Methane Adsorption Capacity Of Shale Research Articles

Determination of adsorption parameters in shale gas resource/reserve calculation: Case study of Wufeng Formation–Longmaxi Formation in the Sichuan Basin

In the calculation of shale gas resources/reserves, isothermal adsorption parameters are mainly determined by dry sample data at the laboratory temperature, and the regression effect of total organic carbon content (TOC) isothermal adsorption parameters is poor. Based on the physical significance of key parameters in Langmuir and Henry adsorption models, the problems in determining the isothermal adsorption parameters in the calculation of shale gas reserves/reserves are analyzed by taking the marine shale in the Upper Ordovician Wufeng Forming–Lower Silurian Longmaxi Formation in the Sichuan Basin as an example. Based on a large number of measured isothermal adsorption data, the effects of TOC, temperature and water saturation on the shale gas adsorption parameters are analyzed. The influence model of TOC, temperature and water saturation on isothermal adsorption parameters of shale gas is established, and a novel method for calculating the adsorption parameters of shale gas from under experimental conditions to original reservoir conditions is proposed. The results are obtained as follows. First, there are problems in the calculation of shale gas resources/reserves, such as poor and contradictory fitting relation between isothermal adsorption parameters and TOC, difficulty in the conversion of Van't Hoff equation, and difficulty in direct application of water saturation (Sw) in resource/reserves calculation. Second, the problem of poor direct fitting relation between Langmuir pressure (pL) and TOC is solved by integrating the Langmuir adsorption model with the Henry adsorption model and by establishing a new parameter – Henry constant a for methane adsorption capacity of shale. Third, when Sw<40%, the Langmuir volume (VL) is linearly negatively correlated with Sw; when Sw<20%, a is constant relatively; by establishing the relationship between the normalized absolute adsorption capacity and Sw (<50%) under the pressure exceeding 30 MPa, the effect of Sw on the isothermal adsorption capacity can be calculated. Fourth, the in-situ stress in the Wufeng Formation–Longmaxi Formation shale reservoir affects the adsorption capacity of shale. For shale reservoirs with the same TOC, the higher the in-situ stress, the smaller the VL and a values. Under high pressure (>30 MPa), the effect of Sw on the methane adsorption capacity of shale shows a similar trend, and the effect of water molecules on the adsorption capacity on shale pore surface is constant. It is concluded that the proposed novel method for determining the isothermal adsorption parameters of shale with different TOC, temperature and water saturation conditions provides a technical support for the accurate calculation of shale gas resources/reserves and contributes to the scientific development of shale gas industry.

Adsorption Characteristics and Pore Structure of Organic-Rich Shale With Different Moisture Contents

A moisture equilibration test has been designed to study the pore structure and adsorption capacity of organic-rich shale with different moisture contents. Five humidity environments were artificially controlled to obtain shale samples with different moisture contents. With the moisture equilibration test and N2 adsorption/desorption, the differences in pore structure of samples with different moisture contents were compared and analysed. The results showed that the diameter of 2–10 nm pores decreased with increasing humidity and that the moisture adsorption characteristics conformed to the GAB adsorption model. It is proposed that when moisture enters a sample, monolayer adsorption will first occur because moisture is preferentially adsorbed on the pore surface with strong hydrophilicity, filling in the relatively small pores. Mesopores and micropores play a major role in water adsorption. With increasing humidity, capillary condensation of moisture gradually occurs in pores. Based on the methane isothermal adsorption test of shale samples with different moisture contents, a quantitative linear relationship between the moisture content and methane adsorption capacity of shale samples has been established. It has been determined that the methane adsorption capacity of shale in underwater conditions is less than that of dry samples, and that the rate of decline in the adsorption capacity of different samples under dry and water balance conditions varies greatly. The distribution characteristics of clay minerals are the main controlling factor of the hydrophilicity of shale, which has a certain guiding significance for further accurate evaluation of shale adsorption gas reserves.

The effect of oil extraction on porosity and methane adsorption for dry and moisture-equilibrated shales

The porosity and methane adsorption capacity of shale used to estimate gas in place (GIP) are affected both by moisture and oil residing in the pore structure, as well as oil naturally present from maturation, which can include contaminant drilling mud fluids used for drilling. To demonstrate the impact of extractable oil on methane adsorption capacity for both dry and moisture-equilibrated shales, two overmature shales from China (SH1, SH2) and two lower mature shales from UK (BS3, GH4) have been investigated. The oils extracted from the overmature shales (<0.5 wt% TOC) are in low yield and arise from oil-based drilling mud, while the much higher yields from the lower maturity UK shales (1.1–2.5 wt% TOC) is mainly from oil generated by maturation. After extraction, minimal changes (<5%) in total nanopore volume (<100 nm) were observed for the dry over mature shales, but significant increases (95 and 176%) were observed for the dry lower maturity shales. More than 60% of the extracted oil resides in micro and mesopores, and removal could unblock the micropore necks and enlarge the accessible meso and macropore volume. Moisture contents are lower for extracted shales, with reductions of 7–37% observed. Methane equilibrium adsorption capacities increased after oil extraction for both the dry and wet shales, especially for lower maturity shales, where increases were over 200% for the wet shales. Henry’s Law was used to show that there were not significant amounts of dissolved methane in oils for the dry shales. Extracting oil from shales prior to determining the porosity and methane adsorption capacity can lead to the GIP being over-estimated for moisture equilibrated shales, particularly for oil-window shales where an overestimation of 22% was obtained for the shale investigated in this study. These findings provide a better understanding of the combined impacts of residual oil and water on GIP and avoid its overestimation.

Clarifying the Effect of Clay Minerals on Methane Adsorption Capacity of Marine Shales in Sichuan Basin, China

The effect of clay minerals on the methane adsorption capacity of shales is a basic issue that needs to be clarified and is of great significance for understanding the adsorption characteristics and mechanisms of shale gas. In this study, a variety of experimental methods, including XRD, LTNA, HPMA experiments, were conducted on 82 marine shale samples from the Wufeng–Longmaxi Formation of 10 evaluation wells in the southern Sichuan Basin of China. The controlling factors of adsorption capacities were determined through a correlation analysis with pore characteristics and mineral composition. In terms of mineral composition, organic matter (OM) is the most key methane adsorbent in marine shale, and clay minerals have little effect on methane adsorption. The ultra-low adsorption capacity of illite and chlorite and the hydrophilicity and water absorption ability of clay minerals are the main reasons for their limited effect on gas adsorption in marine shales. From the perspective of the pore structure, the micropore and mesopore specific surface areas (SSAs) control the methane adsorption capacity of marine shales, which are mainly provided by OM. Clay minerals have no relationship with SSAs, regardless of mesopores or micropores. In the competitive adsorption process of OM and clay minerals, OM has an absolute advantage. Clay minerals become carriers for water absorption, due to their interlayer polarity and water wettability. Based on the analysis of a large number of experimental datasets, this study clarified the key problem of whether clay minerals in marine shales control methane adsorption.

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.

Characteristics and Origin of Methane Adsorption Capacity of Marine, Transitional, and Lacustrine Shales in Sichuan Basin, China

Adsorbed gas is an important component of shale gas. The methane adsorption capacity of shale determines the composition of shale gas. In this study, the methane adsorption capacity of marine, transitional, and lacustrine shales in the Sichuan Basin was analyzed through its isothermal adsorption, mineral composition, water content, etc. The results show that the methane adsorption capacity of marine (Qiongzhusi Formation and Longmaxi Formation), transitional (Longtan Formation), and lacustrine (Xujiahe Formation and Ziliujing Formation) shales is significantly different. The Longtan Formation has the strongest methane adsorption capacity. This is primarily related to its high organic matter and organic matter type III content. The methane adsorption capacity of the lacustrine shale was the weakest. This is primarily related to the low thermal evolution degree and the high content of water-bearing clay minerals. Smectite has the highest methane adsorption capacity of the clay minerals, due to its crystal structure. The water content has a significant effect on methane adsorption largely because water molecules occupy the adsorption site. Additionally, the temperature and pressure in a specific range significantly affect methane adsorption capacity.

Effect of supercritical CO2 saturation pressures and temperatures on the methane adsorption behaviours of Longmaxi shale

Abstract To investigate the effects of supercritical CO2 (SC–CO2) saturation pressures and temperatures on the methane adsorption capacity of shale, total organic carbon (TOC) analysis, X-ray diffraction (XRD) analysis, scanning electron microscope and energy dispersive spectrometer (SEM/EDS) analysis, low-pressure N2 adsorption (LP-NA), and high-pressure methane adsorption (HP-MA) were conducted on raw and SC–CO2–saturated (8, 12, 16 MPa; 40, 60, 80 °C) shale collected from the Sichuan Basin. Results indicate that the excess adsorption isotherm of shale to methane clearly exhibited excess adsorption characteristics with increasing adsorption pressures. This excess methane adsorption capacity decreased after SC-CO2 saturation and is mainly attributable to decreases in the TOC content, clay minerals and specific surface area (SSA) in the SC–CO2–saturated shale. The density of adsorbed phase methane was considered at different adsorption models, and the results suggest that the Langmuir-Freundlich (LF) and Dubinin-Astakhov (DA) models better describe methane adsorption behaviours than the Langmuir and Ono-kondo models. The methane adsorption capacity of shale is closely related to the solubility of SC-CO2, which decreased significantly with increasing SC-CO2 saturation time and pressure, while the influence of SC-CO2 saturation temperatures was not evident at low-pressure (8 MPa). This study provides a theoretical reference for CO2 enhanced shale gas recovery.

Nanostructure Effect on Methane Adsorption Capacity of Shale with Type III Kerogen

This study focuses on the nanostructure of shale samples with type III kerogen and its effect on methane adsorption capacity. The composition, pore size distribution, and methane adsorption capacities of 12 shale samples were analyzed by using the high-pressure mercury injection experiment, low-temperature N2/CO2 adsorption experiments, and the isothermal methane adsorption experiment. The results show that the total organic carbon (TOC) content of the 12 shale samples ranges from 0.70% to ~35.84%. In shales with type III kerogen, clay minerals and organic matter tend to be deposited simultaneously. When the TOC content is higher than 10%, the clay minerals in these shale samples contribute more than 70% of the total inorganic matter. The CO2 adsorption experimental results show that micropores in shales with type III kerogen are mainly formed in organic matter. However, mesopores and macropores are significantly affected by the contents of clay minerals and quartz. The methane isothermal capacity experimental results show that the Langmuir volume, indicating the maximum methane adsorption capacity, of all the shale samples is between 0.78 cm3/g and 9.26 cm3/g. Moreover, methane is mainly adsorbed in micropores and developed in organic matter, whereas the influence of mesopores and macropores on the methane adsorption capacity of shale with type III kerogen is small. At different stages, the influencing factors of methane adsorption capacity are different. When the TOC content is &lt;1.4% or &gt;4.5%, the methane adsorption capacity is positively correlated with the TOC content. When the TOC content is in the range of 1.4–4.5%, clay minerals have obviously positive effects on the methane adsorption capacity.

FRACTAL CHARACTERISTICS OF NANOSCALE PORES IN SHALE AND ITS IMPLICATIONS ON METHANE ADSORPTION CAPACITY

Pore structure in shale controls the gas storage mechanism and gas transport behaviors. Since nanoscale pores in shale matrix have fractal characteristics, fractal theory can be used to study its structure. In addition, fractal method has its own advantages to investigate nanopores in shale, especially for the heterogeneity and irregularity of nanopores in shale. In this work, fractal features of nanoscale pores and the implication on methane adsorption capacity of shale were investigated by employing low pressure nitrogen adsorption, scanning electron microscopy (SEM), and methane adsorption experiments. Frenkel–Halsey–Hill (FHH) model was also used to calculate the fractal parameters of nanoscale pores in shale. The results showed that nanoscale pores in 12 shale samples have obvious fractal features. All the fractal curves of these shale samples can be divided into two segments, which are cut off by [Formula: see text], and the fractal dimensions of these two segments vary from 2.48 to 2.92 [Formula: see text] and 2.42 to 2.80 [Formula: see text], respectively. Based on SEM images, it is found that self-similarity of organic pore systems in shales refers to two aspects. One is that relatively large-scale and small-scale pores have similar formation properties and types, which are of elliptical shape with rough surface. The other is that some small-scale pores are formed by rough surface of relatively large pores. The results also demonstrate that methane adsorption capacity of shale samples increase with increasing total organic carbon (TOC) contents. This is mainly because organic matter is rich in pores and has relatively large fractal dimension values. Larger fractal dimensions indicate rougher pore surfaces and could form more small-scale organic pores. These organic pores would provide more space for methane adsorption.

INVESTIGATION OF FRACTAL CHARACTERISTICS AND METHANE ADSORPTION CAPACITY OF THE UPPER TRIASSIC LACUSTRINE SHALE IN THE SICHUAN BASIN, SOUTHWEST CHINA

To better understand the nanopore characteristics and their effects on methane adsorption capacity of shales, we performed fractal analysis of nine shale samples collected from the fifth member of Upper Triassic Xujiahe Formation in the Sichuan Basin, southwest China. [Formula: see text] adsorption results show that shales have different adsorption characteristics at relative pressure of 0–0.5 and 0.5–1. Two fractal dimensions [Formula: see text] and [Formula: see text] were calculated using the Frenkel–Halsey–Hill (FHH) equation. Results show that the methane adsorption capacity increases with the increase of [Formula: see text] and [Formula: see text], of which [Formula: see text] has a more significant influence on adsorption capacity than [Formula: see text]. Further studies indicate that [Formula: see text] represents the pore surface fractal characteristics caused by the irregularity of shale surface, whereas [Formula: see text] represents the pore structure fractal characteristics, which is mainly affected by shale components (e.g. TOC, clay minerals) and pore parameters (e.g. average pore diameter, micropores content). A higher [Formula: see text] corresponds to a more irregular pore surface, which provides more space for methane adsorption. While a higher [Formula: see text] indicates a more complex pore structure and a stronger capillary condensation action on the pore surface, which in turn enhances the methane adsorption capacity.

Investigation of the methane adsorption characteristics of marine organic-rich shale: A case study of the lower Cambrian Niutitang Shale in the Fenggang block, northern Guizhou Province, South China

The marine shale in South China has great gas exploration potential, and exploration in the Sichuan Basin has been successful, but the degree of exploration remains low in the Guizhou Province. We used organic geochemical analyses (total organic carbon content and kerogen type), scanning electron microscopy (SEM), field emission SEM, nuclear magnetic resonance (NMR), X-ray diffraction analysis, and low-temperature [Formula: see text] and [Formula: see text] adsorption experimental methods to study the micropore types and pore structures and their effects on the methane adsorption capacity of organic-rich shales found in the Fenggang block in northern Guizhou Province. The results indicate that the microscopic surface porosity of the lower Cambrian Niutitang Formation ranges from 2.88% to 5.34%, with an average value of 3.86%. Based on nitrogen adsorption methods, the range of the average pore size distribution is 4.6–9.491 nm, with an average value of 6.68 nm. All of the samples exhibit significant unimodal distributions. The main pore size is less than 10 nm, and these pores account for most of the mesopore volume, which is generally consistent with the NMR results. The methane adsorption capacity of the shale samples gradually increases in the range of 0–8 MPa at 30°C and reaches a maximum at approximately 10 MPa. Positive correlations were found between the gas content and specific surface area, total pore volume, and micropore volume. These strong correlations indicate that the Niutitang Shale has a high specific surface area, a high pore volume, and narrow-diameter pores, demonstrating that it has a high gas adsorption capacity. The results of this study provide valuable information regarding the adsorption characteristics of marine shales and the factors that affect those characteristics.

Methane adsorption behavior on shale matrix at in-situ pressure and temperature conditions: Measurement and modeling

Adsorbed gas is a significant component of shale gas due to the abundant nanopores of organic matter in shales. Methane adsorption behavior on shale matrix is complex considering the geochemical properties, lithology, pore structure and pressure-temperature conditions. In this work, methane adsorption experiments were conducted through a gravimetric method for shale samples at reservoir pressure and temperature conditions. Meanwhile, total organic carbon (TOC), mineral contents and pore structure parameters of samples were measured, respectively. Experimental results show that (1) an excess adsorption phenomenon is obvious at high-pressure and high-temperature conditions; (2)methane adsorption capacity of shale tends to increase with an increase of TOC; (3) lithology and pore structure also affect the methane adsorption capacity of shales, inducing the different adsorption results of two samples with similar TOC; (4) a shale with a large TOC, a low illite content, a large specific area, a large pore volume and a small average diameter would have a strong methane adsorption capacity, nevertheless the effect of TOC is generally dominant. In order to further investigate the methane adsorption behavior on shales, a simplified local density adsorption model considering the cylindrical pore geometry is established, and is regressed and verified by the experimental data. The modeling results indicate that a sample with a large TOC would have a strong fluid-solid interaction energy and a large surface area of methane adsorption. At last, the mechanism of methane adsorption on shales at in-situ conditions is summarized. This work is beneficial for an accurate shale gas reservoir modeling.

Study of the Characteristics of Marine–Terrigenous Facies Shale from the Permo-Carboniferous System in the Guxian Block, Southwest Qinshui Basin

This paper analyzes the characteristics of coal measure shale using samples from the Guxian Block of the southwest Qinshui Basin. Several methods, including X-ray diffraction (XRD), Rock-Eval pyrolysis, high-pressure mercury intrusion porosimetry (MIP), low-pressure nitrogen adsorption/desorption and isothermal adsorption experiments, were used to investigate the organic geochemical characteristics, mineral composition, pore structure and methane adsorption characteristics of the shales. Furthermore, the effect of the total organic carbon (TOC), thermal maturity and mineral composition on the pore structure and methane adsorption capacity of shale was also investigated. The results showed that the TOC of the shale samples ranged from 0.19% to 31.66%, and the shale samples with TOC higher than 2% account for 31.17% of the total samples. The shale samples were in the high-over mature stage with high hydrocarbon conversion rates. The mineral composition of the shale samples are mainly clay minerals and quart...

Geochemical characterization and methane adsorption capacity of overmature organic-rich Lower Cambrian shales in northeast Guizhou region, southwest China

The Niutitang Shale (Lower Cambrian) is another set of organic-rich shale in addition to the Lower Silurian Longmaxi Shale in southwest China. In this study, methane adsorption capacities of both whole rock and organic matter were investigated based on adsorption isotherms measured at various temperatures (40–120 °C) and pressures (up to 35.0 MPa) for eleven Niutitang Shale samples collected from northeast Guizhou Province. The investigated samples cover a wide range of TOC contents, varying from 1.8 to 11.3%, with an average equivalent vitrinite reflectance (EqVRo) value of approximately 4.0%; their BET specific surface areas and micropore volumes range from 11.1 to 26.2 m2/g rock and between 4.3 and 11.2 cm3/kg rock, respectively, both of which are positively correlated to TOC content. Model-fitted methane maximum absolute adsorption capacities (n∞) range from 1.80 to 5.85 cm3/g rock at 60 °C and are found to largely increase with increasing TOC; this suggests that the TOC control on methane adsorption capacity obtained by other authors for other shales with relative low thermal maturity levels may be extended to a very high thermal maturity level, e.g., EqVRo≈4.0%. The methane adsorption capacity of organic matter (OM) in our shale samples, however, is somehow reduced as compared to the Lower Silurian Longmaxi Shale and other shales that display EqVRo values smaller than 3.0%, indicating thermal maturity may adversely affect methane adsorption capacity of shales when it evolves to be EqVRo≈4.0%. Nevertheless, this reduction in adsorption capacity may be compensated by the very enrichment of OM in the Niutitang Shale. In addition, a higher thermal maturity level results in a lower Langmuir pressure value, which makes it more difficult for methane desorption at reservoirs conditions. The temperature dependency of adsorption parameters was also investigated, which could be used to predict the changes of methane adsorption with burial depth under geological conditions beyond experimental temperature and pressure ranges.

Geological controls on methane adsorption capacity of Lower Permian transitional black shales in the Southern North China Basin, Central China: Experimental results and geological implications

The goal of this paper is to investigate the geological controls on the methane adsorption capacity of Lower Permian transitional black shales. To this end, a variety of methods, including quantifying organic matter richness, vitrinite reflectance, kerogen stable isotope analysis, X-ray diffraction (XRD), low-pressure nitrogen adsorption, and high-pressure methane adsorption were performed on black shale samples collected from the Mouye-1 well in the Southern North China Basin. Among them, high-pressure methane adsorption experiments were performed over a pressure range of 0–20MPa at temperatures of 30°C, 40°C, and 50°C. Then, the effects of organic matter, mineral compositions, pore properties, temperature, and pressure on methane adsorption capacity were analyzed, and a new formula for predicting the gas adsorption capacity and methane adsorption capacity of transitional shales as a function of burial depth in the Southern North China Basin was established.Experimental results indicate that the total organic carbon content (TOC) of shales in the present study ranges from 0.49% to 2.37% with an average value of 1.14%. The thermal maturity of these samples, as reflected by their vitrinite reflectance (Ro) values, demonstrates that all involved shale samples have extremely high thermal maturities with an average value of 3.23%. The levels of kerogen stable carbon isotopes (δ13CPDB) range from −25.00‰ to −24.10‰, thereby indicating the presence of primarily type III organic matter within these shale samples. Mineral compositions mainly comprise clay minerals and quartz with average values of 57.8% and 37.6%, respectively. Within clay mineral populations, illite, kaolinite, I-S mixed layer clays, and chlorite are the dominant clay minerals. BET (Brunauer-Emmett-Teller) surface area and total pore volumes of the studied shale samples range from 4.7085m2/g to 9.1883m2/g and 0.01069cm3/g to 0.01802cm3/g, respectively. Under the measured pressure range, methane adsorption capacity correlates positively with TOC content, likely due to the increase in surface area and total pore volume with increasing TOC content. Nanometer-scale pores ranging from 2 to 10nm, as revealed by low-pressure nitrogen adsorption, are the main contributors to surface area and total pore volume within these shales. Although the TOC-normalized surface area increases with thermal maturity, a negative correlation between thermal maturity and methane adsorption capacity was observed in the present study, most likely due to the decrease in TOC during thermal maturation. A weak positive quadratic correlation was also observed between clay mineral contents and methane adsorption capacity, with the Langmuir volume initially decreasing before subsequently increasing with increasing total clay content, thereby indicating that clay minerals have a weaker effect than TOC on methane adsorption capacity. Geologically applying the methane adsorption capacity of shales as a function of burial depth, which was established based on the Langmuir model, indicates that the methane adsorption capacity of transitional shales initially increases before ultimately decreasing as the depth increases due to the joint effects of temperature and pressure.

The effect of moisture on the methane adsorption capacity of shales: A study case in the eastern Qaidam Basin in China

This study investigated the effects of moisture on high-pressure methane adsorption in carboniferous shales from the Qaidam Basin, China. The shale characteristics, including the organic/inorganic compositions and pore structure (volume and surface) distribution, were obtained using various techniques. Gibbs adsorption measurements were performed over a pressure range up to 6MPa and temperatures of 308.15K on dry samples and moisture-equilibrated samples to analyze the correlations between organic/inorganic matter, pore structure, and moisture content on the methane sorption capacity.Compared to dry samples, the sorption capacity of wet samples (0.44–2.52% of water content) is reduced from 19.7±5.3% to 36.1%±6.1%. Langmuir fitting is conducted to investigate moisture-dependent variations of adsorbed methane density, Langmuir pressure, and volume. By combining the pore volume and surface distribution analyses, our observations suggested that the main competition sites for CH4-H2O covered pores of approximately 2–7nm, whereas the effective sites for methane and water were predominantly distributed within smaller (<4nm) and larger pores (>10nm), respectively. Regarding the compositional correlations, the impact of moisture on the amount of adsorbed methane shows a roughly linearly decreasing trend with increasing TOC content ranging from 0.62 to 2.88%, whereas the correlation between the moisture effect and various inorganic components is more complicated. Further fitting results indicate that illite/smectite mixed formations are closely related to the methane capacity, whereas the illite content show an evident connection to the pore structural (volume and surface) variations in the presence of moisture.

Molecular simulation of methane adsorption in shale based on grand canonical Monte Carlo method and pore size distribution

To explore the influence of the pore size distribution on the methane adsorption capacity of shale, methane adsorption amount for different pore sizes has been calculated by using the simulation results and pore size distribution data. In the study, excess adsorption per unit area of different pore sizes has been simulated by the grand canonical Monte Carlo (GCMC) method. And the pore size distribution of Longmaxi Formation shale samples was characterized by high pressure mercury injection (HPMI) experiment, low pressure nitrogen adsorption (LP-N2-GA) experiment, and low pressure CO2 adsorption (LP-CO2-GA) experiment. The results indicate that in the range of 0.5–1.5 nm, the excess adsorption per unit area shows a stepped increase with the pore size increasing. When the pore size is larger than 1.5 nm, the excess adsorption per unit area keep unchanged with the increase in pore size. According to the methane adsorption capacity and pore surface area, pores in the shale samples can be divided to three parts: <1 nm, 1–4 nm, >4 nm. Pores in the first part (width <1 nm) have a large specific surface area, but the excess adsorption per unit area is much smaller than other pores. They account for about 65% of the total specific surface area, while accounting for only 48% of the total adsorption amount. Pores in the second part (1–4 nm) have a large specific pore area and large methane adsorption capacity. They provide 30% of the total specific surface area, while providing 44% of the total adsorption amount. Pores in the third part (width >4 nm) contribute only 8% of total adsorption amount as the specific surface area of these pores is notably small.

Geochemical Characterization of Irati And Palermo Formations (Paraná Basin–Southern Brazil) for Shale Oil/Gas Exploration

AbstractShale gas/oil currently are two of the most important unconventional energy resources. Their exploitation has caused an energy revolution in USA, and many countries are investing in it. Brazil has large areas covered with sedimentary basins, but little attention has been devoted to the study of shale containing oil and gas. The parameters analyzed and studied for geochemical data evaluation are: clay mineral identification, mineral matter analysis, elemental analysis (including total organic carbon, total carbon, H, N, and S), and the methane adsorption capacity of shale. Adsorption in Palermo Formation samples (depth 238.5 m) was 13.72 cm3 g−1 and for samples from Irati Formation (depth 218.45, 95.3, and 107.5 m) 11.73, 6.17, and 4.61 cm3 g−1.