Hydrocarbon Generation Modelling Research Articles

Organic geochemical characterization and hydrocarbon generation modeling of Paleozoic-Paleogene shales, Wadi Sirhan basin, south-eastern Jordan

The Wadi Sirhan Basin in Jordan originated from the Arabian Platform and served as a stable shelf during the Paleozoic era. The Lower Paleozoic-Eocene sequence in the Wadi Sirhan Basin contains numerous shales, found, in ascending order the Upper Ordovician Dubeidib, Lower Silurian Mudawwara, Maastrichtian Ghareb, Paleocene Taqiyeh, and Eocene Sara fms. These strata warrant investigation of their source-rock potential and hydrocarbon generation modeling, to precisely elucidate the timing of petroleum generation. To achieve this, datasets were utilized from various analytical approaches, including Rock-Eval pyrolysis, visual kerogen analysis, pyrolysis-GC, and lipid biomarker geochemistry. The aim of this study is to assess these source rocks regarding organic matter quantity and quality, paleoenvironmental implications, thermal maturity, and petroleum generation depth/time. The Lower Paleozoic Dubeidib and Mudawwara shales are identified as effective source rocks, containing kerogen types II, II-III, and III. A high proportion of well-preserved, weakly fluorescent amorphous organic matter suggests an origin from marine plankton-derived alginite in an oxygen-deficient setting. These formations reached the peak oil window during the Devonian (∼405-380 Ma) and Carboniferous (∼320-300 Ma). The Dubeidib Fm experienced late-stage oil generation during the Early Triassic (∼255-250 Ma), with a transformation ratio (TR) of 68%. The Ghareb Fm predominantly contains type II kerogen, while the Taqiyeh and Sara fms mainly contain type I kerogen with minor type II kerogen. Thermal maturity assessments using integrated parameters indicate that the Dubeidib and Mudawwara shales have entered the main phase of hydrocarbon generation, while the Ghareb, Taqiyeh, and Sara shales remain immature. Furthermore, analysis of biomarker ratios reveals the dominance of marine over terrestrial organic matter in the studied strata. These clay-rich sediments were deposited under reducing conditions, which further facilitated the rearrangement of steranes into diasteranes. The modeled TRs indicate the generation and subsequent expulsion of hydrocarbons, but the absence of suitable reservoirs and/or improper trapping system, owing to the major Hercynian unconformity, led to an incomplete petroleum system in the basin. Additional investigation is required to evaluate the potential of the Early Paleozoic shales as subsurface unconventional resources, considering parameters such as brittleness index and hydraulic fracturing. This study holds important implications for future hydrocarbon exploration and development in the Wadi Sirhan Basin. The insights gained from such investigations could help mitigate the risk of petroleum exploration failures in the Wadi Sirhan Basin, guiding future exploration and development efforts towards promising approaches.

Geochemical characteristics and hydrocarbon generation modeling of the Paleogene source rocks in the Qinnan Depression, Bohai Bay Basin, China

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.

Hydrocarbon Generation and Accumulation in the Eastern Kuqa Depression, Northwestern China: Insights from Basin and Petroleum System Modeling

The eastern Kuqa Depression in the northern Tarim Basin, NW China, is rich in oil and gas. However, recent exploration has been hindered by a lack of knowledge on the evolution of the petroleum system. To address this, we conducted hydrocarbon generation and accumulation modeling using both the 2Dmove and PetroMod2017 software for a complex tectonic extrusion section in the Kuqa Depression. The results show that the source rocks in the northern slope zone became mature quite early at around 170 Ma, but the thermal maturity evolution stagnated subsequently because of tectonic extrusion and uplift. The source rocks in the central anticline zone, the southern slope zone, and the deep sag zone were of overall low maturity during the Jurassic to Paleogene but rapidly became mature to highly mature with the deposition of the Neogene Jidike and Kangcun formations. The main hydrocarbon generation periods are in the late Neogene and Quaternary, and the main hydrocarbon generation stratum is the lower Jurassic Yangxia formation. The amount of cumulative hydrocarbon generation gradually increases for carbonaceous mudstone, mudstone, and coal source rocks. Sourced from source rocks mainly in the northern slope zone, oil and gas migrated to anticlinal traps along sandstone transport layers and faults. Recent discoveries, such as the Tudong-2 gas field in the central anticline zone, underscore the richness of this region in petroleum resources. Some gas fields were also predicted in lithologic traps in the southern slope zone and the deep sag zone, as well as in fault-related traps in the northern part of the northern slope zone.

Exploitation and Utilization of Generated Oil and Gas by Pyrolysis Simulation Modeling of Shale Source Rocks under the Condition of In Situ Conversion

Previous studies have mainly focused on the source rocks of the 7th Member of Yanchang Formation (Chang 7 Member) in the Ordos Basin, with very few studies focusing on the extracts from the source rocks. These extracts have important guiding significance for studying the in situ conversion process of shale oil. Taking the shale source rock of the Chang 7 Member as an example, this paper selected the extract of shale source rock (i.e., retained oil), which has been less studied previously, as the sample to carry out the hydrocarbon-generating pyrolysis simulation experiment of a semi-open–semi-closed system. Seven groups of parallel simulation experiments were designed with a pressure of 20 MPa. The generated oil and gas were collected and quantified, and their geochemical characteristics were researched. In addition, the generated oil and gas were investigated from aspects of cumulative yield and net increased yield, and the chromatographic and mass spectral characteristics of the generated oil were also researched. Based on this, an inductive hydrocarbon generation model of retained oil in shale source rocks was established: slow hydrocarbon generation stage (300–320 °C), rapid hydrocarbon generation stage (320–360 °C), and residual oil pyrolysis stage (0.79%Ro–1.47%Ro). This study is of important significance to guide the research on the in situ conversion process of shale source rock.

An Improved Method for Evaluating Hydrocarbon Generation of Shale: A Case Study of the Lower Cretaceous Qingshankou Formation Shale in the Songliao Basin

AbstractBecause of the influence of hydrocarbons, especially adsorbed hydrocarbons, on the detection of cracked hydrocarbon (S2) and total organic carbon (TOC), the hydrogen index (HI)‐based hydrocarbon generation model deviates from actual practice. In this study, the shale in the first member of the Qingshankou Formation in the central depression of the Songliao Basin, where in northeastern China, was taken as the research object and a correction method for S2 and TOC was established. By correcting the experimental results of different maturity samples, the actual hydrocarbon generation model has been revealed, the differences before and after correction compared, and the evolutionary characteristics of the adsorbed hydrocarbon content were clarified. The results show that the organic matter enters the hydrocarbon generation threshold at Ro–0.5% and reaches the hydrocarbon generation peak at Ro–1.0% and that the hydrocarbon generation process ends at Ro–1.3%. The hydrocarbon generation model established based on the measured values has a ‘lag effect’ compared to actual values, and this extends the hydrocarbon generation window of organic matter and delays the hydrocarbon generation peak. With the increase of maturity, adsorbed hydrocarbon content shows the characteristics of ‘first increasing, then stabilizing, and then decreasing’, and reaches the most abundant stage at Ro of 0.9%–1.3%.

Low organic matter abundance and highly efficient hydrocarbon generation of saline source rock in the Qaidam Basin, NW China

The geochemical analysis and experimental simulation are comprehensively used to systematically study the hydrocarbon generation material, organic matter enrichment and hydrocarbon generation model of Paleogene source rock in the Western Qaidam Depression, Qaidam Basin, NW China. Three main factors result in low TOC values of saline lacustrine source rock of the Qaidam Basin: relatively poor nutrient supply inhibits the algal bloom, too fast deposition rate causes the dilution of organic matter, and high organic matter conversion efficiency causes the low residual organic carbon. For this type of hydrogen-rich organic matter, due to the reduction of organic carbon during hydrocarbon generation, TOC needs to be restored based on maturity before evaluating organic matter abundance. The hydrocarbon generation of saline lacustrine source rocks of the Qaidam Basin is from two parts: soluble organic matter and insoluble organic matter. The soluble organic matter is inherited from organisms and preserved in saline lacustrine basins. It generates hydrocarbons during low-maturity stage, and the formed hydrocarbons are rich in complex compounds such as NOS, and undergo secondary cracking to form light components in the later stage; the hydrocarbon generation model of insoluble organic matter conforms to the traditional “Tissot” model, with an oil generation peak corresponding to Ro of 1.0%.

Quantitative effect of kerogen type on the hydrocarbon generation potential of Paleogene lacustrine source rocks, Liaohe Western Depression, China

Kerogen types exert a decisive effect on the onset and capacity of hydrocarbon generation of source rocks. Lacustrine source rocks in the Liaohe Western Depression are characterized by thick deposition, high total organic carbon (TOC) content, various kerogen types, and a wide range of thermal maturity. Consequently, their hydrocarbon generation potential and resource estimation can be misinterpreted. In this study, geochemical tests, numerical analysis, hydrocarbon generation kinetics, and basin modeling were integrated to investigate the differential effects of kerogen types on the hydrocarbon generation potential of lacustrine source rocks. Optimized hydrocarbon generation and expulsion (HGE) models of different kerogen types were established quantitatively upon abundant Rock-Eval/TOC/vitrinite reflectance (Ro) datasets. Three sets of good–excellent source rocks deposited in the fourth (Es4), third (Es3), and first (Es1) members of Paleogene Shahejie Formation, are predominantly types I–II1, II1–II2, and II–III, respectively. The activation energy of types I–II2 kerogen is concentrated (180–230 kcal/mol), whereas that of type III kerogen is widely distributed (150–280 kcal/mol). The original hydrocarbon generation potentials of types I, II1, II2, and III kerogens are 790, 510, 270, and 85 mg/g TOC, respectively. The Ro values of the hydrocarbon generation threshold for type I–III source rocks gradually increase from 0.42% to 0.74%, and Ro values of the hydrocarbon expulsion threshold increase from 0.49% to 0.87%. Types I and II1 source rocks are characterized by earlier hydrocarbon generation, more rapid hydrocarbon expulsion, and narrower hydrocarbon generation windows than types II2 and III source rocks. The kerogen types also affect the HGE history and resource potential. Three types (conventional, tight, and shale oil/gas) and three levels (realistic, expected, and prospective) of hydrocarbon resources of different members in the Liaohe Western Depression are evaluated. Findings suggest that the Es3 member has considerable conventional and unconventional hydrocarbon resources. This study can quantitatively characterize the hydrocarbon generation potential of source rocks with different kerogen types, and facilitate a quick and accurate assessment of hydrocarbon resources, providing strategies for future oil and gas exploration.

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.

Geochemistry of carbonate-derived oils in the Seram Basin, eastern Indonesia: A new hydrocarbon generation, migration, and preservation model for exploration in fold-thrust belts

Geochemistry of carbonate-derived oils in the Seram Basin, eastern Indonesia: A new hydrocarbon generation, migration, and preservation model for exploration in fold-thrust belts

Hydrocarbon generation modelling in the Permian and Triassic strata of the Polish Basin: implications for hydrocarbon potential assessment

Hydrocarbon generation modelling in the Permian and Triassic strata of the Polish Basin: implications for hydrocarbon potential assessment

A comparison of hydrocarbon generation and expulsion in carbonate and argillaceous source rocks using semi-open pyrolysis experiments

To investigate the hydrocarbon generation and expulsion efficiency from carbonate and argillaceous source rocks, a series of pyrolysis experiments were conducted on two representative samples with Type II kerogen in a semi-open simulation system. The shale sample was obtained from the Upper Cretaceous Second White Speckled Shale Formation, while the carbonate sample was collected from the Middle Devonian Brightholme Member of the Winnipegosis Formation, both from the Western Canada Sedimentary Basin. The results show that the carbonate has a higher hydrocarbon generation capacity than the shale. During the pyrolysis, the expelled hydrocarbons from the carbonate were about 100–200 mg/g TOC higher than the hydrogen index reduction, while the amount of expelled hydrocarbons from the shale was generally lower than the hydrogen index reduction. The peak oil generation from the carbonate occurred earlier than that from the shale, but the oil expulsion efficiency was lower. However, a larger quantity of unexpelled oil retained in the carbonate was conducive to later oil expulsion, more hydrocarbon gas generation, and slightly higher gas expulsion efficiency than for the shale. Although hydrocarbon gases generated from both sources share similar evolution trends with heating, the relative proportions of CO2 and methane differ significantly between the two lithologies, with much higher abundance of CO2 in shale pyrolysate. The carbon loss during maturation of the two source rocks is very similar during the oil generation window, but the carbon loss trend was reversed in shale after the onset of gas generation, due to the conversion of some bitumen to pyrobitumen. Conversely, carbon loss continued in the carbonate to a higher maturity stage. This difference can be attributed to the occurrence of different organic matter types in the carbonate, including dispersed organic matter, aggregated organic matter, crystal-enclosed organic matter, and inclusion-hosted organic matter. These various organic matter types contribute to continuous oil and gas expulsion over a much wider maturity range than shale. Although the two samples chosen for this study do not encompass the entire range of carbonate and shale formations, the established hydrocarbon generation and expulsion models and evaluation criteria for argillaceous source rocks may not be directly applicable to carbonates, particularly at high maturity stages. These valuable insights have significant implications for oil and gas exploration in diverse geological settings. The research highlights the tendency of carbonate source rocks to experience higher organic carbon loss during maturation compared to argillaceous rocks. This suggests that certain low-TOC, highly mature carbonate source rocks can potentially serve as effective hydrocarbon source rocks if successful oil expulsion occurs. These findings underscore the need to take into account the distinctive characteristics of carbonate source rocks when developing strategies for hydrocarbon exploration and production.

Distribution characteristics of organic matter in the Fengcheng Formation in Mahu Sag, Junggar Basin: implications for hydrocarbon generation model in alkaline lacustrine deposition

Alkaline lacustrine deposits are known for their high primary productivity, unique aquatic environments, and sedimentary patterns, which are conducive to the formation and preservation of organic matter. Consequently, related source rocks have significant hydrocarbon generation potential. The study of hydrocarbon source rocks in the Fengcheng Formation of the Mahu Sag in the Junggar Basin serves as a good example for understanding organic matter enrichment and hydrocarbon generation characteristics of such alkaline lacustrine deposits source rocks. However, the characteristics of organic matter and hydrocarbon generation model in the source rocks of Fengcheng Formation lack systematic research, thus hindering exploration planning and favorable area selection. In this study, analysis of mineral content based on X-ray diffraction and organic geochemical analysis were employed, along with systematic observations of bio-precursor types under fluorescence microscopy. Based on mineral identification and quantitative statistics, the Fengcheng Formation was classified into three zones according to different alkaline mineral assemblages: an inner zone dominated by sodium carbonate minerals, a transitional zone with higher borosilicate mineral content, and a marginal zone characterized by abundant calcite deposition. The inner zone is characterized by the presence of lamalginite and telalginite, which are influenced by high pH values and changes in water depth, and exhibit high maturity characteristics. The transitional zone exhibits high total organic carbon (TOC) values, with predominantly type I and type II1 kerogen. Under fluorescence, the main components were observed to be lamalginite and telalginite, with their distribution being influenced by high salinity and ash supply. The marginal zone has relatively lower TOC than the previous two zones, which is dominated by type II2 kerogens, and contains a certain quantity of terrigenous inertinite supply. The hydrocarbon generation patterns of lamalginite and telalginite are consistent with the bimodal efficient hydrocarbon generation model observed in the source rocks of Fengcheng Formation, revealing the unique hydrocarbon generation model of organic matter in alkaline lacustrine source rocks. This research has significant implications for the exploration strategy of the alkaline lacustrine deposits in the Fengcheng Formation and similar oil- and gas-bearing basins.

Long-lived paleo-uplift controls on Neoproterozoic–Cambrian black shales in the Tarim basin

Neoproterozoic–Cambrian black shales are one of the most important hydrocarbon source rocks worldwide, including in the Shunbei and Fuman regions in the Tarim Basin, China. However, the hydrocarbon generation from these shales is complex, with liquid petroleum found in reservoirs at depths of 6000–8000 m. Based on drilling, seismic, and well testing data, the ultra-deep tectonic evolution of the northern Tarim Basin, and its effects on hydrocarbon generation from black shales were investigated. During the Neoproterozoic, the northern Tarim Basin was filled with rift and passive continental margin sedimentary rocks between the north and central Tarim paleo-uplifts. A sequence of lower Cambrian black shales was developed on the slope around the paleo-uplifts over a wide area, which are thick and have high contents of total organic carbon. Even after multiple stages of tectonism, including the Caledonian, Hercynian, Indosinian, Yanshanian, and Himalayan orogenies, the north (Tabei) and central paleo-uplifts were preserved. The Caledonian, Hercynian, and Himalayan orogenies were the main periods of hydrocarbon generation. Four hydrocarbon-generation models were established, which are the Tabei-, Bachu-, Tazhong-, and Tadong-types. The current Ro values of the Tabei-type black shales are 1.0%–1.5%, whereas those of the Bachu-, Tazhong-, and Tadong-type black shales are >2.0%. Due to the long-lived paleo-uplifts and short-lived deep burial during the Himalayan Orogeny, the Tabei-type black shale is in the oil and early gas generation stage, which obviously differs from the over-mature Cambrian and Ordovician black shales in South China. Therefore, the long-lived paleo-uplifts not only affected the deposition and distribution of black shale, but also hydrocarbon generation processes and the depth limit of active source rock. The thermal evolution of black shale in the ultra-deep Tarim Basin requires further investigation.

Oligocene source-rock characteristics and hydrocarbon generation modeling of the eastern Nile delta, Egypt

This study investigates Oligocene source rock development in the eastern Nile Delta, integrating TOC, Rock-Eval pyrolysis, as well as vitrinite reflectance (Ro%) measurements from over 9 onshore and offshore wells. 1D basin models, constructed for 2 wells onshore and 2 wells offshore, investigate the burial, thermal histories, and the stage and timing of hydrocarbon generation. The present-day data indicate that the Oligocene section encompasses Type III and rarely Type IV kerogen onshore, whereas offshore Type III and Type II-III kerogen dominate. The back-calculated original TOCo and HIo values indicate a significant hydrocarbon generation (i.e. effective to relic source rock) for Rupelian section in Tayifah Deep-1x and Satis-1 wells. The different maturity indicators used here show significant differences in some intervals. The variability may be attributed to natural impregnation of migrated hydrocarbon in permeable strata, in-situ expelled hydrocarbons where S2 contamination is rather likely for samples within the oil window, or retarded Ro% and/or Tmax caused by overpressure. Therefore, thermal and generation models are calibrated with measured bottomhole temperatures, which match quite well with δ13C values of gases C1-3, and indicate that the onshore Oligocene basal section comes in the early stage of hydrocarbon generation throughout the middle-late Miocene, and was in the main stage of hydrocarbon generation since the early Pliocene. The transformation ratio indicates an in-situ expulsion (25–50%) since the Pleistocene time. Offshore models indicate the basal Oligocene section entered the late phase of hydrocarbon generation during the early to middle-late Miocene, where its transformation ratio exceeds 50%. This indicates the main hydrocarbon expulsion from the late Oligocene to the early-middle Miocene time. Further integrated approaches to the Oligocene geochemical analysis after solvent extraction are vastly required. Higher resolution overpressure and maturity indices (Tmax and Ro) profiles for some deep sections are essential to strengthen concepts about the mechanism(s) and magnitude of their retardation/suppression.

Thermal Evolution, Hydrocarbon Generation, and Heat Accumulation of a High Geothermal Coalfield: A Case Study of Pingdingshan Coalfield, China.

As an important energy base in central China, the Pingdingshan coalfield has abundant coal and geothermal resources. The cooperative exploration of coal and geothermal resources is significant for the comprehensive utilization of energy resources. This work collected coal-bearing samples from the Pingdingshan coalfield to investigate the tectono-thermal evolution of a high geothermal coalfield, especially the present geothermal field and hydrocarbon generation model. The geochemical results show that the Shanxi and Taiyuan source rocks have average R o values of 0.88 and 0.97%, respectively, with an average Rock-Eval T max value of 442 °C. Hydrocarbon generation of source rocks started at ∼205 Ma, with the highest rates at ∼170 Ma, reaching the maximum transformation ratio of 40-50% in the middle of the Early Cretaceous. The age and length of apatite fission tracks (AFTs) indicate that coal-bearing strata underwent significant post-depositional annealing after the Late Permian and suggest an abnormal thermal event that occurred in the Late Mesozoic. Meso-Cenozoic thermal event was mainly caused by the plutonic metamorphism of the Early Jurassic and magmatic thermal metamorphism of the Early Cretaceous, achieving a maximum paleotemperature of ∼140 °C. The magmatic thermal event resulted from the intensive post-orogenic extension of the Qinling-Dabie Orogenic Belt caused by the tectonic transition of the North and South China Plates. The present-day high geotemperature of Pingdingshan Coalfield is dominated by the horst structure caused by the regional extension of the basin-mountain system. The Cambrian limestone with a high thermal conductivity underlying coal measure collects deep heat, forming a heat accumulation center of this horst structure with a heat flow of 74 mW/m2 and a maximum temperature of ∼50 °C nowadays.

Multistage Hydrocarbon Generation of Saline Lacustrine Source Rocks in Hydrous Pyrolysis: Insights from Clay Mineral-Organic Matter Interactions.

The organic matter (OM) in shale is closely associated with clay minerals, and its maturation is usually accompanied by the diagenesis of these minerals, especially smectite illitization. However, the effect of mineral transformation and its accompanying change of mineral-OM interactions in shale on hydrocarbon generation is still unclear. To investigate this question, smectite-rich immature shale was selected to carry out hydrous pyrolysis. Organic geochemistry and mineralogy of pyrolysates at different temperatures show that the maturation of OM is accompanied by the transformation of bulk and clay minerals. Based on the change in hydrocarbon yield, Rock-Eval parameters, and mineral composition, hydrocarbon generation in this study is divided into three stages: 25-300, 300-400, and 400-500 °C, which are the result of the synergistic evolution of clay minerals and OM. Multistage hydrocarbon generation can be attributed to the mineral transformation-induced desorption of mineral-bound soluble OM (SOM), decarboxylation and hydrocracking of kerogen promoted by solid acids, and cross-linking and cracking reactions of free SOM and residual kerogen under high temperatures. Although different from the classical hydrocarbon generation model of kerogen, this multistage hydrocarbon generation is consistent with the characteristics of the saline lacustrine source rocks in nature. The mineral transformation-induced desorption of SOM is a new pathway for petroleum formation, which can well explain the formation of low-mature oils in nature. In addition, the release of mineral-bound and kerogen-bound biomarkers results in two reversals of isomerization ratios. Considering mineral transformation and mineral-OM interactions can help us better understand and refine the hydrocarbon generation theory of OM.

Hydrocarbon generation and organic matter enrichment of limestone in a lacustrine mixed sedimentary environment: A case study of the Jurassic Da'anzhai member in the central Sichuan Basin, SW China

The hydrocarbon generation effectiveness of lacustrine limestone has been gradually proven. The Da'anzhai Member limestone is the most important Jurassic oil-producing layer in the central Sichuan Basin, and the characteristics of limestone organic matter are often overlooked. 175 typical samples of different lithologies from 19 wells were systematically analyzed to determine hydrocarbon generation, controlling factors and formation models by analyses of organic matter, minerals, elements, isotopes and petrography. (1) Lacustrine paleoenvironments can be beneficial for the enrichment of organic matter in limestone. A favorable environment would be a quiet, low-energy zone in a warm and humid climate with an appropriate supply of terrestrial inputs. (2) Lacustrine limestone has a higher organic matter conversion rate, and a lower hydrocarbon generation threshold than argillaceous source rocks, and can be effective source rock. (3) The mud-bearing shell limestone from the forebeach to the lake slope is thick, with a relatively high abundance of organic matter, and its hydrocarbon generation is effective. This study can clarify the effectiveness and enrichment of the limestone organic matters in the study area, and contribute to an understanding of hydrocarbon generation for full-rock system in a lacustrine mixed sedimentary environment.

Natural gas potential of Neogene source rocks in the Yiliping area, Qaidam Basin: Using an improved hydrocarbon generation and expulsion model based on least‐squares Monte Carlo

The Neogene petroleum system in the Yiliping area of the Qaidam Basin presents great prospects for natural gas exploration. However, its natural gas potential, including the source rock characteristics, is insufficient. Due to a lack of geological constraints, the hydrocarbon generation and expulsion (HGE) model, which is widely used in resource potential evaluation, may be unable to obtain optimal parameters. Here, we propose an improved HGE model based on least‐squares Monte Carlo to assess the HGE characteristics and natural gas resource potential of the Neogene source rocks in the Yiliping area by combining geological and geochemical investigations. The findings show that the Neogene source rock is effective and has significant potential for natural gas generation. Algae and bacteria, which were deposited in a saline and anoxic environment, are the primary sources of organic matter in Neogene source rock (primarily Type II and Type III). Modelling work suggests that Type II and III kerogen of Neogene source rock reach hydrocarbon generation threshold (HGT) at Ro = 0.38% and Ro = 0.49% and reach hydrocarbon expulsion threshold (HET) at Ro = 0.45% and Ro = 0.55%. The maximum HGE intensities are 3400 × 104 and 3378 × 104 t/km2. The extra‐source natural gas and shale gas resource potentials are predicted to be 2.05 × 1012 m3 to 4.11 × 1012 m3 and 7.03 × 1012 m3. The findings will guide future Neogene natural gas exploration in the Yiliping area of the Qaidam Basin.

A Data-Driven Approach to the Unified Evaluation of Conventional and Unconventional Hydrocarbon Resources: Application to Low-Mature to Mature Source Rocks in the Liaohe Western Depression

Hydrocarbon potential evaluation is a high priority in oil/gas exploration which is significantly influenced by evaluation methods and subjective cognition. With the aim of quantitatively establishing a hydrocarbon generation and expulsion (HGE) model of source rocks, a data-driven approach is proposed based on abundant and readily available Rock-Eval/total organic carbon content (TOC)/vitrinite reflectance (VRo) datasets. This approach takes into account the original hydrocarbon generation potential (GPIo) and the loss of TOC. Hydrocarbon generation simulation was also adopted in this study. This data-driven method was applied to the Lower Paleogene Shahejie Formation (Es4), which has three sets of superior source rocks (average thickness > 250 m, TOC > 3%). The GPIo of the Es4 low-maturity source rock was 600 mg HC/g TOC. The initial maturity values of hydrocarbon generation and expulsion were 0.36% and 0.46%, respectively. The Gaosheng sub-member of the Es4 source rock had the largest amount of hydrocarbon generation but a limited amount of hydrocarbon expulsion, implying a favorable exploration of shale oil resources. By contrast, the values of the conventional, unconventional tight, and shale oil resource potentials of the Niuxintuo sub-member were 3.20 × 107, 7.70 × 107, and 5.93 × 108 t, respectively, indicating good prospects for tight oil and shale oil exploration. A comparison between the previous method and the data-driven method showed considerable differences in the restoration of GPIo and TOC, and both had their own limitations. This data-driven approach provides a quick and valid source rock evaluation method and can greatly enhance the accuracy of resource assessment.

Hydrocarbon generation and expulsion modeling of different lithological combination source rocks from the Funing Formation in the Subei Basin

The oil expulsion efficiency and retention efficiency of shale affect the enrichment and preservation of shale oil. Two series of semi-closed hydrous pyrolysis experiments were performed under in situ geological conditions on a Paleogene shale sample as a comparable analog to evaluate the generation and preservation potential of shale oil in the Funing Formation shale in the Subei Basin. The results show that 1) the oil-generation capacity evolution of different lithological combination source rocks in the Funing Formation of the Subei Basin can be roughly divided into four stages: a) relatively slow oil-generating and slow gas-generating, b) relatively fast oil-generating and slow gas-generating, c) oil cracking into gas, and d) kerogen cracking into gas; 2) different lithological combinations have different hydrocarbon generation, expulsion, and retention efficiencies. The total oil generation rate and gas generation rate of pure shale are higher than those of shale with a silty interlayer, and the exchange point between the oil expulsion rate and retention rate of pure shale is earlier than that of shale with the silty interlayer, which indicates that the pure shale experienced the expulsion and retention process earlier. Oil retention mainly occurs at an EqVRo of 0.84%–1.12%, while oil is mainly discharged to the adjacent siltstone at an EqVRo of 1.12%–1.28%. Based on the simulation under geological conditions, it is recognized that for shale oil exploration in the Subei Basin, the favorable thermal maturity is at an EqVRo of 0.84%–1.12%, and the favorable lithology is the shale with the silty interlayer. On one hand, the siltstone interlayer can provide pore space for the early generated oil, and the concentration difference of hydrocarbons between the shale and the interlayer can be formed so that the generated shale can continuously enter the interlayer. On the other hand, the shale above the interlayer can be used as a cap rock to preserve shale oil. The favorable area for shale oil exploration in the Subei Basin is the area with relatively high maturity (at a VR value of about 1.1%)