Search Results (18)

The Baorao Trough of the Jiergalangtu Sag, located in the central Erlian Basin, is rich in petroleum resources. However, due to a lack of systematic geochemical characterization and comparative studies with other source rocks, the hydrocarbon generation potential of its Jurassic strata remains unclear. In this study, 125 samples from the Baorao Trough were analyzed to evaluate their hydrocarbon generation potential, identify organic matter sources and depositional environments, and characterize hydrocarbon generation and expulsion. Results show that source rocks from the first member of the Tengge’er (K₁bt₁) Formation and the Aershan (K₁ba) Formation have high organic matter content, favorable kerogen types, and have reached low to medium maturity. In contrast, Jurassic source rocks are predominantly Type III kerogen and highly mature. K₁bt₁ was deposited in a weakly oxidizing to reducing, brackish environment, while K₁ba formed under weakly reducing, saline conditions. Jurassic source rocks also developed in weakly reducing, brackish to saline settings. Notably, saline and reducing environments promote the development of high-quality source rocks. The lower total organic carbon (TOC) threshold for effective source rocks in the study area is 0.8%, and the hydrocarbon expulsion threshold for vitrinite reflectance ratio (R_o) is approximately 0.8%. Accordingly, K₁bt₁ and K₁ba have undergone partial hydrocarbon expulsion but remain within the oil-generating window, indicating strong oil-generating potential. Jurassic source rocks likely experienced early thermal cracking of Type III kerogen, with generated oil migrating or escaping during early geological activity. However, some gas-generating potential remains. These findings provide significant evidence for assessing resource potential, predicting the distribution of high-quality source rocks and favorable exploration areas. Full article

The Silurian marine shale in the Sichuan Basin is currently the main reservoir for shale gas reserves and production in China. This study investigates the reservoir evolution of the Silurian marine shale based on fractal dimension, quantifying the complexity and heterogeneity of the shale’s pore structure. Physical simulation experiments were conducted on field-collected shale samples, revealing the evolution of total organic carbon, mineral composition, porosity, and micro-fractures. The fractal dimension of shale pore was characterized using the Frenkel–Halsey–Hill and capillary bundle models. The relationships among shale components, porosity, and fractal dimensions were investigated through a correlation analysis and a principal component analysis. A comprehensive evolution model for porosity and micro-fractures was established. The evolution of mineral composition indicates a gradual increase in quartz content, accompanied by a decline in clay, feldspar, and carbonate minerals. The thermal evolution of organic matter is characterized by the formation of organic pores and shrinkage fractures on the surface of kerogen. Retained hydrocarbons undergo cracking in the late stages of thermal evolution, resulting in the formation of numerous nanometer-scale organic pores. The evolution of inorganic minerals is represented by compaction, dissolution, and the transformation of clay minerals. Throughout the simulation, porosity evolution exhibited distinct stages of rapid decline, notable increase, and relative stabilization. Both pore volume and specific surface area exhibit a trend of decreasing initially and then increasing during thermal evolution. However, pore volume slowly decreases after reaching its peak in the late overmature stage. Fractal dimensions derived from the Frenkel–Halsey–Hill model indicate that the surface roughness of pores (D1) in organic-rich shale is generally lower than the complexity of their internal structures (D2) across different maturity levels. Additionally, the average fractal dimension calculated based on the capillary bundle model is higher, suggesting that larger pores exhibit more complex structures. The correlation matrix indicates a co-evolution relationship between shale components and pore structure. Principal component analysis results show a close relationship between the porosity of inorganic pores, microfractures, and fractal dimension D2. The porosity of organic pores, the pore volume and specific surface area of the main pore size are closely related to fractal dimension D1. D1 serves as an indicator of pore development extent and characterizes the changes in components that are “consumed” or “generated” during the evolution process. Based on mineral composition, fractal dimensions, and pore structure evolution, a comprehensive model describing the evolution of pores and fractal dimensions in organic-rich shale was established. Full article

The Kuqa Depression is rich in oil and gas resources and serves as a key production area in the Tarim Basin. However, controversy persists over the genesis of oil and gas in the various structural zones of the Kuqa Depression. This study employs natural gas composition analysis, gas carbon isotope analysis and gold pipe thermal simulation experiments, to comprehensively analyze the differences in the genesis and sources of hydrocarbon gas fluid from the eastern and western Kuqa Depression. The results show that the Kuqa Depression is dominated by alkane gas, with an average gas drying coefficient of 95.6, with nitrogen and carbon dioxide as the primary non-hydrocarbon gases. The average of δ¹³C₁, δ¹³C₂ and δ¹³C₃ values in natural gas are −27.70‰, −20.43‰ and −21.75‰, respectively. Based on comprehensive natural gas geochemical maps, the CO₂ in the natural gas from the Tudong and Dabei areas, as well as the KT-1 well of the Kuqa Depression, is thought to be of organic origin. Additionally, natural gas formation in the Tudong area is relatively simple, consisting entirely of thermally generated coal gas derived from the initial cracking of kerogen. The natural gas in the KT-1 well and the Dabei area are mixed gasses, formed by the initial cracking of kerogen from highly evolved lacustrine and coal-bearing source rocks, exhibiting characteristics resembling those of crude oil cracking gas. The methane (CH₄) content of natural gas in the Dabei area is high and the carbon isotopes are unusually heavy. Considering the regional geological background, potential source rock characteristics and geochemical features may be related to the large-scale invasion of dry gas contributed by CH₄ from highly evolved, underlying coal-bearing source rocks. Consequently, the CH₄ content in the mixed gas is generally high (Ln (C₁/C₂) can reach up to 5.38), while the relative content of heavy components is low, though remains relatively unchanged. Thus, the map of the relative content of heavy components still reflects the characteristics of the original gas genesis (initial cracking of kerogen). Mixed-source gas was analyzed using thermal simulation experiments and natural gas composition ratio diagrams. The contributions of natural gas from deep, highly evolved coal-bearing source rocks in the KT-1 well and the Dabei area accounted for more than 90% and approximately 60%, respectively. This analysis provides theoretical guidance for natural gas exploration in the research area. Full article

This work is focused on developing a computational model to predict the production rate and pressure evolution of natural gas from unconventional reservoirs, particularly shale gas deposits. The model is based on the principle of conservation of mechanical energy and was developed from the transient solution of Bernoulli’s equation. This solution was obtained by computing the pressure evolution in the well resulting from the combined action of extracting the free gas and of gasification from kerogen. The transient behavior of gas production by hydraulic fracturing was calculated by numerically integrating Bernoulli’s equation. The curves representing gas flow evolution were considered as a series of stepwise steady states under a constant gas flow rate, similar to the pressure–time curves. These time steps were connected by instantaneous drops in pressure or gas flow rates. On the other hand, the delayed release of the adsorbed and dissolved gas in the kerogen was accurately calculated by introducing a semi-empirical gas pressure source term into the gas well pressure equation. The effect of this source is to gradually increase the gas pressure in the reservoir, emulating the gas release mechanisms from the organic matter. Model validation was based on production data from the unconventional reservoirs Eagle Ford, U.S.A., and Burgos basin, México. The initial measured gas production rate was used to determine a global friction factor of the gas flowing out from soil cracks and ducts. Additionally, measured production rate data were used to determine the coefficients of the source term function. Pearson correlation coefficients of 0.97 and 0.96 were obtained for Eagle Ford and Burgos basins data, respectively. In contrast, the corresponding coefficients calculated from the traditional Arps’ model were 0.89 and 0.5, respectively. The present pressure source model (PSM) represents a new approach to characterize the process of gas production from unconventional reservoirs, proving to be accurate in forecasting both the gas flow rate and pressure evolution during gas production. The postulated pressure source term was shown to mimic the desorption and diffusion kinetics, which release free gas from the kerogen. Full article

Sub-critical water is an environment-friendly solvent. It is widely used for the extraction of various organic compounds. It can be used to dissolve and transport organic matter in oil shale. In this study, the conversion of oil shale was synergistically catalyzed by the addition of Fe or Ni to the Fe inherent in samples under sub-critical water conditions. Oil shale can be converted to gas, oil and residues of oil. Thermogravimetric (TG) analysis results presented that the weight loss of raw oil shale was up to 15.85%. After sub-critical water extraction, the weight loss rate of the residues was reduced to 8.41%. With the application of a metal catalyst, Fe or Ni, the weight loss of residues was further reduced to 7.43% and 6.57%, respectively. According to DTG curves, it was found that there were two weight-loss rate peaks. The decomposition process of kerogen in oil shale could be divided into two cracking processes. One is decomposed at a high velocity at around 420 °C, and another is decomposed at a low velocity at around 515 °C. Gas chromatography (GC) results of gas products indicated that Fe or Ni could contribute to producing normal alkanes, such as methane, ethane, propane, etc., which are produced by the hydrogenation of alkenes via hydrogen transfer during the conversion process of kerogen. Gas chromatography-mass spectrometry (GC–MS) was conducted to analyze the components of the liquid products. The results showed that n-alkanes, iso-alkane, oxygenated hydrocarbons and aromatic compounds were the major components of the kerogen cracking products. When Ni was introduced as a catalyst, the contents of aromatic compounds and oxygenated hydrocarbons in the liquid products were increased from 19.55% and 6.87% to 22.38% and 13.77%, respectively. This is due to the synergistic effect of the addition of Ni with the inherent Fe in oil shale under sub-critical water which ensures kerogen is more easily cracked to produce aromatic compounds and oxygenated hydrocarbons. Full article

To investigate the characteristics and generation potential of gas generated from over-mature shale, hydrous and anhydrous pyrolysis experiments were carried out on the Longmaxi Formation in the Anwen 1 well of the Sichuan Basin of China at temperatures of 400–598 °C and pressures of 50 Mpa, with (hydrous) and without (anhydrous) the addition of liquid water. The results show that in the presence of water, the total yield of carbon-containing gases (i.e., the sum of methane, ethane, and carbon dioxide) was increased by up to 1.8 times when compared to the total yield from the anhydrous pyrolysis experiments. The increased yield of carbon dioxide and methane accounted for 89% and 10.5% of the total increased yield of carbon-containing gases. This indicated that the participation of water could have promoted the release of carbon from over-mature shale, like we used in this study. The methane generated in the hydrous pyrolysis experiments was heavier, with a δ¹³C value of −21.27‰ (544 °C) compared to that generated in the anhydrous pyrolysis experiments, which showed a lighter δ¹³C of −33.70‰ (544 °C). It is noteworthy that the δ¹³C values of the methane from hydrous pyrolysis at >500 °C were even heavier than that of the kerogen from the over-mature shale, although the δ¹³C values of the methane show an overall increasing trend with increasing temperature both in hydrous and anhydrous pyrolysis. The carbon dioxide from hydrous pyrolysis was less enriched in ¹³C relative to that from anhydrous pyrolysis. Specifically, the δ ¹³C values of the carbon dioxide increased with the increasing temperature in anhydrous pyrolysis, whereas they remained nearly constant with increasing temperature in hydrous pyrolysis. The overall lighter δ¹³C values of the carbon dioxide generated in the hydrous pyrolysis experiments likely indicate that water tends to prompt the release of lighter carbon and/or suppress the release of heavier carbon from over-mature shale in the form of carbon dioxide, especially at higher temperatures, for example, of >510 °C. Full article

The present study investigates the adsorption of hydrogen gas by the Triassic Chang 7 Shale Member in the Ordos Basin, China. The mineral composition, microscopic morphology, pore characteristics, hydrogen adsorption capacity, and factors influencing hydrogen adsorption were explored using X-ray diffraction (XRD), thin section observations, nitrogen adsorption, scanning electron microscopy (SEM), and high-pressure hydrogen adsorption experiments. Based on these integrated tools, it was revealed that the Chang 7 Shale Member primarily comprises organic matter (kerogen) and clay minerals (predominantly an illite/smectite-mixed layer [I/S]). Nitrogen adsorption–desorption curves indicated the presence of slit-shaped pores, cracks, and wedge-shaped structures. The adsorption of hydrogen by shale decreases with increasing temperature and increases with increasing pressure. This adsorption behaviour conforms to both the Freundlich and Langmuir equations; moreover, the Freundlich equation provides a better fit. Organic matter (kerogen) and clay minerals considerably influence hydrogen adsorption. The present research provides insights into the occurrence of hydrogen in shale, offering implications for the exploration of natural hydrogen gas. Full article

In order to evaluate the hydrocarbon generation potential and effectiveness of the carbonate source rock from the Lower Permian Taiyuan Formation of the Upper Paleozoic gas reservoirs in the central and eastern Ordos Basin, 87 core samples from the formation were analyzed through the comprehensive application of core observation, thin section analysis, lithofacies division, and organic geochemistry experiments. The results show that the carbonate source rocks of the Taiyuan Formation comprise four lithofacies types with type I–II kerogen: laminar argillaceous micritic limestone, massive micrite, massive bioclastic micritic limestone, and massive algae-clotted limestone. Among them, laminar argillaceous micritic limestone and massive micrite are favorable lithofacies for high-quality source rocks, with a TOC distribution range of 0.99% to 6.07% (average 2.56%) and 0.24% to 8.27% (average 1.77%), respectively. Hydrous gold tube pyrolysis showed that the samples of laminar argillaceous micritic limestone and massive micrite attained a peak yield of nearly 115.0 mL/g TOC (heating rate 2 °C/h) and 101.4 mL/g TOC (heating rate 2 °C/h), respectively, for C_1–5 compounds. Due to the higher maturity of the samples, the hydrocarbon gases were dominated by residual kerogen pyrolysis gases and lacked liquid hydrocarbon cracking gas. Furthermore, the carbonate source rocks had weak methane absorption ability, with a maximum adsorption capacity of only about 0.15 cm³/g. In addition, the hydrocarbon gas generation of carbonate source rocks of the Taiyuan Formation was far greater than 0.2 mL/g rock, which is the lower limit standard for effective gas source rock. Therefore, the carbonate source rocks of the Taiyuan Formation should be regarded as important gas source rocks in subsequent explorations of the central and eastern Ordos Basin. Full article

The reservoir properties of low–medium-maturity shale undergo complex changes during the in situ conversion process (ICP). The experiments were performed at high temperature (up to 450 °C), high pressure (30 MPa), and a low heating rate (0.4 °C/h) on low–medium-maturity shale samples of the Chang 7 Member shale in the southern Ordos Basin. The changes in the shale composition, pore structure, and reservoir properties during the ICP were quantitatively characterized by X-ray diffraction (XRD), microscopic observation, vitrinite reflectance (Ro), scanning electron microscopy (SEM), and reservoir physical property measurements. The results showed that a sharp change occurred in mineral and maceral composition, pore structure, porosity, and permeability at a temperature threshold of 350 °C. In the case of a temperature > 350 °C, pyrite, K-feldspar, ankerite, and siderite were almost completely decomposed, and organic matter (OM) was cracked into large quantities of oil and gas. Furthermore, a three-scale millimeter–micrometer–nanometer pore–fracture network was formed along the shale bedding, between OM and mineral particles and within OM, respectively. During the ICP, porosity and permeability showed a substantial improvement, with porosity increasing by approximately 10-times and permeability by 2- to 4-orders of magnitude. Kerogen pyrolysis, clay–mineral transformation, unstable mineral dissolution, and thermal stress were the main mechanisms for the substantial improvement in the reservoir’s physical properties. This study is expected to provide a basis for formulating a heating procedure and constructing a numerical model of reservoir properties for the ICP field pilot in the Chang 7 shale of the Ordos Basin. Full article

Petroleum was the most-consumed energy source in the world during the past century. With the continuous global consumption of conventional oil, shale oil is known as a new growth point in oil production capacity. However, medium–low mature shale oil needs to be exploited after in situ conversion due to the higher viscosity of oil and the lower permeability of shale. This paper summarizes previous studies on the process of kerogen cracking to generate oil and gas, and the development of micropore structures and fractures in organic-rich shale formations during in situ conversion. The results show that the temperature of kerogen cracking to generate oil and gas is generally 300–450 °C during the oil shale in situ conversion process (ICP). In addition, a large number of microscale pores and fractures are formed in oil shale formation, which forms a connecting channel and improves the permeability of the oil shale formation. In addition, the principles and the latest technical scheme of ICP, namely, conduction heating, convection heating, reaction-heat heating, and radiation heating, are introduced in detail. Meanwhile, this paper discusses the influence of the heating mode, formation conditions, the distribution pattern of wells, and catalysts on the energy consumption of ICP technology in the process of oil shale in situ conversion. Lastly, a fine description of the hydrocarbon generation process of the target formation, the development of new and efficient catalysts, and the support of carbon capture and storage in depleted organic-rich shale formations after in situ conversion are important for improving the future engineering efficiency of ICP. Full article

As an unconventional oil and gas reservoir, the diagenesis and evolution of continental shale controls the formation and occurrence of inorganic and organic pores. In order to quantitatively characterize the pore characteristics of a continental shale reservoir and their influence on the evolution of the diagenesis stage, the characteristics of organic and inorganic pore types of continental shale in the Da’anzhai section of the lower Jurassic Ziliujing Formation were identified by means of X-ray diffraction mineral composition analysis and argon ion polishing scanning electron microscope measurements and observations, and the influence control of the diagenesis stage on the pore development of the continental shale reservoir and its control were clarified. The results show the following: ① The organic matter pores in continental shale are developed in large quantities, including organic matter pores in the mineral asphalt matrix and organic matter pores in the kerogen; the pore types of inorganic minerals are very rich, the main pore types are linear pores between clay minerals, intergranular (intergranular) pores, and intragranular corrosion pores, and microcracks are also developed. ② When affected by compaction diagenesis, the inorganic pores of continental shale decrease with an increase in the burial depth and diagenesis degree. ③ The burial depth of continental shale is 2000–3000 m in the middle of diagenetic stage A, and a large number of organic matter pores and dissolved inorganic pores develop at this depth, meaning that the total porosity of shale increases significantly. The burial depth of continental shale is 3000–4000 m at diagenetic stage B, where kaolinite and other clay minerals are dehydrated and converted into illite, the brittleness of shale is increased, and the interior of the shale is subject to external stress, causing microcracks to form. In the late diagenetic stage, when the buried depth of the continental shale is more than 4000 m, the organic matter is subject to secondary cracking and hydrocarbon generation, the organic pores of shale increase in number again, and the inorganic pores decrease in number due to compaction. In conclusion, we found that the burial depth is the main control factor for the development of pores and microfractures in continental shale reservoirs; diagenesis caused by burial depth is the main factor affecting the development of pores and microfractures in continental shale reservoirs; and the shale burial depth in this case is more than 3500 m, which is in the middle of diagenetic stage B. Inorganic porosity in shale is reduced, and the number of microfractures is increased. When the shale is buried more than 4000 m deep in the late diagenetic stage, the thermal evolution of organic matter in shale is high, and methane gas is generated in large quantities, which is conducive to the formation and development of organic matter pores in continental shale. Full article

Affected by the complex mechanism of organic–inorganic interactions, the generation–retention–expulsion model of mixed siliciclastic–carbonate sediments is more complicated than that of common siliciclastic and carbonate shale deposited in lacustrine and marine environments. In this study, mixed siliciclastic–carbonate shale from Lucaogou Formation in Junggar Basin was selected for semi–closed hydrous pyrolysis experiments, and seven experiments were conducted from room temperature to 300, 325, 350, 375, 400, 450, and 500 °C, respectively. The quantities and chemical composition of oil, gases, and bitumen were comprehensively analyzed. The results show that the hydrocarbon generation stage of shale in Lucaogou Formation can be divided into kerogen cracking stage (300–350 °C), peak oil generation stage (350–400 °C), wet gas generation stage (400–450 °C), and gas secondary cracking stage (450–500 °C). The liquid hydrocarbon yield (oil + bitumen) reached the peak of 720.42 mg/g TOC at 400 °C. The saturate, aromatic, resin, and asphaltine percentages of bitumen were similar to those of crude oil collected from Lucaogou Formation, indicating that semi–closed pyrolysis could stimulate the natural hydrocarbon generation process. Lucaogou shale does not strictly follow the “sequential” reaction model of kerogen, which is described as kerogen firstly generating the intermediate products of heavy hydrocarbon compounds (NSOs) and NSOs then cracking to generate oil and gas. Indeed, the results of this study show that the generation of oil and gas was synchronous with that of NSOs and followed the “alternate pathway” mechanism during the initial pyrolysis stage. The hydrocarbon expulsion efficiency sharply increased from an average of 27% to 97% at 450 °C, meaning that the shale retained considerable amounts of oil below 450 °C. The producible oil reached the peak yield of 515.45 mg/g TOC at 400 °C and was synchronous with liquid hydrocarbons. Therefore, 400 °C is considered the most suitable temperature for fracturing technology. Full article

Strong overpressure conditions are widely distributed in the deep Longmaxi Formation (Fm) shale reservoirs in the Southern Sichuan Basin, with pressure coefficients ranging from 1.75 to 2.45. Overpressure plays a positive role in the high yield of shale gas, but a detailed study of its generation mechanism, evolution history, and potential impact on pore development is still lacking. This study’s evidence from theoretical analysis and the logging response method indicates that hydrocarbon generation expansion is the main generation mechanism for strong overpressure. Through the combined analysis of basin modeling, inclusions analysis, and numerical simulation, pressure evolution at different stages is quantitatively characterized. The results show that, during the shale’s long-term subsidence process, the shale reservoir’s pressure coefficient increased to 1.40 because of oil generated by kerogen pyrolysis. Then it increased to 1.92 due to gas generated by residual oil cracking. During the late strong uplift process of the shale, temperature decrease, gas escape, and stratum denudation caused the pressure coefficient to first decrease to 1.84 and then increased to 2.04. Comparing pore characteristics under different pressure coefficients indicates that higher pressure coefficients within shale reservoirs contribute to the maintenance of total porosity and the development of organic macropores, but the influence on the morphology of organic pores is negligible. These results will provide the scientific basis for optimizing sweet spots and guiding shale gas exploration in the study area. Full article

The Middle Devonian Marcellus Formation of North America is the most prolific hydrocarbon play in the Appalachian basin, the second largest producer of natural gas in the United States, and one of the most productive gas fields in the world. Regional differences in Marcellus fluid chemistry reflect variations in thermal maturity, migration, and hydrocarbon alteration. These differences define specific wet gas/condensate and dry gas production in the basin. Marcellus gases co-produced with condensate in southwest Pennsylvania and northwest West Virginia are mixtures of residual primary-associated gases generated in the late oil window and postmature secondary hydrocarbons generated from oil cracking in the wet gas window. Correlation of API gravity and C₇ expulsion temperatures, high heptane and isoheptane ratios, and the gas geochemical data confirm that the Marcellus condensates formed through oil cracking. Respective low toluene/nC₇ and high nC₇/methylcyclohexane ratios indicate selective depletion of low-boiling point aromatics and cyclic light saturates in all samples, suggesting that water washing and gas stripping altered the fluids. These alterations may be related to deep migration of hot basinal brines. Dry Marcellus gases produced in northeast Pennsylvania and northcentral West Virginia are mixtures of overmature methane largely cracked from refractory kerogen and ethane and propane cracked from light oil and wet gas. Carbon and hydrogen isotope distributions are interpreted to indicate (1) mixing of hydrocarbons of different thermal maturities, (2) high temperature Rayleigh fractionation of wet gas during redox reactions with transition metals and formation water, (3) isotope exchange between methane and water, and, possibly, (4) thermodynamic equilibrium conditions within the reservoirs. Evidence for thermodynamic equilibrium in the dry gases includes measured molecular proportions (C₁/(C₁ − C₅) = 0.96 to 0.985) and δ¹³C₁ values significantly greater than δ¹³C_KEROGEN. Noble gas systematics support the interpretation of hydrocarbon–formation water interactions, constrain the high thermal maturity of the hydrocarbon fluids, and provide a method of quantifying gas retention versus expulsion in the reservoirs. Full article

Geochemical studies of gases from low-permeability reservoirs have raised new questions regarding the chemical and stable isotope systematics of gas hydrocarbons. For instance, the possibility of thermodynamic equilibrium is recurrently in discussion. However, it is not clear whether there is anything “unconventional” in the way these systems continue to be studied. Using molecular and stable carbon isotope data from North American unconventional and conventional reservoirs, this research has applied two parameters that well describe key transformation stages during gas generation. The δ¹³C of ethane and the C₂/C₃ ratio increase from baseline values (<1%Ro, prominent kerogen cracking) until a first inflexion at 1.5%Ro. The same inflexion leads to ¹³C depletion of ethane and a rapidly increasing C₂/C₃ ratio as hydrocarbon cracking becomes prominent. The transition between these two stages is proposed to be a crossover from equilibrium to non-equilibrium conditions. There is no evidence for these characteristics to be limited to low-permeability reservoirs. Unconventional gas geochemistry should represent an approach that acknowledges that chemical and isotope distributions are not ruled by only one mechanism but several and at specific intervals of the thermal history. Full article