Adsorbed Gas Content Research Articles

Measurement of adsorption phase densities with respect to different pressure: Potential application for determination of free and adsorbed methane in coalbed methane reservoir

Evaluation of free and adsorption gas in the in-situ reservoir is extremely significant for the exploration and production of coalbed methane. The adsorbed gas content is commonly estimated based on isothermal adsorption experiments from the volumetric or gravimetric methods that are essentially measurements of the excess adsorption amount, but not the absolute adsorption amount. To evaluate the in-situ gas content, the excess adsorption amount must be calibrated as the absolute adsorption amount through mathematical correction. However, the theoretical base for these mathematical assumptions is either unreasonable or questionable, which limited the application of these methods. We conducted the excess isothermal adsorption experiments on a coal core plug sample, and meanwhile used NMR to quantify the free and adsorbed methane, and to obtain absolute adsorption isotherms, and then to obtain the accurate values of the in-situ densities and volumes of adsorbed phase methane during the gas adsorption process. Results show that the adsorbed phase methane density increased with pressure, showing a Langmuir-type function, while the density decreased with temperature. The adsorbed phase methane volume is independent of gas pressure and temperature, based on which as well as the adsorption potential theory, the absolute adsorption isotherms at different temperatures were predicted from one set of absolute adsorption experiments using NMR. The method for calculations of the absolute adsorption amount and adsorption phase volume from NMR is applied to estimate the free and adsorbed methane in the in-situ reservoir. The adsorption gas dominates in shallow formations, whereas the free gas dominates in deep strata. The excess adsorption can result in evident overestimation of free gas and underestimation of adsorption gas in the reservoir.

Modelling Methane Adsorption Isotherms on Shale at Different Temperatures

Prediction of adsorption isotherms under different temperatures is significant to reserve estimation of shale gas reservoirs. Based on the Polanyi adsorption potential theory and Langmuir adsorption theory, a method was presented to predict adsorption isotherms at different temperatures. In this method, the relationship between Langmuir pressure and temperature was quantified. By utilizing this method, we predicted adsorption isotherms of Longmaxi shale from 45 °C to 120 °C according to experimental data at 30 °C. Meanwhile, by considering the pressure and temperature gradients, we also predicted the adsorption capacity of Longmaxi shale with geologic depth. Results show that the adsorption data predicted by our method are in accord with experimental data and the error coefficient is less than 5%. In addition, the isosteric heat of adsorption for Longmaxi shale can be calculated by predicted adsorption data based on the Clausius–Clapeyron equation of capillary systems. Therefore, our study illustrates theoretical foundations for the efficient evaluation of adsorbed gas content in shale gas reservoirs at geologic conditions.

Nuclear magnetic resonance study on the law of methane adsorption in water-bearing medium rank lump coal

ABSTRACT To reveal the influence of water on the gas adsorption process of medium rank lump coals, four groups of medium rank coals were selected for the study, and pore analysis experiments and low-field nuclear magnetic resonance (NMR) isothermal adsorption experiments with different water contents were carried out. The microscopic pore structure characteristics of medium rank lump coals were characterized by the combined mercury-pressure method and nitrogen adsorption method; the gas adsorption process of water-bearing coal samples was quantitatively analyzed based on the NMR isothermal adsorption experimental platform, and the influence of the water endowment state on the gas content of lump coal reservoirs was discussed. The results show that medium grade coals are predominantly microporous and small pore, followed by mesoporous, with the least macrospores, and have good gas storage capacity and that the adsorption capacity increases with the degree of metamorphism. With the increase of adsorption time, the gas adsorption of the aqueous coal samples showed a trend of first increasing and then remaining constant, reaching the adsorption equilibrium within 9 h. The adsorption saturation, adsorption increment, and adsorption gas content all increased with the increase of metamorphism, while the non-adsorbed gas content decreased for the same moisture content coal sample. The saturation, increment, adsorption, and non-adsorption gas content decreased with increasing water content for the same coal sample.

Geological and Geochemical Characteristics of the Terrestrial Lower Jurassic Shale in Tarim Basin and its Favorable Exploration Areas

Large amounts of conventional gas resources that originated from terrestrial Lower Jurassic shale were discovered in the Tarim Basin, indicating promising exploration prospects for shale gas resources, whereas limited understandings were obtained on the geological and geochemical characteristics of the Lower Jurassic shale. In this study, based on cores of exploration wells and field outcrops, total organic carbon (TOC) pyrolysis, microscopic composition, organic elements, vitrinite reflectance, x-ray diffraction, and methane isothermal adsorption experiments were carried out on Lower Jurassic shale in the Tarim Basin. The results show that the TOC content of shale is relatively high, but the TOC content of shale in different regions is quite different. Among them, the Kuqa Depression is the highest (more than 3%), the Southwest Tarim Basin is second (more than 1%), and the East Tarim Basin is the lowest. The main types of kerogen in shale are mainly type III and type II2. The thermal evolution maturity of shale in different regions is quite different; the highest Ro of shale in the Southwest Tarim Basin is more than 2.0% and that of shale in the Kuqa depression is higher than 1.5%, both of which have entered the stage of high-over-mature evolution, and the shale in the East Tarim Basin is only in the low maturity–mature stage. The overall content of brittle minerals such as quartz in shale is greater than 40%, which has good fracturing properties. The adsorbed gas content of shale is high, but there is a great difference (0.5–4 m3/t), which is related to the large difference in the abundance of organic matter, thermal maturity, and clay mineral content of shale. Therefore, the Lower Jurassic shale gas in the Tarim Basin has good prospects for exploration. Based on the superposition method of the main controlling geological factors, it is predicted that the favorable areas for shale gas exploration are mainly located in the Keshen and Yinan-Yeyun areas of the Kuqa Depression and the Caohu Sag-Mandong area of the East Tarim Basin. This research not only provides basic data for the evaluation of shale gas resources in our country, but also provides certain guidance for the exploration of Lower Jurassic shale gas in the Tarim Basin.

Gas-Bearing Characteristics of the Longmaxi Formation Shale in the Changning Area, Southern Sichuan Basin, SW China

The Changning area, located in the south of the Sichuan Basin, has obtained commercial shale gas from the Silurian Longmaxi Formation, which is characterized by rich organic matter, large hydrocarbon generation, and high gas content. A series of studies have been carried out on the shale of the Wufeng Longmaxi Formation in the Changning area, including mineral petrological characteristics, shale reservoir characteristics, and accumulation characteristics. Although there are studies on the gas-bearing characteristics of the Wufeng Formation-Longmaxi Formation shale in the Changning area, the research is not systematic. In this work, based on isothermal adsorption experiments, field desorption experiments, and well log interpretation, the gas-bearing characteristics of the Longmaxi Formation shale in the Changning area were studied in detail. The results showed that the average of saturated-adsorbed methane gas volume of the Longmaxi Formation is 1 m3/t, which demonstrated that the Longmaxi shale reservoirs had strong adsorption capacity. The total gas content of section Long11-1, Long11-2, Long11-3, and Long11-4 is greater than 2 m3/t, which were the prolific shale gas layers. The Long12 sub-member has the lowest total gas content, ranging from 0.34 m3/t to 3.84 m3/t, with an average of 1.59 m3/t. The free gas content of the Longmaxi Formation in the Changning area was slightly smaller than the adsorbed gas content and it shows increasing trend from the bottom to top, while the adsorbed gas content shows an opposite trend. With the top of Long11-3 as the circumscription, the adsorbed gas accounts for the main part of shale gas in the lower part and the free gas shale in the upper part.

A theoretical and experimental investigation of gas adsorption-dependent bulk modulus of fractured coal

Changes in the bulk modulus of coal induced by sorbing gases occur during gas production and CO2 sequestration processes in coal seams. Understanding these changes, however, remains a challenge due to the complexity of coupled sorptive poromechanical processes. Some studies report that the bulk modulus of fractured coal reduces with gas adsorption, others state otherwise. In this study, we perform a set of triaxial experiments to investigate the bulk modulus variation in fractured coals with non-sorbing (helium) and sorbing (carbon dioxide) gases. We then present a theoretical model developed based on energy conservation and poroelasticity to predict the bulk modulus of fractured coal and its variation with sorbing gases. The model performance in predicting the bulk modulus is then assessed using the experimental results where a good performance is observed. A parametric study is further conducted to investigate the effect of key model parameters on the bulk modulus. The experimental results demonstrate that bulk modulus variations are predominantly caused by two counteracting effects: a hydromechanical effect resulting from a decrease in the effective stress due to pore pressure buildup and a sorptive-mechanical effect due to adsorption-induced matrix swelling. The experimental and theoretical results also show that these effects can lead to an increase or decrease in the bulk modulus of fractured coal. The parametric study using the theoretical model reveals that the initial fracture porosity and the adsorbed gas content are important factors controlling the variations in bulk modulus.

Mathematical Model and Numerical Simulation of Coalbed Methane Migration Considering the Adsorption Expansion Effect

The influence of gas adsorption and desorption on the volumetric strain of coal was measured by a self-designed, fluid–solid coupling triaxial coal adsorption deformation experimental system. The experimental results show that coal deformation has a threshold value with an increase in gas content. Before the gas content reaches the threshold value, coal deformation is not obvious. When the gas content reaches the threshold value, the deformation will increase sharply. At the same time, coal volume strain changes with coal gas content in accordance with exponential law ε = ε0(eϒc-1). Based on the experimental results, considering the coupling effects of heat transfer, water seepage, coal and rock mass deformation, and coalbed methane desorption and seepage, a mathematical model of heat transfer–deformation–seepage coupling coalbed methane migration was established, and a numerical simulation study was carried out on the heat injection-enhanced coalbed methane mining project. The results show that (1) With continuous heat injection, the gas in the coal seam is rapidly desorbed, and the adsorbed gas content forms an elliptical funnel that extends from the extraction hole to the deep part of the coal body and takes the fracturing crack as the center to the upper and lower boundaries of the coal seam. At day 30, the adsorbed gas content in the whole drainage area has decreased to 0.1 m3/t within 2m from the fracture zone. (2) On the basis of considering the gas adsorption expansion effect, the strain of the coal body decreases from roof to floor. With the increase in the heat injection time, the strain value will also increase, and the strain increase will decrease. When the heat injection is 30 days, the maximum strain at the roof is 0.015. The research results have important guiding significance for predicting coal rock deformation and determining gas extraction efficiency in the process of heat injection-enhanced coalbed methane extraction.

Micropore Structural Characteristics and Influence Factors of Triassic Shale Gas Adsorption in the Ordos Basin

Continental shale is investigated for potential shale gas reservoirs in the Tongchuan area, southern Ordos Basin. The kerogen macerals of Upper Triassic Chang 7 Shale are vitrinite 28–43%, exinite 4–7%, and inertinite 52–69%, and Ro is 0.85–0.88%, and the kerogen type is II. The total organic carbon (TOC) content is 9.75–29.92%, free hydrocarbon (S1) is 3.21–12.14%, pyrolysis hydrocarbon (S2) is 41.86–165.39%, and maximum pyrolysis temperature (Tmax) is 439–445°C. The mineral composition is mainly dominated by quartz 3.94–43.27%, followed by feldspar 9.65–30.07% and clay minerals 13.46–59%. Illonite/smectite (I/S) is the main clay mineral, accounting for 47–69%. The liquid nitrogen adsorption curve showed that the pore types were tubular and plate-like. The pores are mainly microporous (<2 nm) and mesoporous (2–50 nm) in size. Isothermal adsorption results show that Langmuir volume (VL) is 2.06–5.57 cm3 g−1, Langmuir pressure (PL) is 2.16–3.28 MPa, and shale adsorption capacity is small and easy to desorb. A quartz content less than 25% is negatively correlated with the specific surface area (SSA); otherwise, it is positively correlated. A clay mineral content less than 45% is negatively correlated with SSA; otherwise, it is positively correlated. The relationship between the carbonate content and pore structure is not obvious. Pyrite content less than 2% is positively correlated with SSA; otherwise, it is negatively correlated. The SSA is positively correlated with TOC, inertinite, and exinite and negatively correlated with vitrinite. The adsorbed gas content is positively correlated with the TOC content, SSA, inertinite content, and exinite content and negatively correlated with vitrinite.

Geochemical and Geological Characterization of Upper Permian Linghao Formation Shale in Nanpanjiang Basin, SW China

The Upper Permian Linghao Formation shale is the most potential shale gas exploration target in Nanpanjiang Basin. In this study, X-ray diffraction, field emission scanning electron microscopy, CH4 isothermal adsorption, and nuclear magnetic resonance cryoporometry are intergrated to reveal comprehensive characterization of Linghao Formation shale collected from a well in Nanpanjiang Basin. Results indicate that organic-rich shales developed in the Ling 1 member and the lower part of Ling 3 member. The organic-rich shales are predominantly characterized by kerogen type I, with a relatively highly mature to overmature status. The Ling 1 organic-rich shale mainly consists of mixed shale lithofacies, and the organic-rich shale in the lower part of Ling 3 is mainly composed of argillaceous shale. The pore volume in Ling 1 organic-rich shale is mainly contributed by 3- to 6-nm and 8- to 11-nm organic pores. The pore volume of Ling 3 organic-rich shale is mainly contributed by 2- to 3-nm and 4- to 11-nm organic pores. The organic pores between 3 and 10 nm also have a small contribution to the pore volume. The absolute adsorption gas content of Ling 1 and Ling 3 organic-rich shale is 1.21 m3/t and 1.64 m3/t, respectively. The absolute adsorption gas content of Ling 1 and Ling 3 organic-rich shale exceeds the minimum standard for commercial shale gas development in China (1.0 m3/t). According to the adsorption gas ratio of 50%, the total gas content of Ling 1 and Ling 3 organic-rich shale can reach 3.28 m3/t and 2.28 m3/t, respectively. It is suggested that the Upper Permian Linghao Formation shale in the Nanpanjiang Basin has a significant potential for shale gas exploration.

Evaluation on carbon isotope fractionation and gas-in-place content based on pressure-holding coring technique

Gas-in-place (GIP) and gas-adsorbed ratio are crucial parameters for resource potential assessment and production strategy optimization. Although various methods have been proposed to evaluate these two parameters, none have been widely recognized due to a lack of convincing comparison and validation. In this study, we established a GIP content calculation method by summing five gas components in the pressure-holding coring (PHC) technique: lost gas during retrieving, extracted gas during depressurization, lost gas during surface exposure, degassed gas, and residual gas. The GIP content of the four pressure-holding shale cores retrieved from the Longmaxi Formation of Lu-2 well, Sichuan Basin, China, ranges from 6.46 cm3/g to 10.58 cm3/g, which is used for comparing and verifying theoretical methods. The comparison results show that traditional methods, including the USBM, polynomial fit, ACF, and MCF methods, failed to accurately evaluate GIP content due to their defects in the theoretical foundation and boundary conditions settings. The carbon isotope fractionation (CIF) model derived on a rigorous theoretical basis and equipped with variable boundary conditions achieves the highest accuracy when evaluating the GIP content. Furthermore, the CIF model can determine the gas-adsorbed ratio, another critical parameter that traditional methods cannot obtain; the calculated gas-adsorbed ratio of five shale samples from the Lu-2 well is between 11.15% and 24.56%, with an average of 17.10%. With the help of the CIF model, we confirmed the general pattern of isotope fractionation during shale gas degassing and discussed the limitation and potential of two empirical parameters, δ13C1 of the first sample and △δ13C1 (the difference in δ13C1 value between the last and first sample), in indicating the adsorbed gas content.

Characteristics of Pore Structure and Gas Content of the Lower Paleozoic Shale from the Upper Yangtze Plate, South China

This study is predominantly about the differences in shale pore structure and the controlling factors of shale gas content between Lower Silurian and Lower Cambrian from the upper Yangtze plate, which are of great significance to the occurrence mechanism of shale gas. The field emission scanning electron microscopy combined with Particles (Pores) and Cracks Analysis System software, CO2/N2 adsorption and the high-pressure mercury injection porosimetry, and methane adsorption were used to investigate characteristics of overall shale pore structure and organic matter pore, heterogeneity and gas content of the Lower Paleozoic in southern Sichuan Basin and northern Guizhou province from the upper Yangtze plate. Results show that porosity and the development of organic matter pores of the Lower Silurian are better than that of the Lower Cambrian, and there are four main types of pore, including interparticle pore, intraparticle pore, organic matter pore and micro-fracture. The micropores of the Lower Cambrian shale provide major pore volume and specific surface areas. In the Lower Silurian shale, there are mesopores besides micropores. Fractal dimensions representing pore structure complexity and heterogeneity gradually increase with the increase in pore volume and specific surface areas. There is a significant positive linear relationship between total organic carbon content and micropores volume and specific surface areas of the Lower Paleozoic shale, and the correlation of the Lower Silurian is more obvious than that of the Lower Cambrian. The plane porosity of organic matter increases with the increase in total organic carbon when it is less than 5%. The plane porosity of organic matter pores is positively correlated with clay minerals content and negatively correlated with brittle minerals content. The adsorption gas content of Lower Silurian and Lower Cambrian shale are 1.51–3.86 m3/t (average, 2.31 m3/t) and 0.35–2.38 m3/t (average, 1.36 m3/t). Total organic carbon, clay minerals and porosity are the main controlling factors for the differences in shale gas content between Lower Cambrian and Lower Silurian from the upper Yangtze plate. Probability entropy and organic matter plane porosity of the Lower Silurian are higher than those of Lower Cambrian shale, but form factor and roundness is smaller.

Effect of Pre-Adsorbed Water on Methane Adsorption Capacity in Shale-Gas Systems

The presence and content of water will certainly affect the gas adsorption capacity of shale and the evaluation of shale gas content. In order to reasonably evaluate the gas adsorption capacity of shale under actual reservoir conditions, the effect of water on methane adsorption capacity needs to be investigated. Taking the Da’anzhai Member of the Lower Jurassic Ziliujing Formation in the northeastern Sichuan Basin, China as an example, this study attempts to reveal the effect of pre-adsorbed water on methane adsorption capacity in shale-gas systems by conducting methane adsorption experiments in two sequences, firstly at different temperatures under dry condition and secondly at different relative humidity levels under the same temperature. The results show that temperature and relative humidity (i.e., water saturation) are the main factors affecting the methane adsorption capacity of shale for a single sample. The key findings of this study include: 1) Methane adsorption capacity of shale first increases then decreases with depth, reaching a peak at about 1,600–2,400 m. 2) Lower relative humidity correlates to greater maximum methane adsorption capacity and greater depth to reach the maximum methane adsorption capacity. 3) 20% increase of relative humidity results in roughly 10% reduction of maximum methane adsorption capacity. As a conclusion, methane adsorption capacity of shale is predominately affected by water saturation, pore type and pore size of shale. This study could provide a theoretical basis for the establishment of a reasonable evaluation method for shale adsorbed gas content.

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.

Correlation between adsorbed methane concentration and pore structure of organic-rich black shale from the Liard Basin, Canada

Evaluating the adsorbed gas content in shale gas reservoirs is crucial for calculating total gas production potential of the reservoir. In this study, we analyzed the chemical composition and total organic carbon content of the black shale samples collected from different depths in the Liard Basin, Canada. The samples were identified as siliceous-rich shale samples; specifically, organic-rich black shale with a total organic carbon content of more than approximately 3%. We also analyzed the adsorbed methane gas content and the pore structure of the shale samples. We conducted a mechanistic study to identify the important factors affecting the amount of adsorbed CH4 gas in the shale by evaluating the correlation between the adsorbed CH4 gas content and quantitative pore structure results (i.e., specific surface area and micropore, mesopore, and macropore volume). The results indicate that the micropore volume can be effectively used to predict the content of adsorbed CH4 gas in organic-rich black shale samples from the Liard Basin.

Borehole measurements of adsorbed gas content in coals using stimulated diffusion nuclear magnetic resonance

We present an NMR measurement technique which has the unique ability to determine the in-situ adsorbed gas concentration within coal seams. The measurement of adsorbed gas content is of critical importance for operational safety and commercial resource evaluation in the development of coal mining operations and coal seam gas (CSG) resources. The current measurement technique involves laboratory core analysis, using a canister desorption measurement which is subject to significant measurement uncertainty due to the gas lost between coring and analysis. The NMR measurement technique enables in-situ measurement of fluid content within the coal seams without disturbing the coal seams. The technique utilises the stimulated echo diffusion editing (SEDE) pulse sequence which simultaneously captures relaxation and diffusion behaviour of fluids contained within coal seams. In this work, we have optimised the SEDE pulse sequence by using two diffusion times which are appropriate for capturing the diffusive behaviour of water and adsorbed gas. The measured signal captured by the SEDE sequence is inverted to provide a T2-StimD distribution. The appropriate interpretation of the T2-StimD distribution enables the determination of the free and adsorbed gas concentrations. The adsorbed gas concentration measured using the optimised SEDE sequence shows very good agreement with core canister desorption measurements. The sequence also enables the detection of free gas which is important for understanding the depressurisation of the coal seams and the impact on development strategies.

Study on the Critical Value of Residual Gas Content Based on the Difference of Adsorption Structure between Soft and Hard Coal.

In view of the difference of the adsorption structure between soft and hard coal, there is a big difference in the critical value of the inspection index for the regional outburst risk caused by the gas content. For the coal seams with soft and hard coal stratification, the model of gas content in the equilibrium state was established first, and the microscopic parameters of different rank coals were determined by the low-temperature liquid nitrogen adsorption test and mercury intrusion test. Then, the adsorption capacity of coal samples was determined by the adsorption test. Finally, the residual gas content of the coal seam in the equilibrium state was calculated based on the adsorbed gas content, and the critical value of prediction indexes of regional outburst based on the residual gas content was studied. The results show that for the same metamorphic degree, the specific surface area of soft coal is larger than that of hard coal. However, under the same gas pressure, the residual gas content of hard coal of anthracite and lean coal is greater than that of soft coal with the same metamorphic degree, while that of meager-lean coal and gas-fat coal is opposite. It is suggested to adopt the small value (rounded) of the measured gas content of soft and hard coal at 0.74 MPa as the critical value of the residual gas content in the regional effect test from the economic perspective. It is of great significance to determine the critical standard of the residual gas content in the regional effect test according to local conditions for reducing the cost of outburst prevention work.

Evaluation of the in-place adsorbed gas content of organic-rich shales using wireline logging data: a new method and its application

Evaluation of the in-place adsorbed gas content of organic-rich shales using wireline logging data: a new method and its application

Experimental study of slickwater volume effect on methane desorption on Longmaxi shale

A large portion of slickwater is trapped in gas shale formations after the hydraulic fracking process. To address the effect of slickwater retention on methane desorption, the adsorption and desorption isotherms for methane before and after slickwater treatment were measured based on the volumetric method using shale samples from the Longmaxi formation, China. We found the adsorption and desorption data for the methane before and after treatment fit well with the Freundlich model. We compared the effect of slickwater volume on desorption isotherms, desorption efficiency, adsorbed methane content and cumulative gas production. Slickwater treatment significantly reduces methane adsorption. The Freundlich constant k reduction decreases nearly linearly with the slickwater volume, and constant n increases nearly linearly first and then becomes slower with slickwater volume. Test results also reflected that slickwater treatment could improve methane desorption efficiency. The curve of desorption efficiency after treatment is significantly lower than before. Under 30 MPa pressure, the desorption efficiency increases by 50.93% when slickwater volume increases to 10.40 ml from 2.02 ml. A closed loop exists between two curves of adsorbed gas content before and after treatment, and its area increases with slickwater volume. Slickwater treatment improves cumulative gas production. The cumulative production of methane before treatment is smaller than after. 8.16 ml of slickwater is the best option for 130 g of shale powders to obtain the most cumulative gas production in the lab-scale condition. These results can be used to optimize the slickwater volume during hydraulic fracturing.

Effects of pore morphology and moisture on CBM‐related sorption‐induced coal deformation: An experimental investigation

AbstractCoalbed methane (CBM) is an important resource of energy. For CBM recovery, sorption‐induced coal deformation can cause significant reservoir permeability change. Moisture content and coal pore morphology affect the gas adsorption capacity and can alter the coal deformation of the coal seam. Therefore, it is crucial to establish a coal gas moisture‐coupled model for CBM production prediction. However, there are currently insufficient data available for quantitative analyses. In this paper, a series of typical sorption‐induced strain experiments were carried out during methane adsorption and desorption on coal samples with different metamorphic degrees and moisture content. The pore morphology and adsorption capacity of coals were measured to analyze the reason for different deformation of coals with various pore structures and moisture. Results show that the adsorption capacity and deformation is corresponding to the specific surface area of micropore, which first decreases and then increases with coal ranks. The deformation and adsorption gas content of dried coals is greater than that of natural moisture coals, which means that moisture can reduce the sorption capacity of coals, resulting in the decrease of gas adsorption‐induced coal deformation. There is also residual deformation of coal samples after gas desorption caused by the residual adsorbed gas in coals. This paper quantitatively investigates the effects of pore characteristics and moisture on coal deformation and the internal mechanism. This work will provide essential information for building out a fully cross‐coupled model of coal gas‐moisture relationships for CBM production prediction.

A process-based coal swelling model: Bridging the gaps between localized swelling and bulk swelling

Injection of CO2 and coal seam gas production induce coal swelling/shrinkage. Laboratory tests indicate that coal swelling may go through several stages from localized swelling at fracture surfaces to bulk rock swelling. The coal Langmuir swelling strain constant normally ranges from 0 to 0.04. This study provides a process-based coal swelling model that covers the whole swelling procedure. We account for three swelling strains, videlicet, the matrix swelling strain, fracture swelling strain, and bulk rock swelling strain. Dynamic partial separation coefficients are employed to quantify the contributions of the matrix swelling strain to bulk swelling and the fracture (cleat) aperture reduction, bridge the gaps between localized swelling and bulk swelling, and link the three types of strains. This model is inserted into a permeability model and verified against permeability measurement and rock swelling data. The three samples used for verification are bituminous coals from the Illinois Basin (depth of ~ 200 m) in the US and Henan Province in China (depth of ~ 310 m). In essence, the swelling model is also applicable to other coal types with a linear relationship between the matrix swelling strain and adsorbed gas content. By matching with long-term permeability measurement data, multiple permeability evolution stages are observed due to the swelling transition. Sensitivity analyses show that the matrix block size, matrix swelling properties, and diffusivity control the duration, occurrence, and magnitude of matrix swelling’s contribution to local and bulk swelling during swelling transition, while rock bridge swelling properties have a marginal influence on coal swelling.