Search

The pore structure of coal has a great influence on the exploitation of coalbed methane. The primary coal and tectonic coal of the Faer Coal Mine and Wenjiaba Coal Mine in Guizhou, China, were selected for low-temperature liquid nitrogen and high-pressure mercury injection experiments. Based on the Frenkel–Halsey–Hill fractal model and multifractal model, combined with nano-CT system, the difference between primary structural coal and tectonic coal and their relationships with fractal dimension were analyzed. According to the results, coal can increase its pore volume and surface area by tectonic action. From the perspective of pore volume and surface area, micropores occupy the main part. According to the pore volume and pore surface area of micropores, that of primary structural coal was lower than that of tectonic coal. For the studied coal samples, their pores have fractal characteristics and complex structure. It can be seen from the fractional dimension that that of tectonic coal was higher than that of primary structure coal, indicating that the microscopic pore structure of coal tends to be complex after tectonic action. According to the results of multifractal and nano-CT analysis, the Hausdorff dimension of tectonic coal was slightly smaller than that of primary structure coal, but the multifractal parameter value was higher than that of primary structure coal. After tectonic action, the connected pores of coal increased by 142.86% compared with the connected pores of primary coal, and the adsorption capacity was further improved. It is further proved that the structure can affect the adsorption and desorption capacity by changing the distribution of pore structure. [ABSTRACT FROM AUTHOR]

Copyright of Coal Geology & Exploration is the property of Xian Research Institute of China Coal Research Institute and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Properly identifying microscopic pore structure properties of shale reservoirs is essential for developing efficient extraction techniques of shale hydrocarbons. To understand the unique and complex pore network of the Northern Guizhou shale reservoir, shale samples from the Wufeng-longmaxi Formation were investigated using different analytical techniques, X-Ray Diffractometry, low-pressure nitrogen gas adsorption-desorption isotherms, and Mercury intrusion capillary porosimeter. Results indicate that the Wufeng-longmaxi formation is mainly composed of a high quantity of quartz ranging from 0.6 % to 64.1 % and an average extent of 55.825 %, the lowest amount of potassium feldspar ranging from 0.6 % to 2.2 % and an average extent of 1.45 % with Total organic contents ranging from 3.672 to 5.209 %. Similarly, the BJH adsorption techniques for pore volume and area were investigated. The results indicate the dominance of the mesopore with pore size ranging from 2.03 nm to 40nm, average pore volume of 0.073715 m3/g, and average pore area of 13.0324 m2/g. The pore throat distributions from MICP showed drain pressure and median pore throat radius ranging from 0.47 to 13.79 MPa and 0.05–0.08 μm, respectively. Suggested complementary experimental techniques reveal the connectivity of pore networks of the Wufeng-longmaxi Formation shale reservoir, which shows a high production potential of hydrocarbons. The findings of this study can provide a valuable understanding of fluid transport properties and storage space of shale gas that can help decision-makers as they set exploration initiatives for shale gas reservoirs. • Three different methods were used to characterize pore evolution of shales. • Pore network was investigated through experimental study and numerical simulation. • Porosity, pore size, surface area, and connectivity were quantitatively studied. • Percolation theory was presented to assess pore network. [ABSTRACT FROM AUTHOR]

Fine dissection of microscopic pore structure variations between the Niutitang Formation and the Wufeng-Longmaxi Formation will help to improve the understanding of the underlying geological theory of shale gas in northern Guizhou Province. The stratigraphic, geochemical, physical, and tectonic properties of the two formations vary greatly, resulting in differential development of the microscopic pore structure among reservoirs and, as a result, major variances in gas concentration. To explore the mechanism of differential pore evolution, experimental techniques and instruments such as gas adsorption, liquid intrusion, SEM, XRD, and organic geochemical tests were utilized. The results indicate that the Wufeng-Longmaxi Formation is in a high-maturity stage, while the Niutitang Formation is in an over-mature stage. The latter has a higher TOC content. Both petrographic phases are siliceous shale petrographic phases, and the former has more developed dissolution pores with better pore volume, throat radius, and macropore pore diameters than the latter, as well as organic matter pores, intergranular pores, and microfracture structural parameters, whereas the specific surface area is the opposite. The differences in reservoir pore formation between the two formations were analyzed, and the results showed that the petrographic type, thermal evolution, and tectonic preservation conditions were the primary controlling elements of differential shale gas reservoir formation. A differential reservoir-forming model of the Wufeng-Longmaxi Formation and the Niutitang Formation was constructed, providing a geological and theoretical basis for shale gas geological exploration in northern Guizhou Province. [ABSTRACT FROM AUTHOR]

Shale gas reservoir is a fine-grained sedimentary rock with component of clastic particles and organic matters, and the accumulation of the organic matters would determine the effective development of shale gas. The paleoclimate, detrital influx, redox of the water and paleoproductivity are effective geochemical indicators that could help to find the favorable shale gas reservoir stratum. In this study, the shale samples collected from Niutitang Formation (Northern Guizhou, China) were launched the measurements of the content of major elements and trace elements, and the characteristics of geochemical indicators were analyzed, which can be used to discuss the accumulation model of organic matters. Besides, the pore structure of shale sample controlled by the enrichment of organic matters is also discussed. The paleoclimate is dominant cold and dry, and it changes to warm and humid at the later Niutitang period, and the detrital influx also increased at the later Niutitang period; the water environment of Niutitang Formation shale presents as reductive, and the paleoproductivity of the Niutitang Formation shale is commonly high. The enrichment of organic matters in the Niutitang Formation is dominantly controlled by the redox of the water, while the hydrothermal activity and the paleoproductivity lead to the difference enrichment of organic matters in the Niutitang Formation shale. The accumulation model of organic matters also influences the characteristics of pore structure from the Niutitang Formation shale, and the pore structure could be divided into two types. The shale with high content of organic matters also features high content of quartz and pyrite, and these minerals contribute to the preservation of pore space in the shale, while that of the clay minerals is contrary. The high content of organic matters and preferable pore characteristics indicate the Niutitang Formation favors the development of shale gas, especially that for the lower Niutitang Formation. [ABSTRACT FROM AUTHOR]

The occurrence and migration of coalbed methane (CBM) is inseparably associated with the pore structure within the coal seams. Three Permian Longtan Formation tectonic coal samples (QL, XL, XT) from Guizhou Province were studied to determine pore size distribution and characteristics, as well as factors that influence adsorption. Adsorption test results show that all samples generally have "ink bottle"-type pores, with large pore capacity but poor connectivity. Furthermore, the fractal dimension Df, the tortuosity "τ", and tortuous fractal dimension DT of samples were calculated. Among the studied tectonic coals, moisture, ash, tortuosity, and volatile fraction have a positive effect on the maximum adsorption capacity (VL), whereas intact coals' tortuosity volatile has a negative correlation with the maximum adsorption capacity (VL). [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The heterogeneity of shale pores, a crucial factor in the occurrence and migration of shale gas, exerts a significant impact on the pore connectivity. Pores exhibiting a range of structural attributes to the complexity of pore connectivity. A comprehensive study into the impact of pore heterogeneity on pore connectivity in shale is lacking. This study aims to explore the impact of pore heterogeneity on pore connectivity in shale and the primary controlling factors of pore connectivity. Shale pore connectivity, pore structures, mineral composition, and geochemical parameters were assessed using various tests, including spontaneous imbibition, adsorption, mercury intrusion capillary pressure (MICP), focus ion beam-scanning electron microscopy (FIB-SEM), sulfur and carbon analysis, vitrinite reflectivity, and X-ray diffraction (XRD). Pore heterogeneity was quantitatively analyzed using the multifractal dimensions method. Results show that the increased heterogeneity of pore structure and surface roughness facilitating the potential for increased connectivity. The presence of well-developed micro-mesopores within the organic matter, alongside numerous disconnected and independent pores, contributes to an increase in pore heterogeneity. Micro-mesopore structures have a more pronounced impact on pore heterogeneity than macropores. The heterogeneity of the pores is predominantly influenced by variations in the PV and SSA of micro-mesopores. Furthermore, the heightened heterogeneity of pore structure (D 1) and surface roughness (D 2) leads to a more complex pore structure with increased roughness, promoting the potential for enhanced connectivity through additional throats and facilitating the formation of secondary microfractures. Shale cores characterized by high total organic carbon (TOC) content, porosity, and clay mineral content are conducive to improved pore connectivity. Conversely, the increase of thermal evolution maturity of shale in the over-mature stage is not conducive to the increase of pore connectivity. Thermal evolution maturity, TOC content, and clay mineral are key factors that control pore heterogeneity, further affecting the connectivity of shale pores. High pore connectivity is conducive to spontaneous imbibition capacity and the formation of hydraulic microfractures, promoting the migration of shale gas. • EqVRo, TOC content, and clays are key factors governing pore heterogeneity. • Micro-mesopores have a more pronounced impact on pore heterogeneity. • The enhanced pore heterogeneity promotes pore connectivity. • Strong pore connectivity is conducive to spontaneous imbibition capacity. [ABSTRACT FROM AUTHOR]

Since shale gas mainly occurs in shale pores, research on pore structure characteristics is the key to understanding the shale gas accumulation mechanism. The pore structure of the Lower Carboniferous Dawuba Formation shale in the Qianxi area, represented by the well QSD-1, which obtains a daily shale gas flow of 10,000 m3 and represents an important breakthrough in the investigation of marine shale gas in the Upper Paleozoic region of southern China, is characterized by high-pressure mercury compression experiments and low-temperature gas adsorption (N2 and CO2) experiments with whole pore size. The main controlling factors affecting the pore development of the shale are discussed. (i) The micropores and mesopores are more developed in the shale, and the macropores are the second most developed in the shales of the Dawuba Formation in the Qianxi area, among which the mesopores and macropores contribute most to the pore volume and the micropores and mesopores contribute most to the pore-specific surface area. (ii) The microfractures and interlayer pores of clay minerals are developed in the shales of the Dawuba Formation, which are the main storage spaces for hydrocarbon gases. (iii) The main factors affecting the adsorption capacity of the shales of the Dawuba Formation in the Qianxi area are the organic carbon content and clay mineral content of the shales, both of which have an obvious positive correlation with the variation of pore structure. [ABSTRACT FROM AUTHOR]

Copyright of Coal Science & Technology (0253-2336) is the property of Coal Science & Technology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Coal Science & Technology (0253-2336) is the property of Coal Science & Technology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The methods of nuclear magnetic resonance (NMR) spectroscopy, mercury injection porosimetry (MIP), and gas‐water relative permeability (GWRP) were used to reveal the pore structure and permeability characteristics of high‐rank coal reservoirs in the Bide‐Santang basin, western Guizhou, South China, to provide guidance for coalbed methane (CBM) exploration and exploitation and obtain direct insights for the development of CBM wells. The results indicate that the coal reservoirs in the study area are characterized by well‐developed adsorption pores and poorly developed seepage pores. The bimodal NMR transverse relaxation time (T2) spectra and the mutation in the fractal characteristic of the MIP pore volume indicate poor connectivity between the adsorption pores and the seepage pores. As a result, the effective porosity is relatively low, with an average of 1.70%. The irreducible water saturation of the coal reservoir is relatively high, with an average of 66%, leading to a low gas relative permeability under irreducible water saturation. This is the main reason for the low recovery of high‐rank CBM reservoirs, and effective enhanced CBM recovery technology urgently is needed. As a nondestructive and less time‐consuming technique, the NMR is a promising method to quantitatively characterize the pores and fractures of coals. [ABSTRACT FROM AUTHOR]

Copyright of Coal Science & Technology (0253-2336) is the property of Coal Science & Technology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Abstract The coal pore structure is closely related to the accumulation and migration of coalbed methane (CBM). This study collected 12 coal samples in western Guizhou and used low-temperature carbon dioxide adsorption/desorption (LT-CO 2 GA), low-temperature nitrogen adsorption/desorption (LT-N 2 GA) and nuclear magnetic resonance (NMR) experimental methods to systematically discuss the pore structure and fractal characterization of main coal-bearing syncline. The study shows that coal rank is an important reason for the difference of 6 synclines coal reservoirs. Bide syncline and Panguan syncline have similar pore structure and fractal characteristics. As the coal rank increases, the DR–SSA, DA–TPV, D 2 , DNMR and V L increase linearly, whereas the BET–SSA and BJH –TPV decrease gradually. Moreover, the connectivity between pores decreases with increasing coal rank. A positive correlation is observed between coal rank, BET–SSA, and BJH –TPV and D 2 , whereas a negative correlation is seen between moisture, ash yield and D 2. DNMR is positively correlated with coal rank, mineral content and ash yield, but negatively correlated with volatile matter content. Although the north synclines have good gas content and a good development potential, poor connectivity and high heterogeneity must be valued during the development process. Highlights • The pore structure and fractal characterization of main coal-bearing synclines in western Guizhou were analyzed. • The influence of coal rank on the pore structure and fractal characterization of coal reservoirs was discussed. • The differential development characteristics of 6 synclines coal reservoirs were discussed. [ABSTRACT FROM AUTHOR]

The coal and coalbed methane (CBM) resources are abundant in western Guizhou and eastern Yunnan, South China. However, commercial CBM production in this region has not been achieved. Reservoir properties are the prerequisites in determining the possibility of CBM exploration and its development potential. Thus, to help to select the most favorable block and to prioritize CBM development in the study area, a comprehensive program of experimental work has been carried out to study the physical properties of coal reservoirs in different blocks. Experimental results show that the properties of coal reservoir change significantly with respect to coal rank, and the coal rank in the study area is very uneven, with the vitrinite reflectance ( R o ) of coal samples ranging from 0.68% to 3.31%. In detail, low rank coals have well developed seepage pores but undeveloped adsorption pores, resulting in the low adsorption capacity and high porosity and permeability. With burial depth increase, the metamorphic degree and compaction degree of coals grow accordingly, as a result pores and fractures are gradually closed under stress, leading to a sharp reduction of porosity and permeability in medium rank coals. However, most of the high rank coals in the study area have experienced a large number of tectonic thermal events, which not only increased the metamorphism degree and adsorption capacity, but also improved the porosity and permeability of the coal reservoirs. Based on experimental results, the CBM potentials of coal reservoirs in different blocks in the study area were evaluated using multi-objective and multi-level fuzzy optimization model, and the most prospective zones for CBM production were suggested. [ABSTRACT FROM AUTHOR]

Shale pore heterogeneity (as described by the fractal dimension) may influence the shale gas-bearing property (GBP). Previous studies on the fractal dimension and its influence on shale GBP were mainly focused on the dry shale samples. Our study investigates the pore structure characteristics under both the dry and moist conditions utilizing low-pressure N 2 /CO 2 adsorption experiments, water-bearing property, and GBP on the eleven as-received (moist) marine Longmaxi shale sampled from the XK3 well in northern Guizhou. Moreover, the fractal dimensions D1 (P/P 0 : 0–0.5) and D2 (P/P 0 : 0.5–1.0) for the dry and moist shales were determined respectively, using low-pressure N 2 adsorption data based on the Frenkel-Halsey-Hill (FHH) method. The results show that the ranges of D1 and D2 for the dry shales are 2.5759–2.7387 and 2.7681–2.8756, respectively, with averages of 2.6970 and 2.8470, while those for the moist shales are 2.0879–2.2215 and 2.6190–2.7252 respectively (averages 2.1591 and 2.6903). Shale water occurs mainly on nonmicropores (>2 nm) surfaces, and part of water fills the micropores (<2 nm), which reduces the nonmicropores BET specific surface area (S BET), micropore volume (V mic), and pore size distribution (PSD) and increases the average pore size (APS), thus reducing the D1 and D2 (19.94 and 5.50% on average, respectively). The shales have high gas contents with an average of 2.59 m3/t, which is dominated by adsorbed gas (75.21% on average). Compared with D2, D1 is more suitable for indicating the pore heterogeneity (especially nonmicropores surface heterogeneity) and shows stronger positive linear relationships with the shale GBP, implying that a larger pore surface heterogeneity is favorable for gas adsorption. Water mainly occurs in the clay minerals and reduces the D1 of the clay pores, thus the TOC content controls the D1 and shale GBP. • Calculation of fractal dimensions (D1 and D2) for both the dry and moist shales. • Water reduces the heterogeneity of the shale effective pore. • D1 relates more closely to shale heterogeneity and gas-bearing property than D2. • TOC content controls the D1 and shale gas-bearing property. [ABSTRACT FROM AUTHOR]

The Lower Cambrian Niutitang Formation is one of the most important shale reservoirs in the Northern Guizhou. To study the characteristics of pore structures and the relationships between shale's physical properties and pore structures in the complex tectonic area, from the perspective of hydrocarbon generation and evolution, the mineral composition, pore structure characteristics of shale samples in northern Guizhou were analyzed using X-ray diffraction (XRD), optical microscopic composition analysis, focused ion beam-scanning electron microscopy (FIB-SEM), vitrinite reflectivity and nitrogen adsorption experiments. Results indicate that the pore structures can be categorized into conical, ink bottle, spherical, elliptical, beaded, irregular, and plate-like intersecting microfractures. Shale samples are organic-rich with an average total organic carbon content of 4.39%. Organic matter is consumed within the shale matrix during the hydrocarbon generation and evolution, which increases the organic pore size and the proportion of organic pores. The high TOC content is conducive to developing organic pores. In addition, the average content of brittle minerals is greater than 70%. High content of brittle minerals during diagenesis is conducive to developing the residual pores at the edges of mineral particles and dissolved pores within mineral particles. Thus, the high content of brittle minerals and TOC content is favorable for the development of meso-macropores. The content of clay minerals within the shale samples ranges from 6.3% to 42.2%, with an average of 20.02%. Micropores and mesopores mainly occur in the clay minerals. Pores in clay minerals are easily compacted under tectonic stress. Meanwhile, high thermal evolution degree and the vitrinite reflectance R o greater than 3.5 is not conducive to developing pores. Hence, high TOC content, high brittle minerals content, and thermal evolution degree ranging from 0.6% to 3% make the Lower Cambrian Niutitang Formation shale reservoirs favorable for shale gas exploration. • The pore structures in the complex tectonic area were studied. • The pore formation process and its evolution were discussed. • The reservoir physical properties of favorable shale reservoirs were summarized. [ABSTRACT FROM AUTHOR]

• Anthracite primarily experiences thermal breakdown and electrical breakdown stages. • Porosity growth rate of seepage pores is higher than that of adsorbed pores. • The larger the breakdown voltage, the more the tensile microscopic cracks. Enhanced coalbed methane recovery using high-voltage electrical pulses (HVEP) has been a popular research topic in recent years. However, the breakdown process and fragmentation characteristics of anthracite subjected to HVEP treatment remain unclear. This limits the popularization and application of this technology. In this work, Guizhou anthracite samples were subjected to electrical pulse tests with different breakdown voltages. This was performed using a high-frequency oscilloscope to obtain the voltage and current waveforms during coal breakdown. Furthermore, the pore structure and evolution of the microscopic cracks in the coal were analyzed via field emission-scanning electron microscopy, nuclear magnetic resonance, and X-ray computed tomography. Our results reveal that the breakdown of anthracite by the electrical pulse occurs mainly in two stages: thermal breakdown and electrical breakdown. Most of the energy stored in the capacitor is injected into the plasma channel of the coal in the electrical breakdown stage, during which the coal body displays apparent damage. Additional mesopores and macropores are produced as the breakdown voltage increases. The growth rate of seepage pores is significantly higher than that of adsorbed pores under a fixed breakdown voltage. In addition, the seepage pores of coal samples after HVEP treatment exhibit significant fractal characteristics. Meanwhile, several radial tensile microscopic cracks are formed inside the coal body. In general, the larger is the breakdown voltage, the more abundant are the tensile microscopic cracks. The mineral impurities in a coal body affect the expansion of the discharge channel. This, in turn, affects the direction of microscopic crack expansion. [ABSTRACT FROM AUTHOR]

The Cambrian Niutitang Formation shale reservoirs are widely distributed in the complex tectonic area in northern Guizhou. Fifteen organic-rich Niutitang Formation cores were selected from the tectonic deformation zones and tectonic stability zone in northern Guizhou, including the FC1 well related to fold, TM1 well related to faults, and TX1 well in the tectonic stability zone. Pore structures and reservoir physical properties of shale were tested via microphysical experiments and low-temperature nitrogen adsorption (LTNA) test. Results indicate that the thermal evolution maturity of shale is in the over mature stage, with R O distributed between 2.30 and 3.74% and the total organic carbon content (TOC) between 3.8 and 7.5%. Shale cores in the tectonic stability zone have higher TOC content (6.25%) than that of shale (5.16%) in the tectonic deformation zones. Shale cores in the tectonic deformation zones have higher thermal evolution maturity R o (2.98%) than that of shale (2.76%) in the tectonic stability zone. The pore size of shale cores ranges from 4.15 to 15.62 nm. The total pore volume of shale cores ranges from 9.71 to 33.20 cm3/kg, and the meso-macropore volume ranges from 7.4 to 28.21 cm3/kg. Shale cores in the tectonic deformation zones have higher average pore size, total pore volume, and meso-macropore volume percentage than that of shale cores in the tectonic stability zone. Meanwhile, the specific surface area of shale cores (S BET) ranges from 7.34 to 30.37 m2/g, and the micropore volume of shale cores ranges from 2.29 to 5.82 m3/kg. Shale cores in the tectonic stability zone have higher micropore volume, specific surface area, and percentage of micropore volume than that of shale cores in the tectonic deformation zones. Shale cores in the tectonic stability zone mainly develop micropores and mesopores. Mesopores and macropores are more susceptible to geological tectonism than micropores. The pore structures of shale in the tectonic stability zone have been effectively preserved during tectonic movements. The research results have certain guiding significance for the exploration of shale gas in the complex tectonic regions. • Comparison of pores structures in different tectonic locations. • Analysis the effect of reservoir physical properties on pore structures. • Summary of main controlling factors of shale gas-bearing properties. [ABSTRACT FROM AUTHOR]