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This study integrated palynological, geochemical, and petrophysical analysis that maybe used to analyze petroleum rocks. Shales and sediments rich in carbonate are essential in assessing the geological history of source rocks for the generation of petroleum. This emphasizes the important role of carbonate source rocks on a global level. This study evaluated the source and reservoir rocks of Meyal oilfield, Potwar Basin. Twenty-five well cutting samples from two wells and four fresh outcrop samples were studied. Results of TOC and Rock-Eval of Sakesar Formation samples showed fair to good TOC, Patala Formation in well had very good TOC contents in well both wells. S2 values of both formations' samples showed fair to good generative potential. Both formations lie in the maturity window having primarily mixed Type II/III and Type III kerogen with good oil/gas-generation potential. Palynological analysis also shows Type III kerogen in productive oil/gas window and in good agreement with pyrolysis data. Three forms of kerogen assemblages were identified: Structured and Bio-structured phytoclasts, opaque phytoclasts, and AOM. Petrophysical analysis of Chorgali formation showed average porosity ∼12.01%, average water saturation ∼37.71%, and average hydrocarbon saturation ∼62.28%, indicating average to good reservoir potential. Findings of this research will help and guide exploration and production companies. [ABSTRACT FROM AUTHOR]

Basin modeling and thermal maturity estimation are crucial for understanding sedimentary basin evolution and hydrocarbon potential. Assessing thermal maturity in the oil and gas industry is vital during exploration. With artificial intelligence advancements, more accurate evaluation of hydrocarbon source rocks and efficient thermal maturity estimation are possible. This study employed 1D basin modeling using PetroMod and a novel hybrid group method of data handling (GMDH) neural network optimized by a differential evolution (DE) algorithm to estimate thermal maturity (Tmax) and assess kerogen type in Triassic–Jurassic source rocks of the Mandawa Basin, Tanzania. The GMDH–DE addresses the limitations of conventional methods by offering a data-driven approach that reduces computational time, overcomes overfitting, and improves accuracy. The 1D thermal maturity basin modeling suggests that the Mbuo source rocks reached the gas–oil window in late Triassic times and began expulsion in the early Jurassic while located in an immature-to-mature zone. The GMDH–DE model effectively estimated Tmax with high coefficient of determination (R2 = 0.9946), low root mean square error (RMSE = 0.004), and mean absolute error (MAE = 0.006) during training. When tested on unseen data, the GMDH–DE model yielded an R2 of 0.9703, RMSE of 0.017, and MAE of 0.025. Moreover, GMDH–DE reduced the computational time by 94% during training and 87% during testing. The results demonstrated the model's exceptional reliability compared to the benchmark methods such as artificial neural network–particle swarm optimization and principal component analysis coupled with artificial neural network. The GMDH–DE Tmax model offers a unique and independent approach for rapid real-time determination of Tmax values in organic matter, promoting efficient resource assessment in oil and gas exploration. [ABSTRACT FROM AUTHOR]

Understanding source rocks' organic content and thermal maturity is crucial in assessing their hydrocarbon potential. To address this, our study focused on developing an accurate artificial neural network (ANN) model for estimating total organic carbon (TOC) content and a complete set of pyrolysis parameters from conventional well logs. The accuracy of the ANN-based technique in estimating TOC content was found to be significantly higher (correlation coefficient of 0.95) compared to the results obtained using Passey's method (correlation coefficient of 0.44). Additionally, the ANN model provided highly accurate predictions for the pyrolysis parameters S1, S2, S3, and Tmax, with correlation coefficients of 0.85, 0.90, 0.86, and 0.93, respectively. The study focused on the Abu Gabra Formation in the Hamra field, and the ANN data analysis revealed that the source rock in this area is of fair to good quality. The assessment of kerogen type indicated a mixed kerogen type II and type III, suggesting the potentiality for oil and gas generation. The predicted parameters further confirmed that the Abu Gabra source rock is thermally mature and capable of generating indigenous hydrocarbons. The results of the ANN-based modeling were consistent with laboratory measurements, demonstrating the reliability of the predictions for comprehensive source rock evaluation using well logs. [ABSTRACT FROM AUTHOR]

The adsorption behaviors of methane(CH 4), hydrogen(H 2), and their mixtures are crucial for estimating the underground hydrogen storage(UHS) capacity in depleted shale gas reservoirs. In this study, we developed four formulated kerogen models, each representing different maturation levels of type II kerogen molecules via utilizing molecular dynamics (MD) methodologies. We investigated the adsorption characteristics of pure H 2 and mixed gases(H 2 and CH 4) on these kerogen models with varying gas components(0.5:0.5 to 0.9:0.1) and moisture content(0–3.0 wt percentage) through grand canonical Monte Carlo(GCMC) simulations. Our findings reveal that pure H 2 lacks a pressure point for adsorption equilibrium below 100 MPa at ambient temperature(298K). The competitive adsorption dynamics between H 2 and CH 4 on kerogen models demonstrate that CH 4 exhibits stronger selectivity at lower pressures. Yet, this selectivity diminishes compared to H 2 as system pressure increases, indicating turning points in pressure buildup with kerogen maturity. Additionally, the presence of pre-loading H 2 O molecules reduces the adsorption capacity of mixed gases, particularly affecting CH 4 more than H 2. This study offers profound insights into the effect of kerogen maturity and moisture content on the interaction between H 2 /CH 4 and kerogen at a microscopic scale. • Hydrogen adsorption fits the Langmuir model poorly. • Methane and hydrogen have the same preferred adsorption sites. • Hydrogen can become a more selective adsorbent in high-pressure conditions. • Water reduces hydrogen adsorption non-significantly compared with methane. • Hydrogen-accessible volume resists water harm on adsorption. [ABSTRACT FROM AUTHOR]

Low-maturity shale oil predominates in shale oil resources. China's onshore shale oil, particularly the Cretaceous Nenjiang Formation in the Songliao Basin, holds significant potential for low-maturity shale oil, presenting promising exploration and development prospects. This study delves into the hydrocarbon generation conditions, reservoir characteristics, and oil-bearing property analysis of the mud shale from the Nen-1 and Nen-2 sub-formations of the Nenjiang Formation to pinpoint favorable intervals for shale oil exploration. Through the integration of lithology, pressure, and fracture distribution data in the study area, favorable zones were delineated. The Nen-1 sub-formation is widely distributed in the Changling Depression, with mud shale thickness ranging from 30 to 100 m and a total organic content exceeding 2.0%. Type I kerogen predominated as the source rock, while some samples contained type II kerogen. Organic microcomponents primarily comprised algal bodies, with vitrinite reflectance (Ro) ranging from 0.5% to 0.8%. Compared to Nen-1 shale, Nen-2 shale exhibited less total organic content, kerogen type, and thermal evolution degree, albeit both are conducive to low-maturity shale oil generation. The Nen-1 and Nen-2 sub-formations predominantly consist of clay, quartz, feldspar, calcite, and pyrite minerals, with minor dolomite, siderite, and anhydrite. Hydrocarbons primarily reside in microfractures and micropores, including interlayer micropores, organic matter micropores, intra-cuticle micropores, and intercrystalline microporosity, with interlayer and intra-cuticle micropores being dominant. The free oil content (S1) in Nen-1 shale ranged from 0.01 mg/g to 5.04 mg/g (average: 1.13 mg/g), while in Nen-2 shale, it ranged from 0.01 mg/g to 3.28 mg/g (average: 0.75 mg/g). The Nen-1 and Nen-2 sub-formations are identified as potential intervals for shale oil exploration. Considering total organic content, oil saturation, vitrinite reflectance, and shale formation thickness in the study area, the favorable zone for low-maturity shale oil generation is primarily situated in the Heidimiao Sub-Depression and its vicinity. The Nen-2 shale-oil-enriched zone is concentrated in the northwest part of the Heidimiao Sub-Depression, while the Nen-1 shale-oil-enriched zone lies in the northeast part. [ABSTRACT FROM AUTHOR]

The present study focused on the Permian to Jurassic sequence in the Northern Highlands area, NW Jordan. The Permian to Jurassic sequence in this area is thick and deeply buried, consisting mainly of carbonate intercalated with clastic shale. This study integrated various datasets, including total organic carbon (TOC, wt%), Rock-Eval pyrolysis, visual kerogen examination, gross composition, lipid biomarkers, vitrinite reflectance (VRo%), and bottom-hole temperature measurements. The main aim was to investigate the source rock characteristics of these strata regarding organic richness, kerogen type, depositional setting, thermal maturity, and hydrocarbon generation timing. The Permian strata are poor to fair source rocks, primarily containing kerogen type (KT) III. They are immature in the AJ-1 well and over-mature in the NH-2 well. The Upper Triassic strata are poor source rocks in the NH-1 well and fair to marginally good source rocks in the NH-2 well, containing highly mature terrestrial KT III. These strata are immature to early mature in the AJ-1 well and at the peak oil window stage in the NH-2 well. The Jurassic strata are poor source rocks, dominated by KT III and KT II-III. They are immature to early mature in the AJ-1 well and have reached the oil window in the NH-2 well. Biomarker-related ratios indicate that the Upper Triassic oils and Jurassic samples are source rocks that received mainly terrestrial organic input accumulated in shallow marine environments under highly reducing conditions. These strata are composed mostly of clay-rich lithologies with evidence of deposition in hypersaline and/or stratified water columns. 1D basin models revealed that the Upper Triassic strata reached the peak oil window from the Early Cretaceous (~80 Ma) to the present day in the NH-1 well and from ~130 Ma (Early Cretaceous) to ~90 Ma (Late Cretaceous) in the NH-2 well, with the late stage of hydrocarbon generation continuing from ~90 Ma to the present time. The present-day transformation ratio equals 77% in the Upper Triassic source rocks, suggesting that these rocks have expelled substantial volumes of hydrocarbons in the NH-2 well. To achieve future successful hydrocarbon discoveries in NW Jordan, accurate seismic studies and further geochemical analyses are recommended to precisely define the migration pathways. [ABSTRACT FROM AUTHOR]

This study successfully applied reactive force field (ReaxFF) molecular dynamic simulations to study the two-stage transformation of kerogen: initially transforming into pyrolytic bitumen and then into final products. It was found that the carbonâoxygen bond in the kerogen skeleton chain breaks first, while further transformation involves significant carbonâcarbon bond breakage. Specifically, carbonâcarbon bond breakage contributes almost 66.7% to pyrolytic bitumen formation, and nearly 80% to the final product formation. In addition, higher heating rates favor higher bond rupture speed and lead to a decline in heteroatoms within shale oil. In summary, this work provides more atomic insights of oil shale kerogen decomposition.

In the engineering of oil shale, in situ extraction technology using electric heating involves heating the oil shale reservoir with an electric heater at high temperatures to convert the solid kerogen in oil shale into liquid hydrocarbons. These liquid hydrocarbons are then extracted from underground using traditional oil and gas drilling and production techniques. This paper discusses the pyrolysis mechanism, pore evolution, mineral transformation, and classification of electric heating technology for oil shale. It also summarizes research progress aimed at improving in situ extraction technology for oil shale, providing valuable insights for further research and development in this field.

The paper presents the results of the study of rock samples from Bazhenov deposits before and after laboratory modelling of hydrothermal processes in autoclaves. To evaluate the influence of hydrothermal influence on rocks of different degrees of transformation, 3 samples from the well, the rocks in which are located at the very beginning of the main zone of oil formation (PK3–MK1), and 4 samples from the well, the rocks in which are located in the middle of generation (MK2–MK3) were studied. Comparison of samples before and after heating was carried out by means of pyrolytic, coal petrography studies and analyses of polished section under scanning electron microscope. It is shown that at 350 °C there is a change in pyrolytic characteristics of the rock, which depends on the nature of organic matter and the degree of catagenetic transformation of kerogen at the time of exposure. It was found that as a result of exposure the initial macerals decrease in size and change their luminescence in ultraviolet light, secondary (kerogenic) porosity appears in onychite fragments. New minerals, in particular barium zeolites, are formed in the rocks. Identification of such formations in natural objects may indicate the occurrence of local temperature processes, which may lead to heterogeneity of organic matter transformation in Bazhenov sediments and should be taken into account to identify local zones of increased catagenesis.

Talchir Basin forms the southeastern end of the Gondwanan Son–Mahanadi Master Basin of India and hosts extensive sedimentary successions of coals and shales of Early Permian to Upper Triassic ages. Significant coal-bearing formations in the basin include the Barakar and Karharbari. This study intends to characterize the properties of kerogen in carbonaceous shales and coals of the Barakar and Karharbari Formation of Talchir coalfield in the Talchir Basin of Odisha, Eastern India, along with their kerogen degradation kinetics, to infer the hydrocarbon generation potential. The samples form part of formations exposed in the Kaniah and Nandijhar regions of Angul in the state of Odisha, Eastern India. The total organic carbon (TOC) content of carbonaceous and silty shales from Kaniah ranges between 1.9 to 9.6 wt.% and 1.1 to 7.2 wt.%, respectively, whereas that of coals ranges between 16.6 and 46.9 wt.%. The pyrolysis Tmax lies between 417° and 530°C. Organic matter is characterized by Type III, thermally immature to early mature kerogen. Kerogen decomposition kinetics indicates wide activation energy distribution, while its transformation and hydrocarbon generation occur at lower temperatures with faster rates. Compared to Karharbari, the organically rich and thermally mature shales of Barakar exhibit promising potential for natural gas generation. Research highlights: Kerogen properties and thermal decomposition kinetics of Permian Shales, Talchir Basin, Eastern India. High TOC content (1.9–46.9 wt.%); however, low thermal maturity in immature to early oil window. Kerogen transformation and hydrocarbon generation occur at lower temperatures with faster rates. Suitable for facile conversion into hydrocarbon products using artificial processes. [ABSTRACT FROM AUTHOR]

Kerogen has a lower affinity to hydrogen than methane; thus, it allows hydrogen to flow more easily, but it is unclear how the permeabilities of hydrogen and methane differ. This study determines the single-phase permeability of hydrogen and compares it with methane permeability in organic-rich caprock. It takes into account adsorption to the pore wall and slippage at the boundary. It implements the two processes at 370 K for pressures from 500 to 4000 psi to obtain the hydraulic conductance of a sub-100-nm conduit. It then relates them to the macroscopic behavior via network modeling. Lower pressures represent depleted gas reservoirs in the subsurface. Decreasing pore pressure enhances hydrogen transport by reducing its adsorption to the pore wall and transitioning its behavior from continuum to discrete particles, leading to first- or second-order slippage. The results show that hydrogen conductance, q i n − s i t u (H 2), is always larger than the reference conductance without adsorption and slippage (q 0). Hydrogen permeability, k i n − s i t u (H 2), is also larger than methane permeability, k i n − s i t u (CH 4), while the permeability values differ by 70% − 130%, depending on the pore pressure. This study also determines the conduit size corresponding to the ratio of hydrogen permeability to methane permeability at in-situ conditions by comparing it with the ratio of hydraulic conductance of hydrogen to methane. The results have applications in underground hydrogen storage by indicating how hydrogen flow changes with pressure in ultra-tight formations. [Display omitted] • This study investigates H 2 permeability in organic-rich caprock in the subsurface. • It quantifies the effects of adsorption and slippage for H 2 in the nanosize conduit. • Slippage dominates H 2 flow, and the effects of adsorption are negligible. • H 2 conductance is higher than CH 4 conductance because H 2 adsorbs less to kerogen and slips more. • H 2 permeability is almost twice the CH 4 permeability in the organic-rich caprock. [ABSTRACT FROM AUTHOR]

This study provides an updated quantitative analysis and prospective paleoenvironment reconstruction of the Tut oilfield, Shushan Basin, North Egypt to evaluate the hydrocarbon reservoirs in space and times for further development plans and modeling in the Tethyan region. Two sporomorph interval zones (Classopollis brasiliensis and Afropollis jardinus), and one total foraminiferal Range Zone (Thomasinella punica) are proposed. Three palynofacies assemblages are differentiated using cluster analysis of the different palynofacies parameters. The paleoenvironmental conditions during the Cenomanian were reconstructed. Palynofacies assemblage I of the Baharyia Formation suggests a marginally dysoxic-oxic basin environment with a common occurrence of ostracods and terrestrial organic matter, while palynofacies assemblage II reflects the high abundance of dinoflagellate cysts, suggesting a suboxic-anoxic middle neritic environment. Palynofacies assemblage III of the upper part of the Abu Roash G Member represents a relatively deep water inner-middle neritic environment. Three 3rd order significant sequences separated by two hiatus surfaces (Ce3 and Ce4) are described and correlated with the global eustatic sea-level. The hydrocarbon evaluation results show that the samples from the Abu Roash G Member contain oil-prone material of kerogen type II, while the samples of the Baharyia Formation are characterized by kerogen type III (gas-prone). Spore coloration analysis reveals that the samples from the studied units are too immature to produce gas or oil and are ineffective as sources of hydrocarbons. [ABSTRACT FROM AUTHOR]

The exploration level of tight sandstone gas reservoirs in the Denglouku Formation (DF) in the Xujiaweizi Fault Depression is low, and hydrocarbon source and accumulation process remain unclear. Through the analysis of natural gas geochemistry, X-ray diffraction, thin section observation, scanning electron microscope, physical property testing, cathodoluminescence, fluid inclusions, and basin simulation, we examine source of hydrocarbon, the period of hydrocarbon accumulation, and the evolution of physical properties of the tight sandstone gas in the DF. Additionally, the formation process of tight sandstone gas reservoirs in the DF is discussed. The results reveal the following: (1) the tight sandstone gas in the DF is categorized as III kerogen cracking gas, primarily sourced from dark mudstone of the second member of the DF, with some contribution from dark mudstone of the Shahezi Formation. (2) The tight sandstone in the DF is in stage B of middle diagenesis. Based on apparent compaction rate, apparent cementation rate, and apparent dissolution rate, it can be divided into four diagenetic facies: (1) strong compaction–medium cementation–weak dissolution facies; (2) medium compaction–strong cementation–medium dissolution facies; (3) medium compaction–strong cementation–weak dissolution facies; and (4) medium compaction–medium cementation–medium dissolution facies. The predominant diagenetic facies are the medium compaction–strong cementation–medium dissolution facies and medium compaction–medium cementation–medium dissolution facies. (3) The hydrocarbon charging period of the DF in study area ranged from 98 to 67.5 Ma. This period is earlier than the tight period of the strong compaction–medium cementation–weak dissolution facies sandstone and later than the tight period of the medium compaction–strong cementation–medium dissolution facies, medium compaction–strong cementation–weak dissolution facies, and medium compaction–medium cementation–medium dissolution facies sandstone. Consequently, two types of tight sandstone gas reservoirs exist in study area: (1) tight sandstone gas reservoir with tight first and then accumulation type and (2) composite tight sandstone gas reservoirs. Our research offers theoretical instruction for exploration of deep tight sandstone gas in northern Songliao Basin. [ABSTRACT FROM AUTHOR]

The shale of different potential layers is studied by using rock pyrolysis analysis, total organic carbon determination (TOC), kerogen microscopic component identification, mineral X-ray diffraction, scanning electron microscopy, and low-temperature nitrogen adsorption experiments. The results are as follows: (1) Shishui Formation of the Lower Carboniferous and Longtan Formation of the Upper Permian are the two most important shale gas reservoirs in the Chenlei Depression. The sedimentary environment of the target shale is a marine land interaction facies coastal bay lagoon swamp sedimentary system. Two sedimentary facies of tidal flat facies, subtidal zone, and lagoon swamp facies are developed. (2) The organic matter types of shale are Type III and II2, with TOC content greater than 1%. The maturity of shale samples is relatively higher (Ro,max is above 2%), which means they have entered the stage of large-scale gas generation. The overall brittle mineral content of the target shale sample is relatively higher (above 40%), which is conducive to artificial fracturing and fracture formation in the later stage, while an appropriate amount of clay minerals (generally stable at 40%) is conducive to gas adsorption. (3) The overall pore structure of the water measurement group and Longtan group is good, with a higher specific surface area and total pore volume (average specific surface area is 12.21 and 8.36 m2/g, respectively), which is conducive to the occurrence of shale gas and has good adsorption and storage potential. The gas content of the water measurement group and the Longtan Formation varies from 0.42 to 5 cm3/g, with an average of 2.1 cm3/g. It indicates that the water measurement group and the Longtan Formation shale gas in the study area have good resource potential. [ABSTRACT FROM AUTHOR]

A palynological study of 84 cutting samples from Cape Three Points 1 (CTP-1) well in the Tano basin allows the identification of three biozones based on the First Appearance Datum (FAD) and Last Appearance Datum (LAD) of stratigraphically significant sporomorphs taxa recovery. These are Elateropollenites jardinei - Reyrea polymorphus Zone, Elaterocolpites castelainii - Afropollis jardinus Zone, and Cretacaeiporites polygonalis - Classopollis classoides Zone, which permit an age assignment of early - middle Albian, late Albian - early Cenomanian and late Cenomanian respectively. The diagnostic miospores from the samples are characteristic of the Albian-Cenomanian Elaterate paleofloral Province in a semi-arid to arid climate, with sediments yielding mixed kerogen assemblage which reflects a marginal marine or nearshore environment. Four palynofacies assemblages (P-1 to P-4) and kerogen types identified indicate deposition under marginal dysoxic-anoxic basin (kerogen type III), shelf to basin transition (kerogen type III/II), a distal suboxic-anoxic basin (kerogen type II>I) and distal dysoxic-anoxic shelf (kerogen type II) conditions respectively. Thermal maturity values obtained from colour changes of psilate spore (Deltoidspora, Cyathidites) reveal that samples from P-1 and P-2 are within immature phase and P-3 and P-4 are mature. [ABSTRACT FROM AUTHOR]

Understanding the origins of potential source rocks and unraveling the intricate connections between reservoir oils and their source formations in the Siwa Basin (Western Desert, Egypt) necessitate a thorough oil-source correlation investigation. This objective is achieved through a meticulous analysis of well-log responses, Rock-Eval pyrolysis, and biomarker data. The analysis of Total Organic Carbon across 31 samples representing Paleozoic formations in the Siwa A-1X well reveals a spectrum of organic richness ranging from 0.17 wt% to 2.04 wt%, thereby highlighting diverse levels of organic content and the presence of both Type II and Type III kerogen. Examination of the fingerprint characteristics of eight samples from the well suggests that the Dhiffah Formation comprises a blend of terrestrial and marine organic matter. Notably, a significant contribution from more oxidized residual organic matter and gasprone Type III kerogen is observed. Contrarily, the Desouky and Zeitoun formations exhibit mixed organic matter indicative of a transitional environment, and thus featuring a pronounced marine influence within a more reducing setting, which is associated with Type II kerogen. Through analysis of five oil samples from different wellsdSIWA L-1X, SIWA R-3X, SIWA D-1X, PTAH 5X, and PTAH 6X, it is evident that terrestrial organic matter, augmented by considerable marine input, was deposited in an oxidizing environment, and contains Type III kerogen. Geochemical scrutiny confirms the coexistence of mixed terrestrial organic matter within varying redox environments. Noteworthy is the uniformity of identified kerogen Types II and III across all samples, known to have potential for hydrocarbon generation. The discovery presented in this paper unveils captivating prospects concerning the genesis of oil in the Jurassic Safa reservoir, suggesting potential links to Paleozoic sources or even originating from the Safa Member itself. These revelations mark a substantial advancement in understanding source rock dynamics and their intricate relationship with reservoir oils within the Siwa Basin. By illuminating the processes of hydrocarbon genesis in the region, this study significantly enriches our knowledge base. [ABSTRACT FROM AUTHOR]

Geochemical analysis was performed on the Cretaceous sequence of the Azhar‐A‐2 well in the West Beni Suef Basin (WBSB), Western Desert, Egypt, utilizing data on total organic carbon (TOC), kerogen composition, vitrinite reflectance (Ro%) and Rock‐Eval pyrolysis. In addition, a 1D basin model was built to investigate the burial and temperature history of the study area. The most important Cretaceous source rocks are predominantly reported within the Albian Kharita Formation and Late Cenomanian‐Santonian Abu Roash (AR) Formation. Based on visual kerogen tests and Rock‐Eval pyrolysis, AR Formation (A, E, F, and G) are mixed oil‐ and gas‐prone source rocks with kerogens ranging from type II to type III, where A/R 'A and F' Members show dominant oil‐prone kerogen with the highest generative potential, while A/R 'E and G' Members are more gas‐prone kerogen. Most samples of the lower Kh Formation were interpreted as gas‐prone kerogen type III with low generative potential. On the other hand, the high amount of liptinite in the visual kerogen macerals is a strong indicator that the lower Petroleum Formation is an oil‐prone rather than gas‐prone source rock. The thermal maturity of the studied members increases consistently with depth, ranging from immature at the top of the AR Formation to the main/peak oil window at the base of the Lower Kharita Formation, which served as an active source rock for the hydrocarbons generated in the WBSB. The high value of the heat flow in the Beni Suef Basin (57 and 60 mW/m2) is a good indicator for the shallowing of the active source rock depth limit depth. From the study of the basin modeling, the main mature zone reached between 9811 and 11,090 ft in the middle of the Late Cretaceous (84.3–82.5 Ma) is through the L. Kharita Formation with three phases of hydrocarbon generation according to transformation ratio, where the second phase is the main stage in which TR is 5%–50%, showing the beginning of oil expulsion (Ro: 0.73%–0.78%, possibly 0.81%). [ABSTRACT FROM AUTHOR]

Investigating the adsorption and diffusion processes of shale gas within the nanopores of kerogen is essential for comprehending the presence of shale gas in organic matter of shale. In this study, an organic nanoporous structure was constructed based on the unit structure of Longmaxi shale kerogen. Grand canonical Monte Carlo and molecular dynamics simulation methods were employed to explore the adsorption and diffusion mechanisms of pure CH4, CO2, and N2, as well as their binary mixtures with varying mole fractions. The results revealed that the physical adsorption characteristics of CH4, CO2, and N2 gases on kerogen adhered to the Langmuir adsorption law. The quantity of adsorbed gas molecules increased with rising pressure but decreased with increasing temperature. The variation in the heat of adsorption was also analyzed. Under identical temperature and pressure conditions, the adsorption of CH4 increased with higher mole fractions of CH4, whereas it decreased with greater mole fractions of CO2 and N2. Notably, CO2 molecules exhibited a robust interaction with kerogen molecules compared to the adsorption properties of CH4 and N2. Furthermore, the self-diffusion coefficient of gas within kerogen nanopores gradually decreased with increasing pressure or decreasing temperature. The diffusion capacity of gas molecules followed the descending order N2 > CH4 > CO2 under the same pressure and temperature conditions. [ABSTRACT FROM AUTHOR]

Despite the significant discovery of hydrocarbon in the Cretaceous Deep-Water Tano Basin of Ghana, detailed molecular characteristics and paleo-depositional environment of the Basin are insufficiently documented in peer-reviewed works. Therefore, in our study, gas chromatography-mass spectrometric (GC-MS) and gas chromatographic (GC) analyses were used to characterize biomarkers obtained from organic matter (oils and rock extracts) to determine the organic matter source, the environment of deposition, and maturity. Sixteen (16) oil and ninety-eight (98) rock samples from seven wells were studied. The work has indicated that distributions of these biomarkers suggested that Cretaceous oils were derived from a mixed kerogen source (marine and terrestrial) deposited in anoxic to suboxic paleo depositional conditions. CPI, Ts/Tm and C29 ββ/(ββ + αα) sterane ratios plotted against C29 20S/(20S + 20R) sterane ratios indicates that the studied samples are relatively low to medium level maturity. [ABSTRACT FROM AUTHOR]

This study predicts favorable oil and gas source-rock formation conditions in the Aryskum Depression of the South Turgay Basin, Kazakhstan. This study assesses the thermal maturity and characteristics of organic matter by determining its environmental conditions using data from geochemical analysis of core (pyrolysis) and oil (biomarkers and carbon isotopic compositions) samples. According to the geochemical parameters obtained by pyrolysis, the oil generation potential of the original rocks of most studied samples varies from poor to rich. The facies–genetic organic matter is predominantly humic and less frequently humus–sapropel, indicating organic matter accumulation in the studied samples were under moderately reducing conditions (kerogen III and II types) and coastal–marine environments (kerogen type I). The carbon isotopic compositions of oils derived from the Jurassic deposits of the Aryskum Depression also indicate the sapropelic and mixed humic–sapropelic type of organic matter (kerogen II and I). Biomarker analysis of oils indicates original organic matter formation in an anoxic environment. [ABSTRACT FROM AUTHOR]

Two hundred and fifty single first-order Arrhenius reactions are simulated to generate S2 pyrograms at three heating rates 25, 15, and 5 °C·min−1. The activation energy (E) and pre-exponential factor (A) of the reactions simulated follow a long-established trend of those variable values displayed by shales and kerogens. The characteristics of the transformation fraction (TF) profiles (product generation window temperatures) of the simulated single reactions are compared to the TF profiles of recorded shale pyrograms generated by multiple reactions with different E-A values lying near the defined E-A trend. Important similarities and differences are observed between the TF profile values of the two datasets. The similarities support the spread of E-A values involved in shale pyrogram best fits. The differences are most likely explained by the complexity of the multiple kerogen first-order and second-order reactions contributing to the recorded shale pyrograms versus the simplicity and crispness of the single first-order reactions simulated. The results also justify the validity of using the previously described "variable E-A pyrogram-fitting method" of multi-heating-rate shale pyrograms enabling optimizers to choose multiple reactions from an unlimited range of E-A values. In contrast, further doubt is cast on the validity of the constant-A pyrogram-fitting method used by the Easy%Ro technique, in that a distribution of reactions with a single A value is unlikely to represent the complex variety of kerogen macerals observed in shale formations. TF profiles generated by the variable E-A pyrogram-fitting method lie close to the established E-A trend and are likely to provide more realistic TF generation window temperatures than TF profiles generated by the constant-A pyrogram-fitting method. [ABSTRACT FROM AUTHOR]

In order to study the adsorption process and adsorption characteristics of shale oil at the macro scale, the isothermal adsorption experiments of illite and kerogen on a heptadecane (oil phase) solution were carried out by infrared spectrophotometry and gas chromatography–mass spectrometry. Based on the adsorption isotherm model and adsorption thermodynamic model, the characteristics of heptadecane adsorbed by illite and kerogen at different temperatures and oily solution concentrations were studied. The experimental results show that the concentration and temperature of the alkane solution help to enhance the adsorption and increase the saturated adsorption capacity. The difference is that the concentration will have a certain effect on the adsorption rate, while the temperature will not. Based on the three adsorption isotherm models, it was found that Langmuir and Freundlich were more suitable for describing the adsorption process of the heptadecane solution by illite and kerogen, and the adsorption characteristics of heptadecane molecules at different temperatures and adsorbents were evaluated. Heating leads to an increase in the collision efficiency between adsorbate molecules and adsorbents, thereby accelerating the migration rate of alkanes. Therefore, increasing temperature helps to enhance the adsorption capacity of rocks and increase the saturated adsorption capacity of minerals. The research results clarify the adsorption characteristics of shale oil heavy components from the macro level and fill the research gap in the application of solid–liquid isothermal adsorption physical experiments on the adsorption and occurrence of shale oil. [ABSTRACT FROM AUTHOR]

This article explores the role of fossil organic carbon (FOC) weathering in global biogeochemical cycles. FOC is a unique type of organic carbon that has accumulated and fossilized in the Earth's lithosphere over time. Recent studies have shown that FOC is easily reacted, mobilized, and transformed under surface conditions, releasing CO2 and impacting global biogeochemical cycles. However, there are challenges in understanding FOC weathering, including limited data for calibrating its kinetics and the influence of factors like rock types, tectonic activities, geomorphic processes, and climate. The article suggests that future research should focus on studying FOC weathering in different environments and developing proxies to reconstruct past weathering. It also emphasizes the importance of understanding the connection between FOC weathering and the biogeochemical cycles of other nutrient elements. [Extracted from the article]

The controlling factors of organic-rich shale accumulation is essential for the exploration and development of shale oil and gas resources. The sedimentary environment plays a vital role in the formation of organic-rich sediments in lacustrine facies. This article unravels the mineralogy, geochemistry, and paleoenvironmental evolution during the deposition of the Paleogene Shahejie Formation (Es3 L). It discusses the effects of paleoclimate, paleosalinity, paleoredox conditions, paleowater depth, and paleoproductivity on organic matter (OM) enrichment. Finally, the OM enrichment model was established. The results show that the mineralogical compositions are mainly composed of calcite (avg. 40.13%), quartz (avg. 21.64%) and clay minerals (avg. 24.07%), accompanied by dolomite (avg. 7.07%), feldspar (avg. 6.36%) and pyrite (avg. 2.95%). The Es3 L shale has a high abundance of OM, with total organic carbon (TOC) ranging from 1.07% to 5.12%. The organic matter type is mainly composed of type I-II1 kerogen, which is generally considered a good-quality source rock. The source of OM is a mixture of lower bacteria, algae, and plants. During the early sedimentary period, the paleoclimate was dry and cold, with high salinity, intense reducibility, and relatively low productivity. During the late sedimentary period, the climate became warmer and more humid. As a result, the salinity decreased to a level that was suitable for biological reproduction, and productivity increased gradually due to the input of terrigenous plants. Paleosalinity and paleoclimate determined the environment of the sedimentary period, in addition, paleoproductivity and paleoredox condition indicated the formation and preservation conditions of OM. The warm and humid climate, brackish water, suitable reduction conditions and high productivity are the favorable conditions for the generation and preservation of organic matter. The research results may have implications for the genetic mechanisms of organic matter accumulation. They will provide theoretical and technical insights into the exploration and development of shale oil. [ABSTRACT FROM AUTHOR]

A series of kerogen samples were isolated from Domanik oil shale before and after hydrothermal treatment in an autoclave (at 250–375°C, for 24 h). Than composition of the C1–C5 hydrocarbon gases generated in stepwise (300–800°C) pyrolysis of these kerogens was characterized by gas chromatography. According to the calculated EASY %Ro and Rock-Eval pyrolysis data, the highest maturity level of the organic matter reached by the hydrothermal treatment corresponded to the MC4 stage. As the hydrothermal treatment temperature of the oil shale was elevated up to 325°C, the dry pyrolysis of residual kerogen led to the predominant generation of wet gases in which C2+ prevailed over methane; at temperatures above 325°C, methane was predominant. Based on the pattern of the generation curves plotted individually for C1, C2, C3, C2–C5, and C4–C5 gases, methane was found to have additional sources in the kerogen structure, compared to C2+ gases. Ethane and ethylene are generated simultaneously via the free-radical decomposition of alkyl structures; moreover, at high pyrolysis temperatures, ethane and ethylene have some precursors other than those of C3+ gases. [ABSTRACT FROM AUTHOR]

Under geological conditions, the initial generation of oil and gas in source rocks reaches saturation before being expelled and migrating, with the adsorption of hydrocarbons by kerogen being a key factor influencing oil saturation. The hydrocarbons produced by pyrolysis interact with kerogen macromolecules. Understanding the solvency and adsorption capacities of solid kerogen organic matter for liquid hydrocarbons can clarify the selective retention of hydrocarbons by source rocks and their characteristics in hydrocarbon generation and expulsion. Aromatic hydrocarbons are crucial components of petroleum hydrocarbons. Based on a three-dimensional model of kerogen, this study employed Autodock software to perform semi-flexible docking calculations between different types of aromatic hydrocarbon molecules (including benzene, polycyclic aromatic hydrocarbons, and their derivatives) and kerogen molecules of varying maturities. The Gibbs free energy required for their binding was calculated to study the characte-risticsof the interaction between aromatic hydrocarbons and kerogen. This study investigated the mechanism of kerogen adsorption of aromatic hydrocarbons at the molecular level, revealing the nature of solid and liquid organic matter interactions. When binding with kerogen of the same maturity, the larger the molecular weight of the polycyclic aromatic hydrocarbons, the greater the number of methyl groups in the compound, and the higher the degree of molecular condensation, the lower the Gibbs free energy required for binding with kerogen molecules. The interaction between aromatic hydrocarbons and kerogen molecules was influenced by three factors: the molecular mass of the aromatic hydrocarbons, the degree of molecular condensation, and the number of methyl groups in the system. After reaching the peak of hydrocarbon generation, kerogen with higher content of aromatic carbon methyl groups showed a stronger adsorption capacity for aromatic hydrocarbons. Polycyclic aromatic hydrocarbons and their derivatives with larger molecular mass and higher degrees of condensation demonstrated stronger binding abilities with kerogen. Conversely, smaller aromatic molecules with conventional connectivity exhibited weaker retention capacities in kerogen, making them more prone to hydrocarbon expulsion, migration, and accumulation into reservoirs.

On the basis of an inorganic concept of the petroleum origin, the phase relationships of crystalline kerogens of black shales and liquid oil at the physicochemical conditions of a typical geobarotherm on the Texas Gulf Coast are considered. At the conditions of the carbon dioxide (CO2) high fluid pressure, the process of oil transformation into kerogens of varying degrees of “maturity” (retrograde metamorphism) takes place with decreasing temperature and hydrogen pressure. Kerogen generation in black shale rocks occurs by the sequential transition through metastable equilibria of liquid oil and crystalline kerogens (phase “freezing” of oil). The upward migration of hydrocarbons (HC) of oil fluids, clearly recorded in the processes of oil deposit replenishment in oil fields, shifts the oil ↔ kerogen equilibrium towards the formation of kerogen. In addition, with decreasing of the hydrogen chemical potential as a result of the process of high-temperature carboxylation and low-temperature hydration of oil hydrocarbons, the “mature” and “immature” kerogens are formed, respectively.The phase relationships of crystalline black shale kerogens and liquid oil under hypothetical conditions of high fluid pressure of the HC generated in the regime of geodynamic compression of silicate shells of the Earth in the result of the deep alkaline magmatism development. It is substantiated that a falling of hydrogen pressure in rising HC fluids will lead to the transformation of fluid hydrocarbons into liquid oil, and as the HC fluids rise to the surface, the HC ↔oil ↔ kerogen equilibrium will shift towards the formation of oil and kerogen.It is round that both in the geodynamic regime of compression and in the regime of expansion of the mantle and crust, carboxylation and hydration are the main geochemical pathways for the transformation of oil hydrocarbons into kerogen and, therefore, the most powerful geological mechanism for the black shale formations.

This study introduces results of lithological, petrophysical and geochemical investigation of Lower Cretaceous (K1 ) and Middle Jurassic (J2 a-b) rocks of East Pre-Caucasian basin.According to pyrolytic and bituminological studies method of separate determination of kerogen and bitumen concentration been developed. In accordance with this method differentiation of organic matter components in different lithotypes of rocks been described. Also relationship between bitumen and kerogen concentrations been revealed.The majority of samples have poor to fair organic richness and poor source potential. Kerogen type is commonly presented by type III and stages of maturity characterized by stages PC3 to MC3 . Bitumen compounds have low concentrations of asphaltenes and aromatic hydrocarbons and mainly contains light and heavy resins.Based on petrophysical and geochemical studies a close relationship between the concentration of organic carbon and the weight concentration of potassium nuclides was obtained. This relationship indicates that kerogen in the sediments under consideration is associated with clay minerals, which is also confirmed by the mineral composition of the rocks.

To get properties and characteristics of oil and gas source rocks and for other geological aims, geologists analyzes core samples from wells and outcrop samples. But we should probably somehow correct geochemical source rock properties data we get on outcrop samples, because organic matter could change significantly due to oxidizing and weathering. This problem is very important but poorly developed in modern publications, so it attracted our interest and led to this investigation. Published information on the organic matter weathering which change it’s content and quality in sedimentary rocks is collected and summarized in this article. The changes of the kerogen (isolated from the mineral matrix) elemental composition during its long-term storage are presented.We compared the results we get in laboratory and results of other authors who dealt with natural changes of organic matter in outcrops. An attempt to interpret the results obtained from the point of view of hypergene changes in OM was made. Uncertainties that require further study and development are indicated. This work is the first step to better understanding of weathering effect on organic matter content and properties – question of great importance for making adequate oil and gas prospects estimations.This study continues the work of our foregoers and Teachers – geochemists of the Petroleum Geology Department of Lomonosov Moscow State University: N.B. Vassoevich, Yu.I. Korchagina, O.A. Radchenko, V.A. Uspensky, I.E. Leifman, A.N. Guseva, O.K. Bazhenova, T.A. Kiryukhina.

Different from the Qaidam basin with about 320 billion m3 microbial gas, only limited microbial gases were found from the Junggar basin with similarly abundant type III kerogen. To determine whether microbial gases have not yet identified, natural gas samples from the Carboniferous to Cretaceous in the Junggar basin have been analyzed for chemical and stable isotope compositions. The results reveal some of the gases from the Mahu sag, Zhongguai, Luliang and Wu-Xia areas in the basin may have mixed with microbial gas leading to straight ethane to butane trends with a "dogleg" light methane in the Chung's plot. Primary microbial gas from degradation of immature sedimentary organic matter is found to occur in the Mahu sag and secondary microbial gas from biodegradation of oils and propane occurred in the Zhongguai, Luliang and Beisantai areas where the associated oils were biodegraded to produce calcites with δ13C values from + 22.10‰ to + 22.16‰ or propane was biodegraded leading to its 13C enrichment. Microbial CH4 in the Mahu sag is most likely to have migrated up from the Lower Wuerhe Formation coal-bearing strata by the end of the Triassic, and secondary microbial gas in Zhongguai and Beisantan uplifts may have generated after the reservoirs were uplifted during the period of the Middle and Late Jurassic. This study suggests widespread distribution of microbial gas and shows the potential to find large microbial gas accumulation in the basin. [ABSTRACT FROM AUTHOR]

The Côte d'Ivoire Basin is one of the most important oil production areas in Africa; and it is also the focus of global oil and gas exploration, but the degree of oil exploration and development in this basin are still in the early stages. Based on a comprehensive analysis of drilling, logging, and geochemical data in the Côte d'Ivoire Basin, this study comprehensively evaluates the Cretaceous lacustrine source rocks in the study area, establishes a total organic carbon (TOC) quantitative prediction model by using the total organic carbon method, determines the relationship between seismic reflections and the geochemical characteristics of the source rocks, and tracks the main source rocks horizontally. The results show that the TOC of the Lower Cretaceous Albian stage source rocks is 2.63 wt.%, the kerogen type II is dominant, and the vitrinite reflectance (RO) ranges from 0.3% to 0.9%. The source rocks are mainly in the low-mature to mature stage, and they are generally of good and premium quality. The distribution range of high-quality source rocks with TOC values of 4.00~5.00% is predicted using the total organic carbon method, and useing the seismic method, we determine that high-quality source rocks with larger thickness values and better continuity are mainly developed in the eastern depression center of the basin. [ABSTRACT FROM AUTHOR]

Introduction: The Qinnan Depression in the Bohai Bay Basin is lowly explored, where hydrocarbon generation potential of source rocks is required detailed investigation to identify hydrocarbon exploration potential and direction. Methods: This study is based on organic geochemical analysis performed on the Paleogene source rocks. After that, the burial, thermal maturity, and hydrocarbon generation histories of the Paleogene source rocks at various sags were reconstructed on BasinMod software based on reasonable geological models and geological parameters derived from geological analogy. Results: Results show that the 3rd member (Es3) and 1st member (Es1) of the Eocene Shahejie Formation are high-quality source rocks with a mixture of type I and II kerogen, whose organic matter was originated from aquatic organisms under a reducing environment. The 3rd member (Ed3) of the Oligocene Dongying Formation are fair-quality source rocks with type II kerogen and are dominated by mixed organic matter depositing in a weakly reducing environment. Clear differences in hydrocarbon generation were observed in these three source rocks owing to differential subsidence and sedimentation among the Eastern, Southeastern, and Western sags. Source rocks at the Eastern Sag were maturated early and lasted for a long time, which were currently at late mature (1.0-1.3%Ro) to high mature (1.3-2.0%Ro) stages. Two hydrocarbon generation events occurred in the Oligocene and Miocene, respectively, with intensive hydrocarbon generation capacity. Source rocks at the Southeastern Sag were maturated late and lasted for a short period, which were currently at a medium mature (0.7-1.0%Ro) stage. The major hydrocarbon generation event had occurred since the late Miocene, with intensive hydrocarbon generation capacity. Source rocks at the Western Sag were at an early mature (0.5-0.7%Ro) stage and began to generate hydrocarbon in the Pliocene, with weak hydrocarbon generation capacity. The hydrocarbon generation capacity of the Paleogene source rocks is as follows: Es3>Es1>Ed3. Discussion: The Qinnan Depression has high oil and gas exploration potential, where exploration activities should focus on effective traps around depression and slope zones located at the Eastern and Southeastern sags. [ABSTRACT FROM AUTHOR]

Marine shales from the Niutitang Formation and marine–continental transitional shales from the Longtan Formation are two sets of extremely important hydrocarbon source rocks in South China. In order to quantitatively compare the pore complexity characteristics between marine and marine–continental transitional shales, the shale and kerogen of the Niutitang Formation and the Longtan Formation are taken as our research subjects. Based on organic petrology, geochemistry, and low-temperature gas adsorption analyses, the fractal dimension of their pores is calculated by the Frenkel–Halsey–Hill (FHH) and Sierpinski models, and the influences of total organic carbon (TOC), vitrinite reflectance (Ro), and mineral composition on the pore fractals of the shale and kerogen are discussed. Our results show the following: (1) Marine shale predominantly has wedge-shaped and slit pores, while marine–continental transitional shale has inkpot-shaped and slit pores. (2) Cylindrical pores are common in organic matter of both shale types, with marine shale having a greater gas storage space (CRV) from organic matter pores, while marine–continental transitional shale relies more on inorganic pores, especially interlayer clay mineral pores, for gas storage due to their large specific surface area and high adsorption capacity (CRA). (3) The fractal characteristics of marine and marine–continental transitional shale pores are influenced differently. In marine shale, TOC positively correlates with fractal dimensions, while in marine–continental shale, Ro and clay minerals have a stronger influence. Ro is the primary factor affecting organic matter pore complexity. (4) Our two pore fractal models show that the complexity of the shale in the Longtan Formation surpasses that of the shale in the Niutitang Formation, and type I kerogen has more complex organic matter pores than type III, aiding in evaluating pore connectivity and flow effectiveness in shale reservoirs. [ABSTRACT FROM AUTHOR]

The unclear understanding of the source rock characteristics for the Paleogene Dongying Formation in the Bozhong Sag leads to the lack of cognition in oil and gas exploration. This research systematically evaluated the discrepancy in geochemical characteristics of source rock intervals in the Dongying Formation based on detailed analysis using Rock‐Eval pyrolysis, total organic carbon (TOC), vitrinite reflectance (Ro), maceral components, stable carbon isotopes and biomarker parameters. It discusses the organic matter sources, depositional environment, thermal maturity and hydrocarbon generation potential in the source rock intervals of the Dongying Formation. The organic matter abundance in the third member (E3d3) and lower sub‐member of the second member (E3d2L) of the Dongying Formation is higher, with an average TOC of 2.08% and 1.03%, respectively, indicating that these source rock intervals could have good and excellent quality. The source rocks of the Dongying Formation predominately contain exinite maceral group and type II1 and II2 kerogen. The thermal evolution is mainly in the low‐mature and mature stages. The organic matter sources in the Dongying Formation are mainly dominated by mixed origin (the carbon isotope reversal of aromatics also provides a potential explanation). However, the values of 1,2,5−/1,3,6‐trimethylnaphthalene, (1,2,5,6 + 1,2,3,5)‐tetramethylnaphthalene/tetramethylnaphthalenes, methyldibenzofuran/methylphenanthrene (MDBF/MP) and dibenzofuran/phenanthrene (DBF/PHEN) parameters in the E3d3 and some samples in E3d2L decipher relatively smaller values than other source rock intervals, proving the enhancement of the contribution of lower organisms. Moreover, the terrestrial input in the bottom‐up deposition process of the Dongying Formation gradually increases. The depositional environment reveals the Dongying Formation source rocks mainly developed freshwater sulphur‐poor lacustrine facies and shallow lake‐fluvial delta facies in an open clay‐rich sedimentary environment with poor water column stratification, belonging to the typical weak oxidation–reduction depositional conditions. The comprehensive geochemical evaluation concludes that the favourable supply of lower organisms and stable clay‐rich depositional environment in the E3d3 interval of the Dongying Formation are potential explanations for the formation of lacustrine source rocks with high organic matter abundance, intermediate thermal evolution and excellent hydrocarbon generation potential, providing a good foundation for the exploration and development prospects of hydrocarbons. [ABSTRACT FROM AUTHOR]

The effective electrical conductivity of organic-rich mudrocks can be influenced by the presence of clay, pyrite, and thermally mature organic matter. In this paper, we investigate the impacts of conductivity, volumetric concentrations, and spatial distribution/connectivity of clay, pyrite, and kerogen networks on the effective conductivity of the rock and how this affects the assessment of water/hydrocarbon saturation. This quantification enables an understanding of when such components need to be considered in interpreting resistivity measurements in organic-rich mudrocks. We perform sensitivity analysis on the impacts of (a) thermal-maturity-dependent kerogen conductivity, (b) volumetric concentration/spatial distribution of kerogen, (c) conductivity and volumetric concentration/spatial distribution of pyrite, and (d) cation exchange capacities of various clay minerals and their concentration/spatial distribution on the effective conductivity of the rock. The sensitivity analysis showed that with increasing pyrite concentration, the effective conductivity of the rock increased. This increment became significant when the concentration of pyrite was above 2%. Lastly, we observed that thermally mature kerogen increased the conductivity of the rock, with a significant increment occurring when the kerogen conductivity was above 0.01 S m−1. Results confirmed that the incorporation of conductive rock components such as clay, pyrite, and kerogen into the electrical rock physics model improved the estimates of hydrocarbon reserves. [ABSTRACT FROM AUTHOR]

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The Côte d' Ivoire Basin is one of the important oil production areas in Africa. Based on the comprehensive analysis of drilling, logging, and geochemical data in Côte d' Ivoire Basin, this paper comprehensively evaluated the Cretaceous lacustrine source rocks in the study area, established the total organic carbon(TOC) quantitative prediction model of the Cretaceous source rocks in the study area by using the organic carbon method, determined the relationship between seismic reflection characteristics and geochemical characteristics of the source rocks, and tracked the main source rocks horizontally. The results show that the TOC of the Lower Cretaceous Albian source rocks is 2.63%, the kerogen type II is dominant, and the Ro is 0.3%-0. 9%. Source rocks are mainly in the low-mature to mature stage, and generally of good and premium quality. Premium quality source rocks are mainly distributed in the central area of the eastern depression of the basin, TOC values is ranging from 4. 00 % to 5.00 %, thickness is large, and continuity is good. [ABSTRACT FROM AUTHOR]

The effect of hydrothermal treatment of high-carbon low-permeability Domanik rock on the efficiency of recovering hydrocarbons from this rock by prolonged four-step extraction for 20, 68, 116, and 220 h with a mixture of organic solvents (chloroform, toluene, and isopropyl alcohol) was studied. As compared to the extraction from the untreated rock, the hydrothermal treatment at 300°С in a СО2 medium allows recovery of a 6 times larger amount of the extract in the first step (in 20 h). In the second extraction step (68 h), the extract yield decreases by a factor of 8, but the relative content of saturated hydrocarbons in the extract increases by a factor of more than 3 compared to the first step, whereas the relative content of asphaltenes, resins, and aromatic compounds decreases. In the third extraction step (116 h), the extract yield is as low as 0.16%, the content of resins in it drastically decreases, whereas the content of asphaltenes increases to 52%. The extract of the fourth step (220 h) consists to 80.77% of asphaltenes. From the initial rock, the maximal yield of the extract enriched in saturated hydrocarbons with the minimal content of asphaltenes was observed after the second extraction step. In the course of prolonged extraction, the yield of petroleum fractions from the initial rock increases by a factor of almost 4, and in combination with the preliminary hydrothermal treatment, by a factor of 7. This fact demonstrates the possibility of generating an additional amount of hydrocarbons. Changes were revealed in the structural-group, hydrocarbon, elemental, and microelemental composition of petroleum fractions recovered from the low-permeability Domanik rock, depending on the extraction time and transformations of the organic matter of this rock in the course of hydrothermal treatment. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

The opening of Neo-Tethys within Gondwanaland during the Guadalupian (transition signified a pivotal transgressive event) in the Permian Period. Consequently, an attempt has been undertaken to elucidate the sequence stratigraphy and palaeodepositional settings of fluvial sedimentary deposits encompassing coal and shale sediments within the Godavari Valley Coalfield, South India. The Total Organic Carbon (TOC) content across the examined samples exhibits a discernible range from 0.07 to 65.53 wt%, with reactive carbon, measured as Pyrolyzable Carbon (PC), displaying variations from 0.02 to 15.93 wt% and non-reactive carbon, characterized, as Residual Carbon (RC), spans a percentage range of 0–66.86 wt% within the selected samples. The predominant organic matter manifests as type III kerogen, except Sh-47, where type II kerogen is identified. The combination of Rock–Eval pyrolysis alongside palynofacies analysis facilitates the differentiation of significant system tracts arising from relative sea level fluctuations within the deposited terrestrial sequences. These tracts include swampy and flooded palaeomires settings. Terminologies denoting system tracts within the sequences are indicted as T-lst, T-hst, T-tst and T-mfs corresponding to the Low Stand System Tract (LST), High Stand System Tract (HST), Transgressive System Tract (TST) and Maximum Flooding Surface (MFS) respectively. A noteworthy one and half cycles are discerned within the sequence, predicted on Amorphous Organic Matter (AOM), TOC, Hydrogen Index (HI), PC and Gelification Index (GI) values. In the initial cycle, T-mfs is identified based on the preponderance of fluorescent AOM, coupled with the highest value of HI and PC. The ratio of opaque/translucent phytoclasts serves as a discriminant in delineating the boundaries of T-lst, T-tst and T-hst within the sequences, corroborating the aforementioned observation. This research serves as a preliminary assessment of the system tracts within fluvial environments. A more intricate, high-resolution exploration of deeper sequences holds the potential to furnish comprehensive insights for subsequent studies. [ABSTRACT FROM AUTHOR]

Oil shale is a potential strategic resource with large reserves and widespread application potential, and in situ combustion is an effective method to exploit oil shale. However, the interaction mechanism between pyrolysis and combustion reaction is still not clear; hence, the evolution of components and temperature in the reservoir is hard to describe, limiting the application of in situ combustion in oil shale. In this paper, we established a comprehensive reactive flow model to describe the in situ combustion in oil shale, and the in situ combustion process is analyzed in detail. During the in situ combustion, only pyrolysis reactions occur in the matrix system, while combustion reactions only occur in the fracture system. Under the interaction mechanisms of these two kinds of chemical reactions, in situ combustion upgrading can be carried out continuously. The produced oil and hydrocarbon gas per unit volume of oil shale are 0.06 m3/m3 and 12.5 m3/m3 , respectively, but about 83.3 m3/m3 of CO2 is produced that needs to be stored subsequently when air is directly injected into the reservoir to maintain the combustion reactions. Increasing oil content and air injection rate can increase the cumulative oil and gas production, but there are optimal values above which the increase rate slows down. The energy conversion efficiency of in situ combustion is 49.5, and it is much higher than the energy conversion efficiency in other in situ upgrading methods for oil shale. [ABSTRACT FROM AUTHOR]

Jiaojiang sag in the East China Sea Basin is at the earlier exploration stage, where characterizing hydrocarbon generation of source rocks is important to understand oil-gas exploration potential. Utilizing geochemical and basin modeling analysis, hydrocarbon generation capacity and process of the Paleocene E1y, E1l and E1m formations were investigated. Results show that E1y and E1l mudstones are high-quality source rocks with Type II kerogen, which is dominated by both aquatic organisms and terrestrial higher plants deposited in sub-reduced environment. E1m mudstone interbedded with thin carbonaceous mudstone and coal is poor-quality source rock with Type III kerogen, whose organic matter was originated from terrestrial higher plants under oxidized environment. Controlled by burial and maturity histories, E1y and E1l source rocks experienced two hydrocarbon generation stages, which took place in the Late Paleocene and in the Middle to Late Eocene, respectively, and had high hydrocarbon generation capacity with cumulative hydrocarbon volume of 363 and 328 mg/g, respectively. E1m source rock only had one hydrocarbon generation process in the Late Eocene, which had low hydrocarbon generation capacity with cumulative hydrocarbon volume of only 24 mg/g. The future oil-gas exploration in the Jiaojiang sag should focus on hydrocarbon generation center and select targets in the central uplift formed before the Miocene with high-quality traps. [ABSTRACT FROM AUTHOR]

Understanding the quantitative responses of anisotropic dynamic properties in organic-rich shale with different kerogen content (KC) is of great significance in hydrocarbon exploration and development. Conducting controlled experiments with a single variable is challenging for natural shales due to their high variations in components, diagenesis conditions, or pore fluid. We employed the hot-pressing technique to construct 11 well-controlled artificial shale with varying KC. These artificial shale samples were successive machined into prismatic shape for ultrasonic measurements along different directions. Observations revealed bedding perpendicular P-wave velocities are more sensitive to the increasing KC than bedding paralleling velocities due to the preferential alignments of kerogen. All elastic stiffnesses except C13 are generally decreasing with the increasing KC, the variation of C11 and C33 on kerogen content are more sensitive than those of C44 and C66. Apparent dynamic mechanical parameters (n and E) were found to have linear correlation with the true ones from complete anisotropic equations independent of KC, which hold value towards the interpretation of well logs consistently across formations. Anisotropic mechanical parameters (DE and brittleness DB) tend to decrease with the reducing KC, with DB showing great sensitivity to KC variations. In the range of low KC (<10%), the VP/VS ratio demonstrated a linearly negative correlation with KC, and the VP/VS ratio magnitude of less than 1.75 may serve as a significant characterization for highly organic-rich (>10%) shale, compilation of data from natural organic rich-shales globally verified the similar systematic relationships that can be empirically used to predict the fraction of KC in shales. [ABSTRACT FROM AUTHOR]

This study conducted a comparative analysis of extractable hopanoid hydrocarbons and those released via stepwise pyrolysis of typical Eocene immature oil shales in China, namely the Huadian, Maoming, and Fushun shales. Both the Huadian and Maoming shales exhibit immature indicators in extractable and kerogen-bound hopanoids (notably, high abundance of C29 to C32 17β,21β-hopanes and unsaturated hopenes). In contrast, the Fushun oil shale's hopanoids from extracts and pyrolyzates suggest a higher maturity level. The absence of neohopenes in the pyrolyzates of the shales underpins that the kerogenbound hopanoid skeletons resist rearrangement. However, the Huadian oil shale's asymmetric distribution of C29 and C30 hopenes and neohopenes hints at the presence of an additional source. Novel unsaturated hopenes, such as hop-20 (21)-enes, identified in pyrolyzates of the three kerogens at various pyrolysis temperatures, reveal the occurrence of double bonds in kerogen-bound hopanoid skeletons without methyl rearrangements. The absence of hop-20-(21)-ene in extracts suggests that it might act as an intermediate of these novel hopenes during the epimerization of hopanoid skeletons within kerogen. The extractable and pyrolytic hopanoids' stereochemical alignment indicates that epimerization may occur in both ring systems and alkyl side chains of kerogen-bound hopanoid skeletons. Sequential stepwise pyrolysis proves to be a quick screening method for geological hopanoids without causing any significant alteration to the original skeletons even when cracking multiple covalent bonds is necessary. [ABSTRACT FROM AUTHOR]