Dark Mudstone Research Articles

PETROLEUM SYSTEMS OF THE BONGOR BASIN AND THE GREAT BAOBAB OILFIELD, SOUTHERN CHAD

The Bongor Basin in southern Chad is an inverted rift basin located on Precambrian crystalline basement which is linked regionally to the Mesozoic – Cenozoic Western and Central African Rift System. Pay zones present in nearby rift basins (e.g. Upper Cretaceous and Paleogene reservoirs overlying Lower Cretaceous source rocks) are absent from the Bongor Basin, having been removed during latest Cretaceous – Paleogene inversion‐related uplift and erosion. This study characterizes the petroleum system of the Bongor Basin through systematic analyses of source rocks, reservoirs and cap rocks.Geochemical analyses of core plug samples of dark mudstones indicate that source rock intervals are present in Lower Cretaceous lacustrine shales of the Mimosa and upper Prosopis Formations. In addition, these mudstones are confirmed as a regional seal. Reservoir units include both Lower Cretaceous sandstones and Precambrian basement rocks, and mature source rocks may also act as a potential reservoir for shale oil. Dominant structural styles are large‐scale inversion anticlines in the Lower Cretaceous succession whilst underlying “buried hill” ‐type basement plays may also be important. Accumulations of heavy to light oils and gas have been discovered in Lower Cretaceous sandstones and basement reservoirs.The Great Baobab field, the largest discovery in the Bongor Basin with about 1.5 billion barrels of oil in‐place, is located in the Northern Slope, a structural unit near the northern margin of the basin. Reservoirs are Lower Cretaceous syn‐rift sandstones and weathered and fractured zones in the crystalline basement. The field currently produces about 32,000 barrels of oil per day.

Discovery of Sinian source rocks in proterozoic in the Tarim Basin, NW China

As one of three cratonic basins in China, the Tarim Basin has the most abundant oil and gas resource, and its Precambrian petroleum system is a new region for hydrocarbon exploration. After conducting numerous field investigations in the Tarim Basin, we discovered the Sinian source rocks with 150m of thickness in Kuruktag area. These source rocks have total organic carbon (TOC) contents between 0.6% and 1.6%, with equivalent vitrinite reflectance (%Ro) between 1.23% and 1.42%. In addition, dark mudstone and a large amount of reservoir bitumen is present in the Upper Sinian outcrops in Aksu region. Biomarkers analysis indicates that reservoir bitumens in the Sinian and Cambrian strata were derived from the Sinian dark mudstones. Meanwhile, biomarkers of the reservoir bitumens from well ST1 in the Lower Cambrian Xiaoerbulake Formation indicate that the bitumen was originated from the Sinian source rocks and subsequently experienced biodegradation influence. Furthermore, a special hydrocarbon charging event with homogenization temperature of 50–60 °C has been elucidated from coeval aqueous phase of oil inclusions from in well ZS5, indicating that the oil and gas charging event in the Sinian source rocks occurred throughout the basin. As a result, the Sinian petroleum system in the Tarim Basin may contain high-quality source rocks, which contribute to the massive amount of Lower Paleozoic oil and gas resources in the basin. This study has important practical significance for oil and gas exploration of the Precambrian petroleum system in the Tarim Basin.

Origin of calcite cements and their impact on reservoir heterogeneity in the Triassic Yanchang Formation, Ordos Basin, China: A combined petrological and geochemical study

Abstract Calcite cement is a typical product of fluid–rock interaction in petroleum reservoirs, and its migration has a major impact on reservoir heterogeneity. A case study of a closed diagenetic system was carried out on the Upper Triassic Yanchang Formation of Ordos Basin, China—the most successful exploration region for tight sandstone oil in China. The investigated sandstones are mainly lithic arkoses (Q31F42L27). Three occurrences of calcite cement are the most important diagenetic minerals affecting reservoir quality: early calcite completely filling intergranular volumes; late calcite filling pores after chlorite coating, distributed in oil layers, or locally replacing feldspar; and crystal-stock calcite typically distributed in dry layers. δ13C values of the sandstones are in the range −9.69‰ to −2.05‰, indicating that calcite is derived mainly from thermodynamic decarboxylation of organic matter. Dark mudstone interbedded with sandstone and hydrocarbon emplacement are the two crucial sources of organic fluid, providing sufficient Ca2+, Mn2+, Fe2+, and Mg2+ for calcite precipitation through interaction with feldspar and other silicates, such as dissolution and replacement together with transformation of smectite to illite. Manganese was continuously enriched in calcite during burial diagenesis. Driven by compaction of interbedded mudstone and fluid overpressure, calcite migrated widely into calcite-cemented zones (CCZs) where fluid–rock interaction was strong, such as in the margins of sandstone bodies, intrastratal sandstones with original high-permeability zones, and thin sandstones, thereby forming an important organic CO2 sink. Potential high-quality reservoirs are distributed mainly in the central part of the closed system, restricted by calcite-cemented zones, and are an exploration target. Our data suggest that frequently alternating sandstone and mudstone sequences comprise a complete organic CO2 source/sink system, controlling the migration of calcite cement in a closed diagenetic system and reservoir heterogeneity by fluid–rock interaction.

Hydrocarbon accumulation patterns of salt crust covered biogenic gas reservoirs in the Sanhu Depression, Qaidam Basin

Quaternary biogenic gas reservoirs are extensively developed in the Sanhu Depression of the Qaidam Basin, where the largest domestic biogenic gas production base has been built up. In recent years, however, the exploration of biogenic gas there encounters a variety of difficulties, such as the identification of true and false seismic abnormality, the determination of micro-relief structure and the identification and description of lithologic traps, which are the bottlenecks restricting its exploration breakthrough. In this paper, hydrocarbon accumulation patterns of biogenic gas were studied. Then, based on fine structure interpretation results, combined with laboratory experiments, the sealing capacity, distribution range, formation time and genesis of salt crust were discussed, and the salt crust covered hydrocarbon accumulation pattern of biogenic gas was put forward. Finally, combined with the conditions of source rocks and reservoirs, the exploration prospect of salt crust covered biogenic gas reservoirs was predicted. And the following research results were obtained. First, the Quaternary in the Sanhu Depression is composed of sandstone–mudstone interbeds of shore-shallow lake facies, with superior conditions of source rocks and reservoirs. Many source–reservoir–caprock assemblages are vertically formed. The biogenic gas has the characteristics of dynamic hydrocarbon accumulation, i.e., continuous migration, accumulation, diffusion and re-accumulation. Second, under the effect of Himalayan movement, the climate changes frequently and the salinity of the ancient lake is zoned in the Sanhu Depression. A freshwater area is formed at the inlet of the river in the south and a brine area is formed in the north. Under the influence of evaporation, the phreatic water in the north is salinized continuously, and a set of extensively distributed salt crust with steady thickness and a strong sealing capacity is formed at the eastern part of Lingjian fault. Third, the biogenic gas generated by dark mudstone of lacustrine facies in the depression center migrates laterally and vertically to Lingjian fault zone and gets accumulated under the sealing of salt crust. In conclusion, high-quality source rocks and reservoirs and the salt crust with a strong sealing capacity in the Sanhu Depression constitute a good spatial–temporal configuration relationship of source rocks, reservoirs and cap rocks, so salt crust covered biogenic gas reservoirs can be formed to provide abundant natural gas resources with a broad exploration prospect.

Effect of pore structure on oil‐bearing property in the third member of Paleogene Funing Formation in Subei Basin, East China

AbstractMercury injection capillary pressure (MICP) tests, nuclear magnetic resonance (NMR), (fluorescence) thin section, X‐ray diffraction (XRD), and scanning electron microscope (SEM) analyses were used to describe the size and distribution of entire pore‐throat structures in the sandstones of the E1f3 (the third member of Paleogene Funing Formation) in the Subei Basin. The lithologies of E1f3 in the Subei Basin are mainly dark‐gray, very fine‐grained sandstones and siltstones, interbedded with dark mudstones. The pore systems predominantly feature secondary intergranular and intragranular dissolution pores, micropores coexisting with minor amounts of intergranular pores, and microfractures. The high threshold pressure and bulk volume of irreducible fluids values and the significant variation in the NMR and MICP parameters indicate that the E1f3 reservoirs are characterized by complex and heterogeneous microscopic pore structures. Microscopic pore‐throat parameters are linked with macroscopic properties through the reservoir quality index (RQI). The NMR T2 (transverse time relaxation) spectrum is unimodal or bimodal but with weak right peaks, indicating the rarity of large intergranular pores. However, large‐scale pore throats, though only account for a minor part of the total pore volume, significantly contribute to the total permeability. The abundance of small‐scale pore‐throat systems (short T2 components) results in high irreducible water content. Therefore, the oil saturation in E1f3 sandstones is low, and the pore structure, especially the number of micropores, determines the oil‐bearing property. Oil primarily occurs in the intragranular dissolution pores with minor amounts occurring in the large intergranular pores. Most of the micropores are bound by capillary water. The sandstones with chlorite clay minerals tend to be oil‐wet and have high oil‐bearing potential, while the abundance of detrital clay or illite contributes to a low oil‐bearing grade. The combination of core and microscopic observations and the MICP and NMR analyses have allowed the determination of the pore structure characteristics and their coupling effects on oil‐bearing property.

Astronomical forcing and sedimentary noise modeling of lake-level changes in the Paleogene Dongpu Depression of North China

Challenges in interpreting continental sequence stratigraphy and typically uncertain geochronology hinder the understanding of paleolake evolution and hydrocarbon exploration in terrestrial basins. The Dongpu Depression in North China is a lacustrine basin with abundant hydrocarbon resources. An accurate chronology for the Paleogene stratigraphy in the Dongpu Depression is lacking, and the mechanism of lake-level variation remains unclear. In this study, we utilize high-resolution gamma ray logs to conduct a cyclostratigraphic analysis of the Shahejie Formation, which is a Paleogene succession in the Dongpu Depression characterized by sandstones and dark mudstones interbedded with thin salt rocks. Time series analysis reveals evidence for 405 kyr eccentricity cycles in the gamma ray series, which is supported by statistical modeling of optimal sedimentation rates. Tuning of the gamma ray data to this 405 kyr eccentricity cyclicity enables a 14.7-Myr-long astronomical time scale to be constructed. This astrochronology is anchored to the astronomical age of the Dongying Formation/Shahejie Formation boundary (28.86 Ma) in the Bohai Bay Basin, thus providing an absolute timescale for the studied interval that extends from 28.86 Ma to 43.59 Ma. Using this anchored astrochronology, we show that a recently established sedimentary noise model for inferring sea level change in marginal marine settings can be used to similarly infer lake level fluctuations in terrestrial basins. In particular, sedimentary noise modeling of the tuned gamma ray series reveals high-resolution changes in sedimentary noise that are indicative of lake-level variations linked to million-year scale (i.e., ∼4.8 Myr, 2.4 Myr and 1.2 Myr) astronomical forcing. These inferred changes in lake level are supported by previously published sequence stratigraphic interpretations. Moreover, an evolutionary correlation coefficient (eCOCO) analysis of the gamma ray series also indicates recurrent distortions in sedimentation that may be linked to lake level changes. This study provides new methods for the assessment of paleolake level variations, as well as insights into the connection between astronomical forcing and lake evolution across long timescales in terrestrial basins.

Sequence stratigraphic framework and sedimentary model of Shanxi Formation in northeast Zhoukou Depression of the North China Plate

ABSTRACT The sequence stratigraphic framework of Shanxi Formation in the northeast Zhoukou Depression was established based on detailed sequence stratigraphical and sedimentological analysis by utilizing the logging and core data of six wells drilled in the eastern tectonic unit of Zhoukou Depression. It was divided into three third-order sequences, namely SQs1, SQs2, and SQs3 from bottom to top. Each sequence can be divided into a transgressive system tract (TST) and a highstand system tract (HST). Furthermore, four sequence boundaries and three maximum flooding surfaces were identified, and they are the bottom interface SBs and maximum flooding surface mfss1 of SQs1, the bottom interface SBs1 and maximum flooding surface mfss2 of SQs2, the bottom interface SBs3 and maximum flooding surface mfss3 of SQs3, and the top interface SBx from bottom to top. Carbonate tidal flat –clastic tidal flat sedimentary system developed in Shanxi Formation in the northeast Zhoukou Depression (also referred to as the study area) under the control of regression. Meanwhile, four sedimentary microfacies were identified in the sedimentary system, which are lime-mud flats, sand flats, mixed flats, and mud flats. The transgression in the study area occurred from the southeast to the northwest. Therefore, the northwestern part is the seaward side, and the southeastern part is the landward side. As revealed by relevant drilling data, SQs1 of the Shanxi Formation is characterized by the development of limestone and carbonaceous mudstone, with limestone, dark mudstone, and carbonaceous mudstone mainly developing. Meanwhile, lime-mud flats were mainly deposited in it. During the periods of SQs2 and SQs3, the sedimentary environment of the study area changed from the carbonate tidal flats to clastic tidal flats as the coastline migrated towards the sea. In these periods, sand flats mainly developed near the maximum flooding surfaces and were relatively continuous in the eastern and southern parts of the transgressive system tract; mixed flats were relatively continuous in the western and northern parts of the transgressive system tract as well as the eastern and southern parts of the highstand system tract; mud flats widely developed in the highstand system tract. Peat flats mainly developed in the period of HSTs2, with coal seams relatively developing in the southeastern part of the study area as revealed by drilling data. The peat flats in SQs2 are favorable hydrocarbon source layers, the lime-mud flats in SQs1 and sand flats formed in the transgression periods of SQs2 and SQs3 constitute favorable hydrocarbon reservoirs, and the mud flats form in the transgressions periods serve as favorable cap rocks. Therefore, the study area features a reservoir-cap assemblage for self-generating and self-storing of hydrocarbon, and the southeastern part of the study area can be taken as a favorable exploration area.

Geochemical characterization and possible hydrocarbon contribution of the Carboniferous interval natively developed in the Chepaizi Uplift of Junggar Basin, northwestern China

Previous studies on Chepaizi Uplift mainly focused on its reservoirs, and the potential source rocks natively occurred was ignored. During the exploration process, dark mudstones and tuffaceous mudstones were found in the Carboniferous interval. These possible source rocks have caused great concern about whether they have hydrocarbon generation potential and can contribute to the reservoirs of the Chepaizi Uplift. In this paper, the potential source rocks are not only evaluated by the organic richness, type, maturity, and depositional environment, but also divided into different kinetics groups. The Carboniferous mudstones dominated by Type III kerogen were evolved into the stage of mature. Biomarkers indicate that the source rocks were deposited in a marine environment under weakly reducing conditions and received mixed aquatic and terrigenous organic matter, with the latter being predominant. The effective source rocks are characterized by the total organic carbon values >0.5 wt.% and the buried depth >1500 m. The tuffaceous mudstone shows a greater potential for its lower active energy and longer hydrocarbon generation time. Considering the hydrocarbon generation potential, base limits of the total organic carbon and positive correlation of oil–source rock together, the native Carboniferous mudstones and tuffaceous mudstones might contribute to the Chepaizi Uplift reservoirs of the northwestern region of the Junggar Basin, especially the deeper effective source rocks should be paid enough attention to.

A new Hauterivian palynoflora from the Vale Cortiço site (central Portugal), and its palaeoecological implications for western Iberia

Abstract Palynofloral assemblages are an invaluable source of information about the interactions between fossil plants and their environments. Here we describe a new Early Cretaceous palynoflora from the Lusitanian Basin in the Estremadura region of central western Portugal. A palynological assemblage of 28 genera and 40 species was extracted from 14 samples collected in the Vale Cortiço clay pit complex near the small village of Ameal (Torres Vedras Municipality). The source is a dark grey mudstone layer belonging to the lower part of the Santa Susana Formation, which is considered to be of early Hauterivian age. The palynoflora is dominated by fern spores and gymnosperm pollen. Bryophyte and lycophyte palynomorphs are also present but subordinate. Angiosperm pollen and algal or dinoflagellate cysts were not recognised in the studied samples. The palynological assemblage represents mixed conifer forest with the ground cover and understorey vegetation dominated by ferns, with patchy occurrences of bryophytes and lycophytes. A riverine environment with surrounding vegetation of open woodland and ground cover primarily of ferns is strongly indicated for the region.

Superheavy pyrite in the Upper Cretaceous mudstone of the Songliao Basin, NE China and its implication for paleolimnological environments

The widely developed dark mudstone in the Upper Cretaceous Nenjiang Formation of the Songliao Basin is a natural archive for reconstructing the palaeoenvironment. A time series sulfur isotope study on the Nenjiang Formation reveals that authigenic pyrite from the paleo-lake is enriched in 34S relative to coeval marine sulfate in the lower Nenjiang Member I and basal Nenjiang Member II. The occurrence of 34S-enriched pyrite must be explained to understand the paleolimnological environment and the sulfur cycling during this period, for which several explanations can be advanced. Based on a comparison of various mechanisms for superheavy pyrite formation, we consider the presence of an anaerobic sulfate minimum zone (SMZ) in the paleo-lake as the most likely scenario. In this zone, sulfate was enriched in 34S through microbial sulfate reduction (MSR), and this heavy sulfate became the source for pore water or bottom water, from which superheavy pyrite was produced. The conceptual model for formation of the superheavy pyrite in the Nenjiang Formation indicates that the distribution range of the SMZ was variable in the different sedimentary stages of the Nenjiang Formation. These variations were likely related to successive inputs of sulfate from continental weathering, which led to partial mixing of sulfate and attenuation of the SMZ in the basal Nenjiang Member II.

The positive prospect of coal-derived gas in the Yingjisu Sag, Tarim Basin, China

Coal-derived gas determined by stable carbon isotopes were found in Well HYC 1 in the Yingjisu Sag, which brings a new dawn for gas exploration in this sag. Thermal maturity of the source rocks ranges 0.50%–0.65%. According to the traditional views that industrial oil/gas accumulations can only be formed if the thermal maturity of the source rocks is over 0.70%, so the recoverable resources of coal-derived gas were only 24.5 × 109 m3, and there was no drilling in the last 15 years. The TOC values of the Jurassic coal-measure mudstone, carbonaceous mudstone, and coal in the Yingjisu Sag are similar to those in the Kuqa Depression. Both of them belong to medium quality source rocks; hence the potential of gas generation and accumulation is good. In the Yingjisu Sag, the Jurassic residual thickness is 1000–2000 m. The distribution area with the maximum thickness of coal is basically overlapped with the distribution areas with the maximum thickness of carbonaceous mudstone and dark mudstone. The continuous distribution area is about 8000 km2, which should be the richest and the most favorable exploration area for the coal-derived gas resource, wherein gas fields will be discovered in the future.

Depositional characteristics and evolution of the shallow water deltaic channel sand bodies in Fuyu oil layer of central downwarp zone of Songliao Basin, NE China

Relatively few subsurface studies have been conducted on shallow water deltaic channel characteristics and evolution in Songliao Basin’s Fuyu oil layer. Using data from 2000-m cores and 60 wells, the shallow water deltaic channels sand bodies in the Fuyu oil layer are reconstructed. The main controlling factors over depositional system evolution are identified. Twelve lithofacies and four main facies associations are summarized. Four facies associations are identified, including (1) a simple distributary channel association, (2) type A point bar distributary channel association, (3) type B point bar distributary channel association, and (4) an underwater distributary channel association. The depositional evolution of the channels is derived from a lacustrine regressive–transgressive cycle that is driven by climate variability and tectonics, and linked to changes in relative lake-level. During periods of rapid drops in relative lake-level or rises in the semi-arid lower shallow water delta plain, channel, sand bodies are type B point bar distributary channel of laterally aggregational deposits. When relative lake level reaches to its lowest value, it results in a large-scale erosive bounding surface juxtaposed with type A point bar distributary channel sand bodies that are infilled with thick bedding in the upper shallow water delta plain. When high relative lake levels generate regional high accommodation/sediment supply ratios, the thin-bedding underwater distributary channel sand bodies are deposited in the humid shallow water deltaic front. Shallow water delta fills are capped by laterally extensive and continuous deep lacustrine dark mudstone and oil shale elements as the relative lake level rises to its highest value.

Nature of dispersed organic matter and paleoxygenation of the Campano-Maastrichtian dark mudstone unit, Benin flank, western Anambra Basin: Implications for Maastrichtian Trans-Saharan seaway paleoceanographic conditions

The Campano-Maastrichtian age is an important time in the geological evolution of Nigeria as it marked the re-establishment of the Trans-Saharan seaway that was broken due to Santonian inversion tectonics. In this paper, we conducted a high-resolution investigation of the dark mudstone unit of the Campano-Maastrichtian Mamu Formation exposed in 4-outcrops in the western segment of the Anambra basin, Nigeria, using multidisciplinary tools involving geochemistry, palynofacies, and microfabric analyses. Our objectives were to determine the nature of organic matter preserved in the sediments and the paleo-oxygenation conditions of the Trans-Saharan seaway. Our findings reveal that the Trans-Saharan seaway was of low salinity, characterized by the dominance of terrestrial organic matter in the more proximal marsh and bay sub-environments (organic facies C and CD) and mixed terrestrial – marine organic matter (organic facies BC and C) in the more distal central basin. Bottom water paleo-oxygenation was predominantly oxic. However, palynofacies and microfabric evidences as well as inferences from Fe-TS-TOC relationship suggests pyrite formation occurred in at least two phases. The first phase of syngenetic to early diagenetic pyrite formation, which was due to bacterial sulphate reduction that occurred in the anoxic zone below the sediment water interface, whereas secondary (late diagenetic) pyrite growth which formed the bulk of pyrite preserved occurred at the base of the bottom water. Furthermore, we hypothesize that pyrite formation occurred faster, and was better preserved in the central basin than in the other sub-environments. This is attributed to the presence of more reactive organic matter (marine palynomorphs), higher salinity (more sulphate), mineralogy (higher clay content), and microfabric (thinner lamination with low degree of bioturbation).

The mercury isotope signatures of coalbed gas and oil-type gas: Implications for the origins of the gases

The concentration of mercury vapor (elemental mercury, Hg0) in natural gases has been used to differentiate between coalbed gas and oil-type gas. However, the concentrations of Hg0 in coalbed gas and oil-type gas are highly variable, and its use as a genetic indicator is problematic. Here, for the first time, we report significant differences in the mass-dependent fractionation (MDF, measured with δ202Hg) and the mass-independent fractionation (MIF, measured with Δ199Hg, Δ200Hg and Δ201Hg) of Hg0 isotopes between coalbed gas and oil-type gas. Coalbed gas has an extremely negative δ202Hg (−5.8‰ to −3.08‰) and negative Δ199Hg (−0.19‰ to −0.01‰) relative to the assumed source, which is Permian coal from the Henan Province, China. Oil-type gas is characterized by less negative δ202Hg (−3.08‰ to −0.77‰) and positive Δ199Hg (0.06‰–0.30‰) relative to its E2-3s source rocks in the Liaohe oilfield (dark mudstones: δ202Hg = −1.96‰ to −2.48‰, Δ199Hg = 0.09‰–0.17‰). This significant difference in the MIF can be used to distinguish between coalbed gas and oil-type gas. Notably, the Δ200Hg values of our samples are as high as 0.15‰. We suggest that significant Hg0 MDF might occur during the formation of coalbed gas, but not during the formation of oil-type gas. This study highlights the potential of Hg0 isotopes as proxies for the source of natural gases.

Oil and gas enrichment patterns and major controlling factors for stable and high production of tight lacustrine carbonate rocks, a case study of Yingxi area in Qaidam Basin, West China

In recent years, sustained important discoveries of oil and gas exploration in the E 32 reservoir of Oligocene in the Yingxi area have been achieved, which revealed great exploration potential in Qaidam Basin. Based on core observations and systematic research on micro-petrological and structural characteristics, lithology, hydrocarbons enrichment patterns, and major controlling factors of stable and high production of the Oligocene reservoir in the Yingxi area of Qaidam were studied. The following findings were reported: (1) the lithology of the target layer is mainly lacustrine carbonate rocks, which can be divided into inter-salt and subsalt strata. In addition, many thick layers of halites widely developed in inter-salt strata. While thin layers of gypsum also developed scatteringly in the subsalt strata. (2) Fine-grained lacustrine carbonate rocks (including dark mudstone) were deposited under saline conditions, which not only are relatively the best quality source rock, but also developed a “dessert” dolomite reservoir. This set of strata is characteristic of “authigenic source rock and authigenic reservoir”. The upper salt layers have a strong sealing ability because of their very high capillary breakthrough pressure and plastic characteristics, and joints formed widely in the subsalt strata since stress concentration. The good matching relationship among all of the above factors led to the formation of favorable area for large-scale hydrocarbon accumulation in the subsalt strata. (3) The development of the matrix intercrystalline pores controls the scale of oil and gas reservoirs and stable production. Moreover, the development of fractures controls the enrichment of oil and gas reservoirs and high production. The research results have important guiding significance for further research on subsalt oil and gas distributing regularities, as well as further exploration deployment of E 32 in the Yingxi area.

Geology of the area between Bardibas and Sindhuli Madi, Sub-Himalaya, Central Nepal

The Siwalik Group (Sub-Himalaya) is the east-west extending youngest mountain belt formed by the sediments derived from the rising Himalaya on the north. The Siwalik Group is separated from the Lesser Himalaya to the north by the Main Boundary Thrust (MBT), and the Indo-Gangetic Plain to the south by the Main Frontal Thrust (MFT). The study was carried out mainly along the Ratu Nadi, Kamala Nadi river sections and was lithostratigraphically divided into the Lower Siwalik, Middle Siwalik, and Upper Siwalik, from the bottom to the top section, respectively. The Lower Siwalik is composed of fine-grained greenish grey calcareous sandstone (subarkose and lithic arenite), variegated mudstone, and calcareous siltstone. The Lower Siwalik is exposed due to the Marine Khola Thrust in the Gadyauli Khola, and sandstone there is more indurated and non-calcareous. The Middle Siwalik is mainly comprised of the medium- to coarse-grained salt-and-pepper sandstone (arkose and subarkose) with large cross lamination, calcareous sand lenses, convolute bedding, dark grey siltstone and mudstone. Plant fossils are also present in the finely laminated clay bed of the Middle Siwalik along the Ratu Nadi section. The Upper Siwalik comprises of mud- to sand-supported pebble to cobble conglomerates.

Geochemical differences of pyrolysis gas of various coal-bearing source rocks and its application in the Sulige gas field, Ordos Basin, China

In order to study the gas generation process of different coaly source rocks, thermal simulation experiments were performed on coal, dark mudstone, and carbonaceous mudstone. Additionally, a series of geochemical analysis including chemical composition, carbon and hydrocarbon isotope composition, as well as light hydrocarbon analysis on thermal simulation gas were also carried out in this study. It revealed that coal has the highest gas production rate; in addition, it yields a large amount of CO2 gas in the early stage of the simulation experiment. The carbon and hydrocarbon isotope of the coal thermal simulation gas is slightly heavier than that of coaly mudstone and carbon mudstone gas. Prior to reaching 500 °C, the carbon and hydrogen isotopes of these three kinds of gas became lighter and higher with the increase of temperature, but after 500 °C, they became lighter all throughout. Carbon isotope series reversal is observed in this process. The coal thermal simulation gas has the highest content of benzene, toluene, and 2,3-methylpentane. This study specified three highlights on the Sulige gas field: (1) CO2, formed in the early stage of hydrocarbon generation, may have a direct relationship with the reservoir densification in the Sulige gas field. (2) According to the analysis of light hydrocarbon, coal should be the dominant contributor to the accumulation of the Sulige natural gas. However, the contribution of coaly mudstone and carbon mudstone should not be ignored.

Key factors controlling hydrocarbon enrichment in a deep petroleum system in a terrestrial rift basin—A case study of the uppermost member of the upper Paleogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin, NE China

Abstract Mineralogical, petrographical, geochemical analyses, and fluid inclusions petrography and microthermometry were combined to investigate the basic properties of the source rock (organic matter content, kerogen type, and thermal maturity) and sandstone reservoirs (composition, pore systems, porosity, and permeability), the hydrocarbon origin, and the formation mechanisms of the deep (>3.5 km) petroleum system in the Upper Paleogene Es1 (the uppermost member of the Shahejie Formation) in the No. 3 Structural Belt in the Nanpu Sag, Bohai Bay Basin. The results indicate that the Es1 source rock is primarily composed of dark gray mudstone and presents a set of high-quality source rocks (>500 m, average total organic carbon (TOC) 1.38%, in a mature stage (maximum pyrolysis yield of 430 °C–460 °C)). The Es1 sandstone is composed of lithic arkose formed in a braided river delta and has low porosity (average 13.4%) but moderate-high permeability (average 184.9 mD). The hydrocarbons originated from the Es1 source rocks in the Caofeidian subsag during two charging periods: 10 Ma and 3 Ma. The key factors controlling the formation of the deep petroleum system are as follows: (a) High-quality hydrocarbon supply, (b) Medium-high permeability reservoirs, (c) A favorable configuration of the source rock and reservoirs (self-generated and self-accumulated), and (d) Late hydrocarbon charging; the second factor is the most important. The medium-high permeability reservoirs are attributed to a high-energy depositional environment (distributary channels of braid delta front), a high content of rigid detrital grains (mainly quartz and metamorphic rock fragments) provided by the Archean granite provenance, and the secondary pores formed by feldspar dissolution. This study provides a new example for revealing the formation mechanisms of deep (>3.5 km) petroleum systems in the terrestrial rift basin across the Bohai Bay Basin.

Campano-Maastrichtian paleoenvironment, paleotectonics and sediment provenance of western Anambra Basin, Nigeria: Multi-proxy evidences from the Mamu Formation

This article presents the results of a high-resolution evaluation of the sedimentological, mineralogical, palynofacies, and geochemical aspects of the Mamu Formation aimed at deciphering the sediment provenance, as well as the prevailing paleoenvironmental, paleoclimatic and paleotectonic conditions that occurred during the late Campanian-middle Maastrichtian age in the less studied western section of the Anambra Basin, Nigeria. Four measured sections exposed in Uzebba (composite), Auchi, Okpekpe, and Imiegba were investigated using sedimentological (outcrop studies and laser diffraction particle size analysis), mineralogical (XRD), geochemical (ICP-MS and XRF) and palynofacies techniques. Seven lithofacies were identified and grouped into central basin, marsh, bay, barrier, beach, and washover fan facies association as well as meandering fluvial-tidal channel facies association interpreted as indicative of a tidally influenced wave dominated estuarine paleoenvironment. In addition, mineralogical and palynofacies characterization revealed the heterogeneous nature of the dark mudstone lithofacies, varying from a more proximal low salinity phytoclast and quartz dominated marsh and bay mudstones to a more distal higher salinity palynomorph and clay dominated central basin accumulating deep-water mudstones. Consistent with recent Campano-Maastrichtian paleogeographic and paleoclimatic models we observed a dominance of kaolinite, a high chemical index of alteration above 90%, and a predominantly low index of compositional variability values (<1%), which signifies mineralogical maturity of the sediments due to sediment recycling and intensive chemical weathering under humid tropical paleoclimate. Furthermore, trace and major element discriminant plots revealed a felsic-intermediate provenance for the sediments under passive margin paleotectonic regime, which is in agreement with the regional distribution, geology, and geochemistry of the pre-Santonian rocks and the Precambrian basement rocks in the area.

Analysis of Occurrence Conditions of Cretaceous Aquifer in Longdong Ningzheng Mining Area

In order to grasp the occurrence conditions of the Cretaceous aquifer in Longdong Ningzheng mining area, the types and laws of the aquifers in the area, hydrogeological characteristics, and recharge and excretion conditions were analyzed. The study found that the groundwater in the east of the Longdong Basin was replenished in three directions, and the south side was Excretion boundary. The early cretaceous aquifer is the most important groundwater in the Ningzheng mining area. The cretaceous aquifers of the Lower Cretaceous Huanhe Formation are widely distributed in the area. The shallow weathering fissures develop and communicate with each other, which is groundwater migration and a good place to live. The lithology of the pores and fissures of the Huanhe Formation is dark purple red siltstone and mudstone, which is a weak and water-rich aquifer. The lithology of the pores and fissures of the Luohe Formation is mainly purple-red and brown-red medium-grained sandstones. It is a medium-rich water-rich water-rich aquifer. The local borehole has a strong self-flowing water phenomenon. The aquifer recharge is mainly Subgrade recharge of the diving and infiltration replenishment of atmospheric precipitation.