Adsorbed Gas Content Research Articles

Study on Evaluation of the Virtual Saturated Vapor Pressure Model and Prediction of Adsorbed Gas Content in Deep Coalbed Methane

Study on Evaluation of the Virtual Saturated Vapor Pressure Model and Prediction of Adsorbed Gas Content in Deep Coalbed Methane

Estimation of shale adsorption gas content based on machine learning algorithms

Shale gas is a clean and low-carbon natural gas resource. It mainly exists in both adsorbed and free states in pores and fractures. To accurately estimate the in-situ adsorption gas content (AGC), which is helpful in resource evaluation and development planning, methane isothermal adsorption data and geological parameters have been collected, such as total organic carbon (TOC) content, thermal maturity (Ro), siliceous mineral content (VQF), total clay content (VTC), water content (VWC), and temperature (T). Using machine learning (ML) methods, the in-situ AGC estimation models were constructed and optimized. Various geological factors affecting methane adsorption were evaluated, and an application was conducted in the Wufeng-Formation shale. The results reveal that the four ML models have higher accuracy in predicting Langmuir volume (VL) and Langmuir pressure (PL) than empirical formulas and linear regression models. Among the four ML models, the Random Forest Regression (RFR) and eXtreme Gradient Boosting Regression (XGBR) models perform the best, with R2 higher than 0.85. TOC and T are the main factors affecting methane adsorption, followed by Ro and VQF, while the importance of VTC and VWC is relatively low. According to different combinations of geological parameters, there are three schemes for ML model construction. Among them, scheme 1 based on all six geological parameters has the highest accuracy and is most beneficial to predicting AGC. Gradually reducing VWC, VTC, and VQF results in a slight decrease in accuracy, with R2 decreasing by at most about 6%, scheme 2 is suitable for rougher estimation of AGC. Further removal of T and Ro results in a significant decrease in accuracy, with R2 decreasing by up to 50% and MRE exceeding 30%, rendering scheme 3 unavailable for AGC prediction. The AGC of Wufeng-Longmaxi shale is successfully predicted based on XGBR model, with AGC mainly in 1.0 m3/ton-4.0 m3/ton. Overall, the ML models based on multiple geological parameters can simulate the real reservoir environment and achieve rapid and accurate estimation of in-situ AGC.

An anisotropic rock physics modeling for the coalbed methane reservoirs and its applications in anisotropy parameter prediction

The elastic properties and anisotropy of coalbed methane reservoirs are still poorly understood due to the complicated pore structure and the existing state of the coalbed methane. Therefore, an anisotropic rock physics model for the coalbed methane reservoirs is proposed based on the related effective medium theories, which focuses on the equivalent calculation of the elastic properties for adsorbed coalbed methane and the characterization of the multiple pore structure. Many factors related to the elastic properties of coal are considered, including the composition, pore structure, adsorbed gas content and pore fluid. The measured ultrasonic and well-logging data demonstrate that the proposed physics model is effective in predicting the elastic constants and velocity anisotropy parameters. The results suggest that the elastic constants increase with the increase of adsorbed gas content to some extent, and the effect of porosity on the elastic constants is much more obvious than that of adsorbed gas content. The velocity anisotropy parameters increase with the aligned fracture porosity and the fracture aspect ratio, and the P-wave anisotropy is more sensitive to these two factors. With increasing organic matter and clay content and porosity, Young's modulus and brittleness index decrease while the Poisson's ratio increases, and the impact of the porosity on the brittleness index is more significant than that of organic matter and clay content. The results are helpful in establishing the relationship between reservoir physics parameters and seismic response and can provide a basis for coalbed methane reservoir prediction and hydraulic fracturing.

Accumulation and exploration enlightenment of shallow normal-pressure shale gas in southeastern Sichuan Basin, SW China

Based on the drilling, logging, experimental and testing data of Well PD1, a shallow normal-pressure shale gas well in the Laochangping anticline in southeastern Sichuan Basin, the shallow shale gas reservoirs of the Ordovician Wufeng Formation to Silurian Longmaxi Formation (Wufeng–Longmaxi) were investigated in terms of geological characteristics, occurrence mechanism, and adsorption-desorption characteristics, to reveal the enrichment laws and high-yield mechanism of shallow normal-pressure shale gas in complex structure areas. First, the shallow shale gas reservoirs are similar to the medium–deep shale gas reservoirs in static indicators such as high-quality shale thickness, geochemistry, physical properties and mineral composition, but the former is geologically characterized by low formation pressure coefficient, low gas content, high proportion of adsorbed gas, low in-situ stress, and big difference between principal stresses. Second, shallow shales in the complex structure areas have the gas occurrence characteristics including low total gas content (1.1–4.8 m3/t), high adsorbed gas content (2.5–2.8 m3/t), low sensitive desorption pressure (1.7–2.5 MPa), and good self-sealing. Third, the adsorbed gas enrichment of shales is mainly controlled by organic matter abundance, formation temperature and formation pressure: the higher the organic matter abundance and formation pressure, the lower the formation temperature and the higher the adsorption capacity, which is more beneficial for the adsorbed gas occurrence. Fourth, the shallow normal-pressure shale gas corresponds to low sensitive desorption pressure. The adsorbed gas can be rapidly desorbed and recovered when the flowing pressure is reduced below the sensitive desorption pressure. Fifth, the exploration breakthrough of Well PD1 demonstrates that the shallow complex structure areas with adsorbed gas in dominance can form large-scale shale reservoirs, and confirms the good exploration potential of shallow normal-pressure shale gas in the margin of the Sichuan Basin.

Quantitative Prediction of Deep Coalbed Methane Content in Daning-Jixian Block, Ordos Basin, China

The potential of deep coalbed methane resources is substantial. Gas content is an important parameter for resource assessment. At present, the gas content test method commonly used for shallow coal reservoirs is not suitable for determining deep coalbed methane gas content. Therefore, it is urgent to establish a prediction method for deep coalbed methane gas content. This study aims to quantitatively predict the gas content of coalbed methane in deep coal reservoirs and uncover its influencing factors. For this purpose, we selected the Daning-Jixian area, a region in China with relatively advanced development of deep coalbed methane, as a case study. It established a prediction model for adsorbed gas and free gas content in deep coal reservoirs through a series of experimental tests, encompassing gas content, coal quality, isothermal adsorption, and nuclear magnetic resonance. The model sheds light on the impact of coal-rock characteristics, coal quality attributes, and pore characteristics on adsorbed gas and free gas content. The results show that adsorbed gas dominates in deep coal reservoirs with a high metamorphic degree and that the average proportion of adsorbed gas under reservoir burial depth is 80.15%. At a depth of approximately 1800~2000 m, a turning point is observed where adsorbed gas content begins to decline. Beyond this depth range, the detrimental effect of temperature on coalbed methane content surpasses the beneficial impact of pressure. Coal quality characteristics play a major role in controlling adsorbed gas content, and an increase in water content and ash yield significantly reduces the adsorption performance of coal reservoirs. The content of free gas increases with the increase in burial depth, with its controlling factors primarily being confining pressure and porosity. The increase in the proportion of micropores in the pores of deep coal reservoirs has an adverse effect on the content of free gas. The proportion of adsorbed gas in deep coal reservoirs gradually decreases with the increase in burial depth, while the proportion of free gas gradually rises with the increase in burial depth. The development potential of free gas cannot be overlooked in the exploration and development of deep coalbed methane.

A new method to calculate the effect of fracturing fluid imbibition on adsorbed gas content for shale gas reservoir

In-situ methane occurrence in shale gas reservoirs is seriously affected by the massive imbibed fracturing fluid. However, it is difficult to quantify the impact degree due to the complexity of pore connectivity. In this study, we firstly evaluated the ratio of through and blind pores by a proposed method firstly. Then the different influences of imbibition on gas occurrence in through and blind pores were demonstrated through designed experiments and a visual computational simulation. Finally, a new analytical model was proposed to calculate the effect of imbibition on adsorbed gas content, based on the ratio of through and blind pores and their different imbibition phenomenon. The comparison of the calculation and experimental results showed: (1) the new method can accurately predict the impact degree of imbibition on adsorbed gas; (2) imbibition in through pores leads to the co-current and countercurrent imbibition, and imbibition in blind pores leads to a compression of free gas.

Impacts of kerogen type and thermal maturity on methane and water adsorption isotherms: A molecular simulation approach

The molecular structure of kerogen is known to control the type, amount of petroleum generated as well as its interaction with reservoir fluids. The adsorption behavior of kerogen with respect to reservoir fluids can enhance our understanding of kerogen wetting properties. Therefore, quantifying the governing factors controlling the adsorption of water and methane in organic pores is critical in understanding fluid flow and adsorption phenomena in organic-rich mudrocks. In this paper, we perform molecular simulations (MS) and quantify water and methane adsorption isotherms on kerogen pore surfaces for the purpose of investigating the impact of kerogen molecular structure on kerogen-fluid interfacial interaction. To realistically represent kerogen structures, we use different kerogen molecular models to emulate kerogen of different types and thermal maturity. The kerogen molecules are condensed to form a porous kerogen structure. The Grand Canonical Monte Carlo simulation (GCMC) method is applied to calculate adsorption isotherms of methane and water molecules in kerogen nanopores. We compute the adsorption behavior of water and methane molecules on type I, II and III kerogen samples. The molecular simulations of increasing thermal maturity from IIA to IID at low pressures (less than 10 MPa) and temperature of 300 K in type II kerogen resulted in increasing methane adsorption capacity. At 5 MPa, the methane adsorption relatively increased 81% from IIA to IID. The adsorption capacity of methane is also shown to increase from type IA to IIA to IIIA. Similarly to methane, water adsorption capacity is found to increase from type IA to IIA to IIIA. However, water adsorption capacity on kerogen of different thermal maturity increases from IIB to IIA. Kerogen structures of types IID and IIC show very similar adsorption capacity nearly overlapping at four different pressures. However, water adsorption on IID and IIC kerogen is still found to be smaller compared to IIA and IIB. The outcomes of this work contribute to improving the understanding of the impact of kerogen molecular structure on adsorption of fluids on kerogen surfaces. Moreover, it can provide insights into fluid mobility assessments in organic-rich mudrocks by providing information about the adsorbed gas content on kerogen surfaces.

Mechanism of action of heat treatment on the adsorption of polymorphic gases from raw coal

ABSTRACT The adsorption properties of coal determine the economic benefits of coalbed methane (CBM) extraction. To investigate the gas adsorption behavior of raw coal after heating, gas adsorption tests and pore characterization tests were conducted. Meanwhile, the influence of high temperature on coal pore structure and polymorphic gas adsorption was analyzed. The results showed that the gas adsorption gradually increased with the increase of coal grade at the same temperature. For the same coal grade coals, the adsorbed gas content decreased 5.96%-21.53% and the non-adsorbed gas content increased 51.25%-95.47% with the increase of temperature. The high temperature has a dilating effect on coal pores, causing the proportion of tiny pores to decrease and the adsorbed gas storage capacity to become weaker, and the proportion of medium and large pores to increase and the non-adsorbed gas storage capacity to become stronger. This study can provide data support for coalbed methane heat injection extraction.

Geochemical study of coals from Sohagpur Coalfield, India, and its implication to CBM potential

ABSTRACT Coal is a primary and conventional energy source, but it also adversely impacts the environment. To mitigate the adverse effects of fossil fuels, the world is compelled to switch to more environmentally friendly resources like shale gas and coal bed methane (CBM). In India, coal has been mined and utilized for more than a century, but now it is high time to use the coal resource more cleanly. In this regard, CBM can be a good alternative. It is essential to mark out the coal seams which pose a high CBM generation potential. The study aims to determine the relationship between methane content and adsorbed gas content with coal characteristics and its depth of occurrence. In the present study, an investigation was carried out on the coal samples from the Sohagpur coalfield to detect the relation mentioned above. Vitrinite reflectance was calculated, which ranges from 0.85% to 1.08%. Adsorbed gas content and methane content were calculated using proximate analysis results and the coal seam depth. The study revealed that these coals are High Volatile Bituminous in rank. Also, Methane content increases with vitrinite reflectance and fixed carbon. As the depth increases, the value of gas content also increases.

Characterization of kerogen molecular structure and its effect on methane adsorption behavior: A comparative study on outcrop and core samples from Longmaxi shale

It has been known that adsorbed gas, mainly CH4, serves as the dominant source of shale gas yield in the middle and later stages of reservoir exploitation. Therefore, it is of great significance to study the microstructure of kerogen (organic matter rich in shale) and its effect on CH4 adsorption characteristics. In this paper, for the first time, a comparative study was conducted to experimentally characterize the microstructure of both outcrop and core kerogen samples from Longmaxi Shale, Sichuan Basin, SW China, using 13C NMR, FTIR, and XPS. Great differences in the chemical structure such as carbon skeleton (e.g., aromaticity, aliphatic branch) and heteroatoms (e.g., distribution and proportion of various types of functional groups) between the two kerogen samples have been identified. Molecular models of the outcrop and core kerogen samples were constructed based on the experimental data, that is, C237H219O21N5S4 for the former and C239H175O27N5S4 for the latter. CH4 adsorption isotherms obtained from gravimetric adsorption test and molecular simulation using proposed kerogen molecular models are in reasonable agreement with each other, especially at low-pressure range. Interestingly, the adsorption capacity of CH4 in the core sample is found higher than that in the outcrop sample under the same condition, indicating the effect of kerogen microstructure on CH4 adsorption behavior. As a result, to precisely evaluate the adsorbed gas content in shale gas reservoirs, it is strongly recommended to use a core sample rather than an outcrop sample.

Evaluation model of shale-adsorbed gas considering clay and water saturation

Shale adsorption capacity is affected by many factors including temperature, pressure, geochemical characteristics of organic matter, clay, and water saturation. The traditional calculation model of adsorbed gas content only considers the influence of temperature, pressure, and organic geochemical characteristics. The influence of clay and water saturation on adsorption capacity is seldom considered. Isotherm adsorption experiments were conducted on synthetic specimens and natural specimens with varying clay types, clay contents, and water saturations. Then, the influences of clay and water saturation on the adsorption capacity were systematically studied. The experimental results found that the order of clay adsorption capacities was smectite > kaolinite > chlorite > illite. The multicomponent superposition rule was applicable in evaluating shale-adsorbed gas content. The total adsorption capacity was equal to the accumulation of the adsorption capacities of all types of clay and organic matter. Moisture will significantly reduce the adsorption capacity of shale. The adsorption capacities of synthetic specimens and natural specimens after being fully saturated with water were 9%–14% and 42%–61% of those in dry states, respectively. Then, a new shale-adsorbed gas evaluation model was established based on the Langmuir equation considering clay and water saturation. The calculation error of this new model was approximately 11%, which provides a new method for evaluating the adsorbed gas content of shale.

Pore Structure and Gas Content Characteristics of Lower Jurassic Continental Shale Reservoirs in Northeast Sichuan, China

The Jurassic shale in the northeastern Sichuan Basin is one of the main target intervals for continental shale gas exploitation. Research on the pore structure and gas-bearing properties of shales is the key issue in target interval optimization. Through core observation, geochemistry, bulk minerals, scanning electron microscopy, nitrogen adsorption, and isothermal adsorption experiments, various lithofacies with different pore structure characteristics were clarified. In addition, the factors that control gas-bearing properties were discussed, and a continental shale gas enrichment model was finally established. The results show that the Jurassic continental shale in the northeastern Sichuan Basin can be classified into six lithofacies. Organic pores, intergranular pores, interlayer pores in clay minerals, intercrystalline pores in pyrite framboids, and dissolution pores can be observed in shale samples. Pore structures varied in different shale lithofacies. The contact angle of shales is commonly less than 45°, leading to complex wettability of pores in the shales. Free gas content is mainly controlled by the organic matter (OM) content and the brittleness in the Jurassic shale. The adsorbed gas content is mainly controlled by the OM content, clay mineral type, and water saturation of the shales. The enrichment mode of the Lower Jurassic continental shale gas in the northeastern Sichuan Basin is established. Paleoenvironments control the formation of organic-rich shales in the center part of lakes. The "baffle" layer helps the confinement and high pressure, and the complex syncline controls the preservation, forming the enrichment pattern of the complex syncline-central baffle layer.

Interaction between slick water and gas shale and its impact on methane desorption: a case study of Longmaxi member shale formation in the northeast of Chongqing, China

Well shut-in time significantly affects the production performance of shale-gas-well. However, interaction between shale powders and fracking fluid on methane desorption has been rarely reported. In this work, based on the volume method following Boyle’s law under higher pressure, the experimental setup was conducted to obtain the adsorption and desorption isotherms to explore the effect of different shut-in times (including 0, 1, 3, 5, 10, and 30 days) on methane desorption. We fitted the methane adsorption and desorption isotherms by the Freundlich model, and the results show that the interaction can obviously impact desorption isotherm, desorption efficiency and adsorbed phase methane content. The inflection points of the constant k and n reduction curves, desorption efficiency reduction curve and adsorbed gas content reduction curve all occur when the interaction time is to 10 days, indicating that 10 days is the best value for the interaction between slick water and gas shale. The results provide an essential supplement that can help elucidate the impact of shut-in time on gas-shale-well production performance experimentally.

Comprehensive Experimental Study on the Gas Breakthrough Pressure and Its Implication for the Reservoir Performance

Abstract It is challenging to interpret the gas breakthrough mechanisms, controlling factors, and its relationships with the reservoir parameters for unconventional reservoirs such as the gas shale, due to the accumulation characteristics of source-reservoir integration. Take the typical marine shale gas of the B field for example, we use the step-by-step (SBS) test to measure the gas breakthrough pressure of the water saturated shales, and investigate the influential factors such as the pore size distribution, mineral composition, and organic geochemical properties. Moreover, the implication of the gas breakthrough capability for the reservoir quality such as the porosity, permeability, the gas content, and the gas occurrence state are addressed. Based on our work, it is observed that the gas breakthrough capability in shale is influenced by many factors. Generally, the gas breakthrough pressure is positively with the amount of ductile minerals such as the clay and the plagioclase, but negatively with the amount of brittle minerals such as the quartz. In addition, the gas breakthrough pressure is decreased with the increase of the pore radius and the specific surface areas. What is more, the influences of geochemical properties on the gas breakthrough capability should not be neglected. Due to the development of organic pores in the kerogen, the gas breakthrough pressure is found to decrease with the increase of the total organic carbon content (TOC) and the residual carbon content (RC). The breakthrough pressure can be used as the significant parameter to indicate the reservoir quality of the shale gas. It is shown that the breakthrough pressure is inversely with the porosity, permeability, the total gas content, and the adsorbed gas content. It is practical and meaningful to measure and estimate the breakthrough pressure for the formation evaluation in shale gas reservoirs.

Gas content prediction model of water-sensitive shale based on gas–water miscible competitive adsorption

The evaluation of gas content plays a key role in determining the efficient development of shale reservoirs. To better understand the gas–water miscible competitive adsorption mechanism in the pore-fracture system of water-bearing shale, the water vapor adsorption experiment of dry shale and the methane gas adsorption experiment of water-bearing shale were carried out to compare and analyze the competitive adsorption laws of formation water and methane gas on the shale surface under different temperatures, pressures, and water saturation conditions. Moreover, based on the molecular layer adsorption theory, the gas–liquid–solid interface competitive adsorption model considering the coupling of temperature, pressure, and water saturation was established to predict the actual gas content of water-bearing shale reservoirs. The results show that the main controlling factors affecting the adsorbed gas content of water-bearing shale are specific surface area, temperature, and water content in turn according to weight coefficients; Compared with the gas–solid adsorption model, the gas–liquid–solid competitive adsorption model has higher accuracy in calculation results, which are much closer to the desorption data of shale cores in Jiaoshiba area, Fuling, China. Hence, the competitive adsorption model provides a theoretical foundation for reasonably evaluating the exploitation potential of shale gas reservoirs.

Study on characteristics of oil and gas occurrence and reservoir space of medium-high maturity continental shale—A case study of middle jurassic lianggaoshan formation in fuling block, southeast of sichuan basin, south China

Possessed of easy access to development and fair economic benefits, medium-high maturity continental shale oil and gas have become the focus of shale oil and gas study in the future. Shale oil and gas mainly occur in pores, but studies on the pore characteristics of shale oil and gas occurrence are by no means sufficient. Focused on shale from the Middle Jurassic Lianggaoshan Formation in Well TYX, Fuling block, southeast of Sichuan Basin where a breakthrough in shale oil and gas exploration was recently achieved, this study selects core samples and conducts a series of analyses, including vitrinite reflectance analysis, kerogen microscopic examination experiment, total organic carbon (TOC) content analysis, mineral composition analysis, gas content measurement, isothermal adsorption experiment, S1 content analysis, and others. The analyses are to identify the pore characteristics of the continental medium and high maturity shale oil and gas by virtue of scanning electron microscope (SEM) with Ar-ion milling and the image processing software ImageJ. The conclusions are drawn as follows: in terms of lithofacies, medium-high maturity continental shale oil and gas mainly occur in organic-rich clay shale and organic-rich mixed shale; with regard to material composition, shale oil and gas mainly occur in organic matter, illite-smectite mixed layers and illite. Shale adsorbed gas content accounts for at most 40% of the total shale gas content and shale free gas content takes up at least 60% of the total shale gas content. Pores of solid bitumen, solid bitumen-clay mineral complex mass, clay minerals, structured vitrinite, and funginite are mostly developed in shale. Among them, the first three types of pores are the main reservoir space in shale considering their large number, good roundness, medium pore diameter, fairly good roundness of pore edges, and the complex shapes which altogether contribute to the large surface porosity.

An improved method for improving the calculation accuracy of marine low-resistance shale reservoir parameters

In order to accurately evaluate the shale reservoir of the Lower Carboniferous Luzhai Formation in the central Guangxi area, in view of the influence of the low resistivity of the reservoir and the complex mineral composition on the logging response, taking Well A1 as an example, a method to improve the calculation accuracy of reservoir parameters is studied. The reasons for the low resistance in the study area are analyzed from the aspects of minerals, geochemistry and geology. An improved △log R method based on borehole correction and natural gamma spectroscopy logging was proposed to calculate the total organic carbon content. A calcium-corrected HERRON method is proposed to calculate porosity. The P/S time difference ratio-density neutron log overlap difference is proposed to calculate saturation. Calculation of adsorbed gas content based on organic matter correction. The results show that the improved method greatly improves the prediction accuracy, and has high consistency with the core analysis results, and can accurately evaluate the shale reservoirs of the Lower Carboniferous Luzhai Formation in the central area of Guangxi. The improved new method has good applicability and can be further used in the evaluation of this kind of source rock reservoir.

The Pore Structure of Marine to Continental Transitional Shales in the Permian Shanxi Formation on the East Margin of the Ordos Basin, China

The pore structure is an important factor in determining the storage capacity for shale gas development. Twelve samples were selected from the marine to continental transitional shales in the Shanxi Formations on the eastern margin of the Ordos Basin, and their nanoscale pore structure was investigated by a variety of low-temperature N2 adsorption (LT-N2GA) and low-pressure CO2 adsorption (LP-CO2GA) and high-pressure mercury intrusion (HPMI) experiments. The shale pores are complex and are mainly mesopores, which range mainly from 10 nm to 40 nm and greatly contribute to the pore volume (PV), whereas pores with a diameter less than 0.8 nm greatly contribute to the specific surface area (SSA) of the shale. The pore structure is affected by the TOC content, organic matter maturity, and illite/smectite (I/S) mixed layer content. The total PV increases with the increase in TOC content, organic matter maturity, and I/S mixed layer content. The effects of pores on the occurrence shale gas were determined by high-pressure methane adsorption experiments. The maximum adsorption amount of methane was positively correlated with the SSA of the micropores, indicating that the micropores have a large SSA, which controlled the adsorbed gas content of the shale. The mesopores provide the majority of the PV, which mainly corresponds to the volume of free gas in the shale, and the macropores are mainly micron-sized pores, which can form the main migration channels for shale gas.

Macro- and microdamage characteristics and multiscale damage constitutive model of gas-bearing coal under loading

To obtain the correlation between the macro- and microdamage of coal under the coupling action of gas adsorption and stress, the pore structure and mechanical properties of gas-bearing coal under axial loading and the correlations between these factors were studied. The results show that the pore size distribution of coal hardly changed with the change in axial stress, while 45.26% of the micropores and small pores were transformed into mesopores and macropores with the increase in adsorbed gas content within the tested range. Due to different microdeterioration mechanisms, the strength and elastic modulus of gas-bearing coal do not obey a single damage evolution criterion, and their deterioration rates with increasing adsorbed gas content were 27.96% and 11.20%, respectively, within the tested range. The trends of the variations in strength deterioration rate, fracture fractal dimension and pore volume fractal dimension of gas-bearing coal were consistent, and their correlations were greater than 99.2%, but the degrees of the changes in these factors were quite different, indicating that the damage factor at the macroscale cannot be extended to the microscale. To overcome this limitation, a multiscale damage constitutive model considering macro- and microdamage was constructed by using micro-based phenomenological damage theory. The verification indicated that the model accuracy could reach 98.97%, indicating a high reliability.

Predicting adsorbed gas capacity of deep shales under high temperature and pressure: Experiments and modeling

Temperature and pressure conditions of deep shale are beyond experiment range, and the amount of adsorbed gas is difficult to determine. To predict the adsorbed gas content of deep shales under formation conditions, isothermal adsorption experiments and model building were conducted on shale samples from Longmaxi Formation in China. A temperature-dependent adsorption model based on the Langmuir equation is proposed, which can be well-fitted by observed isotherms with a high correlation coefficient. Based on the fitted parameters at 303.15 K, the isothermal adsorption curves at 333.15 K, 363.15 K, and 393.15 K are predicted, showing a good agreement with experimental curves available. Compared with previous prediction methods, the biggest advantage of the proposed method is that it can be carried out only based on one-time isothermal adsorption experiment. Based on the predictions, the downward trend of the excess adsorption curves will slow down under high temperature and pressure conditions, and when the pressure reaches a certain level (> 80 MPa), the temperature has little effect on the excess adsorption capacity. While for absolute adsorption, the gas adsorption reaches saturation much slowly at high temperature, it can also reach saturation under formation pressure. Under the burial depth of marine shale, temperature plays a major role in controlling the adsorbed gas, resulting in the decrease of adsorbed gas content in deep shale, and its ratio will further decrease as the depth increases. Cited as: Zhou, S., Wang, H., Li, B., Li, S., Sepehrnoori, K., Cai, J. Predicting adsorbed gas capacity of deep shales under high temperature and pressure: Experiments and modeling. Advances in Geo-Energy Research, 2022, 6(6): 482-491. https://doi.org/10.46690/ager.2022.06.05