Influence of Petrographic, Geochemical, and Pore-Associated Matrix Characteristics on CH₄ and CO₂ Sorption of Coal and Shale from Early Permian-Gondwana Deposits, India

Abstract

CO₂ storage in various geological formations presents a feasible option for reducing greenhouse gas emissions (GHG) in the atmosphere. The most viable and technoeconomic method involves injecting CO₂ into deep, unmineable coal seams and shale beds to enhance CH₄ recovery. CO₂ exhibits a greater affinity with coal, shale, and associated siliciclastic-organic rich rock compared to CH₄. However, detailed information about the coal and shale reservoirs is crucial prior to the CO₂ injection and enhanced CH₄ recovery. This study aims to evaluate the petrographic, geochemical (proximate, ultimate), and pore-matrix characteristics of coal and shale samples to assess the enhanced CH₄ recovery through CO₂ injection. Pore distribution studies, conducted through micropetrography, Field Emission Scanning Electron Microscopy photographs, and low-pressure BET sorption isotherms, categorized the pore structures of coal and shale into three types: cylindrical, slit, and wedge-shaped. These pore structures, particularly the end-opening of the pores, were found to be suitable for gas storage and release. Clays intermixed with organic matter formed pores, which created suitable adsorption sites for CH₄ and CO₂. The studied coal exhibited higher CH₄ diffusivity and gas saturation compared to shale, favoring CH₄ recovery with CO₂ injection. The dominating collotelinite maceral has a positive relation with the Langmuir volume (V _L) of CH₄ and CO₂ favoring greater sorption in coal/shale. Conversely, the semifusinite and sporinite macerals influence gas accumulation and diffusivity. The CH₄ diffusivity of coal seam ranges from 2.355 × 10^–3 to 4.019 × 10^–3 min^–1 (avg. 3.197 × 10^–3 min^–1), while shale diffusivity ranges from 1.185 × 10^–3 to 2.371 × 10^–3 min^–1 (avg. 1.531 × 10^–3 min^–1). The higher diffusivity in coal is supported by the pore distribution and cleat intensity. The sorption ratio of CH₄ and CO₂, which is directly proportional to in situ gas, indicates an increase in CH₄ diffusion and CO₂ adsorption. Increasing vitrinite reflectance (VR_o) values indicate improved maturity of coal and shale, associated with changes in macromolecular structures and pore-matrix systems suitable for CO₂ storage.

1. Introduction

The global energy landscape is undergoing a major transition toward cleaner energy sources to mitigate the environmental impacts of fossil fuel consumption. − Methane (CH₄), a potent greenhouse gas, remains a key energy source, primarily extracted from coal seams and shale gas reservoirs. However, low permeability in these formations limits the efficiency of traditional extraction methods, necessitating enhanced recovery techniques. − CO₂-enhanced coalbed methane and shale gas recovery (ECBM/ESGR) is an emerging technology that addresses these challenges by injecting CO₂ into nonminable coal seams and shale reservoirs. ,, The coal matrix adsorbs CO₂, displacing CH₄ for recovery, providing a dual advantage: enhanced CH₄ production and long-term CO₂ sequestration. − , This method is particularly effective in low-permeability formations, where conventional CH₄ extraction is less viable. ,

Various laboratory studies have investigated supercritical CO₂ and mixed-gas injection into coal and shale samples to address the partial adsorption, shrinkage, and swelling of the coal matrix. − Global research on CO₂ sorption and coal properties has been crucial for ECBM recovery. In the United States, extensive research in San Juan and Powder River basins highlighted coal permeability, maceral composition, and thermal maturity as key factors in CO₂ injection efficiency and CH₄ recovery. , Bustin and Bustin found that moderate thermal maturity and higher permeability improved methane recovery when CO₂ was injected, while Kasala et al. highlighted that CO₂ sorption increased coal matrix pore volume, improving gas flow. Similarly, research in Australia’s, Bowen, Sydney, and Queensland basins revealed that low-rank coals, despite lower permeability, showed ECBM potential when coupled with staged CO₂ injection to mitigate permeability loss due to swelling. , Shale gas reservoirs have also been explored for CO₂-enhanced recovery. ,, Xu et al. observed that CO₂ injection significantly enhanced gas production in organic-rich shales due to its high sorption affinity, suggesting a dual benefit of increased recovery and CO₂ sequestration.

India’s extensive coal reserves, particularly in the Gondwana basins, present significant ECBM potential. These thermally matured, gas-rich coalfields are suitable for CO₂-ECBM techniques. ,− However, their low permeability poses challenges for CH₄ recovery. Studies on CO₂ and CH₄ sorption in Indian coalfields indicate that low-rank coals like those in Sohagpur and Singrauli exhibit high volatile matter yields but low permeability, requiring tailored ECBM approaches. , Research in the Raniganj Coalfield identified vitrinite-rich coals as having the highest CO₂ sorption capacity, an essential factor for both CO₂ sequestration and CH₄ recovery. However, CO₂-induced swelling in vitrinite-rich coals, as observed in the Jharia Basin, can reduce permeability, complicating recovery operations. Mukherjee and Misra highlight that inertinite-rich coals favoring CH₄ sorption over CO₂ underscore the role of coal rank and maceral composition in ECBM and CO₂ sequestration.

ECBM effectiveness is heavily influenced by the petrographic and geochemical properties of coal and shale. ,, Coal lithotypes (vitrain, clarain, durain, and fusain) exhibit distinct sorption properties due to variations in organic content, pore structure, and maceral composition. ,− Vitrain-rich coals, with their high microporosity and large surface area, are optimal for CO₂ sorption. − In contrast, fusain, composed of thermally altered organic matter, shows the least CO₂ affinity. ,, Additionally, volatile matter yield influences gas sorption, with higher-rank coals exhibiting greater CO₂ and CH₄ adsorption capacities. ,− Geochemical factors, including carbon, hydrogen, oxygen, and sulfur content, further shape coal pore structure and gas sorption behavior, with higher carbon content enhancing gas adsorption. ,,−

Despite significant advancements, comprehensive studies on the CO₂ sorption and permeability in Indian coalfields remain limited. This study aims to bridge this gap by analyzing the petrographic, geochemical, and pore-associated matrix characteristics of coal and shale samples of the Indian Gondwana basins. By evaluating CO₂ sorption changes induced by injection, this research aims to provide insights into optimizing CO₂-ECBM for enhanced CH₄ recovery and CO₂ sequestration. The findings will inform large-scale carbon capture and storage initiatives in India, supporting global CO₂ mitigation efforts and CH₄ recovery from the Gondwana basins.

2. Coal and Shale Occurrence in Studied Gondwana Basin

In India, the Gondwana basins comprise mainly 99% of the bituminous coal reserve and have laterally varying thick shale horizons in Barakar, Barren Measures, and Raniganj Formations. ,, The Gondwana basins of India are distributed along four main linear belts, each with distinct geological features and orientations, e.g., (1) Trans-Indian Basin Belt: Satpura and Son Valley Basins trending toward Damodar-Koel Valley Basins; (2) The Wardha, Pranhita, and Godavari Valley Basins Belt, (3) Mahanadi Valley Basin Belt: Ib and Talcher Basins; and (4) Purnea-Rajmahal-Galsi Basin Belt: The Purnea, Rajmahal, and Galsi Basins. The Gondwana basins in India are located along lineaments, e.g., Damodar, Mahanadi, and Godavari Rivers, and exhibit a graben or half-graben geometry. Initially, the basins evolved as a sag during later Carboniferous on Precambrian basement during events of multiple deglaciations and later developed into rift or pull-apart basin, which is mainly controlled and witnessed by fault and large-scale tectonic activities (faulting, sea level changes, and climate) many of which are pan-Gondwanaland events representing a 200 million years long geological evolution of the Gondwana basins. , The geological and genetic aspects of the Gondwana basins, such as stratigraphy, lithofacies, depositional environments, and tectonic evolution, were studied by many geologists. ,− The Indian map shows the studied Gondwana coal basins and the borehole locations of the collected coal and shale core samples (Figure ). Chronostratigraphic successions of the sedimentary sequences in several Gondwana basins and the coal bearing strata are exhibited in Table . The Gondwana basins predominantly consist of a laterally varying thick (>3 m) succession of coal-bearing siliciclastic Barakar and Raniganj sediments. The Karharbari Formation contains thin (<3 m) coal seam deposits in some coalfields, such as North and South Karanpura, indicating a less supply or lower organic matter preservation and its accumulation in the basin. The coal seams of the Barakar Formation are widely distributed and formed from favorable peat-accumulating conditions to sheltered lakes of meandering drainage patterns. The Gondwana formations and associated coal seams were deposited in diversified depositional environments that favored the accumulation of large organic matter. The early approach to anaerobic conditions led to the excellent preservation of organic matter, resulting in the widespread occurrence of coal deposits within the Barakar Formation. − The noncoal-bearing formations, such as the Barren Measures, occur between the Raniganj and Barakar Formations. This is a result of shallow flood plains, where the valley was filled with Barakar sediments. The shallow flood plains and slow subsidence of basins after the deposition of the Barakar Formation did not allow the accumulation of organic matter and the formation of coal seams in Barren Measures sediments. Hence, the carbonaceous shale of laterally varying thickness occurs in Barren Measures having low to moderate gas content and is a good candidate for geologic storage for CO₂. The Gondwana coals are characterized by diverse maceral composition, with relative abundance of vitrain, clarain, durain, and fusian lithotypes showing notable variability across and within basins. As a result, each coal seam and basin has its unique composition, with specific patterns of maceral and microlithotype distribution. ,

1.

Map of India showing the studied Gondwana coal basins and sampling borehole locations.

1. Chronostratigraphic Succession of the Sedimentary Sequences in Several Gondwana Basins; Shaded Regions Mark the Non-deposition and Erosion ,− (Modified after Fox, 1931; Gee, 1932; Das, 1958; Pascoe, 1973; Ahmed and Ahmed, 1977; Raja Rao, 1982; Veevers and Tiwari, 1995; Mukhopadhyay et al., 2010).

3. Materials and Experimental Procedures

3.1. Sampling and Preparation of Coal and Shale Cores

In total, 20 (10 coal and 10 shale) core samples were obtained from exploratory boreholes drilled at different Gondwana basins in India (Figure ). The core samples were sealed in airtight canisters after cleaning the drilling mud using water to measure desorption volume with time. After desorption and residual gas (RG) measurements, the samples were air-dried, following the guidelines outlined by the Bureau of Indian Standards for further analysis. To obtain representative samples, the coning and quartering method was employed, ensuring that the samples accurately represented the original cores. The representative core samples were manually ground and sieved to different sizes. The −212 μm size was prepared for proximate and ultimate analyses. For Field Emission Scanning Electron Microscopy (FE-SEM) and Brunauer–Emmett–Teller (BET) sorption analyses, the fraction between 0.8 and 1.0 mm was used.

3.2. Physical and Lithotype Characteristics

Physical properties of coal and shale core samples were recorded, e.g., color, luster, fracture, sedimentary structures, specific gravity, and mineral constituents (Table ). The lithotypes and their percentage in coal were visually identified and examined (e.g., vitrain, clarain, durain, clairo-vitrain, etc.). , The banded nature of shale, e.g., carbonaceous, silty, sandy, intercalations, etc., was documented.

2. Details of the Coal and Shale Core Sample Type, Location/Basins, Borehole Coordinates, Formations, and Macroscopic Properties.

sample no.	sample type	depth of the sample (m)	location/Basin and borehole coordinates	Gondwana formation	macroscopic description
CNK-1	dull banded coal	330	North Karanpura BH-1 N = 23°48.68 E = 85°12.22′	barakar	black, dull, banded, partially weathered coal mainly of durain, with vitrain bands, and pyrite flecks in fractures. It has a subconchoidal fracture, deformed face, and butt cleats in vitrain bands. Durain: 50–60%, clarain: 20–30%, and vitrain: 10–20%. Banded durain and vitrain show geochemical alteration from late diagenesis and thermal transformation
CNK-2	dull banded coal	417			black, dull, banded coal, mainly durain with pyrite crystals. It has subconchoidal to uneven fractures, minimal face, and butt cleats from thin vitrain bands. Geochemical alterations indicate pre- and postdepositional changes. Lithotypes are mainly durain, claro-durain, and vitrain. The vitrain content is very low (5–10%)
CNK-3	bright banded coal	504			black, bright, banded coal, mainly composed of clarain (40–60%), vitrain (10–20%), claro-durain (10–15%), and durain (5–10%). Vitrain is bright, brittle, with thin bands, well-developed face, and butt cleats and a subconchoidal fracture. Features are due to heterogeneity in organo–inorganic matter mixing. Alternating lithotype bands and geochemical alterations indicate postdepositional changes in a fluvio-terrestrial, oxygen-rich environment
CNK-4	dull banded coal	812			dull black gelified coal with irregular vertical master cleats perpendicular to bedding planes. Mainly consists of clarain (40–60%) and claro-durain (20–40%), with negligible face and butt cleats due to low vitrain content. Homogeneously mixed with organo–inorganic material, influenced by partial decomposition during sediment accumulation under fluvio-terrestrial conditions. Durain content is 10–20%
CRK-5	dull banded coal	507	Kalidaspur-Raniganj BH-2 N = 23°33.75′ E = 87°02.07′	Raniganj	Dull black banded coal with thick vitrain bands and master cleats filled with calcite. Vertical sections, face, and butt cleats absent due to partial homogenization from compaction. Horizontal sections of vitrain show well-developed face and butt cleats. Lithotype composition: clarain (40–50%), vitrain (20–40%), claro-vitrain (10–20%), and durain (5–10%)
CRK-6	dull banded coal	546			Dull black banded coal with distinct spaced bedding planes and thin vitrain bands with bitumen. No master cleats, strongly gelified from thermal compaction. Altered clarain and durain suggest oxic freshwater conditions. Lithotype: clarain (40–60%), claro-vitrain (10–30%), and claro-durain (5–15%)
CRK-7	dull banded coal	797			dull black banded coal with alternating thin bands of vitrain, clarain, and durain due to insufficient and delayed organic matter supply. Bright bitumen laths in vitrain bands. Horizontal sections show face and butt cleats, with irregular cracks partially filled with mud and clays. Lithotype: clarain (40–60%), vitrain (10–20%), claro-durain (10–15%), and durain (5–10%)
CRK-8	bright banded coal	885			black, bright, banded coal with substantial vitrain content, showing well-developed face and butt cleats in both vertical and horizontal sections of vitrain bands. Strong gelification indicates favorable conditions for organic matter preservation during early diagenesis and thermal compaction. Lithotype: vitrain (30–40%), clarain (20–30%), claro-vitrain (10–20%), and durain (5–10%)
CSM-9	dull banded coal	335	Marawa block-Singrauli BH-3 N = 23°16.82′ E = 81°17.16′	Barakar	dull black banded coal, partially decomposed with thick clarain and claro-durain lithotypes, minimal cleats and fractures. Fairly homogenized due to strong postdepositional geochemical alteration. Banded clarain and durain suggest supply of partially decomposed organic material to the basin. Lithotype: claro-durain (40–60%), durain (20–40%), and claro-vitrain (10–20%)
CSM-10	dull banded coal	418			dull black homogenized coal with visible lithotype bands, mainly durain, claro-durain, and clarain. Organic matter decomposed geochemically and thermally in an oxic terrestrial environment, resulting in minimal cleats and fractures. Poor gelification due to decomposed organic matter. Lithotype: durain (40–60%), claro-durain (20–30%), and clarain (10–20%)
SJT-11	carbonaceous shale	225	Telmachu-Jharia BH-4 N = 23°43.74′ E = 86°12.47′	Barren Measures	dark gray banded shale with alternating bands of carbonaceous and silty material. Irregular cracks and fractures from heterogeneous density of organic and inorganic content. Contains rounded to subrounded grains like quartz, K-feldspar, and mica, contributing to compact, massive characteristics. heterogeneous mixing due to varied river currents before basin deposition. Slow sediment accumulation and thermal transformation under fluvio-terrestrial conditions from basin subsidence
SJT-12	coaly shale	450			dark black banded shale, primarily carbonaceous organic matter, with gelified, homogeneous structure from intense mixing under strong river currents in a deep floodplain. Compact, massive appearance reflects thermal transformation. Few subconchoidal to conchoidal fractures indicate low pore network and permeability
SJT-13	coaly shale	582			dark gray banded shale with carbonaceous, silty, clay, and muddy material, along with tiny quartz grains and mica flecks. Absence of fractures suggests compaction effects. Alternating visible bands indicate intermixing of organic and inorganic materials settled in deep valleys under oxic terrestrial conditions with fresh water
SJT-14	silty carbonaceous shale	405	Jamuniatad-Jharia BH-5 N = 23°44.25′ E = 86° 11.49′	Barakar	dull gray silty carbonaceous shale with intercalated bands of silt, fine sand, and carbonaceous matter. Contains fine to medium sand and silt, quartz grains, and mica flecks with weathered edges. Medium to high specific gravity due to high inorganic content ratio. Irregular fractures and plant leaf imprints visible in horizontal sections
SJT-15	carbonaceous shale	656			dark gray carbonaceous shale with slicken fractures in horizontal sections. Alternating bands of very fine silt, clay, mud, and carbonaceous material. Strong mixing of organo-inorganic content during transportation and basin accumulation. Compact, massive, thermally mature shale with uneven cracks and fractures in both horizontal and vertical sections. Contains predominantly altered flecks of mica and subrounded tiny grains of quartz
SJT-16	carbonaceous shale	708			dark black banded carbonaceous shale with heterogeneous mixing of vegetal matter, clay, and mud during transportation and accumulation. Contains large patches of vegetal organic matter in the shale core. Fractures mainly confined to organic bands, contributing to low specific gravity. Irregular fractures visible in horizontal sections, along with fossil leaf imprints on bedding planes
SJT-17	Silty carbonaceous shale	872			light gray banded silty carbonaceous shale with heterogeneous mixing of silt, clay, and carbonaceous material. Moderate to high specific gravity from silt content. Subconchoidal to conchoidal fractures visible on horizontal sections. Massive due to high thermal compaction. Contains visible grains of quartz, K-feldspar, and altered muscovite. Interbedded nature suggests fluvio-terrestrial deposition facies
SJT-18	silty carbonaceous shale	114	Jhagrahibad, Jharia BH-6 N = 23°44.40′ E = 86°10.96′	Barren Measures	dull gray silty carbonaceous shale with interbeds of carbonaceous matter, clay, mud, and silt. Displays cross-bedding ripples from stagnant water plains affected by seasonal winds. Organic bands have cracks due to low density, forming a moderately massive structure from thermal compaction. Contains vegetal matter, altered K-feldspar grains, mica flecks, and uneven to subconchoidal fractures on horizontal sections
SJT-19	silty carbonaceous shale	402			dull gray silty shale composed of carbonaceous matter, silts, and fine-grained sand. Heterogeneous mixing of silt and carbonaceous materials results in an uneven surface with fractures mainly from silts. Moderate to high specific gravity due to silt and clay content. Contains altered and decomposed K-feldspar, mica flecks, and subrounded quartz grains. negligible cracks suggest a poor pore network and low permeability
SJT-20	carbonaceous silty shale	542			dull black gray banded shale with interbands of carbonaceous material, silt, and mud. Features fossil leaf imprints in horizontal sections, along with mica flecks and subrounded quartz grains. Irregular fractures in vertical and horizontal sections contribute to moderate to high specific gravity due to inorganic content dominance. Alternating bands suggest periodic supply and mixing of organic and inorganic materials deposited in a fluvio-terrestrial basin

3.3. Geochemical Properties

Proximate and ultimate analyses were conducted at the laboratory of CSIR-CIMFR, Dhanbad, India. Proximate analysis includes the determination of moisture (M), ash yield, volatile matter yield (VM), and calculation of fixed carbon (FC) by the difference of 100 in coal and shale samples using the standard methods recommended by the Bureau of Indian Standards. Ultimate analyses involved the determination of the C, H, N, and S contents and calculation of the O contents by the difference of 100 in the coal and shale samples. This analysis was carried out by using the “Elementar–vario MACRO Analyser” following the procedure assigned by American Society for Testing and Materials. −

3.4. Petrographic and Mineral Composition

Petrographic pellets were prepared using coal and shale samples of size <1.0 mm after International Organization for Standardization. The different macerals were identified as per the ISO 7404-3, using the Leica DM4P microscope under white-incident light and blue light excitation using an oil immersion objective of 50× magnification at BSIP, Lucknow. The maceral nomenclature provided by the International Committee for Coal and Organic Petrology system 1994 has been adopted. − A total of 1000 counts/sample were taken, covering the entire pellet with the assistance of the Petroglite 2.35 software adopting a single-scan method. The mean random vitrinite reflectance (VR_o) was measured on collotelinite grains (50 measurements per sample) following the procedure given by ISO 7404-5, using the CoalExpert software.

3.5. FE-SEM Analysis

The FE-SEM with EDX (energy-dispersive X-ray spectroscopy) analysis was conducted using the Carl Zeiss FE-SEM system at CSIR-CIMFR, Dhanbad. The spot elemental composition at the selected points was carried out by using EDX for the identification of minerals.

3.6. BET Analysis

Low-pressure N₂ sorption analyses were carried out at CSIR-CIMFR, Dhanbad, using the Quantachrome AutosorbiQ 2MP-XR system. The prepared samples, around 30–40 g, are dried in an oven at 105 °C ± 5 °C for 2–4 h. The dried samples were weighed and employed in the sample tube of the apparatus. To remove the moisture and other free gases, the samples were degassed for 3 to 4 h at 300 °C. The adsorption and desorption isotherms were determined at a relative pressure range (P/P ₀) from 0 to 0.99, and N₂ was utilized as an adsorbent under a liquid nitrogen temperature, i.e., −195.79 °C or 77.35 °K. Brunauer–Emmett–Teller (BET), Langmuir, Density functional theory (DFT), and Barret–Joyner–Halenda (BJH) were used to evaluate the surface area, pore size distribution, pore volume, and pore structures. ,−

3.7. Determination of Gas Content

The gas content is the primary parameter used to assess the resource potential of CBM and shale gas. The Direct method, which was originally recommended by Bertard et al. and afterward improved by numerous researchers like Kissel et al., McCulloch et al., Diamond and Levine, Feng et al., Diamond and Schatzel, and Mendhe et al., ,− for determining the gas content of coal beds has been followed in this study. The coal and shale core samples were retrieved from boreholes, cleaned, and sealed in desorption canisters. The desorbed gas (DG) volume was then measured at different time intervals along with recording the atmospheric temperature and pressure. There are three different stages for the measurement of the gas content, e.g., lost gas (LG) (Q ₁), DG (Q ₂), and RG (Q ₃). The gas content (Q) is determined by the sum of Q ₁, Q ₂, and Q ₃ divided by the weight of the sample (eq ):

$$\mathrm{G}\mathrm{a}\mathrm{s}\mathrm{c}\mathrm{o}\mathrm{n}\mathrm{t}\mathrm{e}\mathrm{n}\mathrm{t}(Q)=\frac{Q_1+Q_2+Q_3}{\mathrm{weight}\mathrm{o}\mathrm{f}\mathrm{s}\mathrm{a}\mathrm{m}\mathrm{p}\mathrm{l}\mathrm{e}}$$ 1

3.8. Gas Composition

DG samples were collected in glass gas sampling tubes during the desorption measurements of coal and shale core samples under saline water. These gas samples were analyzed using a Gas Chromatograph (GC) from Thermo Fisher Scientific (Model: Trace 1110) at CSIR-CIMFR, Dhanbad. The GC has two separate detectors for analyzing hydrocarbons and nonhydrocarbons. Hydrocarbons such as CH₄, C₂H₆, C₃H₆, C₃H₈, i-C₄H₁₀, and n-C₄H₁₀ were measured with a Flame Ionization Detector, while nonhydrocarbons like CO₂, N₂, and O₂ were assessed using a Thermal Conductivity Detector.

3.9. High-Pressure Sorption Isotherms of CH₄ and CO₂

The coal and shale core samples, ranging in size from 0.8 to 1 mm, were used to determine the sorption capacity of CH₄ and CO₂. Equilibrated moisture samples were prepared following the procedure outlined in the Bureau of Indian Standards. , The coal and shale samples were weighed, dried at 50 °C in the oven, then prewetted using deionized water, and kept in a vacuum desiccator with between ∼95 and 97% humidity using a saturated solution of K₂SO₄ at 30 °C. Periodic reweighing and placement in the vacuum desiccator continued until the weight change did not surpass 0.001 g.

The adsorption and desorption measurements of CH₄ and CO₂ were conducted in the laboratory of CSIR-CIMFR Dhanbad, India. The void volume in the sample cells and the connected high-pressure pipes of the system was assessed using nonadsorbing inert helium gas. To calculate the void volume, ∼100 g of the equilibrated moisture sample was placed into the sample cell. The reference cell was loaded with helium gas and linked to the sample cell; the resulting drop in equilibrium pressure was recorded. The void volume was assessed using Boyle’s law after equilibrating the sample with helium under isothermal conditions in a water bath for about 1 h.

Once the dead volume was determined, the apparatus was evacuated again to prepare for the CH₄ and CO₂ sorption isotherms. CH₄ and CO₂ (purity ∼ 99.94%) were loaded to the reference cell from the lowest pressure of about 500–700 kPa and equilibrated under water bath isothermal conditions for 1 h. After settling the pressure conditions, the valve of the reference cell was opened, allowed the adsorbent to enter the sample cell, and recorded the continuous pressure readings for about 10–12 h until equilibrium was reached. The system was monitored until there were no fluctuations in pressure. This process was repetitive for numerous increasing pressure stages (typically 8–9, with an interlude of ∼1000 kPa), filling CH₄ and CO₂ separately into the reference cell and successively allowing it to the sample cell until attaining the pressure of ∼8000 to 9000 kPa. The adsorbed gas volume was calculated from the equilibrated pressure drop (sample cell + reference cell) using the universal gas law and the monolayer Langmuir adsorption model fit. − The reservoir temperatures were kept isothermal; hence, Boyle’s law, which indicates the pressure of a given amount of gas, is inversely proportional to its volume; this can be expressed by eq :

$$P_1{V}_1=P_2{V}_2$$ 2

where T ₁ = T ₂Isothermal conditions; P ₁ is the pressure of the reference cell; P ₂ is the sample cell + reference cell combined equilibrium pressure; V ₁ is the volume of the reference cell; and V ₂ is the adsorbed gas volume. The Langmuir monolayer model is considered to plot and determination of Langmuir coefficients, e.g., V _L and P _L as shown in eq :

$$V_{\mathrm{a}}=V_{\mathrm{L}}\frac{P}{P_{\mathrm{L}}+P}$$ 3

where V _a is the adsorbed volume, P _L is the Langmuir pressure, V _L is the Langmuir volume, and P is the equilibrium pressure. Likewise, the reverse process of desorption was carried out through successive pressure reduction steps until the lowest pressure between 500 and 700 kPa is reached.

4. Results

4.1. Macroscopic Characteristics of the Samples

Altogether, 20 core samples (10 coal and 10 shale) were investigated in this study. The studied coal samples belong to the Barakar and Raniganj Formations, while the shales are from the Barren Measures and Barakar Formations. The particulars of the samples, their borehole location, bearing formation, depth of occurrence, and macroscopic descriptions, e.g., physical properties, lithotype, and depositional facies are outlined in Table . The coal samples are black, subvitreous to vitreous luster, dull to bright banded, depending on the content of vitrain and clarain. In contrast, the shale samples are dull to dark gray and black, delimited by the content of carbonaceous material, clay and silty matter (Figure ).

2.

Lithotype and lithological units in coal and shale showing variation in the supply of the organic–inorganic material and accumulation, (a) Raniganj Formation coal collected from the Kalidaspur–Raniganj location depth of sample 546 m, (b) Barakar Formation coal collected from the North Karanpura location at the depth of 330 m, (c) Barakar Formation shale collected from the Jamuniatad–Jharia location at the depth of 656 m, and (d) Barren Measures shale collected from Telmachu-Jharia at the depth of 402 m.

4.2. Proximate and Ultimate Analyses

The VM yield and FC are the principal gauges of thermal maturity and organic matter transformation process. ,− The moisture, ash yield, VM yield, and FC of coal samples as received basis vary from 2.6–5.7 wt %, 10.3–40.5 wt %, 19.9–31.1 wt %, and 35.1–56.0 wt %, respectively. For shale samples, the values vary from 0.9 to 2.2 wt % for moisture, 74.6–90.9 wt % for ash yield, 6.9–15.2 wt % for VM, and 0.9–10.7 wt % for FC as received basis (Table ). The values of C, H, N, S, and O in coal vary from 40.3 to 67.8 wt %, 2.1–4.0 wt %, 0.7–1.4 wt %, 0.1–4.5 wt %, and 9.6–19.3 wt %, respectively. For shale samples, the values range from 4.2 to 16.7 wt % for C, 0.8–1.6 wt % for H, 0.2–1.4 wt % for N, 0.1–0.2 wt % for S, and 1.0–9.0 wt % for O. The atomic ratios of H/C and O/C for coal vary from 0.62 to 0.90 and 0.12 to 0.36, respectively. For shale, the atomic ratios vary from 0.93 to 2.84 for H/C and 0.08 to 1.23 for O/C (Table ).

3. Geochemical Composition of Studied Coal and Shale Core Samples .

	proximate analysis
	(as-received basis wt %)				(as dry-ash free basis wt %)		ultimate analysis (wt %)						atomic ratios
sample no.	ash	M	VM	FC	VMdaf	FCdaf	C	N	H	S	O	fuel ratio	H/C	O/C
CNK-1	25.7	2.8	25.9	45.6	36.2	63.8	59.4	1.1	3.9	0.3	9.6	1.8	0.78	0.12
CNK-2	16.6	4.3	31.1	48.1	39.3	60.7	55.8	1.0	4.0	4.5	18.1	1.5	0.85	0.24
CNK-3	29.6	2.6	23.5	44.3	34.7	65.3	52.9	0.9	3.3	0.5	12.8	1.9	0.74	0.18
CNK-4	33.0	3.8	19.9	43.3	31.5	68.5	51.9	1.0	3.2	0.3	10.6	2.2	0.73	0.15
CRK-5	36.0	3.9	23.1	37.0	38.4	61.6	43.9	1.3	3.3	0.2	15.3	1.6	0.90	0.26
CRK-6	37.5	2.6	24.7	35.2	41.3	58.7	40.3	0.7	2.1	0.1	19.3	1.8	0.62	0.36
CRK-7	40.5	3.1	21.0	35.4	37.2	62.8	41.6	1.3	3.0	0.7	12.9	1.7	0.86	0.23
CRK-8	26.6	4.3	29.6	39.5	42.9	57.1	49.0	1.4	3.6	0.2	19.2	1.3	0.88	0.29
CSM-9	10.3	5.7	28.0	56.0	33.4	66.6	67.8	1.0	4.0	0.2	16.7	2.0	0.70	0.19
CSM-10	36.5	4.8	23.6	35.1	40.2	59.8	44.8	0.9	3.2	0.1	14.5	1.5	0.85	0.24
SJT-11	86.0	1.3	9.9	2.8	78.1	21.9	5.1	0.2	1.1	0.1	7.5	0.3	2.57	1.10
SJT-12	74.6	1.3	13.4	10.7	55.8	44.2	16.7	0.5	1.6	0.2	6.4	0.8	1.14	0.29
SJT-13	78.0	1.6	15.2	5.2	74.5	25.5	11.2	0.3	1.3	0.2	9.0	0.3	1.38	0.61
SJT-14	79.9	2.2	11.1	6.9	61.7	38.3	11.0	0.4	1.4	0.1	7.2	0.6	1.52	0.49
SJT-15	87.6	1.3	9.4	1.7	84.8	15.2	4.2	0.2	1.0	0.1	6.9	0.2	2.84	1.23
SJT-16	86.5	1.3	9.4	2.9	76.4	23.6	10.2	1.4	0.8	0.1	1.0	0.3	0.93	0.08
SJT-17	78.0	0.9	13.4	7.7	63.6	36.4	12.8	0.4	1.6	0.2	7.0	0.6	1.49	0.41
SJT-18	84.3	1.4	10.8	3.5	75.3	24.7	11.6	0.5	1.4	0.2	2.0	0.3	1.44	0.13
SJT-19	90.9	1.4	6.9	0.9	88.4	11.6	4.2	0.8	1.0	0.1	3.0	0.1	2.84	0.54
SJT-20	85.2	1.7	10.1	3.1	76.2	23.8	8.6	1.2	1.2	0.2	3.6	0.3	1.66	0.32

^aAbbreviations: M, moisture; FC, fixed carbon; VM, volatile matter; daf, dry ash free basis; C, carbon; N, nitrogen; S, sulfur; H, hydrogen; O, oxygen; fuel ratio, FC/VM.

4.3. Organic Petrography

The values of the petrographic composition, vitrinite reflectance, and description of microscopic pores in coal/shale samples are presented in Table . The photomicrographs of the macerals and associated mineral matter of the studied samples are presented in Figure . The coal sample macerals of the vitrinite group including collotellinite, collodetrinite, vitrodetrinite, and corpogelinite vary from 16.3 to 62.1 vol %, 0.3–9.6 vol %, 0.6–4.0 vol %, and 0–3.2 vol %, respectively. Similarly, the inertinite group macerals including fusinite, semifusinite, and inertodetrinite range from 0.7 to 17.2 vol %, 3.8–36.3 vol %, and 2.4–18.2 vol %, respectively. The liptinite group like sporinite, cutinite, resinite, alginite, and liptodetrinite varying from 1.7 to 13.2 vol %, 0.6–2.3 vol %, 0–0.5 vol %, 0–0.7 vol %, and 0.7–3.6 vol %, respectively. The shale sample macerals of the vitrinite group (collotellinite, collodetrinite, vitrodetrinite, and corpogelinite) vary from 3.3–10.1 vol %, 0–3.9 vol %, 0.9–2.7 vol %, and 0–0.6 vol %, respectively. In the inertinite group, fusinite, semifusinite, and inertodetrinite range from 0 to 5.4 vol %, 2.4–10.5 vol %, and 6.9–15.7 vol %, respectively. The liptinite group macerals (sporinite, cutinite, resinite, alginate, and liptodetrinite) vary from 0.2 to 5.1 vol %, 0–1.3 vol %, 0–0.4 vol %, 0.3–2.9 vol %, and 1.3–4.6 vol %, respectively. Vitrinite reflectance for coal samples ranges from 0.57 to 0.89%, and for shale samples, from 0.89 to 0.98% (Table ).

4. Petrographic Composition, Vitrinite Reflectance, and Microscopic Pores Description of Coal and Shale Samples .

	vitrinite (vol %)					inertinite (vol %)						liptinite (vol %)						mineral matter (vol %)			microscopic pores and cleats/fractures (μm)		SEM-pores and cleat/fractures (μm)
sample no	CT	VD	CD	CG	TV	FU	SF	F	R	I	TI	Sp	Cu	Rs	Al	Lt	TL	Others	Py	VRo (%)	Pore size	cleat/fracture spacing	pore size	cleat/fracture spacing
CNK-1	23.5	1.5	2.8	0.0	27.8	3.7	34.6	0.0	0.0	9.2	47.5	6.9	2.0	0.5	0.0	2.3	11.7	13.1	0.0	0.79	5.0	1.0	3.0	2.0
CNK-2	30.6	3.4	5.7	0.4	40.1	5.5	22.3	0.4	0.0	8.3	36.5	13.2	1.9	0.4	0.0	1.9	17.4	5.8	0.4	0.75	4.0	0.8	1.0	4.0
CNK-3	16.3	3.3	3.3	0.5	23.4	17.2	36.3	0.0	0.0	4.2	57.7	10.7	0.9	0.0	0.0	1.4	13	5.1	0.9	0.62	4.0	2.0	4.0	2.0
CNK-4	26.3	3.0	2.1	0.0	31.4	4.2	31.9	0.0	1.2	15.8	53.1	4.5	0.9	0.0	0.0	3.6	9	6.0	0.3	0.74	3.5	4.0	1.0	0.5
CRK-5	62.1	1.3	1.9	0.6	65.9	3.2	6.0	0.0	0.0	2.5	11.7	5.7	1.9	0.0	0.0	1.3	8.9	12.0	0.0	0.66	2.0	6.0	4.0	0.2
CRK-6	37.5	4.0	2.0	0.7	44.2	3.3	10.0	0.0	0.3	4.3	17.9	7.3	2.3	0.0	0.7	1.7	12	25.9	0.0	0.68	3.0	2.5	1.0	1.0
CRK-7	62.1	1.4	2.1	0.0	65.6	0.7	3.8	0.0	0.7	2.4	7.6	1.7	1.4	0.0	0.0	0.7	3.8	23.1	0.0	0.66	5.0	3.0	3.0	0.2
CRK-8	56.5	1.5	2.2	3.1	63.3	2.5	7.4	0.0	0.0	5.6	15.5	3.7	0.6	0.0	0.0	3.1	7.4	13.3	0.0	0.57	2.0	1.0	5.0	1.0
CSM-9	34.0	0.6	0.3	1.5	36.4	13.7	16.7	0.0	0.9	18.2	49.5	8.8	1.5	0.0	0.0	0.9	11.2	2.7	0.0	0.65	6.0	2.5	3.0	1.0
CSM-10	26.3	3.6	9.6	3.2	42.7	1.4	28.8	0.0	0.0	8.5	38.7	6.4	1.1	0.4	0.0	3.2	11.1	7.5	0.0	0.89	2.0	4.0	4.0	2.0
SJT-11	4.1	1.8	0.4	0.0	6.3	5.4	6.1	0.0	0.0	9.7	21.2	2.5	0.9	0.2	1.4	2.5	7.5	63.6	1.4	0.97	2.0	0.5	1.0	0.1
SJT-12	9.1	1.6	3.9	0.0	14.6	2.4	10.5	0.0	0.0	9.3	22.2	5.1	0.2	0.2	1.4	2.6	9.5	52.6	1.2	0.95	1.0	2.0	0.6	3.0
SJT-13	9.1	2.5	2.8	0.0	14.4	2.1	3.7	0.0	0.0	11.9	17.7	0.2	0.5	0.2	0.9	2.1	3.9	61.1	3.2	0.90	2.0	3.0	0.5	1.0
SJT-14	8.6	2.7	0.6	0.4	12.3	0.9	6.6	0.0	0.0	9.7	17.2	1.6	0.9	0.0	1.6	2.0	6.1	62.5	1.8	0.94	1.0	2.0	0.8	0.5
SJT-15	5.9	1.6	0.4	0.0	7.9	1.6	3.0	0.0	0.0	11.7	16.3	1.4	0.8	0.0	2.8	4.2	9.2	65.5	1.0	0.89	5.0	0.2	0.4	0.2
SJT-16	10.1	0.9	0.4	0.0	11.4	3.3	2.4	0.0	0.0	7.5	13.2	0.4	1.3	0.4	2.9	1.3	6.3	66.2	2.9	0.93	0.5	2.0	0.8	2.0
SJT-17	5.5	2.7	1.4	0.0	9.6	3.0	5.2	0.0	0.0	15.7	23.9	0.9	0.3	0.3	2.7	4.6	8.8	55.5	2.2	0.98	3.0	1.0	1.0	1.0
SJT-18	9.2	2.7	0.0	0.6	12.5	2.1	8.4	0.0	0.0	6.9	17.4	2.1	0.0	0.0	1.4	1.9	5.4	63.2	1.7	0.95	4.0	0.5	0.4	2.0
SJT-19	3.3	2.7	1.6	0.0	7.6	0.0	4.4	0.0	0.0	7.9	12.3	0.5	1.1	0.0	0.3	1.6	3.5	76.0	0.5	0.95	2.0	3.0	1.0	2.0
SJT-20	4.9	2.2	0.0	0.0	7.1	0.3	10.5	0.0	0.0	13.3	24.1	0.3	0.3	0.0	1.5	3.1	5.2	63.2	0.3	0.95	6.0	4.0	1.0	0.5

^aAbbreviations: CT, collotelinite; VD, vitrodetrinite; CD, collodetrinite; CG, corpogelinite; T _V, total vitrinite; FU, fusinite; SF, semifusinite; F, funginite; R, macrinite; I, inertodetrinite; T _I, total inertinite; Sp, sporinite; Cu, cutinite; Rs, resinite; Al, alginite; Lt, liptodetrinite; T _L, total liptinite; Py, pyrite; and VR_o, vitrinite Reflectance.

3.

Representative photomicrographs of various macerals and associated Mineral matter (MM) in the studied coal and shale samples: (a) Collotelinite (CT), (b) Collotelinite (CT) with Corpogelinite (CG), (c) Collotelinite (CT) with Vitrodetrinite (VD), (d) Collotelinite (CT) with Collodetrinite (CD), (e,f) Cutinite (Cu), (g–j) Sporinite (Sp), (k,l) Fusinite (FU), (m,n) Semifusinite (SF), (o) Inertodetrinite (I) and Pyrite (Py), and (p) MM. Photomicrographs taken under white incident light (a–d and k–p) and blue light excitation (e–j), in oil immersion (refractive index 1.518) with total magnification 500×.

4.4. Surface Area Analysis

The surface area of coal samples determined through multipoint BET, BJH, Langmuir, and DFT are in the range of 4.88–42.84 m²/g, 2.89–34.32 m²/g, 9.56–81.27 m²/g, and 4.63–38.67 m²/g, whereas the shale samples have a surface area in the range of 0.84–9.66 m²/g, 0.62–4.43 m²/g, 1.81–17.62 m²/g, and 0.66–8.23 m²/g, respectively (Table ). The results of average pore size distribution in coal and shale samples vary in the range of 6.51–13.55 nm and 5.95–9.39 nm, respectively. Similarly, the BJH and DFT pore size distribution for coal and shale ranges from 2.98 to 5.82 nm (BJH), 2.33–4.67 nm (DFT) and 2.98–5.09 nm (BJH), 3.15–4.64 nm (DFT). The total pore volume for coal was 0.008–0.077 cc/g and for shale the value ranged from 0.002 to 0.015 cc/g.

5. Results of BET Analysis of Coal and Shale Samples .

	pore diameter (nm)			pore volume (cc/g)			surface area (m2/g)				pore characterization
sample no	BJH	DFT	average pore	BJH	DFT	total pore volume	multipoint BET	BJH	Langmuir	DFT	hysteresis pattern	adsorption isotherm type	pore structure	pore type
CNK-1	3.15	3.97	9.88	0.016	0.014	0.017	6.79	5.31	13.43	5.96	H3	Type -A	open-end cylinder	cylindrical
CNK-2	5.04	4.01	7.18	0.071	0.070	0.077	42.84	34.32	81.27	38.67	H3	Type-A	open-end cylinder	cylindrical
CNK-3	5.10	3.77	13.55	0.024	0.021	0.024	7.15	15.06	12.10	9.22	H1	Type -A	combined cylinder	cylindrical
CNK-4	4.75	3.64	11.09	0.034	0.023	0.026	9.39	18.20	15.60	13.41	H1	Type -A	combined cylinder	cylindrical
CRK-5	2.99	3.26	6.94	0.008	0.009	0.010	5.60	3.33	10.98	4.98	H3	Type -A	open-end cylinder	cylindrical
CRK-6	2.98	2.33	6.78	0.009	0.009	0.011	6.27	3.24	11.70	5.83	H3	Type-A	Open-end cylinder	cylindrical
CRK-7	3.15	4.10	7.00	0.010	0.010	0.012	6.69	3.99	13.00	5.89	H3	Type -A	open-end cylinder	cylindrical
CRK-8	3.33	3.52	6.51	0.007	0.007	0.008	4.88	2.89	9.56	4.63	H3	Type -A	open-end cylinder	cylindrical
CSM-9	4.20	4.02	9.33	0.024	0.022	0.025	10.59	8.80	21.58	8.93	H3	Type -A	open-end cylinder	cylindrical
CSM-10	5.82	4.67	12.06	0.027	0.023	0.028	9.29	7.17	18.21	8.24	H3	Type-A	open-end cylinder	cylindrical
SJT-11	2.98	3.15	5.95	0.011	0.012	0.014	9.25	4.43	17.25	8.20	H3	Type -A	open-end cylinder	cylindrical
SJT-12	5.09	4.64	9.39	0.002	0.002	0.002	0.84	0.62	1.81	0.79	H2	Type -B	slit	slit
SJT-13	4.30	4.05	9.10	0.002	0.002	0.002	0.93	0.88	2.72	0.69	H2	Type -B	slit	slit
SJT-14	4.05	3.92	7.25	0.004	0.004	0.004	2.22	1.73	5.49	2.19	H3	Type-A	open-end cylinder	cylindrical
SJT-15	3.72	3.46	6.53	0.006	0.007	0.008	4.67	2.62	9.26	4.10	H4	Type –C	wedge	wedge
SJT-16	3.52	3.82	6.83	0.008	0.008	0.009	5.38	3.23	11.42	5.65	H3	Type -A	open-end cylinder	cylindrical
SJT-17	3.53	3.23	7.36	0.002	0.002	0.002	1.19	0.85	6.27	0.66	H2	Type -B	slit	slit
SJT-18	3.94	3.46	6.29	0.011	0.011	0.013	8.02	4.30	15.76	6.48	H1	Type-A	open-end cylinder	cylindrical
SJT-19	2.98	3.85	6.00	0.011	0.012	0.015	9.66	4.12	17.62	8.23	H1	Type -A	open-end cylinder	cylindrical
SJT-20	2.98	3.62	6.85	0.008	0.008	0.009	5.51	3.09	10.64	5.00	H4	Type –C	wedge	wedge

^aAbbreviations: BJH, Barrett–Joyner–Halenda; DFT, density functional theory; BET, Brunauer–Emmett–Teller.

4.5. In Situ Gas Content and High-Pressure CH₄ and CO₂ Sorption Capacity of Coal and Shale

The in situ gas content for the coal samples ranged from 4.09 to 5.99 cc/g. DG ranges from 2.55 to 3.69 cc/g, LG from 0.82 to 1.65 cc/g, and RG from 0.48 to 1.05 cc/g. For the shale samples, the in situ gas content ranged from 2.82 to 3.66 cc/g. DG ranges from 1.57 to 2.46 cc/g, LG from 0.42 to 0.84 cc/g, and RG from 0.32 to 0.68 cc/g (Table ).

6. In Situ Gas, High-Pressure Methane, and CO₂ Sorption Capacity of Coal and Shale Samples .

	in situ gas								CH4 sorption						CO2 sorption
sample no	weight of sample (g)	LG (cc/g)	DG (cc/g)	RG (cc/g)	IG (cc/g)	M	D/r2 (10–3, min–1)	equil. moist. (wt %)	VL (cc/g)	PL (kPa)	b	m	R 2	CH4 SL (%)	VL (cc/g)	PL (kPa)	b	m	R 2	SR
CNK-1	2450	1.06	3.55	0.96	5.57	226	3.863	4.65	12.4	4034	3.21	0.081	0.961	44.92	30.6	7960	2.565	0.033	0.995	0.405
CNK-2	2080	1.2	2.91	0.65	4.76	198	2.957	4.58	12.8	4488	3.472	0.078	0.965	37.19	28.3	7472	2.604	0.035	0.947	0.452
CNK-3	2250	1.65	2.94	0.84	5.43	210	3.300	3.25	13.2	4215	2.891	0.068	0.914	41.14	30.2	8014	2.145	0.025	0.893	0.437
CNK-4	2260	1.05	2.62	1.02	4.69	205	3.236	4.36	12.1	4316	3.055	0.049	0.901	38.76	28.8	7836	2.614	0.175	0.904	0.420
CRK-5	2440	0.95	2.85	1.05	4.85	185	2.586	4.15	10.5	4025	4.124	0.148	0.892	46.19	29.4	8152	3.021	0.189	0.963	0.357
CRK-6	2080	0.82	2.64	0.63	4.09	176	2.355	3.5	8.8	3869	3.682	0.166	0.943	46.48	21.9	7695	2.893	0.056	0.882	0.402
CRK-7	2770	0.96	2.74	0.48	4.18	202	3.133	3.47	13.2	4280	3.199	0.076	0.952	31.67	31.5	7338	2.301	0.032	0.872	0.419
CRK-8	2620	1.45	3.69	0.85	5.99	232	4.019	4.62	13.9	4005	2.98	0.085	0.962	43.09	32.8	7588	2.477	0.247	0.985	0.424
CSM-9	2450	1.22	3.1	0.64	4.96	216	3.539	5.87	15.4	3685	3.016	0.156	0.908	32.21	34.6	7964	2.632	0.086	0.904	0.445
CSM-10	2580	1.64	2.55	0.89	5.08	199	2.981	5.12	11.6	3791	4.162	0.098	0.899	43.79	26.2	8025	2.041	0.136	0.893	0.443
SJT-11	2890	0.84	2.46	0.36	3.66	176	2.371	2.41	7.8	4422	3.872	0.086	0.985	46.92	18.9	8147	2.685	0.066	0.936	0.413
SJT-12	3040	0.67	1.95	0.48	3.1	146	1.641	1.69	8.2	4596	4.006	0.142	0.993	37.80	20.7	8236	3.112	0.042	0.872	0.396
SJT-13	2950	0.56	1.94	0.44	2.94	158	1.951	1.87	6.6	3814	2.986	0.254	0.924	44.55	19.4	8065	3.006	0.252	0.945	0.340
SJT-14	2740	0.75	2.05	0.35	3.15	126	1.185	3.06	6.9	4510	3.174	0.137	0.887	45.65	20.6	7955	2.985	0.039	0.896	0.335
SJT-15	2780	0.82	1.57	0.64	3.03	129	1.276	1.75	7.1	4362	3.452	0.089	0.978	42.68	18.8	7820	3.146	0.081	0.927	0.378
SJT-16	2850	0.64	2.07	0.32	3.03	132	1.317	1.82	8.2	4402	3.485	0.092	0.908	36.95	22.3	8436	3.415	0.176	0.934	0.368
SJT-17	3050	0.72	1.75	0.48	2.95	136	1.422	1.64	8.8	4060	3.694	0.138	0.929	33.52	19.2	7644	2.786	0.064	0.96	0.458
SJT-18	3560	0.42	2.24	0.52	3.18	140	1.498	2.22	6.4	4176	3.8	0.097	0.964	49.69	15.6	7392	2.984	0.231	0.892	0.410
SJT-19	3240	0.56	1.58	0.68	2.82	135	1.424	1.74	8	3417	4.217	0.125	0.982	35.25	29.7	6122	2.036	0.334	0.869	0.269
SJT-20	3470	0.65	2.1	0.49	3.24	128	1.229	2.08	8.3	3614	3.957	0.135	0.953	39.04	26.5	6404	2.152	0.285	0.876	0.313

^aAbbreviations: LG, lost gas; DG, desorbed gas; RG, residual gas; IG, in situ gas; M, slope of the line in the square root of time plot (eq ); D/r ², diffusivity (eq ); equil. moist., equilibrium moisture; V _L, Langmuir volume; P _L, Langmuir pressure; b, intercept; m, slope; CH₄ SL, CH₄ saturation level of the reservoir; SR, CH₄/CO₂ sorption ratio.

The results of high-pressure adsorption isotherm of CH₄ and CO₂ are exhibited in Table . The maximum sorption capacity Langmuir volume (V _L) and Langmuir pressure (P _L) of CH₄ and CO₂ for coal is estimated in the range of 8.8–15.4 cc/g; 3685–4488 kPa and 21.9–34.6 cc/g; and 7338–8152 kPa, respectively. Similarly, for the shale samples, the maximum sorption capacity V _L and P _L of CH₄ and CO₂ are estimated to be in the ranges of 6.4–8.8 cc/g; 3417–4596 kPa and 15.6–29.7 cm³/g; 6122–8436 kPa.

The diffusion coefficient or diffusivity may be determined as the amount of gas is desorbed from coal and shale matrix. − The diffusivity has been calculated from the slope of the line of desorption plot as given in eq :

$$\frac{D}{r^2}={\left(\frac{M}{3.3851\times (\mathrm{LG}+\mathrm{DG})}\right)}^2$$ 4

where $\frac{D}{r^2}$ is the diffusivity, DG is the desorbed gas volume, LG is the lost gas volume, and M is the slope of the intercepting line in the square root of time plot.

The CH₄ diffusivity of coal ranges from 2.355 × 10^–3 to 4.019 × 10^–3 min^–1, with an average of 3.197 × 10^–3 min^–1. In contrast, shale CH₄ diffusivity ranges from 1.185 × 10^–3 to 2.371 × 10^–3 min^–1, averaging 1.531 × 10^–3 min^–1 (Table ).

4.6. DG Composition by Chromatography

The distribution of nonhydrocarbon gases such as CO₂, N₂, and O₂ for coal samples range from 0.46 to 2.27 vol %, 5.58 to 11.41 vol %, and 4.19 to 6.51 vol %, respectively (Table ). Correspondingly, for shale samples, their concentration varies from 0.44 to 3.01 vol %, 4.32 to 9.97 vol %, and 4.08 to 8.56 vol %, whereas the hydrocarbon gases, primarily CH₄, C₂H₆, C₃H₆, C₃H₈, i-C₄H₁₀, and n-C₄H₁₀, for coal varies from 92.26 to 98.29 vol %, 0.95 to 4.07 vol %, 0.24 to 1.95 vol %, 0.14 to 0.85 vol %, 0.02 to 0.67 vol %, and 0.02 to 0.15 vol %, respectively. Similarly, for shale samples, it varies from 89.85 to 96.13 vol %, 1.60 to 3.86 vol %, 0.37 to 2.68 vol %, 0.24 to 0.83 vol %, 0.08 to 0.62 vol %, and 0.04 to 0.24 vol %, respectively.

7. DG Composition of Coal and Shale Samples .

	desorbed gas composition (vol %)				distribution of hydrocarbons in combustible gases (vol %)
sample no.	combustible gases (total hydrocarbons)	CO2	N2	O2 (By difference)	CH4	C2H6	C3H6	C3H8	iC4H10	nC4H10	C3/C1	C2/C1
CNK-1	80.66	1.45	11.41	6.48	93.18	2.14	1.77	0.85	0.09	0.04	28.12	22.97
CNK-2	83.29	0.92	10.95	4.84	92.26	1.16	1.95	0.25	0.67	0.15	23.85	12.57
CNK-3	85.12	0.87	10.64	3.37	95.32	1.07	0.79	0.36	0.38	0.06	12.06	11.23
CNK-4	86.31	0.55	8.52	4.62	96.24	1.19	1.58	0.82	0.06	0.09	12.16	12.36
CRK-5	87.14	1.75	6.14	4.97	95.05	2.48	0.74	0.29	0.02	0.14	10.84	26.09
CRK-6	84.46	1.99	7.98	5.57	96.35	2.90	0.27	0.22	0.14	0.07	5.09	30.10
CRK-7	87.25	0.46	6.45	5.84	97.93	0.95	0.36	0.18	0.28	0.02	5.51	9.70
CRK-8	89.71	0.52	5.58	4.19	98.29	1.16	0.24	0.14	0.07	0.04	3.87	11.80
CSM-9	83.29	1.89	8.36	6.46	92.59	2.85	1.46	0.37	0.08	0.05	19.76	30.78
CSM-10	84.39	2.27	6.83	6.51	93.38	4.07	1.05	0.36	0.14	0.08	15.10	43.59
SJT-11	82.16	1.59	9.4	6.85	90.85	3.78	2.15	0.83	0.27	0.11	32.80	41.61
SJT-12	86.27	0.89	8.57	4.27	94.18	2.14	0.89	0.47	0.32	0.09	14.44	22.72
SJT-13	86.96	1.78	6.05	5.21	94.96	2.60	0.78	0.74	0.62	0.23	13.90	27.38
SJT-14	84.89	1.63	9.02	4.46	92.22	2.95	1.78	0.64	0.15	0.16	26.24	31.99
SJT-15	86.92	0.61	7.69	4.78	95.05	2.88	1.31	0.37	0.18	0.17	17.67	30.30
SJT-16	88.23	0.45	6.14	5.18	94.88	1.85	0.48	0.29	0.25	0.24	8.12	19.50
SJT-17	91.16	0.44	4.32	4.08	96.13	1.60	1.46	0.41	0.26	0.13	11.13	16.64
SJT-18	78.46	3.01	9.97	8.56	89.85	3.86	2.68	0.56	0.08	0.04	38.29	42.96
SJT-19	82.04	1.42	9.54	7.00	93.62	3.72	0.95	0.24	0.23	0.1	12.71	39.74
SJT-20	87.21	0.58	8.12	4.09	96.08	1.78	0.37	0.32	0.24	0.07	7.18	18.53

^aAbbreviations: CO₂, carbon dioxide; N₂, nitrogen; O₂, oxygen; CH₄, methane; C₂H₆, ethane; C₃H₆, propene; C₃H₈, propane; iC₄H₁₀, isobutene; nC₄H₁₀, n-butane; C₃/C₁, C₃H₆ + C₃H₈/CH₄; C₂/C₁, C₂H₆/CH₄.

5. Discussion

5.1. Macroscopic Features of Coal and Shale

The lithotypes are association or assemblage of bands in coal classified as vitrain, clarain, durain, and fusain. − The usual criteria for identifying the coal lithotypes are the color, luster, and proportion of the given window (bright and dull bands) of the different bands. The coal samples of Barakar primarily contain clarain, followed by claro-vitrain, vitrain, claro-durain, and durain (Table , Figure ). The major bands of claro-vitrain and vitrain indicate the accumulation of dense organic matter (plant trunks and branches), passed through early diagenesis and thermal transformation. Also, the alternate bands of claro-durain and durain are attributed to the large supply of soft vegetal matter (plant leaves) and subsequently undergo partial geochemical alteration during pre- and postdepositional conditions. , Hence, the Barakar Formation coal seams lithotype are categorized as banded, dominantly contain clarain, claro-vitrain, Vitrain, and durain, with approximately thicknesses of 30–50%, 20–40%, 10–30%, and 10–20%, respectively, where vitrain has characteristically thin bright bands <5 mm. The banded shaly coal of the Barakar Formation was deposited in a shallow floodplain influenced by a poor supply of vegetal matter and a heterogeneous mixing of organic and inorganic matter influenced by the varying river currents. Likewise, the coal samples of the Raniganj Formation have been categorized for lithotype as vitrain rich followed by clarain, claro-vitrain, and durain, their percentage varying from 40 to 60%, 20 to 40%, and dull bands <5 mm, respectively. It is summarized that the differences in the bands or layers of the studied samples result from variations in the sources of organic and inorganic sediments and the thermal transformation process at different stages of coalification, from deposition to maturity of the formation. The greater proportion of vitrain, clarain, and claro-vitrain lithotypes in the Barakar coal enhances its suitability for CH₄ recovery and CO₂ sequestration due to their higher gas sorption capacity and permeability. In contrast, the Ranjiganj coal formation, characterized by a higher proportion of durain and fusain lithotypes, demonstrates reduced gas sorption potential and permeability, limiting its effectiveness for these recovery techniques. The shales, derived from the Barren Measures and Barakar Formations, exhibit a dark gray to black color with subconchoidal to uneven fractured surfaces. They manifest as carbonaceous and siliceous types, containing diverse proportions of clay minerals, along with specks of quartz/mica and intercalations. The Barakar Formation shales have higher organic content compared to those in the Barren Measures Formation, which gives them better potential for gas sorption, especially for methane. The increased organic richness enhances their capacity to store CH₄ and CO₂, making them more suitable for CH₄ recovery and CO₂ storage.

5.2. Geochemical and Petrographic Attributes

The significant variation in the FC content in both coal and shale samples indicates the irregularity in the supply of organic matter, changes in depositional conditions, and the early onset of diagenesis, favoring the preservation and transformation of organic matter. ,,, According to Seyler’s coal classification based on the volatile matter yield, the studied coals are of high volatile bituminous rank and possess the potential to generate both wet and dry gaseous hydrocarbons. The significant carbon content in coal (Table ) indicates carbon enrichment during the thermal transformation of the organic matter. The thermal transformation of organic matter to bituminous rank (VR_o ranges 0.57–0.89%) indicates that these coals may have generated a quantity of CH₄ and higher hydrocarbons.

The photomicrographs of coal and shale samples showing microlithotypes and macerals are presented in Figure a–p. The laths of collotelinite and carpogelinite are shown in Figure a,b. The collotelinite, vitrodetrinite, and collodetrinite in alternate microlithotypes indicate thermal alternation of organic matter during coalification (Figure c,d). The lenticular strips of cutinite, illustrated in Figure e,f, suggest the compaction effects of coalification. Similarly, the effects of compaction on the structure of sporinite (lenticular shape) due to overburden sediment pressures and temperatures at greater depths can be observed in Figure g–j. The silver bright fusinite and semifusinite honeycomb structures indicate thermochemical alternation of organic matter present in shale, Figure k–n. The detrital inertodetrinite and pyrite are shown in Figure o. The semibright semifusinite and mineral matter in groundmass may be due to heterogeneous mixing of organic–inorganic matter during transportation to the basin as shown in Figure p.

The vitrinite content in the coal samples varies from 23.4 to 65.9 vol %. The petrographic results of coal samples show the relative dominance of vitrinite macerals over inertinite and liptinite. On the other hand, petrographic results of shale samples show the dominance of the inertinite maceral group (12.3–24.1 vol %) attributed to the oxidation and geochemical alteration of organic matter. Also, the organic material was subjected to extensive oxidation in the peat swamp and preserved under laterally varying depositional conditions.

The values of microscopic pore size and cleats/features for coal vary from 2 to 6 μm and 0.5 to 6 μm, whereas for shale vary from 0.5 to 6 μm and 0.2 to 4 μm. It can be concluded that the studied coal and shale have significant microscopic pores and fractures suitable for CH₄ and CO₂ storage, diffusion, and flow in the reservoir.

5.3. Pore-Matrix System in Coal and Shale

Gas storage in coal and shale is directly controlled by the pore types and their distribution and structures. In this study, the coal and shale samples have been investigated for pore matrix and types through FE-SEM photography and examined at different magnitudes. FE-SEM photographs showing organo-inorganic pores of coal and shale are presented in Figure . Wood fiber with striated cell structures is exhibited in Figure a. The deep organic pores in vitrinite and microcleats illustrated in Figure b,c, respectively, and Figure d,f show the organic pore evolved during the thermal cracking of organic compounds and generated the hydrocarbons. Usually, these organic pores are carbon-rich and have a stronger affinity with gases due to van der Waals forces acting between carbon molecules of coal/shale and gases like CH₄ and CO₂. ,,, Likewise, the straited wood fiber contains significant visible bedding plane spaces and organic pores, which have strong affinity toward CH₄ and CO₂ ,, (Figure e). The partial decomposition prior to diagenesis and gelification due to compaction and dehydration and of organo-inorganic matter accountable to the formation of pores and fractures is shown in Figure g,h. These pores are suitable for gas storage and flow in coal and shale beds. The results of the FE-SEM pore size and cleat/fractures measured from the photographs are also given in Table . The values of FE-SEM pore size and cleats/features for coal vary from 1 to 5 μm and 0.2 to 4 μm, whereas for shale vary from 0.4 to 1 μm and 0.1 to 3 μm. The coal and shale have significant pores and fractures suitable for gas storage, diffusion, and flow.

4.

FE-SEM pictures showing pore distribution in coal and shale samples, (a) wood fiber with striated cell structure in coal sample, (b) deep pores in the organic matter in the coal, (c) micro cleats in coal, (d) pores in the organic matter in coal, (e) striated plane spacing, (f) pores in the organic matter in shale, (g) pores in the organic matter, and (h) pores in decomposed organic matter.

5.4. Pore Distribution and Surface Area

The pore size distribution is one of the significant constraints to assessing the desorption, adsorption, and storage of CO₂ and CH₄ in the coal and shale formation. , Low-pressure N₂ sorption isotherms of the samples are exhibited in Figure . Multipoint BET plots of low-pressure N₂ sorption isotherms of the samples show a good linear relation of 0.99–0.98 (Figure ). The surface area is a major parameter to assess the coal and shale bed’s adsorption mechanism and storage capacity, which is directly influenced by the type of pore, interconnection of the pore, its size, and distribution. , The wide variation in surface areas in coal and shale is influenced by the content of organic matter and clays. The significant surface area in coal specifies that the carbon content plays an important role in pore formation; however, the low surface area in shale is attributed to the low organic content. Coal and shale contain pores that exhibit variations in size, categorized into three groups based on their dimensions: macropores (larger than 50 nm), mesopores (2–50 nm), and micropores (less than 2 nm). , The pore structures of the shale and coal are categorized into three types, viz., cylindrical, slit, and wedge shapes (Figure ). The low-pressure N₂ sorption pattern of Type-A and C with H2, H3, and H4 hysteresis indicates narrow adsorption of the Langmuir monolayer followed by multilayer and pore condensation attributed to the end opening of the pores suitable for gas storage and release. The multipoint BET plots used for the surface area estimation suggest that the uniformity of gas adsorption is controlled by van der Waals forces in shale and coal samples (Figure a–d). The distribution of pores in coal and shale determined using the BJH plot is shown in Figure a–d. The larger frequency of meso pores followed by micro- and macropores are observed in coal and shale; however, variation in pore distribution pattern is due to heterogeneity in organo-inorganic content. The mesopores of size between 2 and 50 nm with open-end pores favor the gas diffusion and flow mechanism in coal and shale. Several authors stated that mesopores containing matrix systems of coal and shale are favorable reservoirs for CH₄ and CO₂ storage. ,

5.

Low-pressure N₂ sorption isotherm curves obtained through BET analysis, (a) cylindrical pores of Type-A curve with hysteresis pattern H3, (b) cylindrical pores of Type-A curve with hysteresis pattern H3, (c) cylindrical pores of Type-A curve with hysteresis pattern H3, (d) cylindrical pores of Type-A curve with hysteresis pattern H3, (e) cylindrical pores of Type-A curve with hysteresis pattern H3, (f) Slit pores of Type-B curve with hysteresis pattern H2, (g) Wedge shape pores of Type-C curve with hysteresis pattern H4, and (h) Wedge shape pores of Type-C curve with hysteresis pattern H4.

6.

Multipoint Brunauer–Emmett–Teller (BET) plots of low-pressure N₂ sorption isotherms of coal and shale samples, (a) multipoint BET plot for CNK-1; CNK-2; CNK-3; CNK-4; and CRK-5, (b) Multipoint BET plot for CRK-6; CRK-7; CRK-8; CSM-9; and CSM-10, (c) Multipoint BET plot for SJT-11; SJT-12; SJT-13; SJT-14; and SJT-15; and (d) Multipoint BET plot for SJT-16; SJT-17; SJT-18; SJT-19; and SJT-20.

7.

BJH (Barrett–Joyner–Halenda) plot for pore distribution in coal, (a) BJH plot for CNK-1, (b) BJH plot for CSM-10 and shale, (c) BJH plot for SJT-12, and (d) BJH plot for SJT-20.

5.5. In Situ Gas and Diffusivity

In situ gas content serves as the primary parameter for CBM and shale gas resource development. Similarly, diffusivity supplements gas recovery, influenced by various organo-inorganic properties of coal and shale. The substantial volume of DG in in situ gas indicates a promising potential for CH₄ gas recovery from coal and shale beds. This positive relationship between DG and the in situ gas content supports the aforementioned statement (Figure a). In situ gas content increases with FC content, suggesting CH₄ gas affinity toward the carbon present in the pore matrix of coal and shale beds (Figure b) because the microporosity of coal and shale increases with an increase in carbon and vitrinite content. − The inverse relation of in situ gas with ash yield indicates the negligible role of clay and minerals in pore-matrix formation (Figure c). Similarly, the inverse relationship of vitrinite reflectance with in situ gas emphasizes the thermal compact effect on the pore matrix, reducing the pore openings and restructuring of the basin due to internal basin tectonics (Figure d). Petrographic constituents such as collotelinite, semifusinite, and sporinite directly control gas accumulation in coal and shale (Figure e). Figure f presents the relationship between in situ gas and mineral matter, indicating the usual inverse correlation. The mineral matter in coal and shale primarily consists of hydrous and anhydrous silicates, such as kaolinite, quartz, K-feldspar, and muscovite, which are derived from granitic-gneissic parent rocks. Silicate minerals generally do not have an affinity for CH₄ molecules. Moreover, mineral matter makes a negligible contribution to the formation of the internal pore surface system. The phenomenon of gas flow through the macropores and cleavage system is well understood. However, the gas diffusion from the pore-matrix system to cleave fractures in coal and shale reservoirs is dependent on both pore distribution and cleat–fracture spacing. Typically, the mechanism of gas diffusion is presumed to be driven by the concentration of CH₄ and it modeled by Fick’s law of diffusion in the pore-matrix system of coal and shale. ,,,−

8.

Relation of in situ gas content with different parameters, (a) DG content vs in situ gas content, (b) FC content vs in situ gas content, (c) ash yield vs in situ gas content, (d) vitrinite reflectance (VR_o %) vs in situ gas content, (e) petrographic constituents vs in situ gas content, and (f) MM vs in situ gas content.

The higher diffusivity values in coal suggest excellent diffusion characteristics supported by the pore distribution and cleat intensity. On the other hand, shale exhibits comparatively lower diffusivity due to its massive nature, attributed to clay and mineral matter content. The positive relationship of LG, DG, and diffusivity is depicted in Figure a. This emphasizes the gas release from various pore surfaces and fracture systems in both coal and shale. The slope of the intercepting line in the square root of the time plot, used for estimating LG, shows a direct relationship with diffusivity, indicating a uniform gas molecule diffusion from coal and shale matrix systems (R ² = 0.9959) (Figure b). Similarly, the relationship between the in situ gas content and diffusivity (R ² = 0.8887) also supports the aforementioned statement (Figure c). The diffusivity characteristics (R ² = 0.8093) of coal and shale beds are directly controlled by the FC content (Figure d), primarily due to the substantial contribution of organic carbon to pore-matrix formation. The inverse relationship among the ash yield, vitrinite reflectance, and diffusivity highlights the influence of clay, minerals, and thermal compaction on the pore-matrix system (Figure e,f). The excellent to moderate CH₄ diffusivity of studied coal and shale can be a good site for CO₂ injection and CH₄ recovery advancement from the coal seam reservoir.

9.

Relation of diffusivity with different parameters, (a) LG and DG content vs diffusivity, (b) slope of the line in the square root of time plot vs diffusivity, (c) in situ gas content vs diffusivity, (d) FC content vs diffusivity, (e) ash yield vs diffusivity, and (f) vitrinite reflectance (VR_o %) vs diffusivity.

5.6. High-Pressure Sorption Capacity of CH₄ and CO₂ and Influencing Parameters

The high-pressure adsorption isotherm is being used to determine the maximum storage capacity of gases in the rock/coal/shale or material. , The comparative adsorption plots of CH₄ and CO₂ are presented in Figure a–d. The Langmuir fitting plot of applied pressure versus P/V illustrates uniform CH₄ and CO₂ adsorption on the internal pore surfaces of both coal and shale in the monolayer form. The initial steep slope of the monolayer curve indicates greater adsorption at low pressure due to initial abundance of free surface area. The sudden change in slope signifies the saturation of pore surfaces by CH₄ and CO₂ molecules (Figure a–d). CO₂ exhibits higher adsorption compared to CH₄, suggesting its stronger affinity for coal and shale.

10.

High-pressure methane and CO₂ sorption isotherms of coal samples CNK-1,2 and CRK-7 (a–c) and shale samples SJT-19 (d).

Also, the gas saturation level varies from 31.67 to 49.69, which indicates the need of secondary (CO₂) injection for gas recovery. This enhanced affinity CO₂ toward coal and shale is advantageous for displacing CH₄ from the reservoir. CH₄ displays higher diffusivity in coal compared to shale, implying favorable conditions for enhanced CBM recovery through CO₂ injection. However, critical factors such as shrinkage, swelling, and the behavior of organo-inorganic materials need separate investigation. The linear relationship between the V _L of CH₄ and CO₂ and in situ gas content, as well as FC, indicates an excellent gas adsorption mechanism allied to the carbon content within coal and shale pores (Figure a,b). A reduction in V _L with increased thermal maturity and ash yield demonstrates the influence of compaction, clay/mineral content, and pore formations impact on gas adsorption (Figure c,d). The linear relationship between V _L and diffusivity is presented in Figure e, signifying that the monolayer-adsorbed CH₄ gas diffuses upon pressure reduction from the reservoir. The sorption ratio of CH₄ and CO₂, directly proportional to in situ gas content, indicates an increase in CH₄ diffusion and CO₂ adsorption within coal and shale beds (Figure f).

11.

Relation of Langmuir volume (V _L) with different parameters, (a) in situ gas content vs Langmuir volume (V _L), (b) FC content vs Langmuir volume (V _L), (c) VR_o vs Langmuir volume (V _L), (d) ash yield vs Langmuir volume (V _L), (e) diffusivity vs Langmuir volume (V _L), and (f) sorption ratio vs in situ gas.

The notable diffusivity characteristics of coal suggest the feasibility of CO₂ injection for enhanced CH₄ recovery in coal, as documented by Ottiger et al. , Equally, the lower diffusivity of shale may require more time to release gas due to the impact of thermal compaction and the narrow, constrained pore-matrix characteristics influenced by clay and minerals. The linear positive relation of collotelinite maceral with CH₄ and CO₂ V _L indicates that CO₂ has 2–4 times more sorption capacity than CH₄ (Figure a). Similarly, the semifusinite maceral also shows controls on V _L as depicted in Figure b, highlighting the evolution of pores during inertification. Thus, the pore evolved is attributed to geochemical and thermal alterations that can contribute to gas storage. The positive trend of average pore with V _L suggests a role of pore diameter and opening in gas storage. However, the larger size of CH₄ and CO₂ molecules restricts the penetration in narrow pore openings indicated by the poor correlation coefficient (Figure c). Usually, the surface area is considered as a prime parameter for gas adsorption in coal and shale reservoirs. The linear increasing trend of V _L with surface area is shown in Figure d. The shale and coal samples have larger vitrinite content and higher mesopore frequency, having significant CH₄ and CO₂ storage capacity. Moreover, the clay content in shale contributing to pore internal surfaces negligibly influences the sorption capacities.

12.

Relation of Langmuir volume (V _L) with petrographic constituents and pore characteristics, (a) Collotelinite vs Langmuir volume (V _L), (b) Semifusinite vs Langmuir volume (V _L), (c) average pore diameter vs Langmuir volume (V _L), and (d) multipoint BET surface area vs Langmuir volume (V _L).

5.7. Distribution of Hydrocarbons and Nonhydrocarbons in DG Composition

The DG primarily consists of combustible gases (hydrocarbons), followed by nitrogen, oxygen, and carbon dioxide. CH₄ is the predominant component in the hydrocarbon gas desorbed from both coals and shales, typically comprising more than 90% of the hydrocarbon gas (Table ). The high CH₄ content in DG samples indicates that coal and shale beds might have undergone extensive thermal transformation processes, reaching the thermogenic stage and producing a substantial amount of thermogenic dry gas. Other hydrocarbons present in smaller amounts include C₂H₆ followed by C₃H₆, C₃H₈, iC₄H₁₀, nC₄H₁₀, etc. The trend of the occurrence of different gases in coal and shale with depth is exhibited in Figure . The concentration of combustible gases exhibits a linear increase with depth, which is attributed to the thermal genesis of the DG (Figure a). The genesis of CO₂ in coal and shale is more pronounced during biogenic degradation of organic matter, whereas it decreases during the coalification process. , Figure b shows the reduction in the concentration of CO₂ with increasing depth indicating its consumption during genesis of thermal-dry gas (CH₄) in coal and shale. − Nitrogen in coal and shale exists primarily in the form of organic nitrogen compounds, which are part of the original plant material. As coalification progresses, the heat and pressure cause the coal to lose volatile components, including nitrogen, through processes such as thermal and chemical transformation. ,, The CH₄ concentration has been observed to be higher with increasing depth of coal and shale beds (Figure c). This is because deeper coal and shale beds have undergone more extensive thermal maturation, which not only increases the carbon content but also results in the generation of significant amounts of CH₄. Subsequently, the generated CH₄ is adsorbed onto the internal pore surfaces of the matrix system of coal and shale beds. ,− Other higher hydrocarbons such as C₂H₆, C₃H₆, and C₃H₈ content decreases with increasing depth of coal and shale beds (Figure d–f). This reduction occurs because deeper beds were exposed to higher temperatures and pressures, which caused the breakdown of higher hydrocarbons into simpler compounds and CH₄ gas. Figure exhibits the plot of C₃/C₁ and C₂/C₁, which illustrates the thermogenic-dry gas in the DG of coal and shale samples. , The genesis of CH₄ gas increases with thermally matured coal and shale beds due to the progressive breakdown of organic matter into simpler hydrocarbons. Therefore, the studied coal and shale beds have higher concentrations of thermogenic CH₄ gas, which is an excellent energy resource.

13.

Trend of occurrence of different gases in coal and shales with depth, (a) increasing trend of combustible gases with depth, (b) decreasing concentration of CO₂ with depth, (c) increasing concentration of CH₄ with depth, (d) declining trend of C₂H₆ with depth, (e) reduction of C₃H₆ with depth, and (f) decreasing concentration of C₃H₈.

14.

Plot of C₃/C₁ and C₂/C₁ showing the thermogenic-dry gas in the DG of coal and shale samples (modified after Schoell, 1983).

6. Conclusions

The results of these analyses establish the relationship between the characteristics of coal and shale with the sorption capacity of CH₄ and CO₂ and their applications toward enhanced CH₄ recovery. It is summarized that Gondwana coal and shale have the potential for CO₂ injection and enhanced recovery of CH₄. However, a detailed understanding of coal characteristics, including swelling and deformation behavior, is necessary to accurately predict reservoir performance. Finally, it is summarized that coal and shale comprise varying amounts of organic and inorganic content controlling pore distribution, surface area, and pore network, which can influence CO₂ injection and CH₄ recovery from the reservoir. Hence, the key parameters identified in this study to characterize the coal and shale gas reservoirs are moisture, volatile matter, carbon content, maceral composition, surface area, and pore size distribution. The conclusions drawn from this study are mentioned below:

• The significant carbon content in coal emphasized the favorable condition of organic matter preservation, and its thermal transformation to bituminous rank indicates the generation of a substantial quantity of CH₄ and other higher hydrocarbons.

• The partial decomposition prior to diagenesis and gelification due to compaction, dehydration, and organo-inorganic matter is accountable for the formation of pores and fractures.

• The larger frequency of mesopores followed by micro and macropores are observed in coal and shale; however, variation in pore distribution pattern is due to heterogeneity in organo-inorganic content.

• Coal has higher CH₄ diffusivity compared to shale, which suggests favorable conditions for enhanced coalbed methane recovery through CO₂ injection.

• The linear positive relation of collotelinite maceral with CH₄ and CO₂ V _L indicates that CO₂ has 2–4 times more sorption capacity than CH₄.

• CO₂ exhibits higher adsorption compared to CH₄, suggesting its stronger affinity for coal and shale. Also, the low to moderate gas saturation level indicates the need for secondary (CO₂) injection for required gas recovery.

The authors declare no competing financial interest.