Simplified Local Density Research Articles

Study on the minimum miscibility pressure and phase behavior of CO2–shale oil in nanopores

In recent years, CO2 enhanced oil recovery has gained traction in shale oil reservoirs. Shale oil reservoirs are characterized by numerous nanopores, where shale oil exhibits unique phase behavior due to nano–confinement effects. Traditional theoretical model and microfluidic experiment often fail to accurately depict the minimum miscible pressure (MMP) of CO2–shale oil in nanopores. In this study, nanofluidic experiments were conducted to investigate the MMP of CO2–alkanes in single pore channels and porous media channels with depths of 30 nm and 100 nm. Additionally, a novel thermodynamic model of gas–liquid–adsorbed phase equilibrium, which considers the capillary force and the shift in the critical property, was developed by integrating simplified local density functional theory. The feasibility of the method was determined by comparing the measured MMP with the MMP obtained using the newly established thermodynamic model, resulting in errors of 10.804 % and 5.545 %. Finally, phase behavior and MMP for two typical oil samples in block A in China were conducted using the newly established thermodynamic model. The results revealed that as the pore radius decreases, the area of the two–phase region enclosed by the phase envelope contracts progressively. In addition, the saturation pressure decreases gradually for shale oil with a higher content of light components as the molar fraction of the injected CO2 increases, whereas for shale oil with higher heavy component content, it increases as the CO2 molar fraction increases. The MMP of CO2–shale oil in 10 nm pores is 70.188 bar at 392.75 K of sample 1 and 83.007 bar at 374.72 K of sample 2. Compared to the bulk phase, the MMP was reduced by 63.76 % and 57.64 %.

Studies into confined methane adsorption in shale nanopores using a simplified local density model

The large number of nanopores in shale reservoirs provide an effective storage space for gases, which can assist in accurately characterizing the confined adsorption characteristics, including the adsorption amount of fluid in nanopores that is important for a detailed understanding of shale gas storage mechanisms and production prediction. Although the simplified local density (SLD) model has been widely used to describe the behavior of confined adsorption in slit-like pores, its application in relation to cylindrical pores has not been studied in detail. In this study, the importance of fluid–fluid interaction and fluid–solid interaction has been analyzed, with the expressions for the distribution of confined attractive parameter in cylindrical pores are derived by combining with the (3/8)σff assumption to establish a new SLD model. The reliability of the new model was verified by the publicly available experimental methane excess adsorption data for shale at different temperatures and the simulation results from the Grand Canonical Monte Carlo (GCMC). Moreover, by comparing with the SLD model with the slit pore structure, it was found that the adsorption isotherms and the confined fluid density distribution pattern characterized by the SLD model with the cylindrical pores were closer to the actual reservoir conditions of shale. In addition, the densities characterized by SLD models with a (3/8)σff assumption and with a (1/2)σff assumption at different Λb have been discussed and analyzed, and it is found that the selection of a suitable Λb would help to improve the accuracy of SLD model. The results might provide new theoretical insights into confined methane adsorption, with the new SLD model providing better engineering applications in shale gas development, gas storage, and pore structure characterization.

The primary controlling factors of the occurrence state of deep high-rank coalbed methane in eastern Ordos Basin

Introduction: This study investigates the key controlling factors of the occurrence state of deep coalbed methane (CBM). CBM is an abundant energy resource in China, particularly in deep coal seams. However, the exploration and development of deep CBM face numerous challenges, and the understanding of the controlling factors of its occurrence state is still limited.Methods: The study reveals that deep CBM primarily exists in the form of adsorbed gas and free gas within the pore-fracture system of coal. Factors such as formation temperature, formation pressure, pore structure, and water saturation collectively influence the occurrence state of deep CBM. By employing the Simplified Local Density (SLD) model and molecular simulation methods.Results and discussion: This study examines the impact of two external geological control factors (formation temperature, formation pressure) and three internal geological control factors (pore size, water saturation, Specific surface area) on deep CBM and establishes a theoretical model for gas content. Finally, the relationship between the adsorbed gas, free gas, total gas content, and burial depth is calculated using the model, uncovering the primary factors controlling the occurrence state of deep CBM. This research is of significant importance in providing key parameters for gas content in deep coal and optimizing deep CBM exploration.

Distribution of the adsorbed density of supercritical CO2 onto the anthracite and its implication for CO2 geologic storage in deep coal

CO2 geological storage in deep coal has been a research hotspot in carbon capture and storage under the background of carbon neutrality. Understanding supercritical CO2 adsorption onto coals has been significant for accurately evaluating deep coal's CO2 geological storage capacity and further determining the deployment of a CO2-ECBM project. The supercritical CO2 adsorption experiments on dry Qinshui anthracite coal were conducted. The adsorbed CO2 density and average number of adsorbed molecule layers were calculated. The effects of temperature, pressure, and pore size on the density of the adsorbed phase were discussed using the simplified local density (SLD) adsorption model, and the distribution of adsorbed CO2 on the coal surface was disclosed. Finally, the modified method for calculating CO2 geological storage in coal was proposed. The results show that: (1) The average adsorbed density of supercritical CO2 onto the anthracite at the experimental temperatures ranged from 1.073 to 1.088 g/cm3, and the average number of adsorbed molecular layer ranged from 1.15 to 1.26, indicating the coexistence of micropore filling and multilayer adsorption. (2) The SLD theory demonstrated that the distribution of the adsorbed CO2 density is jointly controlled by temperature, pressure, pore size, and CO2 phase. The supercritical CO2 can form a second layer of adsorbed molecules. The minimum pore size to keep the adsorbed CO2 density unchanged on the pore wall is around 0.82 nm for subcritical CO2 and 3 nm for supercritical CO2. (3) The real average adsorbed CO2 density is always lower than that of the first adsorbed molecular layer and the density under extreme pressure. There are four different distributions of free and adsorbed CO2 on the surface of the coal with the changes in temperature and pressure, consisting of subcritical, gas-like supercritical, liquid-like supercritical, and extreme states. (4) The modified method of CO2 storage capacity for coal, based on excess adsorption and equivalent free CO2 in the total pore, avoids the error caused by the uncertainty of adsorbed CO2 density and free space volume. It is recommended that this method should be preferentially adopted during the selection of the potential target area for CO2 geological storage in deep coal. The study aims to provide a new idea for the mechanism of supercritical CO2 adsorption on coal and the assessment of supercritical CO2 geologic storage capacity in deep coal.

Modeling carbon dioxide and methane adsorption on illite and calcite: enhancing the simplified local density model through crystal structure modifications.

The simplified local density (SLD) model has been frequently utilized to describe gas adsorption in porous media. The common assumptions associated with the SLD model are the graphene slit and uniform distribution of atoms. However, these fail to depict the heterogeneous surface of minerals. In this study, the original SLD model was modified by substituting mineral crystal structures for the homogeneous carbon layer when building the slit. The modified model may capture the heterogeneity-induced variation of the fluid-pore interaction potential and adsorbed phase density near the mineral surface. The calculated adsorption isotherms of methane and carbon dioxide on illite and calcite surfaces at 330.15 K were compared with literature experiment data to validate the modified SLD model. For the simulation of gas adsorption isotherms, the modified model predictions agree reasonably well with the previously reported experiment results using the gravimetric method. The calculated density profile in the slit indicates the monolayer adsorption behavior of CH4 and CO2. Based on more precise interaction potentials, the number of regression parameters was reduced to two, and the physical meaning of the model parameters was clarified. Therefore, for estimating hydrocarbon storage in reservoirs, the modified SLD model could be used as an efficient alternative to time-consuming molecular simulation methods.

CO2 storage in organic nanopores with varying widths: Molecular simulation and simplified local density model

Accurately characterizing CO2 adsorption behavior in organic nanopores is a prerequisite for estimating CO2 storage capacity in shale reservoirs with complex pore structures. This study employs grand canonical Monte Carlo (GCMC) molecular simulations to investigate the CO2 adsorption characteristics in organic nanopores with varying widths over a wide range of temperatures and pressures. Based on GCMC simulations, the pore width in the simplified Local-Density (SLD) adsorption model is related to key adsorption parameters, enabling the SLD model to evaluate CO2 storage density rapidly and accurately in organic nanopores under complex reservoir conditions. The research findings suggest that the features of CO2 excess adsorption curves are mainly influenced by temperature and the number of adsorption layers. Higher temperatures and increased adsorption layers result in higher pressure requirements to achieve the CO2 excess adsorption peak. Under high pressures, the number of adsorption layers plays a critical role in enhancing the adsorption capacity. Due to the constraints of pore size, there are fewer adsorption layers in micropores, leading to higher CO2 excess adsorption in mesopores than in micropores under high pressures. In the SLD model, the key parameter Λb decays exponentially with the increase of pore width. The average density of CO2 in the nanopores calculated by the modified SLD model is in good agreement with the simulation results. Finally, the research reveals that smaller organic nanopore widths result in higher CO2 densities, with limited sensitivity to temperature and pressure variations. Low pressure and high temperature reservoir conditions are unfavorable for CO2 storage, but adsorption significantly enhances CO2 storage density in nanopores, particularly in micropores.

Thermodynamic modeling of adsorption of dimethyl sulfide on raw and modified activated carbon by simplified local density model

The simplified local density (SLD) model was employed to analyze the experimental results of the adsorption of dimethyl sulfide (DMS) from a model fuel (n-hexane) on raw and modified walnut shell activated carbon (WSAC) with different impregnated amounts of silver ions (Ag-2, 4, 6, 8, and 10 mass percent). Modified Peng–Robinson equation of state was used in the liquid phase and the 6-12 Lenard Jones (LJ) potential function was implemented to represent the solid-fluid interactions. The LJ parameters for pure DMS and n-hexane were obtained from the Tsonopoulos correlation for the Second Virial coefficient data. Published experimental results of DMS and n-hexane adsorption were used for the physical properties and the molecular parameters needed in SLD model. Excess adsorption amounts of DMS were then calculated and compared with the experimental data. The average absolute deviations (AAD) between the experimental data and calculated results were 0.0072, 0.0727, 0.0377, 0.0601, 0.0605, and 0.0634 mmol/gr adsorbent for WSAC, WSAC-Ag-2, WSAC-Ag-4, WSAC-Ag-6, WSAC-Ag-8, and WSAC-Ag-10, respectively. For the same adsorbents the percent average absolute relative deviation (AARD%) were 14.11, 15.50, 7.70, 15.48, 16.16, and 29.09, respectively. The applicability of the SLD model in liquid-phase adsorption is validated.

Gas adsorptions of geological carbon storage with enhanced gas recovery

Understanding gas adsorptions in porous media is of critical importance to numerous academic research and industrial applications. Here, adsorptions of methane and carbon dioxide, which are primary compositions of natural gas and carbon capture and storage (CCS) processes, on different minerals are specifically investigated and their effects on reservoir productions and carbon storage processes are evaluated. First, an improved simplified local-density (SLD) model is developed to calculate the gas adsorptions by considering the complex porous composition and confinement effects induced phenomena. Then, the improved SLD model is embedded into a self-developed field simulation program to analyse the production processes of a selected large-scale gas reservoir. The proposed improved adsorption model is validated to be accurate for various multiscale minerals at different temperature and pressure conditions. By using the coupling with reservoir numerical simulation, the adsorption model is successfully up-scaled to practical field scale which is efficient and effective for predicting gas productions and analysing relevant influential factors, such as temperature, pressure and reservoir physical properties. The proposed theoretical approach provides strong technical support for future natural gas productions and CCS projects with its capability of calculating gas adsorptions on different minerals and practical gas field productions.

Wettability Impact on Nanoconfined Methane Adsorption Behavior: A Simplified Local Density Investigation

Wettability Impact on Nanoconfined Methane Adsorption Behavior: A Simplified Local Density Investigation

An adsorption model for cylindrical pore and its method to calculate pore size distribution of coal by combining NMR

Coalbed methane (CBM) adsorption is closely related to pore size distribution in coal, the study of its adsorption state and pore characteristics of coal are of great significance to its exploitation and storage. In this paper, an extended simplified local density adsorption (SLD) model is proposed, which can be applied to cylindrical pores. Combining with the nuclear magnetic resonance (NMR) tests, the extended SLD model can predict the adsorption amount and pore size distribution of the whole sample without destroying its original pore structure. Three coal samples collected from different areas are selected for NMR test to measure T2 distribution and Magnetic Resonance Imaging (MRI) image. Then, the adsorption amount of the samples are obtained under constant temperature and different pressures. The fitting coefficients of the extend SLD model and experimental data of the three samples are all greater than 0.99, indicating that the proposed model matches the experimental results well. The two parameters obtained by fitting, transverse surface relaxivity (K) and the total number of pore (N), combined with T2, can get the radius and number of each pore in the sample. The inversion results show that the number summation of micropores and mesopores of the three samples are all exceeds 99%. However, due to the small pore size of micropores and mesopores, the pore volume summation of the three coal samples occupied by fractures and macropores are all over 27%. Further observation of cylindrical pore size and fluid molecular position shows that the distance between fluid-solid molecules is the main factor affecting the adsorption. The results of this paper are beneficial to predict and calculate the adsorption amount and pore size distribution of coal.

Apparent diffusion coefficient for adsorption-controlled gas transport in nanoporous media

We present an apparent diffusion coefficient derived from a diffusion-based mass conservation equation for single-component gas transport in nanoporous media. Multiple transport and storage mechanisms have been considered, including Knudsen diffusion and viscous flow for the free phase and surface diffusion and multilayer adsorption for the sorbed phase. The real gas effect, confinement effect, and dynamic adsorption layer thickness are also considered. A pore-scale simplified local density method is utilized to obtain sorbed phase properties, such as volume fraction, concentration, and adsorption isotherm. The developed apparent diffusion coefficient is applied to investigate the effects of fluid–solid attraction, fluid–solid species, and pore sizes on the gas diffusion and adsorption in nanoporous media. The results reveal that the sorbed phase occupies a significant volume of nanopores, and the entire pore space becomes sorbed-phase volume in pores with diameters ≤ 2 nm. The total mass transport in these pores is dominated by surface diffusion, and free-phase diffusion contribution increases as the pore size increases. Furthermore, in strong adsorption systems such as CO2-coal, the apparent diffusion coefficient is up to two orders of magnitude smaller than in weak adsorption systems (e.g., N2-coal and CH4-coal). This is attributed to the reduced free-phase volume fraction and increasing adsorption capacity. The proposed apparent diffusion coefficient can be used in the diffusion-based models for gas transport in nanoporous media.

Adsorption equilibrium modelling for different temperature conditions and its influence on adsorption mass transfer

The paper deals with numerical modelling of adsorption kinetics in a narrow channel of a honeycomb type adsorber. The mass transfer model consists of solving the diffusion-convection transport equation for adsorbate species in the fluid phase. The adsorbate flux to the wall is computed implicitly by using the Boundary Element Method for the solution of the transport equation. Scalable boundary condition for the adsorbate concentration on the adsorbent walls is used, defined on basis of the ratio of the accumulated adsorbate mass and the equilibrium adsorbate mass for a given system temperature. As the state of equilibrium is dependent also on the system temperature, a sensitivity study of the adsorption process under different system temperatures is performed. Among the studied adsorption equilibria models, including the Freundlich model, Simplified local density (SLD) model and the Dubinin-Radushkevich model, the latter is proved as the best compromise between accuracy and computational cost and applied in mass transfer kinetics computations. The results of computations show, that the increase in system temperature results in a decrease of breakthrough times, as the equilibrium amounts of adsorbate at the adsorbent walls decrease with increasing temperature, therefore making the derived numerical model suitable for further use in detailed mass transfer kinetics computations.

Reconstructions of supercritical CO2 adsorption isotherms and absolute adsorption estimation in nanoporous coals considering volumetric effects and varying adsorbed phase densities

• Adsorbed phase density and fugacity facilitate identifying the adsorption mechanisms. • SLD-PR model is efficient in obtaining adsorbed phase density at various pore sizes. • Excess adsorption isotherms are effectively rebuilt considering volumetric effects. • Absolute adsorption amounts are calculated accurately and reasonably considering PSD. • Empirical adsorbed densities for engineering practice are proposed through iteration. Understanding supercritical CO 2 (ScCO 2 ) adsorption behavior in nanoporous coals is crucial for long-term CO 2 geological storage. Four coal samples with a broad spectrum in rank were selected to obtain CO 2 excess adsorption isotherms at 35 ℃ and pressure up to 14 MPa using the volumetric method. As conversion from excess adsorption to absolute adsorption requires accurate capture of adsorbed phase density (APD), the simplified local density (SLD) theory and Peng-Robinson (PR) equation of state (EOS) were tailored to calculate the APD considering both pore size distribution (PSD) and pressure. Besides, volumetric effects, including void volume overestimation and coal matrix shrinkage/swelling, were quantificationally calibrated to reconstruct excess adsorption isotherms. Then, we proposed a novel conversion method based on real adsorption space distribution and adsorption mechanism. Results show that micropores in the range of 0.30–1.50 nm dominate the total pore space. APD and fugacity profiles reveal distinct CO 2 adsorption behaviors in micropores and mesopores. Fitted expansion coefficients indicate that coal matrix undergoes a superimposed effect of shrinkage and swelling during adsorption and the reconstructed isotherms could amend the large deviations around 8 MPa caused by the drastic changes of CO 2 bulk density and compressibility factor. Compared with conventional fixed APDs, the converted absolute adsorption isotherms generated by the varied ones exhibit slight fluctuations in the supercritical state and could plateau at high pressures. Continual iterations suggest that “averaged” APD in the range of 33–36 mol/L could be utilized for conversion in engineering practice only when the original excess adsorption isotherms are correctly reconstructed.

Continuum-Scale Gas Transport Modeling in Organic Nanoporous Media Based on Pore-Scale Density Distributions

SummaryWe present a continuum-scale mass transport model informed by pore-scale density distribution for gas diffusion through organic nanoporous media. A diffusion model and a sorption model are developed by considering multiple transport and storage mechanisms, including bulk diffusion and Knudsen diffusion for free phase, and surface diffusion and multilayer adsorption for sorbed phase. The continuum-scale diffusion equation is derived based on the free-phase concentration for the overall mass conservation of free and sorbed phases, carrying a newly defined effective diffusion coefficient and capacity factor to account for multilayer adsorption. Diffusion in free and sorbed phases is coupled with the sorption model, which provides pore-scale multilayer adsorption properties by utilizing a pore-scale simplified local density (SLD) method combined with the modified Peng-Robinson equation of state (PR-EOS) for confinement effect. The model was first implemented to analyze adsorption data from a krypton (Kr) adsorption experiment on graphite. Then, we applied the developed diffusion model to conduct the sensitivity analysis of the effects of pore size on gas transport for Kr-graphite and methane-coal systems. The model was finally used to study Kr diffusion profiles through a coal matrix obtained by using X-ray micro-computed tomography (microCT) imaging. The results show that the sorbed phase occupies most of the pore space in organic nanopores with less than 10 nm due to multilayer adsorption, and surface diffusion contributes significantly to the total mass flux. Therefore, neglecting the volume of sorbed phase and surface diffusion in organic nanoporous rocks may result in considerable errors in the prediction of hydrocarbon production. We also compared Brunauer-Emmett-Teller (BET) and Langmuir models by analyzing adsorption data for the wide pressure range up to the saturation pressure. The comparison between BET and Langmuir models shows that the Langmuir model can only match the adsorption isotherm at low pressure and yield lower effective surface diffusion coefficients. Therefore, implementing a Langmuir model may be erroneous for organic nanoporous media with strong adsorption capacity, particularly when pore pressure is high.

Predicting Adsorption of Methane and Carbon Dioxide Mixture in Shale Using Simplified Local-Density Model: Implications for Enhanced Gas Recovery and Carbon Dioxide Sequestration

Carbon dioxide (CO2) capture and storage have attracted global focus because CO2 emissions are responsible for global warming. Recently, injecting CO2 into shale gas reservoirs is regarded as a promising technique to enhance shale gas (i.e., methane (CH4)) production while permanently storing CO2 underground. This study aims to develop a calculation workflow, which is built on the simplified local-density (SLD) model, to predict excess and absolute adsorption isotherms of gas mixture based on single-component adsorption data. Such a calculation workflow was validated by comparing the measured adsorption of CH4, CO2, and binary CH4/CO2 mixture in shale reported previously in the literature with the predicted results using the calculation workflow. The crucial steps of the calculation workflow are applying the multicomponent SLD model to conduct regression analysis on the measured adsorption isotherm of each component in the gas mixture simultaneously and using the determined key regression parameters to predict the adsorption isotherms of gas mixtures with various feed-gas mole fractions. Through the calculation workflow, the density profiles and mole fractions of the adsorbed gases can be determined, from which the absolute adsorption of the gas mixture is estimated. In addition, the CO2/CH4 adsorption selectivity larger than one is observed, illustrating the preferential adsorption of CO2 over CH4 on shale, which implies that CO2 has enormous potential to enhance CH4 production while sequestering itself in shale. Our findings demonstrate that the proposed calculation workflow depending on the multicomponent SLD model enables us to accurately predict the adsorption of gas mixtures in nanopores based on single-component adsorption results. Following the innovative calculation flow path, we could bypass the experimental difficulties of measuring the multicomponent mole fractions in the gas phase at the equilibrium during the adsorption experiments. This study also provides insight into the CO2/CH4 competitive adsorption behavior in nanopores and gives guidance to CO2-enhanced gas recovery (CO2-EGR) and CO2 sequestration in shale formations.

Evaluation of Gas Adsorption in Nanoporous Shale by Simplified Local Density Model Integrated with Pore Structure and Pore Size Distribution.

Simplified local density (SLD) model has been widely used to describe the gas adsorption behaviors in porous media. However, the slit pore geometry and constant pore width associated with the SLD model may fail to represent the heterogeneous pore network structure in shale. In this study, a new method to integrate the SLD model with the slit and cylindrical pore structures as well as the pore size distribution (PSD) is proposed and validated by the grand canonical Monte Carlo (GCMC) simulations and the experimentally measured adsorption of methane on shale with complex pore network. Comparison results show that reasonably good agreement is achieved between the SLD model and GCMC simulations for both the gas adsorption isotherms and discrete-density profiles in multiwalled carbon nanoslit and nanotube. The corresponding average absolute percentage deviations (% AADs) are below 0.3 and 9.3 for gas adsorption isotherm and discrete-density profile, respectively. In addition, the SLD model coupled with the PSD of slit and cylindrical pores ranging from micro- to macropores properly characterizes the measured excess adsorption of methane on Wolfcamp shale core sample with % AADs between 1.7 and 3.6. It is found that when the pore volume is fixed, the gas adsorption isotherm and gas density profile are heavily dependent on the pore geometry and pore size. Furthermore, integrating the PSD into the SLD model can guarantee the valid identification of the adsorbed- and free-gas regions in flow channels with different sizes based on the gas density profiles. The findings of this study shed light on the effects of pore structure on gas adsorption in nanopores and enable us to precisely evaluate and predict the gas adsorption behaviors in slit and cylindrical pores over a wide range of pore sizes.

Mechanistic insights into confined methane adsorption in carbon nanopores at the molecular level

For methane adsorption, little attention has been given to the comprehensive effect of fluid-wall and fluid–fluid interactions in confined carbon pores. The simplified local density (SLD) model is suitable for confined adsorption studies. However, it has not been unified due to the various utilizations of the equation of states (EOSs). Eighteen selected cubic EOSs were modified, including the first given expressions of confined attractive parameters with the (3/8)σff assumption. After comparing 36 SLD models, the Redlich-Kwong-Soave-type EOS and the (3/8)σff assumption were recommended for accurate confined adsorptions. The confined effect has little impact on fluid–fluid repulsion. As the size of carbon nanopores decreases, the confined adsorption is negatively affected by the decreasing fluid–fluid attractive potential and positively affected by the growing fluid-wall interactive potential. When nanopores are larger than 3 nm, the adsorption is not affected by the confined effect. Our research provided novel mechanistic insights into confined methane adsorption.

Absolute adsorption of light hydrocarbons on organic-rich shale: An efficient determination method

Absolute adsorption has been found being more accurate than directly measured excess adsorption value for estimating the in-situ shale gas-in-place storage. To obtain accurate absolute adsorption, traditional methods determined the adsorbed gas density using complicated molecular simulation methods, which is employed to correct the measured excess value. In this work, excess adsorption, which is deemed to be inaccurate in previous work, of CH4 and C3H8 is first measured on three typical shale rocks. The adsorbed-layer density is then reasonably calculated using the simplified local density theory (SLD) to obtain corresponding absolute adsorption of CH4 and C3H8. It is found that the adsorbed layer density calculated from SLD theory is comparable to that obtained from molecular simulation methods, while it is more efficient for the density computation. Compared to CH4, C3H8 presents stronger adsorption capacity on shale rocks, suggesting that C3H8 is more affinity to organic shale. The CH4′s absolute adsorption is stronger than its excess value and their deviation enlarges as pressure increases, while absolute adsorption for C3H8 is found to be more or less the same with the measured excess value. The importance of this work lies in that we propose a new method for efficiently obtaining the adsorbed-layer density, which is crucial for accurately determining gas and oil storage in shale reservoirs.

Methane adsorption on shale under in situ conditions: Gas-in-place estimation considering in situ stress

Gas-in-place (GIP) is one of the essential indices for the resource evaluation of shale gas storage capacity. In this study, based on the simplified local density (SLD) theory, the shale adsorption capacity was investigated considering the effect of burial depth on the shale pore structure. Shale isotherm adsorption experiments under triaxial conditions were performed with a homemade adsorption test device, and CH4 adsorption isotherms under different shale reservoir conditions representative of different burial depths were obtained. By establishing the relationship between the SLD model regression parameters and burial depth, a shale GIP estimation model considering the influence of in situ stress was established. In situ stress controls the pore structure of shale and consequently affects the gas storage capacity of shale. The conventional method does not consider the influence of in situ stress, resulting in overestimation of the free gas content, underestimation of the adsorbed gas content, and overall overestimation of the GIP by 1.12–1.26 times. Taking into account the influence of the stress state, the contribution of the free gas content to GIP is weakened. In contrast, the adsorbed gas content plays a key role in GIP. The distribution of the shale reservoir GIP concentrates at depths of 2500–4500 m. These findings will be helpful in the future evaluation of shale gas reserves and improvement in shale gas content evaluation methods.

Prediction of high-pressure adsorption of CH4 and CO2 in shale

The study of CH4 and CO2 adsorption behavior in shale under high-pressure is critical for the estimation of gas content and CO2 sequestration in deep shale gas reservoirs. However, it is very difficult for the adsorption experiment pressure to reach the high pressure of the deep shale gas reservoirs. This paper aims to study the feasibility of Langmuir model, supercritical Dubinin-Redushckevich (SDR) model and Simplified Local-Density (SLD) model to predict the high-pressure adsorption based on the low-pressure adsorption data. The results showed that the Langmuir model, SDR model and SLD model can fit the adsorption isotherm of CH4 and CO2 in shale well. In the ranges of pressure (0-12 MPa) and temperature (308.15-328.15 K), the adsorption phase densities obtained by the Langmuir model and the SDR model are fixed values, but the adsorption phase density obtained by the SLD model is a function of temperature and pressure, which makes the SLD model more predictive. The high-pressure adsorption data in four literature sources were used to compare the prediction capabilities of the Langmuir model, the SDR model and the SLD model, and average absolute percent error (%AAD) predicted are 11.56%, 6.15%, and 3.05%, respectively. When predicting the absolute adsorption at higher pressures, it is unreasonable to use a fixed adsorption phase density. Compared with the SLD model, the Langmuir and SDR models slightly underestimated the CH4 absolute adsorption capacity and seriously overestimated the CO2 absolute adsorption capacity. The results can help evaluate shale gas production and the potential for CO2 sequestration.