Hydrocarbon Generation Potential Research Articles

Burial history and hydrocarbon generation model of the Lower–Middle Jurassic sediments in the Tarnovo depression

This study deals with the geodynamic evolution in the Tarnovo depression, contributes to a better understanding of the burial and thermal history, and gives a model of the generation of hydrocarbons from the Lower–Middle Jurassic rocks. The implications of the complex heat flow scenario for the timing of hydrocarbon generation from the Stefanets Member of the Etropole Formation in selected sections were also analyzed. The Tarnovo depression is defined as a small tectonic unit in the central part of the South Moesian Platform margin developed mainly during the Early–Middle Jurassic. Therefore, the sediment subsidence during the Early–Middle Jurassic is largely a consequence of the tectonic processes in an extensional basin with tilted, fault-bounded, and eventually rotated blocks. There is a trend of increasing tectonic and basin subsidence in southern direction, observed in modeled well sections. The Lower–Middle Jurassic rocks enter the “oil window” in the late Barremian, Hauterivian, or even the late Valanginian towards the south, starting active generation in the middle Aptian. The model shows that gas generation is possible only in the southern and marginal zones of the Tarnovo depression. Among the sequence, the Stefanets Member of the Etropole Formation (Aalenian–early Bajocian in age), composed of shales and siltstones, possesses source rock qualities and good hydrocarbon generation potential. The research model argues for peak of the oil generation from the Stefanets Member at the end of the Barremian up to the Albian to the north and gas generation starting in the Barremian and continuing during the Cenozoic only in the southern part.

1D basin modeling and hydrocarbon generation potential of the Late Carboniferous Limburg Group formations, Northwest European Basin, Netherlands

The Carboniferous rock samples of the Limburg Group formations were studied to investigate the source rock characteristics and the hydrocarbon generative potential. The source rock samples have been collected representing four rock units from three different wells. These samples were analyzed using Rock-Eval pyrolysis results and measured vitrinite reflectance values, and also by generating a one-dimensional basin model of K1 Field. The total organic carbon in these samples varies from 0.31 to 83.56% with a mean of 37.68%, suggesting that Limburg Group formations have excellent potential as a source of hydrocarbons. Kerogen in the Limburg Group formations is type II-III and type III, generate gas prominently. The outcomes of thermal maturation by Tmax and measured vitrinite reflectance reveal that the examined Limburg source rocks are located in the mature zone. The burial and thermal history models show irregular trend patterns due to uplift, erosion, and non-deposition events that took place in the K1 field (where the structural element is Cleaver Bank High). For the Maurits Formation, the oil generation took place at 2011 m at 230.1Ma ago and the top of the gas window was encountered 217.8Ma ago at 2535 m, whereas for the Hospital Ground Formation, the top of the oil window was encountered 186.8Ma ago at 2404 m and the gas generation took place at 2404 m at 161.9Ma ago.

Study on Pyrolysis Kinetics, Behavior, and Mechanism of Organic-Rich Tuffaceous Mudstones Based on Thermogravimetric Analysis.

Organic-rich tuffaceous mudstones are important oil and gas resources. The systematic study of the pyrolysis kinetics and characteristics can not only provide the theoretical basis for the rational development and efficient utilization of these rocks but also is an important complement to the theoretical research on the pyrolysis kinetics of organic-rich rocks. In this study, the pyrolysis kinetics, behavior, and mechanism of the organic-rich tuffaceous mudstone in the Junggar Basin were clarified by thermogravimetric analysis. The organic structure and mineral composition were identified by Rock-Eval, Fourier transform infrared (FTIR), and X-ray diffraction (XRD). The results indicated that the mudstone could be described as a type II kerogen with good hydrocarbon generation potential. The mudstone included up to 80.7% quartz, which is associated with Carboniferous volcanic activity. Four isoconversional methods were used to evaluate the activation energies. A novel and simplified method was proposed to separate the pyrolysis processes using the Coats-Redfern method based on the differences in reaction models and activation energies. The pyrolysis processes were divided into four stages, and the reaction models of each stage were preliminarily clarified. The reaction models were further modified by the accommodation function The results showed the kinetic parameters, and the reaction models of each stage were significantly different. Moreover, the obtained kinetic parameters and optimal reaction models can well characterize the pyrolysis processes and mechanism of the tuffaceous mudstone. The results of thermogravimetric-FTIR (TG-FTIR) indicated that the main pyrolysis hydrocarbon volatiles were methane, C2+ aliphatic hydrocarbons, and aromatics. And the types and yields of pyrolysis volatiles differed at each stage.

Corrigendum: Geochemical characteristics and hydrocarbon generation potential of main source rocks in the Upper Triassic Xujiahe Formation, Sichuan Basin, China

Corrigendum: Geochemical characteristics and hydrocarbon generation potential of main source rocks in the Upper Triassic Xujiahe Formation, Sichuan Basin, China

Molecular fossil chronicles and geochemical probes of Paleogene coals from Meghalaya, India

The Paleogene coals from the Jaintia, Khasi, and the Garo hills of Meghalaya, India, are studied for biomarker distributions, carbon isotope signatures (δ13Cbulk), and Rock-Eval pyrolysis (REP) to elucidate their organic matter (OM) source, depositional environment, thermal maturity, and hydrocarbon generation potential. Sulfur-rich OM (1.52 wt%–24.57 wt% S dry-basis) with Hydrogen Index (HI) values ranging from 172 mg HC/g TOC – 353 mg HC/g TOC suggest the presence of type IIS-IIIS admixed kerogen. Mixed gymnosperm – angiospermous OM input to the peatland is implied by δ13Cbulk values spanning from −26.7‰ to −25.5‰, −27.4‰ to −25.1‰, and −27.0‰ to −25.2‰ in the Jaintia, Khasi, and Garo coals, respectively. Further, the presence of pimarane, isopimarane, labdane, rimuane, phyllocladanes, and ent-beyerane, mark the conifer OM input, substantiated by the 1,7-dimethylphenanthrene (1,7-DMP), 1,6-dimethylnaphthalene (1,6-DMN), and 1,2,5- trimethylnaphthalene (1,2,5-TMN) compounds. The abundances of these gymnosperm markers decline from the Garo to the Jaintia coals implying plausible shifts in paleovegetation. Compound A from the oleanoid skeleton and subordinate amounts of oleanane indicate variable contributions from angiosperms. The oleanane index declines from the Garo to Jaintia coals suggesting a lower contribution of angiospermous OM from Garo to the Jaintia samples, which may also indicate a shift in the OM depositional environment towards the Jaintia Hills. Dibenzothiophene isomers increase while dibenzofuran isomers decrease from the Garo to Jaintia coals suggesting shifts from terrestrial to marginal marine depositional environment. Additionally, the gammacerane index increases from the Garo to Jaintia coals implying a transition from a stratified brackish water column or marine transgression to the peatland of the Jaintia Hills. Moreover, the studied coal samples exhibit variable thermal maturity. The mean random vitrinite reflectance of the Garo coals (R¯r=0.48%–0.61%) indicates subbituminous to bituminous rank, while the Khasi (R¯r=0.44%–0.60%) and Jaintia coals (R¯r=0.26%–0.75%) belong to subbituminous to bituminous D, and lignite to bituminous C rank, respectively. Tmax of these coals ranges from 414 °C to 446 °C, indicating the samples span from pre-catagenetic to catagenetic stages of maturation. Saturated C32-bishomohopane epimer and C30 βα-moretane/αβ-hopane ratios, along with aromatic MPI-3 and 3-MP/retene ratios, exhibit an increasing maturity trend from the Garo Hills to the Jaintia Hills samples.

Experimental Characteristics of Hydrocarbon Generation from Scandinavian Alum Shale Carbonate Nodules: Implications for Hydrocarbon Generation from Majiagou Formation Marine Carbonates in China’s Ordos Basin

The hydrocarbon source rocks of the marine carbonates of the Ordovician Majiagou Formation in the Ordos Basin are generally in the high-overmature stage and are, therefore, not suitable for hydrocarbon thermal simulation experiments. Their hydrocarbon generation potential and hydrocarbon generation characteristics are not clearly understood. Meanwhile, Nordic Cambrian carbonates are similar in lithology, parent material type, and sedimentary age, and are in the low evolution stage, which is suitable for hydrocarbon thermal simulation experiments. Therefore, in this study, we selected the Nordic carbonates for the gold tube thermal simulation experiment to analyze the content and geochemical characteristics of the thermal simulation products. The experimental results are also compared and analyzed with the characteristics of thermal simulation products of Pingliang Formation mud shale (contemporaneous with the Majiagou Formation) and Shanxi Formation coal (in the upper part of the Majiagou Formation), which are similar to the Majiagou Formation in the Ordos Basin. The results showed that the Nordic carbonate has different hydrocarbon production characteristics from the mud shale of the Pingliang Formation of the same parent material type, and although the hydrocarbon production yields of the two are not very different, the carbonate still produces methane at 600 °C. The hydrocarbon production yield of the Nordic carbonates is almost equivalent to that of type-II2 kerogen, indicating that the hydrocarbon production yield is not related to lithology and only to the organic matter type; however, the Nordic carbonate can produce a large amount of H2S. The alkane carbon isotope changes are mainly controlled by the degree of thermal evolution, showing gradual heaviness with increasing temperature. No carbon isotope sequence reversal occurred during the thermal simulation, and its distribution range is roughly the same as that of the alkane carbon isotope composition of the mud shale of the Pingliang Formation. The ethane carbon isotope composition is as heavy as −21.2‰ at the high-temperature stage, showing similar coal-type gas characteristics. The addition of calcium sulphate (CaSO4) causes the TSR reaction to occur, which has a significant impact on the methane content under high maturity conditions, reducing its content by more than 50% at 600 °C. However, the addition of CaSO4 increases the yield of heavy hydrocarbon gases, such as ethane, and promotes the production of C6-14 hydrocarbons and C14+ hydrocarbons at high-temperature stages, and the addition of CaSO4 substantially increases the yield of H2, CO2, and H2S. The thermal simulation results have implications for the hydrocarbon formation mechanism of the early Paleozoic marine carbonate formation system in the stacked basins of the Ordos Basin and the Tarim Basin in China.

Burial history, thermal history and hydrocarbon generative potential and modelling of Urandab Shale within Ogaden Basin, Ethiopia

Burial history, thermal history and hydrocarbon generative potential and modelling of Urandab Shale within Ogaden Basin, Ethiopia

Formation mechanism of organic-rich mixed sedimentary rocks in saline lacustrine basin, Permian Lucaogou Formation, Jimsar Sag, Junggar Basin, Northwest China

The organic-rich mixed sedimentary rocks deposited in a saline lacustrine environment are widespread in the Lucaogou Formation (P2l), Jimsar Sag, Junggar Basin. These rocks have complex lithology (mainly including mudstone, dolomitic mudstone and argillaceous dolomite) and significant changes in geochemical characteristics. Presently, the formation mechanism of organic-rich mixed sedimentary rocks in the P2l of the Jimsar Sag is obscure. To address these issues, the formation mechanism of mudstone, dolomitic mudstone and argillaceous dolomite is revealed by evaluating their sedimentary environment, primary productivity and sources of organic matter using organic petrology, organic geochemistry and inorganic geochemistry. The results show that the mixed sedimentary rocks of the P2l exhibit excellent hydrocarbon generation potential. The mixed sedimentary strata were mainly deposited in saline and suboxic to anoxic water column, and the main source of organic matter was aquatic organisms. During the changes from mudstone, dolomite mudstone to argillaceous dolomite deposition, the paleoclimatic condition varied from warm-humid to arid-hot with more frequent hydrothermal activity, which enhanced the salinity of the water column, leading to a higher proportion of halotolerant algae (cyanobacteria and green algae). The improvement in the paleoproductivity caused by volcanic activity was the most critical factor to promote the enrichment of organic matter in the mixed sedimentary rocks. In addition, the decomposition of algae and stratified water column were conducive to the formation of a stable and suboxic to anoxic bottom water environment, which improves the preservation conditions of organic matter, and also favored the organic matter enrichment in mixed sedimentary rocks. Therefore, the frequent changes in paleoclimatic conditions and periodic hydrothermal activity controlled the formation of different lithologies in the P2l. High primary productivity and good preservation conditions promoted the accumulation of organic matter in these mixed sedimentary rocks.

Implications of Organic Matter Input, Sedimentary Environmental Conditions, and Gas Generation Potential of the Organic-Rich Shale in the Onshore Jiza-Qamar Basin, Yemen.

The Jiza-Qamar Basin is one of the most important exploration sedimentary basins in Yemen. For over a decade, the exploration of hydrocarbons has been occurring in this basin. Late Cretaceous age rocks are the most occurring organic-rich sediments in this basin, including coals, coaly shales, and shales. The studied organic-rich shale beds are from the Late Cretaceous Mukalla Formation and associated with coal seams. These organic-rich shales can serve as source rocks for hydrocarbon generation potential. The current study investigates the geochemical characteristics, including assessing the organic matter (OM) input, sedimentary environmental conditions, and hydrocarbon generation potential of the organic-rich shale within the Mukalla Formation from three well locations in the onshore Jiza-Qamar Basin using organic geochemistry, biomarker, and carbon isotope measurements. The studied shale samples have high OM content with total organic carbon values between 0.74 and 19.48 wt %. Furthermore, they contain mainly hydrogen-poor Types III and IV kerogen, indicating the presence of the gas-prone source rock. The presence of these types of kerogen indicates the abundance of vitrinite and inertinite macerals, as established by microscopic investigation. However, the studied organic-rich shales had biomarker features, including high Ph/Ph ratio between 3.82 and 7.46, high Tm/Ts ratio of more than 7, and high C29 regular steranes compared to C27 and C28 regular steranes. Apart from the biomarker results, the studied Mukalla shales are characterized by the abundance of land-derived OM that deposited in fluvial to fluvial deltaic environments under highly oxic conditions. The finding of the considerable concentration of terrigenous OM is probably confirmed by the bulk carbon isotope and maceral composition data. The maturity indicators show that the examined organic-rich shale samples in the studied wells exhibit low VR values of up to 0.71%, and thereby, they have not been yet reached the high maturity for gas generation. This low maturity level in the studied wells is probably attributed to shallow burial depth, exhibiting depth of up to 2835 m. Therefore, the substantial gas exploration operations from the organic-rich shale source rock system of the Late Cretaceous Mukalla Formation can be recommended in the deeper stratigraphic succession in the offshore Jiza-Qamar Basin.

Sedimentary Organic Facies Division and Hydrocarbon-Generation Potential of Source Rocks in Coal-Bearing Strata-A Case Study of the Upper Paleozoic in Huanghua Depression, Bohai Basin, China.

Sedimentary organic facies cover the formation, evolution, and spatial distribution characteristics of organic matter, and they are effective tools for oil and gas resource evaluation and basin prospect prediction. According to the basic organic rock composition of the sedimentary organic facies, combined with the sedimentary facies and organic matter geochemical characteristics of Carboniferous-Permian strata, the characteristics of organic facies and hydrocarbon-generation potential of Upper Paleozoic source rocks in Huanghua Depression are being discussed. The results show that source rocks of Taiyuan and Shanxi Formations in the study area were oil-prone, and the oil-generation potential of mudstone is greater than that of carbonaceous mudstone and coal. The organic facies in the study area can be divided into six types: (1) terrestrial forest organic facies; (2) shallow swamp forest organic facies; (3) deep swamp forest organic facies; (4) deep swamp reed organic facies; (5) flowing water swamp organic facies; and (6) open water organic facies. The Taiyuan Formation is mainly composed of flowing water swamp, deep swamp forest, and shallow swamp forest with a strong hydrocarbon-generation capacity, while the Shanxi Formation chiefly includes organic facies of the deep swamp forest and shallow swamp forest. The deep swamp reed sedimentary organic facies had the highest hydrocarbon-generation potential, while the terrestrial forest sedimentary organic facies had the worst hydrocarbon-generation potential. Coal had a certain oil-generating capacity but was weaker than that of mudstone. Compared with mudstone, coal had a stronger gas-generating capacity.

Geological Characteristics of Shale Reservoir of Pingdiquan Formation in Huoshaoshan Area, Junggar Basin

Unconventional oil and gas, represented by shale gas and shale oil, have occupied an important position in global energy. The rapid growth of shale gas and shale oil production shows great potential for the exploration and development of shale resources. Junggar basin, the main oil-bearing basin in China, is rich in oil and gas resources, so it is of great practical significance to carry out systematic research on the geological characteristics of shale reservoirs in this region. To this end, this paper designates the shale reservoir of Pingdiquan Formation in Huoshaoshan area of the Jungar Basin as the research object, carries out a geological survey in that area, analyzes reservoir forming conditions using the geological interpretation method, analyzes different local trap reservoir types and their main control factors by dissecting the explored reservoir, optimizes and evaluates favorable traps using the source, fault, facies and circle coupling analysis method, establishes single good identification standard of sedimentary microfacies, and carries out well-connected sedimentary microfacies analysis. Using geochemical methods, such as rock pyrolysis, maceral analysis, vitrinite reflectance, kerogen carbon isotope, saturated hydrocarbon chromatography, etc., the abundance and types of organic matter of shale in different intervals are analyzed and the geological characteristics of shale reservoirs are evaluated. This paper aims to analyze the oil and gas content of the shale reservoir in Pingdiquan Formation in the Junggar Basin to provide reliable reservoir evaluation and guide better development of shale oil and gas resources in the future. The innovative expenditure of this paper lies in conducting the research from two aspects: the analysis of the main controlling factors of reservoir formation from the structural point of view and the analysis of the pore structure and geochemical characteristics of shale from the core experiment point of view, and also the classification of organic matter, so as to provide a basis for finding favorable traps. The results show that the shale sedimentary system in the study area is a small fluvial delta, which belongs to a compression structure, with developed NNE-oriented structural belts and faults; the structural form is a short-axis anticline as a whole, forming a structural coil closure at −900 m, with a trap area of 50 km2 and a closure height of 180 m. According to the geological interpretation method, 19 faults of all levels were found in the area and the vertical migration conditions of oil and gas were good. Pingdiquan Formation was oil-bearing, with many vertical oil-bearing strata and strong horizontal independence of the reservoir. The sedimentary thickness of the Permian Pingdiquan Formation in the study area is 300~1200 m and the oil-bearing strata are divided into 3 oil-bearing formations, 9 sublayers, and 22 monolayers from top to bottom. The abundance of organic matter in different strata is generally high, with an average total organic carbon content of 3.53%, an average hydrocarbon generation potential of 18.1 mg/g, an average chloroform asphalt content of 0.57%, and an average total hydrocarbon content of 3011 μg/g, all of which belong to the shale standard, especially Ping-2. The organic matter in different layers belongs to types I-II1, and the organic matter types are I-II1, I-II2, and II1-II2, respectively. The average carbon isotope of shale kerogen is −2.4%, which belongs to type II2 kerogen.

Geochemical characteristics and hydrocarbon generation potential of main source rocks in the Upper Triassic Xujiahe Formation, Sichuan Basin, China

In order to have a comprehensive understanding of the characterization and hydrocarbon generation potential of the source rock in the Upper Triassic Xujiahe Formation, Sichuan Basin, the geochemical data of more than 1,500 cuttings and 106 core samples were collected and analyzed. The T3x5 member of Xujiahe formation show the highest average TOC content (3.63%) followed by the T3x1+2 and T3x3 members. The TOC contents of different members show a general decreasing trend from the bottom to the top in Xujiahe formation. From the rock pyrolysis and kerogen δ13C values, the source rock trend to be kerogen type III with minor amounts of type Ⅱ2. According to the Ro values, the Xujiahe source rock shows high maturity in the northwest and low maturity in the southeast. Most of the source rock in T3x1+2 members are in high to overmature stage, while most of the source rock in the T3x3 and T3x5 member are in the mature to high mature stage. By comparing the burial history and hydrocarbon generation evolution history of source rocks in central and western Sichuan basin, it can be found that the sedimentation rate differences during the Cretaceous period is the main cause of the thermal evolution difference of the source rock. The gas generation intensity and quantity of different members are also compared. The T3x5 member show the highest gas generation potential followed by the T3x31 and the T3x1+2 members. In general, horizontally, the source rock of Xujiahe formation in Sichuan Basin is characterized by great thickness, high maturity, and high gas generation intensity in the northwest, which are gradually decrease to the southeast. Vertically, the T3x5 member show the highest gas generation content, which account for 39.6% of the total amount.

Geochemical and gas bearing characteristics of the marine-continental transitional Longtan shales in southern Sichuan, China

Marine-continental transitional shale, as an important shale type, gains less attention than marine and continental shale, which restricts the exploration and development process of marine-continental transitional shale gas. In this study, the Upper Permian Longtan Formation shale in the southern Sichuan Basin was taken as the research object, and the organic matter development characteristics, hydrocarbon generation ability, mineral composition, physical properties, and gas bearing characteristics of the Longtan Formation shale were systematically analyzed. In addition, the effects of organic matter abundance, maturity, and mineral components on shale gas adsorption capacity have been discussed in detail. The results show that the abundance of organic matter in the marine continental transitional shale of the Longtan Formation in southern Sichuan varies greatly, with the TOC value of the vast majority of shale being greater than 2.0%, with the carbon shale (TOC>12%) accounting for about 5%. The main type of organic matter is Type III, with part of Type II2. The maturity of organic matter is in the stage of high maturity to over maturity, which is conducive to the generation of dry gas. There is a good positive linear correlation between the reflectance of vitrinite (Ro) and the maximum thermal decomposition peak temperature (Tmax) of rock. The higher the abundance of organic matter, the greater the hydrocarbon generation potential of shale, and the carbonaceous shale shows good shale gas generation potential. The shale of the Longtan Formation is rich in clay minerals, with the highest content of the illite/smectite mixed layer. The abundance and maturity of organic matter jointlypromote the enrichment of Longtan shale gas. The enrichment of clay minerals is beneficial to shale gas adsorption, but poses a challenge to production fracturing.

Conversion of the Oil and Gas Generation Potential of the Deep Source Formations of the West Siberian Basin: An Example of Well Tyumen SG-6

A model of the thermal evolution of the lithosphere of the West Siberian Basin in the area of Superdeep Well SG-6, which was drilled through the Koltogor–Urengoi graben, is used to numerically estimate the generation of various hydrocarbon (HC) fractions by the Triassic and Jurassic source rocks. The thermal model assumes the emplacement of a sill into the subsurface layers of the basement in the Early Jurassic and hydrothermal activity in the Late Pliocene–Lower Pleistocene, which noticeably impacted the conversion history of the HC potential of the Triassic and Jurassic source rocks. For the Triassic Pur formation, the emplacement of the sill into the subsurface layers of the basement in the Lower Jurassic drastically intensified the conversion of the HC potential to 84% and the degradation of more than 97% of the generated light oil mass. Calculations show that the heavy oil generated by the rocks of the Pur, Togur, and lower horizons of the Tyumen formations has degraded almost completely as a result of secondary cracking, while heavy oil predominates among the generated HC fractions in the upper horizons of the Tyumen Formation and in the rocks of the Bazhenovo Formation. The light oil remaining nowadays in the matrix of the source rocks has completely degraded in the Triassic rocks but makes up much of the HC products in rocks at the bottom of the Togur Formation and the top of the Tyumen Formation. This oil is the dominant in the upper horizons of the Togur Formation and in the bottom part of the Tyumen Formation. According to calculations, gas hydrocarbons account for a significant proportion of HC products in the Togur and Tyumen formations, and they dominate in the Middle Triassic Pur Formation. At the relatively low initial potential of HC generation and a low content of organic matter in the rocks of the Pur, Togur, and Tyumen formations, no primary expulsion threshold of liquid HC has been reached, and the generated liquid HC probably did not leave the rock matrix, while the gaseous HC likely migrated. The threshold of primary expulsion of liquid HC for the Bazhenov rocks was calculated to be reached at about 65 My.

Deciphering the laminated botryococcus-dominated shales in saline lacustrine basin, Western Qaidam Basin, NW China: Implications for shale oil potential

Given the high lipid content and potentially huge biomass, the explosive occurrence Botryococcus is regarded as a significant marker of high-quality oil source rocks in petroliferous basins. However, they are rarely discovered in saline lacustrine source rocks, and the formation mechanism of these alga-rich shales remains uncertain. In this study, abundant Botryococcus fossils were firstly found, accounting for an average of 43.5% of the total organic debris from the upper Xiaganchaigou Formation in the Yingxiongling and Zhahaquan hydrocarbon-rich sags of the western Qaidam Basin. The Botryococcus-dominated palynofacies assemblages were usually interpreted as derived from a distal oxic shelf environment. These Botryococcus-dominated sediments were characterized by a perfect laminated texture and composed of detrital, carbonate, and clay laminae. The Botryococcus fossils exclusively occur in the detrital laminae with large-grained quartz and feldspar and low carbonate content, possibly reflecting increased river input under relatively heavy precipitation. The cyclothymic deposition between these Botryococcus-rich detrital laminae and other laminae probably indicates that sufficient terrestrial nutrient inputs and lake salinity decreases driven by periodic heavy precipitation result in Botryococcus bloom under fresh or brackish water environments. These Botryococcus-dominated shales in the western Qaidam Basin usually have a high oil-prone hydrocarbon generation potential, as evidenced by their organic geochemistry parameters. These sediments have biomarker features extremely similar to crude oil with a high relative abundance of C20–C24 tricyclic terpanes, phytane, C27ααR sterane, and a unimodal distribution of n-alkanes with the maximum at n-C18. Therefore, these Botryococcus-dominated shales are possibly important oil sources of these prolific oil sags. Additionally, these high-quality source rock sequences can reach a few tens of meters in thickness and evidently have significance for future shale oil resources.

Self-Sourced Unconventional Tight Marlstone Reservoir Potential from Evaporative Lagoon of Triassic Leikoupo Formation in the Central Sichuan Basin

A breakthrough was made in tight marlstone reservoirs from an evaporative lagoon in the second sub-member of the third member of the Leikoupo Formation (Lei3-2) in the Central Sichuan Basin. The source rock characteristics, reservoir characteristics of the marlstone and geochemical parameters of the oil and natural gas were investigated to evaluate the unconventional hydrocarbon exploration potential of the tight marlstone from the evaporative lagoon. The results revealed that the source rocks were deposited in evaporative lagoon environments, and the average total organic carbon (TOC) content value for the samples was 0.75 wt%. The thermal maturity of the organic matter was relatively high, with a calculated vitrinite reflectance (Rc) of 1.7%. The characteristics of marlstones suggest that the potential source rocks had fair to good hydrocarbon generative potential. The condensate samples had low densities, low viscosities and high thermal maturity, with a Rc value of 1.7%. For the natural gas, the dry coefficient was around 0.90, and the carbon isotopic compositions of methane and ethane was −41.3‰ and −28.4‰, respectively. According to the carbon isotopic compositions, thermal maturity and geological background, the oil and natural gas from Lei3-2 are comparable with the marlstone of Lei3-2. Thus, the oil and natural gas is self-sourced and originates from the marlstone in the Lei3-2. Micropores and microfractures are often detected in the marlstone from Lei3-2, and a gypsum layer is conducive to the hydrocarbon preservation. These results suggest that the evaporative lagoon facies in Lei3-2 have large, self-sourced, unconventional, tight marlstone reservoir potential. This study also enhances the prospects for further oil and gas exploration of evaporative lagoon facies in other basins.

The role of organic carbon in the Southern Uplands-Down-Longford Terrane accretionary prism, Scotland and Ireland

Carbonaceous shales in the Southern Uplands-Down-Longford Terrane accretionary prism had extremely high potential for hydrocarbon generation in the Lower Paleozoic. Structural thickening in the prism enhanced the rapid generation of oil. Shale horizons are separated by thick turbidites composed of low-permeability greywackes, so oil under high fluid pressure either pooled along shale bedding surfaces or migrated into fractured greywackes. Pooled oil became solidified to bitumen, which locally formed deposits on a scale of tonnes, mined as coal. The carbon-rich shale also sequestered large amounts of sulfur from seawater, which precipitated as pyrite firstly during early diagenesis, then further during fluid flow through the shale beds. The oil was also sulfur-bearing. Deformation focused on the shale beds during the evolution of the accretionary prism would have been closely related to the fluid flow which precipitated bitumen and sulfides. The palaeo-fluids were also anomalously rich in methane and hydrogen, similar to fluids venting from modern accretionary prisms. Supplementary material: details of localities searched for coal in Lower Palaeozoic, Southern Uplands-Down-Longford Terrane (locations shown in Fig. 6 ) are available at https://doi.org/10.6084/m9.figshare.c.6691597

Comparison of Evaporite-Related Source Rocks and Implications for Petroleum Exploration: A Case Study of the Dongying Depression, Bohai Bay Basin, Eastern China

The Dongying Depression (Bohai Bay Basin, eastern China) was widely filled with evaporite (anhydrite and halite) layers during the Paleogene period, especially the middle of the fourth member of the Shahejie Formation (Es4). Most evaporite layers are interbedded with mudstone strata. The strata of Es4 are divided into three sections, referred to as the upper layers, evaporite layers, and lower layers, respectively. The analysis of elemental concentrations, elemental ratios, and Pr/Ph suggests that the lower layers were deposited in an intermittent saline lake environment within a relatively dry climate. The evaporite layers were formed in a highly saline lake environment, whereas the upper layers were formed in a brackish-saline to fresh-water environment. Organic matter (OM) abundance indices, including total organic carbon (TOC), chloroform extracts, total hydrocarbon content (HC), hydrocarbon generation potential (S1 + S2), and OM type, show that the source rock potential for petroleum generation in the upper layers is best, that in the evaporite layers is fair, and in the lower layers it is poor. Carbon isotopes (δ13C) of hydrocarbons in the evaporite and lower layers were heavier than those in the upper layers. Thermal maturity parameters show that the thermal evolution process of OM in the upper layers was faster where evaporite were present compared with evaporite-free areas, while the thermal evolution of OM in the lower layers was slower in these regions. The high thermal conductivity of evaporites may have accelerated the thermal evolution of source rocks in upper layers and allowed hydrocarbon generation at a shallower burial depth. This resulted in the earlier appearance of the petroleum generation window compared to in evaporite-free areas. Meanwhile, the thermal evolution of OM in the lower layers was restrained, and consequently the hydrocarbon generation window was widened, which implies the potential for petroleum exploration in deep strata under the evaporite sequence. This is a common phenomenon in evaporite-bearing basins, according to previous and present studies.

Geochemical evaluation and hydrocarbon generation potential of the Upper Cretaceous–Pliocene succession, offshore Nile Delta, Egypt

The offshore Nile Delta is a prominent petroleum province; nevertheless, previous research focused mainly on evaluation of Miocene–Pliocene possible source rocks because of lack of data. The current study is the first to evaluate organic geochemical features of the Upper Cretaceous–Pliocene sequence in the western offshore Nile Delta, applying TOC, Rock-Eval pyrolysis and GC-MS procedures for 137 ditch cuttings collected from three wells. The main objectives are to infer organic richness, type of kerogen, maturation, and depositional paleoenvironment of organic matter for these possible source intervals.The analysed rock samples generally display fair to good organic enrichment. Most of these samples are enriched in Type-III and Type-II/III kerogen, suggesting a high influx of terrigenous organic matter. However, Abu Madi, Appollonia, and Khoman formations contain Type-II oil-prone kerogen, reflecting more marine organic matter, whereas Kafr El Sheikh and El Wastani cuttings display the lowest TOC contents and are more enriched in non-generating inert organic matter.Biomarker ratios indicate that Kafr El Sheikh, Abu Madi, Qawasim, and Qantara formations are rich in Type-II/III kerogen (mixed organic matter) preserved under suboxic nearshore or lacustrine depositional environments. In contrast, Sidi Salem, Tineh, Appollonia, and Khoman formations contain abundant Type-II marine-algal organic matter deposited under anoxic marine depositional settings. Vitrinite reflectance data and biomarker ratios indicate immature to peak mature rock samples. The stable carbon isotopic composition of condensate oil samples suggests nonmarine waxy oils. Ratios of n-alkanes and isoprenoids for a condensate sample from the study area reveal no similarity with the Upper Cretaceous–Pliocene rock extracts.

Organic matter enrichment and palaeoenvironmental comparison of Alinian fine-grained sedimentary rocks in lake facies

The Yan'an Formation in the Ordos Basin and the Xintiangou Formation in the Sichuan Basin are typical lake facies sedimentary formations developed in the Alinian period. They contain a large amount of organic-rich fine-grained sedimentary rocks and are the main sites for shale oil and gas enrichment. In this study, geochemical tests, including major, trace, and rare earth elements and TOC tests, were carried out on the fine-grained sedimentary rocks of the shallow lake Yan'an Formation and deep lake Xintiangou Formation to reconstruct their depositional palaeoenvironments, and to explore their organic matter enrichment mechanisms in different depositional environments under lithological differences. The conclusions of this study are as follows: 1) The total organic carbon (TOC) of fine-grained sedimentary rocks increases with increasing mud content and decreasing grain size; 2) The palaeoenvironments of the fine-grained sedimentary rocks in the shallow and deep lake facies are generally consistent, but the redox conditions and deposition rate of the water column in the deep lake facies are stronger than those in the shallow lake facies, while the input of terrigenous detrital, palaeosalinity, and stagnant environment are relatively weaker; 3) The organic matter enrichment mode of lake facies fine-grained sedimentary rocks is a typical palaeoclimatic and palaeoproductivity-dominated “Production mode”; 4) The difference in depositional environments under lithological differences is mainly related to productivity factors, such as palaeoclimate (CIA) and palaeoproductivity (P/Ti). The results of this study help to understand the formation mechanism of lake facies fine-grained sedimentary rocks, distinguish the hydrocarbon generation potential of different lithologies, and provide a basic geological theoretical basis for the exploration of shale oil and gas in the study area.