Coal Source Rocks Research Articles

Influence of thermal maturity on carbazole distributions in coal source rocks during compaction pyrolysis experiments

Carbazole compounds are widely used in determining the direction of petroleum migration, but the effect of thermal maturity on carbazoles is still ambiguity. In this paper, using compaction pyrolysis simulation experiments, artificial mature samples with vitrinite reflectance (Ro) range from 0.38 to 3.0% were acquired. And the content and composition change characteristics of carbazole compounds were analyzed in coal source rocks. The experimental results showed that thermal maturity controls the generation of a large amount of carbazole compounds in coal rocks. Compared with the low mature stage, the content of carbazole compounds was about 10–100 times higher in the mature stage. With the increasing maturity, in the coal sample, the content of carbazole compounds showed a trend of first increasing and then decreasing. In derivatives of carbazole, the corresponding maturity for the maximum generation of ethylcarbazole (EC), dimethylcarbazole (DMCA), methylcarbazole (MCA), carbazole (CA) and benzocarbazole (BCA) performed the increasing sequence. With the increasing maturity, the relative abundance of 2-MCA, 1,7-DMCA and benzo[a]carbazole increased with the increasing maturity, while 4-MCA, 1,4-DMCA and benzo[c]carbazole gradually decreased. Benzocarbazole ratio [a]/[a] +[ c] varies only in a narrow range 0.36–0.61 in the entire maturity range, suggesting limited maturity dependence. The experimental conclusion provides more theoretical basis for future geochemical analysis using carbazole compounds.

Quantitative palaeogeographical reconstruction of the North China Block during the Carboniferous and Permian transition: Implications for coal accumulation and source rock development

The Carboniferous-Permian strata of the North China Block (NCB) contain significant economic reserves of coal and gas. In this paper, a comprehensive dataset comprising 401 stratigraphic sections encompassing the Carboniferous-Permian transition in the NCB is compiled from the OneStratigraphy and Geobiodiversity databases. We conducted quantitative analyses of this dataset using ArcGIS and GPlates software, and utilized an up to date plate motion model, to perform a dynamic palaeogeographical reconstruction. The spatio-temporal distribution of depositional facies were also analysed, including basement terranes, fluvio-lacustrine settings, swamps, shorelines, tidal flats, and carbonate platforms. Our reconstructions reveal that the NCB was flanked by basement areas of the Yinshan-Yanshan landmass in the north and the Qinling-Dabie landmass in the south. Peat (coal) deposition occurred across a range of terrestrial to coastal environments, including fluvio-lacustrine settings, deltas, shorelines and tidal flats. Carbonaceous and organic-rich clastic rocks also developed in these areas while organic-rich carbonate rocks were primarily deposited in carbonate platform. The conditions conducive to peat (coal) formation were intricately connected to eustatic fluctuations, which resulted in frequent transgressions and regressions. The sea-level fluctuations during the Pennsylvanian might be, in part, a response to both the waxing and waning of continental ice sheets and tectonic process in the northern margin of the NCB. In contrast, sea-level changes during the early Permian were probably controlled by the tectonic process only. This paper provides a state-of-the-art review of palaeogeographical evolution of the NCB during the Carboniferous and Permian transition, in response to eustatic and palaeoclimate change, and sheds light on resource accumulation based on quantitative analyses.

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.

Gas Generation from Coal and Coal-Measure Mudstone Source Rocks of the Xujiahe Formation in the Western Sichuan Depression, Sichuan Basin

Gas Generation from Coal and Coal-Measure Mudstone Source Rocks of the Xujiahe Formation in the Western Sichuan Depression, Sichuan Basin

Geocatalytically generated methane from low-maturity coal and shale source rocks at low temperatures (80–120 °C) over 52 months

Geocatalytic methanogenesis has been proposed to contribute to methane generation from low-maturity coal and shale source rocks. This study contributes further evidence for geocatalytic methanogenesis from low-maturity source rocks based on long-term experiments lasting up to 52 months. Samples from the Upper Devonian New Albany Shale (Ro 0.54 %) and Springfield Coal No. 2 (Pennsylvanian; Ro 0.54 %) were heated in glass tubes at 80, 100, and 120 °C for 52 months. Sample aliquots from the Upper Cretaceous Second White Specks Formation (Ro 0.42 %) were heated in gold tubes at 80 and 100 °C for 42 months at elevated hydrostatic pressures of 100 to 300 MPa. The product gases — methane (CH4) and carbon dioxide (CO2) — were collected and quantified, and gas yields were corrected for leakage from imperfectly closed pores in samples during heating. The results show that longer heating produced more CH4. The average CH4 yields from New Albany Shale and Springfield Coal No. 2 are 0.47 and 3.0 μmol CH4 per gram of total organic carbon (TOC) over 52 months of heating. Elevated hydrostatic pressure caused lower CH4 yields from the Second White Specks Formation (3.82 to 1.20 μmol g−1 TOC), suggesting that pressure can retard methanogenesis. Maceral type critically controls the methanogenesis potential of low-maturity coal and shale source rocks. Results of this study provide important insights to the origin of natural gas in low-maturity sedimentary basins.

Depositional environment and hydrocarbon potential of Early Permian coals deposit in the Huanghua Depression, Bohai Bay Basin

The Carboniferous-Permian was an important period for the formation of coal mines and coaly source rocks across the world. Controlled by the paleoclimate, Cathaysia flora, and transitional sedimentary environment of the delta, the Early Permian Shanxi Formation in the Huanghua Depression formed several layers of coal and coaly source rocks that can be explored in the whole depression. However, the development regularity and distribution prediction of high-quality coaly source rocks are still not well understood. The coaly source rocks of the Shanxi Formation in the Huanghua Depression were taken as the research object. With the determination and analysis of organic carbon content, rock pyrolysis, and vitrinite reflectance, we found that the organic matter abundance (i.e., TOC which changed from 20.3 % to 80.0 %), hydrocarbon generation potential (i.e., S1 + S2 which varied from 7.82 mg/g to 208.81 mg/g), and kerogen types (mainly type II2) of the coal were better than carbonaceous mudstone and coaly shale. Maceral component identification indicated that coal and carbonaceous mudstone had more liptinite (i.e. cutinite and sporinite)and hydrogen-rich vitrinite, while coaly shale was mainly composed of hydrogen-poor vitrinite and a small amount of liptinite. The analysis of the ratios of major and trace elements, normal alkanes, and isoparaffin suggested that the paleo-water salinity of coal and carbonaceous mudstone deposition was more than that of part coaly shale. Revealed by the weak reduction of their depositional environment, the development of high-quality coal and carbonaceous mudstone was mostly controlled by the input of oil- and gas-prone organic matter. The formation of high-quality coaly shale was chiefly dominated by a strong reduction environment with an insignificant amount of organic matter input. The formation model of high-quality coaly source rocks was established. This model can be used to predict the distribution of coal mines and coaly source rocks in the Huanghua Depression and Bohai Bay Basin.

Монголын шатах ашигт малтмал, тэдгээрийг агуулсан тунамал савууд

During the last decade, significant geological studies on fossil fuels and sedimentary basins in Mongolia have been completed; e.g., more than 100 coal deposits were explored. This review includes recent advances in tectonic setting of sedimentary basins, depositional environments of fossil fuel hosting sedimentary rocks, and quality and resources of coal, oil shale and petroleum source rocks. It also covers the results of coking coal blending studies, oil shale pyrolysis and the outcome of the first evaluation of coal bed methane potential of Mongolia.

Distribution, development, transformation characteristics, and hydrate prospect prediction of the rift basins of northwest Zealandia in the Southwest Pacific

As the last area with unknown oil exploration potential, Zealandia has attracted the attention of petroleum scientists. Under the constraint of the known rift distribution, the gravity and magnetic anomaly data are utilized to predict the distribution of rift basins, and the balanced cross-section technique and basin simulation technique are utilized to analyze the development of the rift basins and hydrocarbon generation history of source rocks for the hydrate prospect prediction of the rift basins of northwest Zealandia. The time of rifting in Zealandia varies greatly from place to place, and it has experienced extensive rifts, migrated to the east of the Lord Howe Ridge, migrated to the west of the Lord Howe Ridge, migrated to the west of the Dampier Ridge, and finally migrated to both sides of the Lord Howe Ridge and then experienced multiple stages of compression transformation and deep burial transformation. The Upper Cretaceous coal source rock in the rift Ⅱ stage has entered the wet gas generation stage in the deep part of the rift or deeper rift on the eastern side of the Lord Howe Ridge, and the coal-generated wet gas may migrate along the fault and form a gas hydrate in the shallow seabed stable zone.

Distribution of Upper Paleozoic Coal Seams in the Southeastern Ordos Basin

The Ordos Basin contains abundant coal resources in the Upper Paleozoic strata. They are shallowly buried or exposed in the periphery of the basin, forming recoverable coal mines and coalbed methane resources. For the deeply buried coal seams of the basin, however, due to complex changes and difficult mining, less attention was paid before. In recent years, with the exploitation of tight gas related to coal source rocks, a large amount of drilling and seismic data has been accumulated in the southeastern Ordos Basin, which makes it possible to study the distribution change and factors controlling Upper Paleozoic coal seams. Delineation of deep coal development and distribution is an important basis for coal, coalbed methane and related tight gas resources in the Upper Paleozoic. We use core, logging and seismic data to analyze the coal geophysics, thickness variation, paleotopography and sedimentary facies in the southeastern Ordos Basin. The lower part of the Shanxi Formation (Fm.) and the upper part of the Taiyuan Fm. in the southeastern part of the basin are characterized by low natural gamma ray, low density, high resistivity and high sonic logging values. As the coal velocity is very low and alternates with the high-velocity Taiyuan Fm. and Ordovician limestones, the two sets of coals below and above the Taiyuan limestones form an extremely strong-amplitude reflection in the seismic profile. The two sets of coals are cumulatively 1–10 m thick, averaging 2.4 m, and 4 m is the maximum induvial thickness. The individual coal seams thicker than 2 m cover an area of approximately 2500 km2, and the burial depths of the coal seam range from 2500 to 3000 m. The thick coal seams of the Taiyuan Fm. are mainly distributed proximally in the Ordovician paleokarst depression, while the Ordovician paleokarst depression without incised origin was deposited by distal coeval limestone rocks. There is a complementary relationship between the coal seams and the thickened zone of distributary channel sandstone in the Shanxi Fm.

Mechanism and Controlling Factors on Methane Yields Catalytically Generated From Low-Mature Source Rocks at Low Temperatures (60–140°C) in Laboratory and Sedimentary Basins

Various studies have shown that geo-catalytically mediated methanogenesis could happen in immature to early-mature source rocks at temperatures ranging from 60 to 140°C based on a series of long-term laboratory heating experimental evidences. The results of those studies show that methane yields at the given temperature are 5–11 orders of magnitude higher than the theoretically predicted yields from early thermogenic methane generation kinetic models. However, different types of source rocks in these laboratory simulation experiments generated varied CH4 and CO2 yields, which suggest that controls on CH4 generation during catalytic methanogenesis are complex. This study summarizes and compares gas yield results from laboratory low-temperature heating simulation experiments. Pre-existing trapped methane in rock chips could mimic newly generated gas during heating. The yields of catalytically generated CH4 from individual source rocks were re-quantified by subtracting the amounts of pre-existing CH4 in the closed pores of the original source rocks from the total methane amounts released from heating experiments and pre-existing CH4 in the closed pores in heated source rocks. The results show that heating temperature and time exert a positive influence on methane catalytic methanogenesis. Mowry and Second White Specks Formation Shale generated approximately ten times more CH4 than New Albany Shale and Mahogany Shale per gram of total organic carbon (TOC). Samples of Springfield Coal #1 and #2 exhibited ten times yield difference from one another at the same heating temperature. Those yield differences are not strongly associated with TOC content, heating time, temperature, metal content, or kerogen type but appear to be more influenced by maceral composition and also maceral–mineral contact area within the source rocks. We conclude that macerals in the liptinite group have a propensity for methanogenesis. Specifically, amorphous organic matter undergoes transformation into hydrocarbons earlier than alginite at low-temperature heating conditions. Sporinite also contributes to higher yields of methane released from the coal source rock. Vitrinite and inertinite show a positive influence on carbon dioxide but no significant effect on increasing methane yields compared to other macerals. The strongest catalytic methanogenesis in the studied sample produced methane yields at 60°C, which amounted to ∼2.5 μmol per gram of organic carbon during one year of heating. We suggest that geocatalytic methanogenesis could generate economically sizeable gas plays from immature to early-mature source rocks over geologic time.

New approaches to distinguish shale-sourced and coal-sourced gases in petroleum systems

Current approaches relating thermogenic gases to either shale source rocks (predominantly type II kerogen) or coal source rocks (predominantly type III kerogen) are not reliable and not globally applicable. This is because these mostly empirical approaches were developed using small poorly-constrained datasets from limited locations. The evaluation of a large global dataset of molecular and isotopic properties of gases from unconventional shale and coal reservoirs suggests that two genetic diagrams based on stable carbon isotopes of methane and ethane, δ13C-C2H6versus δ13C-CH4 and δ13C-CH4versus Δ(δ13C-C2H6 – δ13C-CH4), provide the best separation of shale-sourced and coal-sourced gases. Newly designated genetic fields and shale/coal separation lines on these diagrams were tested and validated using data from five petroleum systems with, likely, only shale (class B and A organofacies) source rocks (the Maracaibo Basin in Venezuela, the Guajira Basin in Colombia and the Rub Al Khali Basin in Iran) and only coal (class F organofacies) source rocks (the Southern Permian Basin in Germany and the Sichuan Basin in China). The practical usefulness of this new approach to gas-source correlations was demonstrated in two case studies from petroleum systems with debated source rock organofacies (the Mozambique Basin in Mozambique and the Indus Basin in Pakistan). These better constrained and more reliable diagrams with genetic fields and shale/coal separation lines represent a new tool for the evaluation of petroleum systems.

Methane generation from low-maturity coals and shale source rocks at low temperatures (80–120 °C) over 14–38 months

This study contributes long-term (14 to 38 months) experimental evidence for geocatalytically mediated methanogenesis in immature to early mature shale and coal source rocks at temperatures from 80 to 120 °C. Borosilicate glass tubes with pre-outgassed coal and shale source rock chips and water were sealed under vacuum, sterilized, heated isothermally, and finally opened in connection with a vacuum line where headspace gases methane (CH4) and carbon dioxide (CO2) were collected. The possibility of admitting pre-existing CH4 from closed pores into product gases during heating experiments was evaluated by comparative ball milling of original and heated rock chips, followed by quantitation of released gases with a novel closed-circuit laser-based SARAD RTM2200 gas detector system with sub-µmol sensitivity. The yields of produced CH4 from individual source rocks were corrected by subtracting the amounts of pre-existing CH4 from formerly closed pores in original source rocks that had leaked during long-term heating. Different shales and coals express contrasting propensities to geocatalytically generate CH4 and CO2, with CH4 yields ranging from 0.1 to 5.5 µmol g−1 total organic carbon (TOC). CH4 yields from two petrographically different samples of Springfield Coal with comparable thermal maturity suggest that liptinite expresses a far higher propensity for methanogenesis, but liberates less CO2 than vitrinite. Shale from the Second White Specks Formation generated approximately 10 times more CH4 than New Albany Shale per g of TOC, further suggesting complex controls on CH4 generation during catalytic methanogenesis. Higher temperature can enhance the activities of catalytic methanogenesis. The extrapolation of laboratory-based reaction rates to natural conditions in organic-rich buried sediments suggests that geocatalytic methanogenesis can be fast enough in some source rocks to generate economically sizeable gas plays from immature to early mature source rocks over geologic time.

Discovery and geological knowledge of the large deep coal-formed Qingyang Gas Field, Ordos Basin, NW China

Abstract After 50 years of oil and gas exploration in Longdong area of southwest Ordos Basin, NW China, a deep coal-formed gas field was discovered for the first time in Qingyang area. Through observation of field outcrops and core, analysis of common, cast and cathode thin sections, Ro and other geochemistry indexes, carbon isotope, electron microscope and other supporting tests and analyses, the hydrocarbon generation, reserves formation and reservoir formation characteristics of gas reservoirs at different buried depths in Yishaan slope were examined and compared. The deep gas reservoir has an average buried depth of more than 4 200 m, and the main gas-bearing formation is the Member 1 of Lower Permian Shanxi Formation, which is characterized by low porosity, low permeability, low pressure and low abundance. It is believed that hydrocarbon generation in thin seam coal source rocks with high thermal evolution can form large gas fields, high-quality sandstone reservoirs with dissolved pores, intergranular pores and intercrystalline pores can still develop in late diagenetic stage under deep burial depth and high thermal evolution, and fractures improve the permeability of reservoirs. High drying coefficient of natural gas and negative carbon isotope series are typical geochemical characteristics of deep coal-formed gas. The integrated exploration and development method has been innovated, and the economic and effective development mode of gas fields of “dissecting sand body by framework vertical wells, centralized development by horizontal wells” has been formed. The discovery and successful exploration of the large gas field has provided geological basis and technical support for the construction of natural gas fields of 100 billion cubic meter scale in the southwest of the basin, and has important guidance for exploration of coal-derived gas with deep buried depth and high thermal evolution widely distributed in China.

Formation of the primary petroleum reservoir in Wumaying inner buried-hill of Huanghua Depression, Bohai Bay Basin, China

Well Yinggu 1 drilled on the tectonic belt of the Wumaying buried-hill in Huanghua Depression obtained non-H2S high-yield oil and gas flow from the Permian Lower Shihezi Formation sandstone. The oil and gas are derived from the Upper Paleozoic coal source rock, the petroleum reservoir is an inner buried-hill primary oil and gas accumulation, showing a good prospect of the Paleozoic inner buried-hill primary reservoir exploration. The formation and accumulation of the primary petroleum reservoir in the Wumaying inner buried-hill are discussed by studying the primary source conditions, the inner buried-hill reservoir-cap combinations and the hydrocarbon accumulation period. The primary petroleum reservoir has three preponderant characteristics of accumulation: secondary large-scale gas generation of coal source rock, multi reservoir-cap combinations and mainly late hydrocarbon charging, which formed the compound hydrocarbon accumulation of the above-source sandstone and under-source carbonate rock in the Paleozoic inner buried-hill. Along with the Mesozoic and Cenozoic tectonic activities, the formation of the primary reservoir in Wumaying inner buried-hill is characterized by “mixed oil and gas charge in local parts in early stage, adjustment accumulation due to structural high migration in middle stage, and large-scale natural gas charge and compound accumulation in late stage”.

Composition and origin of molecular compounds in the condensate oils of the Dabei gas field, Tarim Basin, NW China

Abstract The Dabei gas field in the Kuqa Depression of the Tarim Basin is the most complex and deep continental condensate gas field in China. Comprehensive two-dimensional gas chromatography-time of flight mass spectrometer (GC×GC-TOFMS) analysis was conducted on five condensate oil samples from this field. The results show that the samples have n-alkane series in complete preservation and rich adamantanes. According to the methyladamantane index, the condensate oil is the product of the source rock with vitrinite reflectance (Ro) of 1.3%–1.6%. According to the gas maturity calculated through carbon isotope and vitrinite reflectance, the natural gas is corresponding to Ro of 1.3%–1.7%, reflecting that the natural gas and condensate oil are basically formed during the same period at the high maturity stage of source rock. The Dabei gas field has favorable geological conditions for hydrocarbon accumulation: thick salt rock in the Paleogene acts as a regional high-quality caprock directly overlying the high-quality sandstone reservoir of the Cretaceous, the coal source rocks have high hydrocarbon generation intensity and provide continuous oil and gas, and the subsalt thrust structures develop in rows with rich faults, providing migration pathways for oil and gas migration. These factors together controlled the formation of the Dabei gas field.

Petroleum generation potentials and kinetics of coaly source rocks in the Kuqa Depression of Tarim Basin, northwest China

Confined pyrolysis experiments (gold capsules) were performed to determine the yields and kinetic features for petroleum formation for seven coal samples with hydrogen index (HI) ranging from 57 to 278 mg HC/g TOC and maturities of 0.58–0.74 %Ro from coal pits within Triassic–Jurassic strata in the Kuqa Depression, China. Gases and liquid yields were measured at regular intervals as the sealed tubes were heated at 2 and 20 °C/h and total thermal stress calculated as a vitrinte reflectance equivalent (%Re) using Easy%Ro. The total confined pyrolysate yields of oil and gaseous hydrocarbons at 1.19–1.50 %Re only account for a portion (38–53%) of the releasable moieties in measured by Rock-Eval (open) pyrolysis, suggesting that a substantial portion of (47–62%) of these moieties was rearranged and incorporated into polyaromatic residual solids. At maturities >1.87 %Re, the solid residues of the seven coals have very similar gas generative potentials (ΣC1–5), which are substantially higher than their quality index (QI = (S1 + S2)/TOC) with differences ranging from 20 to 40 mg/g TOC. This result can be mainly ascribed to the differences both in methane formation mechanisms and final thermal stress levels between open (2.25 %Re) and confined pyrolysis (4.44 %Re). Only a minor portion of gaseous hydrocarbons (∼32% and 44% for the Jurassic and Triassic coals, respectively) was generated up to 2.19 %Re while the major portion was generated at higher maturities. Under a heating rate of 5 °C/My, the Jurassic and Triassic coals are modeled to become effective gas source rocks with gas yield (ΣC1–5) > 20 mg/g TOC at maturities of >1.76 %Re and 1.59 %Re, respectively. The abundant gaseous hydrocarbons found in the Kuqa Depression can be mainly ascribed to the high maturities of coal source rocks (>2.0 %Ro), in combination with excellent seal of thick salt and gypsum for the gas reservoirs.

Carbon Isotope Fractionation in Coal and Marine Source Rocks and Implications for Exploration

Stable isotope composition of gas is widely used in hydrocarbon exploration to determine the composition and thermal maturity of source rocks. The analyses of Australian coal and marine shale samples indicate that during gas desorption both molecular and isotopic compositions change with time. Therefore, a detailed understanding of the mechanism of isotope fractionation is required to improve our ability to better characterize source rocks and fluids. δ13C of Permian coals range between -22 and -26‰ (VPDB) and that of thermogenic methane generated from these range from -25 to -40‰. δ13C of gas desorbed from coal varies with time according to molecular weight and sorption properties. For example, in a set of deep Bowen Basin coals the difference in δ13C-CH4 between early and late desorbed gas varies from 2‰ to 29‰. For higher hydrocarbons this fractionation is lower, where for ethane it is <8‰ and for propane <3‰. Similar isotope fractionation happens during desorption from marine source rocks in the Beetaloo Basin. δ13C for an immature kerogen from the Velkerri shale is -33‰. Where the Velkerri shale is gas mature, during desorption, δ13C-CH4 shows fractionation of up to 28‰. δ13C-C2H6 and δ13C-C3H6 show lower isotope fractionation of 1.6‰ and 0.9‰, respectively. Many published classification systems relating isotope composition of gas to source rock and thermal maturity do not consider the effects of such isotope fractionation. The fractionation mechanism may also have an impact on the so-called “isotope reversal” behaviour in some shale reservoirs which, at present, is poorly understood.

Quantitative evaluation of gas generation from the Upper Paleozoic coal, mudstone and limestone source rocks in the Ordos Basin, China

Significant quantities of tight gas resources have been discovered in the Upper Paleozoic interval in the Ordos Basin, central China. The gas is believed to have been derived primarily from the Upper Paleozoic coal, mudstone and limestone source rocks. An integrated organic geochemistry and basin modeling approach was applied to quantitatively evaluate gas generation from the three types of source rocks. Source-specific gas generation kinetics were first established on the basis of sealed gold tube pyrolysis experiments. Gas generation was then modeled in 1D and 3D using the source-specific kinetics obtained. The results show that (1) near the depositional and thermal center (e.g., Well ZT-1), gas generation occurred much earlier and was greater than that of the Sh-360 well, which is away from the depositional and thermal center; (2) C2-C5 gases in the ZT-1 well underwent thermal cracking, while gases in the Sh-360 well did not experience any secondary thermal alteration; (3) hydrocarbon gases were mainly generated during the Early Cretaceous (135–96 Ma) and the Late Jurassic (161–135 Ma); (4) the cumulative amounts of gas generation from the coal, mudstone and limestone source rocks are 147.23 × 1012, 57.85 × 1012 and 12.73 × 1012 m3, respectively, with coal seams being a major contributor (about 67.6%) to the Upper Paleozoic gas system, followed by the mudstone (about 26.6%) and limestone (about 5.8%). By comparing with previous work and a default kinetics basin model, our source-specific kinetics basin model is more suitable for simulating gas generation in the Upper Paleozoic source rocks within the Ordos Basin.

A REVIEW OF THE COALY SOURCE ROCKS AND GENERATED PETROLEUMS IN THE DANISH NORTH SEA: AN UNDEREXPLORED MIDDLE JURASSIC PETROLEUM SYSTEM?

This paper reviews the Middle Jurassic petroleum system in the Danish Central Graben with a focus on source rock quality, fluid compositions and distributions, and the maturation and generation history. The North Sea including the Danish Central Graben is a mature oil province where the primary source rock is composed of Upper Jurassic – lowermost Cretaceous marine shales. Most of the shale‐sourced structures have been drilled and, to accommodate continued value creation, additional exploration opportunities are increasingly considered in E&amp;P strategies. Triassic and Jurassic sandstone plays charged from coaly Middle Jurassic source rocks have proven to be economically viable in the North Sea. In the Danish‐Norwegian Søgne Basin, coal‐derived gas/condensate is produced from the Harald and Trym fields and oil from the Lulita field; the giant Culzean gas‐condensate field is under development in the UK Central North Sea; and in the Norwegian South Viking Graben, coal‐derived gas and gas‐condensate occur in several fields. The coaly source rock of the Middle Jurassic petroleum system in the greater North Sea is included in the Bryne/Lulu Formations (in Denmark), the Pentland Formation (in the UK), and the Sleipner and Hugin Formations in Norway. In the Danish Central Graben, the coal‐bearing unit is composed of coals, coaly shales and carbonaceous shales, has a regional distribution and can be mapped seismically as the ‘Coal Marker’. The coaly source rocks are primarily gas‐prone but the coals have an average Hydrogen Index value of c. 280 mg HC/g TOC and values above 300 mg HC/g TOC are not uncommon, which underpins the coals' capacity to generate liquid hydrocarbons (condensate and oil). The coal‐sourced liquids are differentiated from the common marine‐sourced oils by characteristic biomarker and isotope compositions, and in the Danish Central Graben are grouped into specific oil families composed of coal‐sourced oil and mixed oils with a significant coaly contribution. Similarly, the coal‐sourced gases are recognized by a normally heavier isotope signature and a relatively high dryness coefficient compared to oil‐associated gas derived from marine shales. The coal‐derived and mixed coaly gases are likewise assigned to well‐defined gas families. Coal‐derived liquids and gas discoveries and shows in Middle Jurassic strata suggest that the coaly Middle Jurassic petroleum system has a regional distribution. A 3D petroleum systems model was constructed covering the Danish Central Graben. The model shows that present‐day temperatures for the Middle Jurassic coal source rock ('Coal Marker') are relatively high (&gt;150 °C) throughout most of the Danish Central Graben, and expulsion of hydrocarbons from the ‘Coal Marker’ was initiated in Late Jurassic time in the deep Tail End Graben. In the Cretaceous, the area of mature coaly source rocks expanded, and at present day nearly the whole area is mature. Hydrocarbon expulsion rates were low in the Paleocene to Late Oligocene, followed by significant expulsion in the Miocene up to the present day. High Middle Jurassic reservoir temperatures prevent biodegradation.

Petroleum geological characteristics of two basin belts in southern continental margin in South China Sea

Based on the seismic, drilling, cores and outcrops data, the formation of basins, source rocks and hydrocarbon accumulations in the southern South China Sea (SSCS) were systematically analyzed to reveal the petroleum geological features of continental margin basins and summarize the distribution rule of oil and gas in the SSCS. The results show that the South China Sea (SCS) has experienced three tectonic stages, namely, the formation and development of proto-SCS, the subduction of proto-SCS and development of neo-SCS, the rapid subsidence and shrinking of SCS. The tectonic evolution of proto-SCS and neo-SCS controlled the regional tectonic pattern of continental margin in the SSCS, forming southern and northern basin belts, and also dominated the formation of basins, source rocks and hydrocarbon accumulation characteristics. The source rocks were mainly Miocene coal source rocks in the southern basin belt, with different thermal evolution degree, and the near-shore source rock was chiefly oil-generating while the off-shore source rock was mainly gas-generating. Compressive folding structural belts and reefs were the favorable belts. Within the northern basin belt, the source rocks were gas-prone and dominated by the Eocene to Oligocene, with high thermal evolution degree. Reefs and faulted blocks were the major accumulation areas. Our study demonstrates that the continental marginal basins of SSCS still have great exploration potential and is an important strategic area of oil and gas exploration and development. The southern basin belt focuses on oil and gas exploration and the northern basin belt focuses on gas exploration.