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As an unconventional resource, oil shale possesses abundant reserves and significant potential for industrial applications. The rational and efficient development of oil shale resources holds immense importance in reducing national energy demand. In-situ catalytic technology, characterized by its high efficiency, low pollution, and minimal energy consumption, represents a key direction for future oil shale development. This paper provides a comprehensive review of research progress in in-situ oil shale mining technology, oil shale pyrolysis catalysts, the pyrolysis mechanism of kerogen, and the compatibility of different heating processes and catalysts. Furthermore, the paper proposes future research directions and prospects for oil shale in-situ catalytic technology, including reservoir modification, high-efficiency catalyst synthesis, injection processes, and high-efficiency heating technology. These insights serve as valuable technical references for the advancement of oil shale in-situ catalytic technology.

The pore structures and controlling factors of several different Paleozoic shales from Southern China and their kerogens were studied using nitrogen adsorption and scanning electron microscopy methods. The results indicate that： 1） The specific surface area is 2.22-3.52 m2/g and has no correlation with the TOC content of the Permian Dalong Formation shales, nanopores are extremely undeveloped in the Dalong Formation kerogens, which have specific surface areas of 20.35-27.49 me/g; 2） the specific surface area of the Silurian Longmaxi Formation shales is in the range of 17.83-29.49 m2/g and is positively correlated with TOC content, the kerogens from the Longmaxi Formation have well-developed nanopores, with round or elliptical shapes, and the specific surface areas of these kerogens are as high as 279.84-300.3 m2/g; 3） for the Niutitang Formation shales, the specific surface area is 20.12-29.49 m2/grock and increases significantly with increasing TOC and smectite content. The Niuti- tang Formation kerogens develop a certain amount of nanopores with a specific surface area of 161.2 m2/g. Oil shale was also examined for comparison, and was found to have a specific surface area of 19.99 m2/g. Nanopores are rare in the Youganwo Formation kerogen, which has a specific surface area of only 5.54 m2/g, suggesting that the specific surface area of oil shale is due mainly to the presence of smectite and other clay minerals. The specific surface area and the number of pores present in shales are closely related to TOC, kerogen type and maturity, smectite content, and other factors. Low-maturity kerogen has very few nanopores and therefore has a very low specific surface area, whereas nanopores are abundant in mature to over- mature kerogen, leading to high specific surface areas. The Longmaxi Formation kerogen has more developed nanopores and a higher specific surface area than the Niutitang Formation kerogen, which may be due to differences in the kerogen type and maceral components. A high content of smectite may also contribute to shale surface area. The pore volume and specific sur- face area of low-maturity kerogens are mainly attributable to pores with diameters above 10 nm. By contrast, the pore volume of mature kerogens consists predominantly of pores with diameters above 10 nm with some contribution from about 4 nm diameter pores, while the specific surface area is due mainly to pores with diameters of less than 4 nm. Through a comparative study of the specific surface area and pore structure characteristics of different shales and their kerogens, we conclude that the Longmaxi Formation shales and Niutitang Formation shales have greater sorption capacities than the Dalong Formation shales.

Organic rich sedimentary rocks of the Late Cretaceous Muwaqqar Formation from the Lajjun outcrop in the Lajjun Sub-basin, Western Central Jordan were geochemically analyzed. This study integrates kerogen microscopy of the isolated kerogen from 10 oil shale samples with a new finding from unconventional geochemical methods [i.e., ultimate elemental (CHNS), fourier transform infrared spectroscopy and pyrolysis–gas chromatography (Py–GC)] to decipher the molecular structure of the analyzed isolated kerogen fraction and evaluate the kerogen composition and characteristics. The optical kerogen microscopy shows that the isolated kerogen from the studied oil shales is originated from marine assemblages [i.e., algae, bituminite and fluorescence amorphous organic matter] with minor amounts of plant origin organic matter (i.e., spores). This finding suggests that the studied kerogen is hydrogen-rich kerogen, and has the potential to generate high paraffinic oil with low wax content. The dominance of such hydrogen-rich kerogen (mainly Type II) was confirmed from the multi-geochemical ratios, including high hydrogen/carbon atomic of more than 1.30 and high A-factor of more than 0.60. This claim agrees with the molecular structure of the kerogen derived from Py–GC results, which suggest that the studied kerogen is mainly Type II-S kerogen exhibiting the possibility of producing high sulphur oils during earlier stages of diagenesis, according to bulk kinetic modeling. The kinetic models of the isolated kerogen fraction suggest that the kerogen conversion, in coincidence with a vitrinite reflectance range of 0.55–0.60%, commenced at considerably lower temperature value ranges between 100 and 106 °C, which have produced oils during the early stage of oil generation. The kinetic models also suggest that the commercial amounts of oil can generate by kerogen conversion of up to 50% during the peak stage of oil window (0.71–0.83%) at relatively low geological temperature values in the range of 122–138 °C. Therefore, further development of the Muwaqqar oil shale successions is highly approved in the shallowly buried stratigraphic succession in the Lajjun Sub-basin, Western Central Jordan.

This study investigates the geochemical characteristics and hydrocarbon generation potential of the Chia Gara Formation (Tithonian–Berriasian) in the Northwestern (NW) Zagros Basin, Iraq. A comprehensive analysis of forty–seven extract samples and seven crude oil samples was conducted to evaluate the formation’s petroleum potential. The total organic carbon (TOC) content of the analyzed samples ranged from 0.68% to 3.95%, indicating fair to excellent source rock quality. Rock–Eval parameters revealed thermal maturity, suggesting an environment favorable for both oil and gas generation. Integrated analysis of TOC/Rock–Eval data, stable carbon isotope data, and biomarker parameters confirmed the existence of kerogen Type–II and mixed–II/III constituents, along with carbonate–rich deposits. These findings suggest deposition within an algal–dominant anoxic-marine environment. Characterization of crude oils from these fields revealed paraffinic types, further supporting the interpretation of the Chia Gara interval as the primary source rock in the NW Zagros Basin. The oil–source correlation strengthens the evidence, consolidating the formation’s significance in the region’s petroleum system.

Despite kerogen’s importance as the organic backbone for hydrocarbon production from source rocks such as gas shale, the interplay between kerogen’s chemistry, morphology and mechanics remains unexplored. As the environmental impact of shale gas rises, identifying functional relations between its geochemical, transport, elastic and fracture properties from realistic molecular models of kerogens becomes all the more important. Here, by using a hybrid experimental–simulation method, we propose a panel of realistic molecular models of mature and immature kerogens that provide a detailed picture of kerogen’s nanostructure without considering the presence of clays and other minerals in shales. We probe the models’ strengths and limitations, and show that they predict essential features amenable to experimental validation, including pore distribution, vibrational density of states and stiffness. We also show that kerogen’s maturation, which manifests itself as an increase in the sp 2 / sp 3 hybridization ratio, entails a crossover from plastic-to-brittle rupture mechanisms. Molecular models of kerogens provide a detailed picture of their nanostructure in organic-rich shale.

Analyses by secondary ion mass spectroscopy (SIMS) of 11 specimens of five taxa of prokaryotic filamentous kerogenous cellular microfossils permineralized in a petrographic thin section of the ∼3,465 Ma Apex chert of northwestern Western Australia, prepared from the same rock sample from which this earliest known assemblage of cellular fossils was described more than two decades ago, show their δ13C compositions to vary systematically taxon to taxon from −31‰ to −39‰. These morphospecies-correlated carbon isotope compositions confirm the biogenicity of the Apex fossils and validate their morphology-based taxonomic assignments. Perhaps most significantly, the δ13C values of each of the five taxa are lower than those of bulk samples of Apex kerogen (−27‰), those of SIMS-measured fossil-associated dispersed particulate kerogen (−27.6‰), and those typical of modern prokaryotic phototrophs (−25 ± 10‰). The SIMS data for the two highest δ13C Apex taxa are consistent with those of extant phototrophic bacteria; those for a somewhat lower δ13C taxon, with nonbacterial methane-producing Archaea; and those for the two lowest δ13C taxa, with methane-metabolizing γ-proteobacteria. Although the existence of both methanogens and methanotrophs has been inferred from bulk analyses of the carbon isotopic compositions of pre-2,500 Ma kerogens, these in situ SIMS analyses of individual microfossils present data interpretable as evidencing the cellular preservation of such microorganisms and are consistent with the near-basal position of the Archaea in rRNA phylogenies.

Deep shale has the characteristics of large burial depth, rapid changes in reservoir properties, complex pore types and structures, and unstable production. The whole-rock X-ray diffraction (XRD) analysis, reservoir physical property parameter testing, scanning electron microscopy (SEM) analysis, high-pressure mercury intrusion testing, CO 2 adsorption experimentation, and low-temperature nitrogen adsorption–desorption testing were performed to study the pore structure characteristics of marine shale reservoirs in the southern Sichuan Basin. The results show that the deep shale of the Wufeng Formation Longyi 1 sub-member in the Luzhou area is superior to that of the Weiyuan area in terms of factors controlling shale gas enrichment, such as organic matter abundance, physical properties, gas-bearing properties, and shale reservoir thickness. SEM is utilized to identify six types of pores (mainly organic matter pores). The porosities of the pyrobitumen pores reach 21.04–31.65%, while the porosities of the solid kerogen pores, siliceous mineral dissolution pores, and carbonate dissolution pores are low at 0.48–1.80%. The pores of shale reservoirs are mainly micropores and mesopores, with a small amount of macropores. The total pore volume ranges from 22.0 to 36.40 μL/g, with an average of 27.46 μL/g, the total pore specific surface area ranges from 34.27 to 50.39 m 2 /g, with an average of 41.12 m 2 /g. The pore volume and specific surface area of deep shale gas are positively correlated with TOC content, siliceous minerals, and clay minerals. The key period for shale gas enrichment, which matches the evolution process of shale hydrocarbon generation, reservoir capacity, and direct and indirect cap rocks, is from the Middle to Late Triassic to the present. Areas with late structural uplift, small uplift amplitude, and high formation pressure coefficient characteristics favor preserving shale gas with high gas content and production levels.

This paper summarizes the most important results and conclusions derived from organic geochemical investigations performed on the Miocene Aleksinac oil shale (Serbia) during the last 60 years. The Aleksinac oil shale is one of the richest and most studied European oil shale deposits. This paper is divided into four sections. The first section includes data from Rock-Eval pyrolysis, organic petrography, and biomarkers of outcrop samples, as well as samples taken from two layers (upper and lower), drilled from the well BD-4. The results consistently indicated that the Aleksinac oil shale contains immature, mostly algal-derived organic matter (kerogen types I and II), deposited in reducing brackish to freshwater environment. However, certain differences were observed between the upper and lower oil shale sequences in the well BD-4, which resulted in two times higher source potential index in the upper layer. The Aleksinac oil shale has been used as a model substance in numerous organic geochemical studies. The second section of the review paper describes how a standard procedure for determination of kerogen chemical structure (controlled gradual degradation of kerogen by an alkaline permanganate solution) is established, which was developed using the Aleksinac oil shale as a substrate. This oil shale was also used as a model substance to investigate the influences of native minerals on the thermal changes of bitumen and kerogen in sediments, and this process is described in the third section of the paper. In the final section, studies (performed on the Aleksinac oil shale) related to the influence of the pyrolysis type and variations of kerogen type on the yield and composition of liquid pyrolysis products are presented. Graphical abstract

We performed molecular dynamics simulation to elucidate the adsorption behavior of hydrogen (H2), carbon dioxide (CO2), and methane (CH4) on four sub-models of type II kerogens (organic matter) of varying thermal maturities over a wide range of pressures (2.75 to 20 MPa) and temperatures (323 to 423 K). The adsorption capacity was directly correlated with pressure but indirectly correlated with temperature, regardless of the kerogen or gas type. The maximum adsorption capacity was 10.6 mmol/g for the CO2, 7.5 mmol/g for CH4, and 3.7 mmol/g for the H2 in overmature kerogen at 20 MPa and 323 K. In all kerogens, adsorption followed the trend CO2 > CH4 > H2 attributed to the larger molecular size of CO2, which increased its affinity toward the kerogen. In addition, the adsorption capacity was directly associated with maturity and carbon content. This behavior can be attributed to a specific functional group, i.e., H, O, N, or S, and an increase in the effective pore volume, as both are correlated with organic matter maturity, which is directly proportional to the adsorption capacity. With the increase in carbon content from 40% to 80%, the adsorption capacity increased from 2.4 to 3.0 mmol/g for H2, 7.7 to 9.5 mmol/g for CO2, and 4.7 to 6.3 mmol/g for CH4 at 15 MPa and 323 K. With the increase in micropores, the porosity increased, and thus II-D offered the maximum adsorption capacity and the minimum II-A kerogen. For example, at a fixed pressure (20 MPa) and temperature (373 K), the CO2 adsorption capacity for type II-A kerogen was 7.3 mmol/g, while type II-D adsorbed 8.9 mmol/g at the same conditions. Kerogen porosity and the respective adsorption capacities of all gases followed the order II-D > II-C > II-B > II-A, suggesting a direct correlation between the adsorption capacity and kerogen porosity. These findings thus serve as a preliminary dataset on the gas adsorption affinity of the organic-rich shale reservoirs and have potential implications for CO2 and H2 storage in organic-rich formations.