Methane Adsorption In Shale Research Articles

Effect of supercritical carbon dioxide on pore structure and methane adsorption of shale with different particle sizes

Supercritical carbon dioxide (SCCO2) fracturing significantly enhances shale gas recovery, which is influenced by particle size. We soaked shale in SCCO2 and investigated the impact of SCCO2 on different particle sizes. Large-particle shales showed the largest percentage changes in specific surface area and total pore volume (54.11 %, 87.87 %; 58.59 %, 76.32 %) followed by small-particle size shales. This trend was also observed in other pore structure parameters. The particle-size effect is: Large-particle shale, with abundant microfractures, enhances SCCO2 flow and pore alteration. Small-particle shale's high specific surface area facilitates SCCO2 penetration. Medium-particle shale is less affected due to balanced interactions of these factors. Methane is primarily found in large and medium pores and microfractures. Methane adsorption in shale mainly involves multi-layer adsorption. Following SCCO2 treatment, pore fractures narrowed, increasing the proportion of methane molecules adsorbed as a single-layer. This study is crucial for evaluating the fracturing effects on shale gas wells.

Measurement and modeling of moisture equilibrium and methane adsorption in shales from the southern Sichuan Basin

The adsorption characteristic of methane in water-bearing shale is essential for the accurate estimation of shale gas reserves. The sorption mechanisms of moisture and methane in shale remain poorly understood. In this work, moisture equilibrium measurements in shales were conducted to study moisture absorption characteristics. The governing factors for moisture absorption were determined, and the suitability of moisture absorption models was evaluated. An innovative water saturation apparatus and an improved methane adsorption system were built to measure methane adsorption in high water-bearing shales. The suitability of the Langmuir model in describing methane adsorption in water-bearing shale was studied. A predictive model for methane adsorption in water-bearing shale was developed based on improved BP neural network algorithm, which was further utilized to determine the primary governing factors for methane adsorption. The results revealed that the equilibrated moisture content in shale presents a three-stage and S-type ascending trend with increasing relative humidity. The methane adsorption amount shows a slide-type downward trend with the increase of water content. The Peleg model demonstrates the superior performance in describing the hygroscopic isotherms, and the Langmuir model performs poorly in characterizing methane adsorption in shales with high water contents. The controlling factors for the ultimate moisture content mainly include specific surface area, average pore diameter, carbonate and pyrite content. The methane adsorption in water-bearing shale is mainly governed by water content and specific surface area. The results of this work enrich the understanding of the adsorption mechanisms of shale gas and provide a solid basis for the assessment of shale gas reserves.

Machine learning method for shale gas adsorption capacity prediction and key influencing factors evaluation

Shale gas plays a pivotal role in the global energy landscape, emphasizing the need for accurate shale gas-in-place (GIP) prediction to facilitate effective production planning. Adsorbed gas in shale, the primary form of gas storage under reservoir conditions, is a critical aspect of this prediction. In this study, a machine learning Gaussian process regression (GPR) model for methane adsorption prediction was established and validated using published experimental data. Five typical variables, i.e., total organic carbon (TOC), clay minerals, temperature, pressure, and moisture were considered, which were derived from the Marine shale of the Longmaxi formation in the Sichuan Basin through correlation analysis. The performance of the GPR model was compared with the widely used an extreme gradient boosting model. It turned out that our GPR model had better accuracy for predicting methane adsorption in shale with an average relative error of less than 3%. Furthermore, a variance-based sensitivity analysis method in conjunction with kernel density estimation theory was employed to conduct a global sensitivity analysis, quantifying the nonlinear influence of each variable methane adsorption. The findings indicate that TOC is the most significant factor affecting methane adsorption, while clay minerals have a limited direct impact but can enhance their influence through interactions with other influencing factors. Finally, based on the GPR model, a GIP prediction method was proposed that eliminates the need for calculating the density of the adsorbed phase. These findings are expected to extend the shale gas reserve assessment methodologies and offer valuable insight for further exploring the adsorption mechanisms of shale gas.

A developed dual-site Langmuir model to represent the high-pressure methane adsorption and thermodynamic parameters in shale

Comprehending the mechanism of methane adsorption in shales is a crucial step towards optimizing the development of deep-buried shale gas. This is because the methane adsorbed in shale represents a significant proportion of the subsurface shale gas resource. To properly characterize the methane adsorption on shale, which exhibits diverse mineral compositions and multi-scale pore sizes, it is crucial to capture the energy heterogeneity of the adsorption sites. In this paper, a dual-site Langmuir model is proposed, which accounts for the temperature and pressure dependence of the density of the adsorbed phase. The model is applied to the isothermals of methane adsorption on shale, at pressures of up to 30 MPa and temperatures ranging from 40 to 100 °C. The results show that the proposed model can describe the adsorption behavior of methane on shale more accurately than conventional models, which assume a constant value for the density of adsorbed phase. Furthermore, the proposed model can be extrapolated to higher temperatures and pressures. Thermodynamic parameters were analyzed using correctly derived equations. The results indicate that the widely used, but incorrect, equation would underestimate the isosteric heat of adsorption. Neglecting the real gas behavior, volume of the adsorbed phase, and energy heterogeneity of the adsorption sites can lead to overestimation of the isosteric heat of adsorption. Furthermore, the isosteric heat evaluated from excess adsorption data can only be used to make a rough estimate of the real isosteric heat at very low pressure.

Quantitative characterization of methane adsorption in shale using low-field NMR

Quantification of methane content in shales is a critical parameter for estimation of their potential gas production capacity. Traditional gravimetric methods for estimation of this quantity are sensitive only to adsorbed methane and are difficult to apply either to intact shale rock cores or via field measurements. Here non-invasive low-field nuclear magnetic resonance (LF-NMR) is applied to quantify excess methane adsorption capacity in two intact shale rock plugs at pressures up to 150 bar; validation is provided against destructive gravimetric methods performed on fragments from the same shale rock plugs. The resultant NMR transverse relaxation time (T2) distributions contain three distinct peaks (referred to as peaks P1 – P3) which are allocated to adsorbed methane in organic pores, methane constrained to inorganic pores and bulk methane located predominately in fractures, respectively. The area of peak P1 is observed to increase with pressure up to 100 bar, after which it reaches a plateau, whilst the area of peaks P2 and P3 both increase linearly with pressure up to 150 bar. The most accurate estimate of excess methane adsorption capacity is obtained via a combination of an overall system mass balance and the methane located in inorganic pores and fractures (peaks P2 and P3, respectively), where excellent agreement is produced with corresponding gravimetric measurements for both shale samples studied.

Comparative study of methane adsorption of Middle-Upper Ordovician marine shales in the western Ordos Basin, NW China: Insights into impacts of moisture on thermodynamics and kinetics of adsorption

Impacts of water molecules on subsurface shale gas adsorption is a challenging topic in the assessment of shale gas resources and the selection of optimized exploitation plans. And scholars have recognized that water molecules occupy adsorption sites on hydrophilic pore walls. However, the impacts of water molecules on the thermodynamics and kinetics of methane adsorption in shales remains poorly understood. We document a series of high-pressure methane adsorption isotherms of dry and moisture-equilibrated samples of the Middle-Upper Ordovician Wulalike shale at 20–120 °C and up to 30 MPa. Quantitative analyses of the thermodynamic and kinetic characteristics are carried out. Results show that water molecules do not change the impacts of temperature and pressure on the trend of isotherms, thermodynamics, and kinetics of methane adsorption. The impacts of temperature, pressure, methane adsorption capacity, and water molecules on the methane adsorption are basically functioned by modifying the interactions between the adsorbate and the adsorbent. The presence of water molecules in shales leads to a decrease of ∼ 77.06% in the capacity of methane adsorption, an increase of ∼ 70.46% in the adsorption heat (Qst), a decrease of ∼ 96.62% in the standard entropy (△S0), and a decrease of ∼ 1/9 to 1/5 in the Bangham adsorption rate (kb). The impacts of water molecules on the decline of methane adsorption at high pressure is lower than that at low pressure, however, on the decrease of methane adsorption rate higher than that at low pressure. The study also reflects the methane adsorption into the three-dimensional network system of kerogen. This work can improve our understanding of subsurface supercritical adsorption under reservoir conditions.

On the prediction of methane adsorption in shale using grey wolf optimizer support vector machine approach

With the advancement of technology, gas shales have become one of the most prominent energy sources all over the world. Therefore, estimating the amount of adsorbed gas in shale resources is necessary for the technical and economic foresight of the production operations. This paper presents a novel machine learning method called grey wolf optimizer support vector machine (GWO-SVM) to predict adsorbed gas. For this purpose, a data set containing temperature, pressure, total organic carbon (TOC), and humidity has been collected from several sources, and the GWO-SVM model was created based on it. The results show that this model has R-squared and root mean square error equal to 0.982 and 0.08, respectively. Also, the results ensure that the proposed model gives an excellent prediction of the amount of adsorbed gas compared to previously proposed models. Besides, according to the sensitivity analysis, among the input parameters, humidity has the highest effect on gas adsorption.

Dynamic model for the simultaneous adsorption of water vapor and methane on shales

Water is almost ubiquitous in shale gas reservoirs. To analyze simultaneous water vapor and methane adsorption in shales, a dynamic model with a time-dependent boundary and diffusivity and a noninstantaneous adsorption mechanism was proposed. The analytical solution of the model was obtained via integral transformation method. The model was applied to match the dynamic data of simultaneous CH4–H2O adsorption. The results suggest that the strength for gas adsorption to shale is characterized by adsorption rate coefficient and desorption rate coefficient, where the adsorption strength of shale to water vapor is stronger than that to methane, and the conversion rate from water vapor to adsorbed water on adsorption sites is larger. The methane and water vapor diffusion coefficients first increase to a maximum and then decrease with time. The maximum methane diffusion coefficient ranges from 5.83 × 10−13–1.08 × 10−11 m2/s; the maximum water vapor diffusion coefficient ranges from 2.06 × 10−19–4.53 × 10−13 m2/s. The methane diffusivity and its variation rate are larger than those of water vapor. The methane and water vapor diffusion coefficients first increase with the density of free gases in pores and then decrease in the late period of the adsorption process. Water vapor reduces the adsorption strength of shale to methane and free methane-to-adsorbed methane conversion rate on adsorption sites. The methane diffusion coefficient in dry shale increases with time, and its growth rate reaches zero at adsorption equilibrium, which ranges from 6.60 × 10−14–4.82 × 10−11 m2/s; the methane diffusivity increases exponentially with the methane adsorption amount and free methane density in pores.

The effect of water vapor on methane adsorption in the nanopores of shale

Water plays an essential role in shale gas migration and adsorption, and most studies on the influence of water on shale gas adsorption refer only to moisture-equilibrated shales. To investigate the impact of water vapor on methane adsorption in shales, three experiments were conducted and compared: (1) pure methane adsorption onto dry shale (PMD), (2) pure methane adsorption onto moisture-equilibrated shale (PMMS), and (3) simultaneous adsorption of water vapor and methane (SAWM) onto shale. The experimental results reveal that the detrimental impact of water vapor on methane adsorption is inferior to that of preadsorbed water. Two mechanisms, water blocking and adsorption competition, are responsible for the reduction and difference in the methane adsorption capacity and adsorption rate between PMMS and SAWM. Compared to PMD, the methane adsorption capacity decreases by 81–96% in PMMS and by 20–49% in SAWM. Methane adsorption equilibrium is achieved the fastest in PMD. Before the equilibration degree reaches 95%, methane adsorption during SAWM progresses more rapidly, while the reverse occurs when the equilibration degree exceeds 95%. Water vapor can impact micropores more easily during the premoistening process, which obviously lowers methane adsorption. The adverse effect of water vapor on micro-to mesopores is inhibited by high methane partial pressure in SAWM. In PMMS, adsorbed water mainly occupies micropores (0.3–1.5 nm), and methane is adsorbed in pores larger than 1.5 nm. In SAWM, methane preferentially occupies micropores; the competition between methane and water vapor is mainly concentrated in mesopores (1.5–20 nm).

Synergetic Effect of Water, Temperature, and Pressure on Methane Adsorption in Shale Gas Reservoirs.

Adsorption is one of the most important forms of storage of gas in shale reservoirs. Shale gas adsorption in the actual reservoir is not only affected by individual factors such as water content, temperature, and pressure but also by the synergetic effect of these factors. In this study, we conducted laboratory experiments on methane adsorption in dry and wet shale at different pressures and temperatures. The synergetic effect of water content, temperature, and pressure on shale gas adsorption is explored. The results show that increasing temperature weakens the interaction between methane and shale and reduces adsorption capacity due to the exothermic nature of adsorption. Water reduces methane adsorption capacity by occupying adsorption sites and blocking pores in the shale system. Although temperature and water reduce methane adsorption individually, the effect of these two factors weakens each other. Temperature has a more significant effect on methane adsorption in shales with low water content, while water has a more remarkable impact on methane adsorption at a low temperature. Furthermore, the increase in pressure reduces the negative influence of water and temperature on methane adsorption. By quantitatively analyzing the relationship between methane adsorption in dry and wet shales, a predictive adsorption model for wet shale considering the influence of in situ conditions is proposed and validated. Validation shows that the proposed model has high accuracy and broad applicability to shales with different properties.

Experimental investigation of methane adsorption and desorption in water-bearing shale

Methane adsorption and desorption in shale can significantly be affected by water due to the water-bearing depositional environment of shale and the application of hydraulic fracturing technology in shale gas production. The characteristics of shale gas adsorption and desorption are comprehensively affected by the temperature, pressure, and especially, the water content in the reservoir. To further explore the impact of water on shale gas adsorption and desorption, the adsorption-desorption experiments of methane in water-bearing shale at different temperatures and different pressures are performed. Afterward, the adsorption behavior and desorption hysteresis are characterized by employing the Langmuir model and Langmuir+λ model. Finally, the ways of the pressure, temperature, and water combinedly affect shale gas adsorption behavior and desorption hysteresis are analyzed. The results show that adsorption and desorption of methane in the water-bearing shale are irreversible, which are consistent with the Langmuir model and the Langmuir+λ model, respectively. An increase in temperature will reduce adsorption and promote desorption, as an increase in temperature essentially enhances the thermal movement of methane molecules. Water lowers the adsorption and desorption of methane in shale, as the water molecules occupy the adsorption sites in organic pores and clay mineral pores in different ways. However, the effect of temperature and water content on adsorption is closely related to the pressure. The lower the pressure, the more significant the effect of temperature and water content. The combined effect analysis demonstrates that the impact of water on methane adsorption in shale is much more significant than that of the temperature. Still, desorption is simultaneously affected by both temperature and water content. As the pressure decreases in the desorption process, the desorption rate is dominantly affected by water when the pressure is lower than 8 MPa, and the desorption rate is aggressively affected by temperature when the pressure is at above 8 MPa. Cited as : Li, A., Han, W., Fang, Q., Memon, A., Ma, M. Experimental investigation of methane adsorption and desorption in water-bearing shale. Capillarity, 2020, 3(3), 45-55, doi: 10.46690/capi.2020.03.02

Prediction of methane adsorption in shale: Classical models and machine learning based models

Shale gas contributes significantly to current global energy consumption, and an accurate estimation of geological gas-in-place (GIP) determines an optimal production plan. As the dominant form of storage, adsorbed gas in shale formation is of primary importance to be assessed. This paper summarizes adsorption models into traditional pressure/density dependent isothermal models, pressure and temperature unified model, and machine learning based models. Using a comprehensive experimental dataset, these models are applied to simulate shale gas adsorption under in-situ conditions. Results show that the modified Dubinin-Radushkevich (DR) model provides the optimal performance in traditional isothermal models. Pressure and temperature unified models make a breakthrough in isothermal conditions and can extrapolate the predictions beyond test ranges of temperature. Well-trained machine learning models not only break the limit of the isothermal condition and types of shale formation, but can also provide reasonable extrapolations beyond test ranges of temperature, total organic carbon (TOC), and moisture. Four popular machine learning algorithms are used, which include artificial neural network (ANN), random forest (RF), support vector machine (SVM), and extreme gradient boosting (XGBoost). The XGBoost model is found to provide the best results for predicting shale gas adsorption, and it can be conveniently updated for broader applications with more available data. Overall, this paper demonstrates the capability of machine learning for prediction of shale gas adsorption, and the well-trained model can potentially be built into a large numerical frame to optimize production curves of shale gas.

Microscopic mechanism of methane adsorption in shale: Experimental data analysis and interaction potential simulation

The adsorbed methane in shale determines the geological reserves of shale gas and production of the well. Therefore, it is of great importance to clarify the microscopic mechanism of methane adsorption in shale for evaluating the geological condition and formulating exploitation plan. In this study, the experimental data and the simulation result were combined to research the microscopic mechanism of methane adsorption in shale. The experimental data for 99 groups of low-temperature nitrogen adsorption and methane isothermal adsorption were collected, to calculate the number of adsorption layers of methane in shale at the micro-level. The surface, microfracture and micropore structures of the organic matter in shale were constructed by graphite structure with the hydroxyl group. Thereafter, they were used to simulate the interaction potential of the organic matter on methane molecules and the adsorption layer's number by using the theory of intermolecular interaction potential field. Furthermore, the effects of different fracture widths and pore diameters on methane adsorption were analyzed and verified. The results show that the adsorption capacity of methane in shale is related to shale's structure, and the order of the adsorption capacity is surface < microfracture < micropore. Meanwhile, the multilayer adsorption can occur in microfractures with a width of 1.44–1.59 nm and micropores with a diameter of 1.49–1.83 nm, whereas the surface structure just can be the monolayer adsorption. These quantitatively results establish a foundation for the development of adsorption theory for methane in the shale.

Methane adsorption capacity of shale samples from Western Australia

To examine the influence of clay minerals on methane adsorption in shales, shale samples with low total organic carbon (TOC), ranging from 0.23 to 3.2 wt%, were collected from the Canning and Perth basins, Western Australia. The collected shale samples were measured on gas adsorption experiments: high-pressure methane adsorption and low-pressure nitrogen and carbon dioxide adsorption. Geological controlling factors of methane adsorption capacity for the studied samples were analysed based on a classification of TOC: low-TOC (<1.5 wt%) and high-TOC (>1.5 wt%) samples. The results show that the contribution of organic matter to the methane adsorption capacity of the studied samples is limited. The clay content appears to have a good relationship with the methane adsorption capacity, especially for the low-TOC (<1.5 wt%) samples, which is also supported by the Brunauer–Emmett–Teller surface area. TOC-normalised methane adsorption capacity decreases with increasing thermal maturity for the high-TOC (>1.5 wt%) samples. Furthermore, adsorption affinity of methane, described by the reciprocal of Langmuir pressure, is positively related to the micropore volume and Tmax for the high-TOC samples (>1.5 wt%).(1) A weak relationship exists between TOC and methane adsorption capacity and clay minerals dominate methane adsorption capacity for low TOC (<1.5 wt%) shale samples.(2) Methane adsorption capacity per wt% TOC decreases with increasing thermal maturity for high TOC samples and may result from changes in surface chemistry or roughness of pores.(3) Affinity of adsorption for the high TOC samples is positively related to the micropore volume and thermal maturity.

Characterization of the combined effect of high temperature and moisture on methane adsorption in shale gas reservoirs

With a significant amount of methane stored in shales in the form of adsorbed gas, it is important to understand the controlling factors of the methane adsorption capacity. Under actual reservoir conditions, the high temperature and moisture are always coexisting which can affect gas adsorption capacity. This paper studied the methane adsorption of shale at different temperatures in dry and wet conditions. The adsorption results indicated that the moisture and high temperature can reduce the adsorbed gas content in shales individually, and the two factors have a synergistic-negative effect on methane adsorption in shales. Thermodynamic parameters showed that the heat of adsorption shows a decreased tendency and the entropy of adsorption becomes less negative after moisturizing the samples. The combined effect of the two factors is sufficiently important in the evaluation of gas adsorption capacity in shale gas systems.

New perspectives on supercritical methane adsorption in shales and associated thermodynamics

Understanding methane adsorption behavior in shales is fundamental for optimizing shale gas development as the adsorbed methane is a large portion of the subsurface shale gas resource. However, the adsorption mechanism of supercritical methane in shales and associated thermodynamics are poorly understood because the equation of state of the adsorbed methane is unmeasurable. This work analyzed adsorption equilibria (up to 32MPa and 393.15K) using a rigorous framework that can account for non-ideal gas properties and accurately extrapolate absolute adsorption uptakes from measured adsorption isotherms. The framework also allows a straightforward calculation of thermodynamic potentials relevant to adsorption such as enthalpy and entropy. Modelling results show that methane adsorption isotherms in shale under different pressures and temperatures are represented by a two dimensional adsorption isotherm surface. The density of the adsorbed methane in shales depends on temperature and pressure, which is always lower than the liquid methane density but higher than the corresponding gaseous methane density. The temperature-dependent and pressure-dependent characteristics of adsorbed methane density leads to the corresponding temperature-dependent and pressure-dependent measured/absolute adsorption isotherms. The maximum adsorption uptake of shales is independent of temperature and pressure. The isosteric enthalpy/entropy of adsorption and enthalpy/entropy of adsorbed methane are found to be temperature- and surface coverage-dependent. These new findings therefore not only clarify some historical misunderstandings of methane adsorption in shales for engineering application, but also provide a novel framework for interpreting methane adsorption behavior in shales and for determining the associated thermodynamics.

A method to determine the permeability of shales by using the dynamic process data of methane adsorption

Permeability is a critical parameter to evaluate the gas migration and development of shales, however, very difficult to get at the laboratory. Methane adsorption in shales is also an important factor of shales in natural state. A method of permeability that considers methane adsorption is described in this study. Permeability is derived from the dynamic data of the methane adsorption equilibrium process. The carboniferous shale samples, C01, C02, C03 and C04, were extracted from the eastern Qaidam Basin in China. The properties of the shales including organic/inorganic matter contents and pore size distribution were obtained by several techniques. Methane adsorption experiments were conducted on crushed shale samples over a pressure range up to 10 MPa and at a temperature of 313.15 K. Additionally, the permeability was calculated using the dynamic data at the adsorption equilibrium. Correlations between the permeability and methane adsorption and sample properties were discussed. The parameters of the calculation process were also analyzed.A parameter called the methane adsorption rate is defined as θ, which represents the variation in methane adsorption amount with pressure. The permeability is found to have the same variation trend with θ at experimental pressures before the inflection point. The pressure relative to the inflection point decreases with the micropore volume percentage, and the permeability increases with the methane adsorption affinity for the sample, nmax. We found that the permeability before the inflection point is considered to represent the micropores permeation property. The methane adsorption rate decreases to an infinitesimal value until the adsorption reaches a saturated state. The permeability values are assumed will stop fluctuating and become a fixed value, which we call kf. The parameter kf is regarded as the true permeability of the sample. The assumption gives a novel idea of permeability calculation. In addition, the permeability of the samples increases with the macropore volume, and the methane adsorption capacity nmax also increases with the total porosity.

A Prediction Model for Methane Adsorption Capacity in Shale Gas Reservoirs

Estimation of methane adsorption capacity is crucial for the characterization of shale gas reservoirs. The methane adsorption capacity in shales is measured using high-pressure methane adsorption to obtain the adsorption isotherms, which can be fitted by Langmuir model. The determined Langmuir parameters can provide the methane adsorption capacity under actual reservoir conditions. In this study, a prediction model for the methane adsorption in shales was constructed based on 66 samples from 6 basins in China and Western Australia. The model was established in four steps: a model of Langmuir volume at experimental temperature, the temperature dependence of Langmuir volume, a model of Langmuir pressure, the temperature dependence of Langmuir pressure. In the model of Langmuir volume at experimental temperature, total organic carbon (TOC) and clay content (Vsh) were considered. A positive relationship was observed between the TOC and the temperature effect on the Langmuir volume. As the Langmuir pressure is sensitive to various factors, the Langmuir pressure at experimental temperature shows no trend with the TOC, clay content and thermal maturity, but a positive trend with the Langmuir volume. The results of this study can help log analysts to quantify adsorbed gas from well-log data since TOC and Vsh, which are the measure inputs of the introduced models, can be obtained from well-log data as well.

Mechanism of methane adsorption on groove space in organic matter surface

ABSTRACTOrganic matter plays an important role in methane adsorption in shale. Pore surface of organic matter is usually rough and uneven, which results in a large amount of groove space on the pore surface. Thus, the influence of groove space on the adsorption capacity of methane in shale cannot be neglected. Nanoscale pore structures of the organic-rich shale in the Longmaxi Formation were investigated by low-pressure nitrogen gas adsorption as a basis for constructing models. We simplified the internal groove space into triangular prisms with different angles. The grand canonical Monte Carlo simulation and molecular dynamics simulation were used to analyse the methane molecule adsorption behaviour in pores. The results showed that the pore morphology of organic-rich shale in the Longmaxi Formation was mainly slit-shaped pores. The excess adsorption isotherms showed good agreement between experiment and simulation, indicating that the model is suitable and reliable. Methane molecules can enter into the groove space with an opening size of 0.738 nm, while they fail to enter into groove spaces with an opening size less than 0.492 nm. This understanding has important significance for the study of the adsorption characteristics of organic pores which have undergone multiple evolutions in geological history.

A multi-site model to determine supercritical methane adsorption in energetically heterogeneous shales

A multi-site adsorption model was employed to determine the supercritical methane adsorption in shales, in which the heterogeneity of surface energy distribution was considered. Additionally, the high-pressure (∼20 MPa) methane adsorption behaviors at different temperature conditions (303 K, 333 K and 363 K) were experimentally investigated, and both the traditional single-site model and the multi-site model were employed to analyze the experimental data. Results show that (i) although these two models can achieve acceptable fitting results with the measured adsorption amounts, the adsorption heat interpreted by them shows significant discrepancy. The adsorption heat calculated by the single-site model is always a constant, while it obtained by the multi-site model decreases with an increase in surface coverage. This coverage-dependent heat directly indicates the nature of the surface-energy heterogeneity of our studied shale samples. (ii) The adsorption heat at the zero-coverage limit condition calculated by Henry’s law, indicating the actual adsorbate-adsorbent interaction, is significantly larger than that calculated by the single-site model; but the zero-coverage heat can be well matched with the value determined by the multi-site model. Therefore, the present multi-site model can accurately depict not only the adsorption isotherms but also the thermodynamic parameters in energetically heterogeneous shales.