Hydrocarbon Generation Capacity Research Articles

Understanding the burial history and the hydrocarbon potential of the late Paleozoic Claromecó foreland Basin (Southwestern Gondwana, Argentina) by combining organic geochemistry, organic petrology, and thermal modeling

The Claromecó foreland Basin (Carboniferous–Permian; southern Buenos Aires province, Argentina) is key to understanding the paleotectonic evolution of the southwestern Gondwana margin and is relevant to energy resource exploration. This study reconstructs the thermal and burial history of the Claromecó Basin by integrating geochemical data, organic petrology, and thermal modeling techniques. Cores samples of the Tunas Formation (Pillahuincó Group, Early Permian) were studied. A 1D thermal model was constructed, calibrated with vitrinite reflectance measurements (VRo %), and corroborated with fluid inclusion and apatite fission track data from previous studies. Rock-Eval pyrolysis results show TOC% values ranging from 0.13 to 60.35 wt%. The Hydrogen index (HI < 50 mg HC/g TOC) and Oxygen index (OI < 50 mg CO2/g TOC) indicate the dominance of Type III and Type IV kerogens, most likely resulting from the thermal maturation of an original Type III kerogen. Petrologic observations confirm the presence of macerals from the inertinite group, as well as minor amounts of vitrinite and liptinite. The Tmax displays a temperature range mostly from 460 to 610 °C. The VRo % values range from 1.5 to 2.0%. Geochemical data combined with VRo % measurements confirm a late catagenesis to metagenesis stage within the wet to dry gas window for coals and organic-rich strata.In order to constrain the thermal evolution of the basin infill, different scenarios were tested by varying the heat flow and the missing section thickness associated with the uplift and erosion of the basin (Permian–Cenozoic unconformity). The best calibration results were obtained with an erosion thickness of 3000 up to 4200 m and paleo heat flow peaks of either 60 or 80 mW/m2 during the Lower Permian–Lower Cretaceous. The Tunas Formation was deposited and buried during the Permian–Triassic (Gondwanides Orogeny phase), reaching a maximum temperature of 180 °C. The results obtained by combining geochemical analysis, organic petrology, and thermal modeling techniques indicate that the coal beds of the Tunas Formation could have a current potential as gas-prone source rocks. Despite that, the hydrocarbon generation capacity of coal levels is currently low due to the high percentage of residual (Type IV) kerogen. Further research could help clarify if the hydrocarbons potentially expelled by these source rocks have been lost due to migration or could be trapped somewhere in the basin.

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&amp;gt;Es1&amp;gt;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.

Understanding the hydrocarbon‒generation potential on jurassic coal-measure source rocks in the Junggar Basin: From the perspective of hydrogen-rich molecular structure

The Jurassic coal-measure source rocks in the Junggar Basin have drawn considerable attention in recent years. In our hydrocarbon thermal simulation experiments of these rocks, we found that the dark mudstone evaluated as good source rock, had a much lower hydrocarbon generation capacity than the coal and carbonaceous mudstone, evaluated as poor source rock. Based on this background, we performed Fourier transform infrared spectroscopy (FTIR) and combined the results of semi‒open thermal simulation experiments to explore the association between the molecular structure and hydrocarbon production capacity, with the aim of obtaining a new understanding of hydrocarbon potential of Jurassic coal‒measure source rocks from the perspective of molecular structure. The results indicate that coals exhibit lower condensation of aromatic structures and higher relative abundance of aliphatic structures with a higher degree of branched chaining than mudstones and carbonaceous mudstones. Apparent aromaticity (fa), aromatic abundance parameter I, and degree of condensation (DOC) are negatively correlated with organic matter abundance. The aliphatic structural parameter H demonstrates a substantial positive correlation with organic matter abundance. Furthermore, aliphatic relative abundance factor A is associated with the type of organic matter; the better is the type of the organic matter, the larger is the A value. The combination of the molecular structures with the thermal simulation results shows that the aliphatic hydrogen enrichment of selected carbonaceous mudstone is similar to that of coal. However, the relative abundance of the aliphatic group of it is high, and the DOC of the aromatic structure is low, making the hydrocarbon generation base stronger and easier to crack. Thus, the hydrocarbon generation capacity of carbonaceous mudstone is slightly higher than that of coal. Mudstone has low H and I values, and the DOC is high, indicating that its hydrocarbon base is low, so it has low hydrocarbon generation capacity. Therefore, the molecular structure is closely associated with the hydrocarbon potential of coal‒measure source rocks. When evaluating the qualities of coal-measure source rocks, the influence of molecular structure on these rocks should be considered.

Hydrocarbon Geological Characteristics and Factors Controlling Hydrocarbon Accumulation of Jurassic Da’anzhai Continental Shale

Continental shale in China is a key exploration target with regard to unconventional hydrocarbons. Systematic research on the mineral composition, organic geochemistry, and hydrocarbon mobility has been performed in the Da’anzhai (J1dn) lacustrine shale oil reservoirs, clarifying the factors controlling shale oil accumulation. The results suggest that J1dn consists of three sub-members, with an organic-rich interval developed within the second sub-member. Three types of lithological associations have developed within the organic-rich interval: Type 1 represents the interbedding relationship between shale and shell limestone and Type 2 represents shale with intercalated limestone, followed by Type 3. The brittleness index of the J1dn continental organic-rich shale is relatively low. The porosity of the Da’anzhai lacustrine shale ranges between 0.5% and 10.5% (average value of 5.89%). The porosity is predominantly due to inorganic pores, with a small amount being attributable to nanoscale microfractures and organic pores. The average porosity of the shell limestone is only 1.2%, but fractures at the micron and centimeter scales are well developed. The organic matter in the J1dn continental shale is mainly II1–II2, with maturity in the oil generation stage. The average oil saturation of the J1dn continental shale is 3.15%, with most samples having oil saturation of less than 4%. The J1dn continental shale has great exploration potential with regard to shale oil. Type 1 shale oil is affected by multiscale fractures, including bedding fractures, and has the best mobility. The high hydrocarbon generation capacity of lacustrine shale, coupled with the multiscale fractures within shell limestone and shale, is the principal controlling factor for hydrocarbon enrichment. Based on exploration practices, the Type 1 shale association may represent the optimal interval for future shale oil exploration in the Da’anzhai Member.

Characteristics of Hydrocarbon-Generating Pressurization in Shale Series of Fengcheng Formation in the West and South of Mahu Sag, the Junggar Basin, China

Formation overpressure is an important controlling factor for the formation of high-yield oil reservoirs in the shale series of the Permian Fengcheng Formation in the west and south of Mahu Sag, the Junggar Basin. Hydrocarbon-generating pressurization (HGP) is an important cause of overpressure in the shale series of Fengcheng Formation, but the evidence for this viewpoint is insufficient. There is still no systematic study on the quantitative calculation and distribution characteristics of HGP in the Fengcheng Formation shale series. The control effect of HGP on the formation of high-pressure and high-yield reservoirs is still unclear. Therefore, by using the data of mudstone logging and measured formation pressure, the causes of overpressure in the Fengcheng Formation shale series are clarified. The predicted organic matter abundance, the predicted maturity and thickness of source rocks, and the statistical ratios of mudstone thickness to formation thickness in each section of Fengcheng Formation are used for HGP of shale series. Combined with the physical characteristics of reservoir rocks and the geochemical characteristics of oil, the control effect of HGP on the formation of high-pressure and high-yield reservoirs is analyzed. The results indicate the following: (1) The organic matter abundance and the thickness of source rocks predicted by the logging data gradually decrease from the eastern lake basin area to the western slope area. (2) The HGP of shale series in Fengcheng Formation is related to the hydrocarbon generation capacity and the overpressure preservation conditions of the source rocks. The HGP can be quantitatively predicted by comprehensively using the organic matter abundance, the maturity, the thickness of source rocks, and the ratios of mudstone thickness to formation thickness. (3) The HGP in the Fengcheng Formation shale series also gradually decreases in distribution characteristic from the eastern lake basin area to the western slope area. (4) The oil accumulation mode of the Fengcheng Formation shale series is that, with the drive of overpressure, the oil migrates slightly within the layer, and finally accumulates to form the oil reservoir. The research results are helpful to understand the distribution characteristics of HGP and the formation mechanism of high-pressure and high-yield reservoirs in the shale series of Fengcheng Formation in the west and south of Mahu Sag, and are of great significance to guide the exploration and development of shale oil and tight oil.

Controlling factors and models of shale oil enrichment in Lower Permian Fengcheng Formation, Mahu Sag, Junggar Basin, NW China

Based on the combination of core observation, experimental analysis and testingand geological analysis, the main controlling factors of shale oil enrichment in the Lower Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin are clarified, and a shale oil enrichment model is established. The results show that the enrichment of shale oil in the Fengcheng Formation in the Mahu Sag is controlled by the organic abundance, organic type, reservoir capacity and the amount of migration hydrocarbon in shale. The abundance of organic matter provides the material basis for shale oil enrichment, and the shales containing types I and II organic matters have good oil content. The reservoir capacity controls shale oil enrichment. Macropores are the main space for shale oil enrichment in the Fengcheng Formation, and pore size and fracture scale directly control the degree of shale oil enrichment. The migration of hydrocarbons in shale affects shale oil enrichment. The shale that has expelled hydrocarbons has poor oil content, while the shale that has received hydrocarbons migrated from other strata has good oil content. Lithofacies reflect the hydrocarbon generation and storage capacity comprehensively. The laminated felsic shale, laminated lime-dolomitic shale and thick-layered felsic shale have good oil content, and they are favorable lithofacies for shale oil enrichment. Under the control of these factors, relative migration of hydrocarbons occurred within the Fengcheng shale, which leads to the the difference in the enrichment process of shale oil. Accordingly, the enrichment mode of shale oil in Fengcheng Formation is established as “in-situ enrichment” and “migration enrichment”. By superimposing favorable lithofacies and main controlling factors of enrichment, the sweet spot of shale oil in the Fengcheng Formation can be selected which has great significance for the exploration and development of shale oil.

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.

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.

Variational Reservoir Characteristics of the Wufeng-Longmaxi Formation from Different Sedimentary Region and Its Implications in Southeastern Sichuan Basin, China.

Shale gas plays a far-reaching role for meeting the worldly increasing energy demand; however, shale gas development exhibits variable situations for a same geological formation at different sedimentary locations, for example, Wufeng-Longmaxi shale. This work introduced three shale gas parameter wells-target strata of Wufeng-Longmaxi shale-aiming to explore the diversity of reservoir characteristics and its implication. Herein, the mineralogy, lithology, organic matter geochemistry, and trace element analyses of the Wufeng-Longmaxi formation in the southeast Sichuan Basin were evaluated in detail. Meanwhile, this work analyzed the deposit source supply, original hydrocarbon generation capacity, and sedimentary environment of Wufeng-Longmaxi shale. The results show that abundant siliceous organisms may be involved in the shale sedimentation process in the YC-LL2 well. Besides, the hydrocarbon generation capacity of shale in the YC-LL1 well is better than that in the YC-LL2 and YC-LL3 wells. Moreover, the Wufeng-Longmaxi shale in the YC-LL1 well was formed in a strongly reducing and hydrostatic environment, while that in the YC-LL2 and YC-LL3 wells is in a relatively weakly redox environment with poor conditions to preserve organic matter. Hopefully, this work offers salutary information for development of shale gas from a same formation but sedimented from different locations.

Overcoming the trap of pyrolysis analyzes of hydrocarbon potential based on palynofacies analysis

Hydrocarbon generation of source rocks is controlled by both the source and evolution of organic matter (OM). Pyrolysis parameters are often used to reflect the hydrocarbon generation capacity. In Dongying sag, the ratio of hydrocarbon generation between the lower Es3 and upper Es4 submember is 1:3, but the pyrolysis parameters cannot accurately reflect this difference. The source, preservation and evolution of OM of the lacustrine mudrocks in the Dongying Sag were studied by palynofacies analysis. The palynofacies can be divided into five types (PF1 to PF5), among which PF5 and PF4 are rich in terrestrial plant tissue fragments and macrophytes fragments, respectively, with weak hydrocarbon generation ability. PF1, PF3 and PF2 are enriched in different types of amorphous organic matter (AOM), respectively. The first two types of OM assemblages are mainly preserved in rocks as particulates with a low degree of evolution, while PF2 is rich in spongy AOM, closely bound with minerals and highly evolved. Differences in preservation methods have affected the evolution of OM, which cannot be accurately reflected by pyrolysis parameters. Further comparing the OM composition each layer, it is found that source rocks in the middle Es3 submember are rich in PF4 and PF5 with weak hydrocarbon generation capacity, which are in line with a poor performance of pyrolysis parameters. The lower Es3 submember is enriched with “particulate” PF1 and PF3, the evolution degree of OM is low, while the upper Es4 is enriched with “mineral-bound” PF2 with higher OM maturation and higher hydrocarbon potential. In general, hydrocarbon generation potential of source rocks is jointly controlled by multiple factors including the source, preservation and evolution of OM. Comprehensive analysis combined with palynofacies and pyrolysis methods is needed to accurately judge the hydrocarbon generation capacity of source rocks.

Discussion on Transitional Shale Gas Accumulation Conditions from the Perspective of Source-Reservoir-Caprock Controlling Hydrocarbon: Examples from Permian Shanxi Formation and Taiyuan Formation in the Eastern Margin of Ordos Basin, NW China

Transitional shale gas, rich in resources, is expected to be a practical contributor to the increase in shale gas reserves and production in China. Its exploration prospect has been demonstrated by several wells in the Daning-Jixian block on the eastern margin of the Ordos Basin. In this paper, the Lower Permian Shanxi Formation (P1s) and Taiyuan Formation (P1t) in the eastern margin of Ordos Basin were compared for organic geochemical parameters, revealing that the overflow fan + lagoon combination (OLC) of the third sub-member of the second member of Shanxi Formation (P1s23) and the marine + lagoon combination (MLC) of the first member of Taiyuan Formation (P1t1) are the most favorable shale gas intervals. The two intervals were comparatively analyzed with respect to mineral composition, brittleness, caprocks, and preservation conditions. It is found that the OLC of P1s23 has a similar porosity to and much lower permeability than the MLC of P1t1 (or MLC1) and a BET surface area of 10–15 m2/g, which is smaller than the MLC1 (15–20 m2/g). Moreover, OLC has a brittle mineral content equivalent to MLC1 but a brittleness index of 33.73–62.36 (avg. 49.86), smaller than MLC1 (53.34–58.27, or avg. 55.85). OLC contains sandstones at both the roof and floor, with a higher permeability than shale in the interval, which cannot serve as good physical seals. In contrast, MLC1 contains limestones with lower permeability at the roof and floor, which, together with the overlying coal seams, have hydrocarbon generation capacity and can physically seal the MLC1 shale but also fill it with hydrocarbons, making MLC1 have higher gas content and superior for shale gas exploration than the OLC shale. Due to the multi-lithologies developed in transitional facies, besides the organic matter enrichment, and reservoir characteristics, it is necessary to find a suitable lithological combination to ensure the gas in shale can be better preserved and retained.

Resin composition: An indicator of oil maturity as revealed by fourier transform ion cyclotron resonance mass spectrometry

A pyrolysis experiment was carried out on a Dongying Depression kerogen sample to separate the resin from the oil. Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) with a positive-ion detector was used to detect the relative proportional changes in the compounds of the resin. During the whole pyrolysis experiment, the relative ratio of resin exceed 10% of the soluble component at each temperature point. Five compounds were detected from the resin: N1, N1O1, N1O2, O1, and O2. To research the changes in the proportions of the compounds during pyrolysis clearly, these five compounds were divided into three classes: N1, N1Ox, and Ox. The N1 class has the largest proportion in resin at the beginning of the pyrolysis, while Ox class has the least proportion. And the relationship between the number and the molecular mass of three classes compound was researched. With increasing maturity, the proportion of N1 and the N1Ox class decreased rapidly, while the Ox class increased slowly. Through researching these resin compounds, it was found that an inversion in the proportions of above three compounds appeared at the end of the oil window. At the same time, we found that the DBE and carbon number of resin compounds have changed obviously during the pyrolysis: the DBE increased, while the carbon number decreased significantly. And the details of the change of each compound have been research. This research extends our knowledge of judging the maturity of crude oil during the pyrolysis through the characteristics of compounds in resin and provides the new index based on resin for the evaluation of thermal evolution stage and hydrocarbon generation capacity of source rocks.

Upper Paleozoic total petroleum system and geological model of natural gas enrichment in Ordos Basin, NW China

Based on the analysis of Upper Paleozoic source rocks, source-reservoir-caprock assemblage, and gas accumulation characteristics in the Ordos Basin, the gas accumulation geological model of total petroleum system is determined. Then, taking the Carboniferous Benxi Formation and the Permian Taiyuan Formation and Shanxi Formation as examples, the main controlling factors of gas accumulation and enrichment are discussed, and the gas enrichment models of total petroleum system are established. The results show that the source rocks, faults and tight reservoirs and their mutual coupling relations control the distribution and enrichment of gas. Specifically, the distribution and hydrocarbon generation capacity of source rocks control the enrichment degree and distribution range of retained shale gas and tight gas in the source. The coupling between the hydrocarbon generation capacity of source rocks and the physical properties of tight reservoirs controls the distribution and sweet spot development of near-source tight gas in the basin center. The far-source tight gas in the basin margin is mainly controlled by the distribution of faults, and the distribution of inner-source, near-source and far-source gas is adjusted and reformed by faults. Generally, the Upper Paleozoic gas in the Ordos Basin is recognized in four enrichment models: inner-source coalbed gas and shale gas, inner-source tight sandstone gas, near-source tight gas, and far-source fault-transported gas. In the Ordos Basin, inner-source tight gas and near-source tight gas are the current focuses of exploration, and inner-source coalbed gas and shale gas and far-source gas will be important potential targets in the future.

Control of complex lithofacies on the shale oil potential in ancient alkaline lacustrine basins: The Fengcheng Formation, Mahu Sag, Junggar basin

The study of ultra-deep (>4500 m) oil and gas reservoirs in hydrocarbon-bearing basins is a hot spot for oil and gas exploration in the world today, the heterogeneity of lithofacies is a key factor influencing the potential of deep-buried shale oil. It is highly important to better understand the control of complex rock on the shale oil potential for shale oil exploration and development. The Fengcheng Formation (P1f) in the Mahu Sag is a type of ancient alkaline lacustrine shale oil, which was chosen as a research example in this paper. Four lithofacies were identified based on mineralogy: felsic, lime, dolomitic and mixed shale lithofacies. P1f exhibits a very high shale oil potential, and the oil saturation index (OSI) can reach 176 mg HC/g TOC, far exceeding the lower limit of effective benefits. The shale lithofacies of P1f is complex, and the complex lithofacies has a controlling effect on shale oil potential, specifically in terms of hydrocarbon generation, storage and hydrocarbon migration. The different lithofacies differ in various aspects and are controlled by different factors. Felsic shale is an enriched oil shale with a high hydrocarbon generation potential and high storage capacity that can receive foreign hydrocarbons. Mixed shale is a self-generating and self-accumulating oil shale with a low hydrocarbon production potential and low storage capacity. Lime shale is a partial reservoir-type oil shale with a low hydrocarbon production capacity and satisfactory storage capacity that can receive foreign hydrocarbons. Dolomite shale is a partial source rock-type oil shale exhibiting a high hydrocarbon generation capacity and low storage capacity, which can expel hydrocarbons. Studies have indicated that felsic shale exhibits a notable hydrocarbon generation potential, high storage capacity, easy foreign hydrocarbon migration, high brittle mineral content, and easy fracture production. This shale type is the most favorable shale oil exploration target in P1f within the Mahu Sag. In addition, this study reveals the relationship between rock lithofacies and shale oil potential, which provides a new idea for the potential evaluation of similar lacustrine shale oil.

A Review of the Heterogeneity of Organic-Matter-Hosted Pores in Shale Reservoirs

Organic-matter-hosted pores are fundamental pore spaces in shale reservoirs, which largely control the expulsion and storage of oil and gas. However, the strong heterogeneity of organic pores greatly increases the complexity of the pore network in shale reservoirs, which make shale reservoir evaluation challenging. The heterogeneity of organic pores in shale reservoirs has beenone of the hottest topics of recent years. In this review, the heterogeneity of organic pores in shale reservoirs and their controlling factors are systematically summarized. The formation and evolution of organic pores in shale reservoirs are directly linked to hydrocarbon generation and expulsion,and the heterogeneity of organic pores is a result of various geological and geochemical factors. The development and heterogeneity of organic pores are basically controlled by the differences in kerogen types and maceral compositions of shale deposits, which are mainly attributed to the differencesin hydrocarbon generation capacity of different maceral compositions. Thermal maturation of organic matter is responsible for the formation and evolutionary mechanisms of organic pores and their heterogeneities. With increasing maturity, the increasing trend of pore volume and porosity diminishes. The reduction in macropore volume first appears, and the collapse of macropores could lead to an increase in micropore and mesopore volumes. An important turning point for the thermal evolution of OM is 3.5% Ro. At an Ro greater than 3.5%, the chemical structure of OM is transformed from amorphous carbon to crystalline graphite, and the hydrocarbon generation capacity of the OM has been exhausted, thus, resulting in the destruction of OM-hosted pores. The TOC content and mineral compositions of shale reservoirs affect the development and preservation of organic pores, but enhanced TOC content and brittle minerals may work against the development and preservation of organic porosity. Geological factors, e.g., compaction, diagenesis, pore fluid pressure and tectonic deformation, can also affect the organic pore structure of shale reservoirs to some extent, and their differences can enhance the heterogeneity of organic pores. On the basis of the above-mentioned understandings, this review also puts forward and discusses the problems existing in the current study of organic pore and its heterogeneity of shale reservoirs, and points out further research directions.

Thermal Evolution and Hydrocarbon Generation Capacity of Typical Palaeozoic Marine Source Rocks in the South China Craton: Constrains from Semiclosed Artificial Thermal Maturation Experiments

Abstract Palaeozoic petroleum systems in the South China craton are prospecting frontiers for unconventional oil/gas. Understanding the hydrocarbon generation/retention capacity of source rocks has critical implications for reserve evaluation and targeting, which yet remains ambiguous in this region. In this study, six representative lithological types of organic-rich, immature-low-mature source rocks (two shales, two carbonates, a coal, and a solid bitumen) taken from the South China craton were treated with semiclosed hydrous pyrolysis (300–550°C). Pyrolysis results show that shale and carbonate source rocks have great hydrocarbon generation capacities, and immature solid bitumen can also generate appreciable quantities of hydrocarbons, whereas coal has the least hydrocarbon generation capacity. Both oil and gas are important hydrocarbon products of thermal maturation of shales, whereas gas generation capacity of carbonate source rocks is relatively moderate compared to their oil generation capacity. Therefore, marine shale is an important exploration target for unconventional oil and gas, yet marine carbonate is an important target for unconventional oils. The presence of appreciable carbonate minerals in shales can facilitate oil and gas generation likely by (1) enhancing oil expulsion, (2) facilitating decarboxylation of organic acid, and (3) catalysis. Pyrolysis data also support that molecular composition of thermogenic gas is not dominantly controlled by lithofacies of source rocks but mainly affected by maturation. Outcomes of this study demonstrate that marine organic-rich rocks within the Palaeozoic strata in the South China craton are critical prospecting targets for unconventional oil and gas.

A study on molecular structural evolution of type II kerogen in a gold tube thermal system: Insights from solid-state 13C NMR

Lacustrine type II kerogen is widely distributed in China and has important hydrocarbon potential, but the study of its structural evolution is not comprehensive enough. In this study, a closed gold tube system was used to simulate the maturation of kerogen extracted from the Nengjiang Formation of the Songliao Basin to investigate a model of hydrocarbon generation and molecular structure change in lacustrine type II kerogen. The pyrolysis products at two heating rates were collected and quantitatively analyzed, and the Easy%Ro of 20 solid kerogen residue samples (solid pyrolysis products after extraction of methylene chloride and methanol) ranged from 0.69 to 2.49. From elemental analysis and 13C nuclear magnetic resonance (13C NMR), the molecular structure evolution of kerogen was clearly determined, and four average molecular models of kerogen were established. The results show that with increasing maturity, the aliphatic fractions of kerogen decreased, and the aromatic fractions increased. Before the main oil window (Easy%Ro < 0.89), the main products were nonhydrocarbon heteroatomic functional groups (NSOs: asphaltene and resin). The oil peak occurred at an Easy%Ro of approximately 1.1 when hydrocarbon C14+ production reached the maximum and kerogen residue was the lowest. After the oil peak, aromatic groups became dominant in the structure. C14+ began to decrease, and the kerogen residue proportion increased, which was related to the occurrence of secondary coking reactions after the main oil window. The hydrocarbon generation capacity of kerogen was exhausted after the oil peak, and the kerogen likely became the precursor of generated gaseous products. In the gas window (Easy%Ro > 1.53), the large quantity of C1-5 was mainly due to the secondary cracking of hydrocarbons. The number of aromatic structures caused by alkyl bond breaking and condensation was estimated. It was found that before the oil peak, the number of aromatic structures caused by alkyl bond breaking decreased and was higher than that of aromatic structures caused by condensation. After the oil peak, the latter structures were obviously dominant, which further indicates that polymerization is the main structural change mechanism of kerogen evolution.

Research on the sedimentary characteristics of organic matter in lacustrine mudrocks and their hydrocarbon generation potential based on palynofacies analysis: Eocene shahejie formation, dongying sag

Lacustrine mudrocks are important hydrocarbon source rocks due to their high contents of organic matter (OM). An accurate determination of the origins of OM in the rocks can contribute greatly to the identification of the sedimentary environment and the evaluation of the hydrocarbon generation capacity of the mudrocks. In this study, the lacustrine mudrocks of the Eocene Shahejie Formation in the Dongying Sag of China were sampled for further discussion of the types and origins of OM and the hydrocarbon generation capacity of the mudrocks. On that basis, the classical palynofacies classification scheme was improved, and five palynofacies types (PF1 to PF5) were classified to accurately reflect different lacustrine environments. Among them, PF1 to PF3 are rich in various amorphous organic matter (AOM), including benthic microbial mats, organic aggregates and algal aggregates, which are part of the lake environment in which aquatic organisms bloom. The hydrocarbon generation abilities of the three palynofacies are different but generally strong. PF5 and PF4 have abundant terrestrial plant fragments and macrophyte fragments, respectively, indicating a shallow, near-provenance lake environment and a shallow, macrophyte-flourishing lake environment. These two types of palynofacies have weaker hydrocarbon generation capacities than the former three. Due to the enrichment of different types of palynofacies, each formation of the Dongying Sag shows distinct hydrocarbon generation potentials. Therefore, it is important to pay special attention to the origin of OM and its influences on the hydrocarbon generation capacity of lacustrine mudrocks for a better understanding of the deposition and hydrocarbon generation potential of source rocks.

Controlling effect of saline sedimentary environment on enrichment and exploitation of shale gas and oil in lacustrine basin

The salinity of continental lacustrine basin has a great influence on the properties of shale. The main objective of this paper is to present the characteristics of shale in different saline stages. In this study, we restored the saline process by the Kauchi method and evaluated the hydrocarbon generation capacity, reservoir property, oiliness and exploitability of shale in different saline stages. The sources of organic matter and paleoproductivity may vary among saline stages. Organic matter mainly originates from coccolithophyta and dinoflagellate in the saltwater stage, demonstrating the highest paleoproductivity. Meanwhile, paleosalinity has an important effect on the lithologic assemblage and mineral composition of shale, which controls its reservoir properties, oiliness and compressibility. The lithology in the saltwater stage is dominated by lamellar argillaceous limestone/calcareous mudstone and lamellar limestone, with good original physical properties. The carbonate content in such stage is the highest, making it easy to dissolve into dissolution pores and thus increasing the porosity and saturation of movable fluid. The high hardness of carbonate gives optimum compressibility to shale.

Evaluation of the Oil-Bearing Properties of Shale and Shale Oil Mobility in the Fengcheng Formation in the Mahu Sag, Junggar Basin, Northwest China: A Case Study of Well Maye-1

Due to an increasing energy demand and the depletion of conventional oil, there is ever increasing demand for unconventional shale oil and gas resources. As the most hydrocarbon-rich sag in the Junggar Basin, the development prospects for shale oil in the Mahu Sag have become a focus of research. However, so far, there have been few studies of the oil-bearing properties of shale and shale oil mobility in the sag. This paper redresses this using a range of methods, such as pyrolysis and multi-temperature step pyrolysis. The results show that the Fengcheng Formation shales are generally good quality source rocks. The main body of the shale is low mature-mature, and the type of organic matter is mostly Type II kerogen. In the depth intervals at 4616.45~4640.30 m, 4661.25~4695.20 m, 4728.30~4759.80 m, 4787.60~4812.30 m, and 4876.70~4940.25 m, the oil-bearing properties of the shale and shale oil mobility are good, with an average S 1 of more than 1.5 mg/g, OSI of more than 100 mg/g.TOC-1, a ratio of free/adsorbed oil ( S 1 − 1 + S 1 − 2 / S 2 − 1 ) of more than 3, and a ratio of free/total oil ( S 1 − 1 + S 1 − 2 / S 1 − 1 + S 1 − 2 + S 2 − 1 ) of more than 80%. The second member (P1f2) and the lower part of the first member (P1f1) of the formation offer the most promising commercial prospects. Shale oil mobility in the formation is greatly affected by the abundance of organic matter. The higher the TOC value, the greater the hydrocarbon generation capacity, and the better its adsorption capability in the shale. The Fengcheng Formation shale is mature, and shale oil mobility is good. Impacted by the main reservoir space, the felsic shale in the formation has optimal shale oil mobility, with the shale oil being characterized by self-generation and self-storage, and accumulation in adjacent layers.