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To compare the micropore structure of marine-continental transitional shale with marine shale, organic geochemical, field emission scanning electron microscopy, and low-temperature nitrogen adsorption experiments were conducted on shale samples from the Shanxi Formation in the eastern Ordos Basin and the Longmaxi Formation in the southern Sichuan Basin. The results show that Shanxi Formation shale has a smaller specific surface area and pore volume than Longmaxi Formation shale; therefore, the transitional shales fail to provide sufficient pore spaces for the effective storage and preservation of natural gas. Both the transitional and marine shales are in an overmature stage with high total organic carbon content, but they differ considerably in pore types and development degrees. Inorganic pores and fractures are dominantly developed in transitional shales, such as intragranular pores and clay mineral interlayer fractures, while organic nanopores are rarely developed. In contrast, organic pores are the dominant pore type in the marine shales and inorganic pores are rarely observed. The fractal analysis also shows that pore structure complexity and heterogeneity are quite different. These differences were related to different organic types, i.e., type I of marine shale and type III of transitional shale. Marine Longmaxi shale has experienced liquid hydrocarbon cracking, gas generation, and pore-forming processes, providing good conditions for natural gas to be preserved. However, during the evolution of transitional Shanxi shale, gas cannot be effectively preserved due to the lack of the above evolution processes, leading to the poor gas-bearing property. The detailed comparison of the micropore structure between the transitional and marine shales is of great importance for the future exploitation of marine-continental transitional shale gas in China.

The significantly different geological processes experienced by the shales in the southern Sichuan Basin provide a means for comparing their pore characteristics and their supercritical m...

In the Carboniferous–Permian period, several organic-rich black shales were deposited in a marine–continental transitional environment in the Linfen area on the eastern margin of the Ordos Basin. Integrated sedimentological and organic geochemical analyses are performed on an outcrop in order to clarify the relationship between paleoenvironment and organic matter accumulation. The results of this study show that the marine–continental transitional strata of the Upper Carboniferous Benxi Formation to Lower Permian Taiyuan and Shanxi Formation exposed in the Linfen area are composed of sandstone, shale, coal, and limestone. Total organic carbon (TOC) contents of the studied samples were mainly distributed in the range of 0.59%–35.4%, with an average of 7.32%. From Benxi Formation to Shanxi formation, the humidity gradually increased, and the climate gradually changed from hot and humid to warm and humid during Carboniferous to Permian. The deposition of the Shanxi Formation ended with the climate returning to hot and humid, having an oxic-suboxic conditions and a high paleoproductivity. Paleoredox conditions and paleoproductivity are the two vital factors controlling the formation of organic matter in black shales. The transitional environment characterized by oxic-suboxic, relatively high deposition rate, and various source of organic matter, although different from the marine environment, provides a good material basis for the deposition of organic-rich shales.

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.

Although the Brunauer-Emmett-Teller (BET) equation is a classic adsorption model for describing the adsorption of gases in adsorbents, it cannot be applied in supercritical conditions because the saturation vapor pressure (p0) in this equation is not defined when T > Tc. In this study, a modified BET equation is proposed, and can be applied to investigate supercritical methane adsorption mechanisms in shale by using density instead of pressure in this equation. The observed (excess) high-pressure methane adsorption isotherms always can be well-fitted by the modified BET model when the adsorbed-phase density (ρa) is not fixed. The fitted results show that the number of adsorption layers (n) ranges from 1.79 to 2.42, with an average value of 2.12, indicating a double-layer adsorption mechanism approximately. Moreover, we compare this novel model with the commonly used Langmuir and DR models, and find that all the three models can fit the excess adsorption isotherms equally well. However, a critical advantage of this new model is that it can calculate the number of adsorption layers (n), while other models cannot. It is this advantage that makes it possible to analyze the shale gas adsorption mechanism experimentally. Moreover, the average number of adsorption layers (θ) is much smaller than the number of adsorption layers (n), indicating that there are many empty adsorption sites in the adsorption space and the density of the second layer must be less than the first layer, which is consistent with the molecular simulation results.

Low-field nuclear magnetic resonance (LF-NMR), high-speed centrifuge and low-pressure nitrogen adsorption (LPNA) experiments were conducted on shale samples from the Lower Silurian Longmaxi Formation to measure pore-throat parameters of the shale reservoir. We measured bound water saturation, helium porosity, bulk density, specific surface area, and pore-size distribution to evaluate reservoir quality. The thickness of the bound water film was calculated based on the equation established from these parameters, showing that its thickness ranges from 1.07 nm to 2.73 nm, with a mean of 1.72 nm. In addition, Grand Canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations were carried out to estimate the methane adsorption capacity and the number of the adsorbed layers in pores with different sizes at the given temperature and pressure (393.15 K, 65 MPa). The simulation results demonstrate that methane is unanimously adsorbed into pores

In this work, new integrated permeability models for micro-nanopores and fractal shale matrixes are constructed by coupling different transport mechanisms, adsorption phenomenon, and real gas effect. The applicability of these proposed models is verified by mathematical models, molecular dynamic simulation results, and experimental data. The impacts of gas properties on gas transport at the pore scale and the contributions of different transport mechanisms on gas flow at pore and core scale are analyzed. The apparent permeability at pore scale and core scale decreases with increasing pressure. The bulk gas transport in micropores is strongly reduced because of the adsorption of methane molecules. The real gas effect enhances both transition diffusion and surface diffusion under high pressure at pore scale. However, the effect of the real gas effect on the slip flow permeability is negligible. At pore scale, surface diffusion, transition diffusion, and slip flow successively dominate the gas transport with increasing pore diameter under lower pressure. At core scale, the dominating transport mechanism under lower pressure is mainly under the control of pore size distribution and gas type. For larger pores and shale matrixes, the Darcy's law is still effective for describing the gas permeability under higher pressure.

The microstructures of shale samples before and after hydration were characterized by field emission scanning electron microscopy (FESEM), and the differences in microstructure and physical parameters of original shale samples, water saturated samples and samples with water centrifugated were examined by micro CT, porosity and permeability tests. The FESEM test shows that the hydration has no effect on the main morphology, position and pores of organic matter (OM). Hydration can increase the number and width of fractures in shale, including generation of new fractures and extension of existent fractures between inorganic minerals and width increase of fractures between banded organic matter and inorganic minerals. Micro CT results of samples with different water saturations show that the intensity of hydration is dominated by primary fracture development, in other words, the more developed the primary fractures of the shale, the stronger the hydration will be. The width of fractures increased two to five times by intense hydration. The porosity of shale is mainly controlled by organic matter content and secondly influenced by the fracture development. The permeability of shale is mainly affected by fracture development and secondly by the porosity. The fracture development influenced both porosity and permeability, but more strongly on permeability than porosity. Key words: shale, hydration, microstructure, physical parameters, fracture, pore

A model for gas transport in shale is proposed by accounting for three major fluid flow mechanisms in shale stratum, which is modeled as a 3D fractal media. The proposed apparent permeability of shale is an analytical expression that also accounts for heterogeneous pore sizes in shale stratum, and is verified using experimental datasets for methane and helium flow in shale. Results of sensitivity analysis indicate that surface diffusion of adsorbed gas plays an important role, specifically in smaller pores, while surface diffusion would be negligible in larger pores. Further, the proposed model shows that flow due to surface diffusion decreases moderately with the increase of isosteric adsorption heat, while it increases significantly with the increase of the maximum adsorption capacity. One of the key novelties of the proposed permeability model is that it accounts for pore size distribution to reveal novel insights on gas transport in shale that can be used to optimize gas production by operational controls (e.g. controlling reservoir pressure) as flow regimes change with time.

Understanding the methane adsorption mechanism is critical for studying shale gas storage and transport in shale nanopores. In this work, we conducted low-pressure nitrogen adsorption (LPNA), scanning electron microscopy (SEM), and high-pressure methane adsorption experiments on seven shale samples from the Longmaxi formation in Sichuan basin. LPNA and SEM results show that pores in the shale samples are mainly nanometer-sized and have a broad size distribution. We have also shown that methane should be not only adsorbed in micropores (< 2 nm) but also in mesopores (2-50 nm) by two hypotheses. Therefore, we established a novel DA-LF model by combining the micropore filling and monolayer coverage theories to describe the methane adsorption process in shale. This new model can fit the high-pressure isotherms quite well, and the fitting error of this new model is slightly smaller than the commonly used D-A and L-F models. The absolute adsorption isotherms and the capacities for micropores and mesopores can be calculated using this new model separately, showing that 77% to 97% of methane molecules are adsorbed in micropores. In addition, we conclude that the methane adsorption mechanism in shale is: the majority of methane molecules are filled in micropores, and the remainder are monolayer-adsorbed in mesopores. It is anticipated that our results provide a more accurate explanation of the shale gas adsorption mechanism in shale formations. Cited as : Zhou, S., Ning, Y., Wang, H., Liu, H., Xue, H. Investigation of methane adsorption mechanism on Longmaxi shale by combining the micropore filling and monolayer coverage theories. Advances in Geo-Energy Research, 2018, 2(3): 269-281, doi: 10.26804/ager.2018.03.05

The graptolitic shale of the Wufeng–Longmaxi Formations is widely deposited across the Ordovician and Silurian transition in South China, which is the target of shale gas exploration and development within China. The contribution of graptolites to organic enrichment and reservoir of gas shale is discussed below based on the statistics of nearly 1000 shale samples from the Wufeng Formation and the bottom part of the Longmaxi Formation in the southern and northern margins of the Yangtze plate. The assessment involves graptolites abundance, the total organic carbon (TOC) content analyses, and the different scales of scanning electron microscopy analyses of related samples. The TOC content of the Wufeng–Longmaxi graptolitic shales (including graptolites and non-graptolites, i.e., the host shale) is mainly controlled by that of its host shale, while less affected by the graptolites abundance, indicating that the graptolites barely influence the organic enrichment. Graptolites consist of a large number of organic matter with reticular biological tissue structure; they account for 20%–50% of the graptolitic area. The aforementioned also developed honeycomb-shaped pores with pore sizes ranging 110 nm-1.7 μm (an average of about 500 nm), which are higher than those of the organic pores in the host shale (108–770 nm, average 330 nm), proving that graptolites have an important contribution to shale gas storage space. Since there are a large number of graptolites within the shales from the Wufeng Formation and the bottom part of the Longmaxi Formation, the laminated and stacked local pattern of their distribution provides abundant storage space for shale gas. Moreover, the feature also serves as the predominant channel for shale gas flow. Therefore, the widely developed graptolites should be considered as one of the essential factors controlling enrichment and high productivity of shale gas in the Wufeng–Longmaxi Formations. Keywords: Shale gas, Graptolites, Longmaxi formation, Organic pore, Organic enrichment, Reservoir, Sichuan basin

To investigate the methane adsorption capacity and the characteristics of gas shales under high pressures, we conducted total organic carbon (TOC), low-pressure nitrogen adsorption (LPNA), and high-pressure methane adsorption experiments (up to 30.0 MPa) on eight Lower Silurian Longmaxi shale samples collected from northeastern Chongqing, China. The experimental results show that the excess adsorption capacity increases to its maximum value and then decreases with further increasing pressures. TOC and the specific surface area of micro-pores are positively correlated with the maximum methane adsorption capacity. The density of adsorbed phase is the key parameter for converting excess adsorption isotherms into absolute adsorption isotherms and has been determined based on three methods for comparison. The DR-based excess adsorption model in the third method has shown to be more reliable than other methods, in which the density of supercritical methane is considered to be lower than the liquid methane density at the boiling point (0.423 g/cm3). The absolute adsorption isotherms were obtained after determining the density of adsorbed phase. The actual adsorption capacity would be underestimated when only low-pressure experiments (0–10 MPa) were performed. The analysis of the adsorbed-phase volume demonstrates that the adsorbed methane is stored not only in micropores (

Shale gas is different from conventional natural gas stored in sandstone and carbonate formations because the shale formation is often both the source and the reservoir of the natural gas itself. The adsorbed gas accounts for 20%–85% of the total amount based on current studies in five major shale formations in the United States. Studying on the mechanism and model of shale gas adsorption is of great importance for reserve evaluation and making development plan. The micropore structure and isothermal adsorption curves of Longmaxi shales were analyzed by low-temperature N2 adsorption and high-pressure CH4 adsorption experiments. The results show that its specific surface area and pore volume are mainly controlled by mesopores (2–200 nm). The excess adsorption capacity ( n ex) increases to a maximum value at the pressure of approximate 10 MPa, and then begins to decline with pressure. This abnormal phenomenon has also been observed in some previous studies, but most researchers stated that the adsorption isotherm of methane in shale monotonically increased with pressure and reached a constant value at a high pressure (i.e., type I isotherm). The main reason for these two different types of adsorption isotherms is whether the volume of the adsorbed phase is assumed to be negligible. To simulate the enrichment and production of methane in shale gas reservoirs, an accurate model of gas adsorption is needed. The most commonly used adsorption model for shale gas reservoirs is the classic Langmuir equation and its extended Langmuir-Freundlich (L-F) equation, which assumes that methane is a monolayer adsorbate and the surface of the solid adsorbent is homogeneous with constant adsorption heat. Many physical adsorption phenomena can be described by the Langmuir model, including coalbed methane adsorption, but the assumptions are too ideal to match the complicated situation of shale gas reservoir. Several multilayer adsorption theories also have been proposed and applied, such as the Dubinin-Radushkevich (D-R) and the Dubinin-Astakhov (D-A) equations based on micropore filling mechanism. The D-R and D-A adsorption model have been widely used in methane adsorption on shale because of its quite good fitting quality. The comparative analysis of the four commonly used adsorption models shows that the fitting effect of D-A model is better than D-R model for micropore filling mode, and the fitting effect of L-F model is better than Langmuir model for monolayer adsorption mode. Further through the two hypotheses, it is proved that the adsorption mode of methane is neither single micropore filling nor single monolayer adsorption, and the adsorption mechanism is the coexistence of micropore filling and monolayer adsorption. Based on the adsorption mechanism, a new model of supercritical adsorption of shale gas—DA-LF model was proposed. The new model has better fitting effect than the commonly used models, and can calculate the adsorption amount of micropores and mesopores, respectively. The results show that the adsorption capacity of micropore filling is larger than that of monolayer adsorption, which accounts for about 76% of the total adsorption capacity, indicating that the supercritical adsorption mechanism is mainly micropore filling and monolayer adsorption coexists.

The isosteric heat of adsorption (IHA) is one of the key thermodynamic variables for evaluating the interaction between shale and methane, which is rarely studied especially under high pressure. In this work, we conducted methane adsorption experiments at pressures up to 30 MPa and different temperatures on shale samples collected from Longmaxi formation in Sichuan Basin, China. Based on the definition of IHA and Langmuir adsorption model, we proposed a new method to analyze the IHA of methane on shale under four conditions. The calculated results show that the commonly used Clausius–Clapeyron equation overestimates the true isosteric heat of shale, especially under high pressure. IHA under four conditions yield a fixed order as q st,i-va > q st,r-va > q st,i+va > q st,r+va , indicating both the real gas behavior and the adsorbed-phase volume have a negative influence on it, and the effect of adsorbed-phase volume is dominant. Moreover, IHA at zero coverage ( q st 0 ) in Henry region determined by linear fitting can be regarded as a maximum value in the above four cases, which is independent of pressure and temperature. Therefore, q st 0 can be used as a unique descriptor to evaluate the adsorption affinity of the shale. This work modified the method to obtain the true IHA of supercritical methane on shale more accurately, which lays the foundation for future investigations of the thermodynamics and heat transfer characteristics of the interaction between high pressure methane and shale.

Accurately determining the adsorbed methane content is critical for the assessment of shale gas reserves and the design of effective production strategies. Methane adsorption in shale has been extensively studied by volumetric and gravimetric isothermal adsorption experiments, but the maximum pressure in most of the previous experiments is far below the actual formation pressure. In this chapter, high-pressure methane adsorption experiments on Lower Silurian Longmaxi shale samples were conducted. The experimental isotherms increased to its maximum value and then decreased with further increasing pressures, and this abnormal behavior was described by some classical models. A novel model by combining the micropore filling and monolayer coverage theories was established to describe the methane adsorption process in shale. The adsorption isotherms and the capacities for micropores and mesopores can be calculated using this new model separately, showing that 77%–97% of methane molecules are adsorbed in micropores. The methane adsorption mechanism in shale is summarized as follows: the majority of methane molecules filled micropores, and the remainder were monolayer-adsorbed in mesopores.

As a new expansion area for natural gas exploration, the Yichuan-Huanglong area improves the complete evolutionary sequence of the Paleozoic natural gas in the eastern part of the Ordos Basin, but the geochemical characteristics and the late gas generation processes involved have not been discussed. By collecting and analyzing gas samples from existing wells, the following insights were obtained. The alkane components had a dichotic characteristic, the wetness of the O1m5–C2b natural gas (average: 3.85%) was relatively higher than that of the Permian natural gas (average: 0.88%). The carbon isotopic compositions exhibited partial reversal (δ13C-CH4 >δ13C-C2H6), and the Permian natural gas from the coal-measure strata had abnormally low δ13C-C2H6 values (

Studying complex pore structures is the key to understanding the mechanism of shale gas accumulation. FIB-SEM (focused ion beam-scanning electron microscope) is the mainstream and effective instrument for imaging nanopores in gas shales. Based on this technology, 2D and 3D characteristics of shale samples from Lower Silurian Longmaxi formation in southern Sichuan Basin were investigated. 2D experimental results show that the pores in shale are nanometer-sized, and the structure of those nanopores can be classified into three types: organic pores, inorganic pores and micro fractures. Among the three types, organic pores are dominantly developed in the OM (organic matter) with three patterns such as continuous distributed OM, OM between clay minerals and OM between pyrite particles, and the size of organic pores range from 5 nm to 200 nm.Inveresly, inorganic pores and micro fractures are less developed in the Longmaxi shales. 3D digital rocks were reconstructed and segmented by 600 continuous images by FIB cutting and SEM imaging simultaneously. The pore size distribution and porosity can be calculated by this 3D digital core, showing that its average value is 32 nm and porosity is 3.62%.The 3D digital porosity is higher than its helium porosity, which can be regarded as one important parameter for evaluation of shale gas reserves. The 2D and 3D characterized results suggest that the nanometer-sized pores in organic matter take up the fundamental storage space for the Longmaxi shale. These characteristics have contributed to the preservation of shale gas in this complex tectonic area.

To verify recent single-well data from the Sichuan Basin, we analyzed the molecular and isotopic composition of late-mature Longmaxi shale gases from the southwestern portion of the Fuling block. The gases are highly enriched in methane (>96.1%) and have low C2+ hydrocarbon contents (