas in overmature shale is stored mainly as free gas and adsorbed gas, and the proportion of adsorbed gas can reach 20-85% [27][28][29]. High-pressure adsorption experiments are considered a common method to evaluate the adsorption capacity of shale and have been widely applied by many scholars [30][31][32][33]. At present, the previous studies mainly focused on the lower Paleozoic marine shales in the Upper Yangtze region.…”

Section: Introductionmentioning

confidence: 99%

Methane Storage Capacity of Permian Shales with Type III Kerogen in the Lower Yangtze Area, Eastern China

et al. 2022

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Marine–terrestrial transitional Permian shales occur throughout South China and have suitable geological and geochemical conditions for shale gas accumulation. However, the Permian shales have not made commercial exploitation, which causes uncertainly for future exploration. In this study, high-pressure methane (CH4) adsorption experiments were carried out on the Permian shales in the Lower Yangtze area, and the influences of total organic carbon (TOC) content and temperature on adsorption parameters were investigated. The characteristics and main controlling factors of methane storage capacity (MSC) of the Permian shales are discussed. The results show that the maximum adsorption and the adsorbed phase density of these Permian samples are positively correlated with TOC contents but negatively correlated with temperatures. The pores of organic matter in shale, especially a large number of micropores and mesopores, can provide important sites for methane storage. Due to underdeveloped pore structure and poor connectivity, the methane adsorption capacities of the Permian shales are significantly lower than those of marine shales. Compared with the Longmaxi shales, the lower porosity and lower methane adsorption of the Permian shales are reasonable explanations for their lower gas-in-place (GIP) contents. It is not suitable to apply the index system of marine shales to the evaluation of marine–terrestrial transitional shales. The further exploration of Permian shales in the study area should be extended to overpressure stable reservoirs with high TOC contents (e.g., >5%), high porosity (e.g., >3%), and deep burial (e.g., >2000 m).

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Molecular Investigation on the Displacement Characteristics of CH4 by CO2, N2 and Their Mixture in a Composite Shale Model

Cited by 11 publications

References 34 publications

Enhancing the Efficiency of Coal Bed Methane Recovery by Injecting Carbon Dioxide Based on an Anthracite Coal Macromolecular Model and Simulation Methods

Enhancing the Efficiency of Coal Bed Methane Recovery by Injecting Carbon Dioxide Based on an Anthracite Coal Macromolecular Model and Simulation Methods

A Review of Molecular Models for Gas Adsorption in Shale Nanopores and Experimental Characterization of Shale Properties

Methane Storage Capacity of Permian Shales with Type III Kerogen in the Lower Yangtze Area, Eastern China

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