Oil Source Rocks Research Articles

Experimental Simulation of Hydrocarbon Expulsion in Semi-open Systems from Variable Organic Richness Source Rocks

To better understand oil and gas generation and expulsion mechanisms and their controlling factors, two-stage heating program (20 and 5 °C/d) at 11 target temperatures (250–580 °C) have been performed in a semi-open reactor on nine immature lacustrine shale samples from the Triassic Yanchang Formation in Ordos Basin, NW China, with total organic carbon (TOC) contents ranging from 0.5% to 30.0%. The cumulative expelled oil and gas were quantified and correlated with the measured vitrinite reflectance (%Ro) and residual TOC. The amount of expelled oil increases substantially with increasing maturity in the Ro range of 0.5–1.25% and ends at Ro of >1.45%, while the volume of expelled gas increases markedly with maturity when Ro is >1.0%. Organic richness exerts primary control on the expulsion yields, which increase linearly with increasing original TOC (TOCo) per unit weight of rock, whereas the increment decreases with TOCo per unit weight of TOC, once the TOCo content is above 5%. Marked TOC reduction occurs in the Ro of 0.5–1.1% due to oil generation and expulsion, but the trend is reversed in the higher maturity range possibly caused by the simultaneous decomposition of minerals. Numerical correlations among heating temperatures, %Ro, TOC content, and expelled oil and gas yields have been constructed, and the minimum TOC contents for effective oil and gas source rocks have been inferred. The lowest TOC contents of 0.5% and 0.48% are required for oil and gas expulsion in the oil and gas generation window, corresponding to the TOCo of 0.91% and 0.76%, respectively. The minimum TOC content for effective gas source rocks decreases slightly with increasing maturity; however, a much higher TOC cutoff is required for lower maturity level source rocks. Wide range of TOC content variation in our studied samples provides well constraint of organic richness on oil and gas generation and expulsion behaviors and their evolution trajectory during thermal evolution, which will fascinate source rock quality and exploration potential assessment in other source rock systems.

Diagenesis of the Malmian Mikulov Formation source rock, Vienna Basin: Focus on matrix and pores

Diagenetic processes and pore development in the matrix of the 1000 m thick main source rock for oil and gas in the Vienna Basin, the autochthonous Malmian mudstones of the Mikulov Formation have been studied. Core samples from wells over a true vertical depth range of 1400 m–8551 m were available. The bulk samples contain quartz, minor amounts of plagioclase, pyrite and a large but variable proportion of calcite; the clay mineral content ranges from 14 to 47%. The clay fraction contains a prominent illite-smectite (I–S) mixed-layer phase, illite, chlorite and kaolinite. The quantities of I–S and kaolinite decrease with depth, whereas illite and chlorite increase with depth. Diagenesis has involved a gradual transformation of smectite to illite through mixed-layer I–S intermediates. The ordering of the mixed layer I–S changes with increasing depth from R0 to R1 and R3. The R1 transformation of the mixed-layer I–S occurs at approximately 3000 m and vitrinite reflectance values of 0.4%–0.6%. Based on petrographic evidence, the cations resulting from the illitization of smectite were the source of a variety of late diagenetic mineral cements, such as Fe and Mg for chlorite formation and for ferroan dolomite precipitation. Illitization also provided Si for local quartz cementation. During diagenesis nanometer to micrometer size pores developed because of specific mineral frameworks and dissolution processes. Organic matter pores developed in deeper, thermally mature samples. Phyllosilicate framework pores between brittle grains are commonly observed. Pores caused by partial dissolution of carbonate grains also occur. In places diagenetic cements, such as quartz overgrowths or carbonate cements keep pores propped open. The connectivity of the pores cannot be established unequivocally from SEM photomicrographs, but they likely contribute to the creation and preservation of effective porosity and gas storage capacity of these rocks.

Base metal mobility linked to brine and hydrocarbon migration at the Huincul High in the Neuquén Basin, Argentina: Implications for the formation of sediment-hosted base metal deposits

This contribution discusses the discovery of PbZn mineralization in hydrocarbon exploration drill holes hosted in siliciclastic Jurassic rocks below the Cretaceous sediment hosted Cu mineralization located north of the Huincul High. In the Early Cretaceous, hydrocarbon and basinal water expulsion took place from the oil source rocks (Los Molles Formation) into the reservoir rocks Lajas Formation (Middle Jurassic), after the formation of diagenetic quartz overgrowths. Marcasite, pyrite and illite + illite-smectite mixed layer minerals then formed together with hydrocarbons. Marcasite (δ34S −3.5 and −2.2‰) and pyrite (δ34S −11.6 to 18.1‰) precipitated via bacterial sulfate reduction from fluids showing temperatures <80 °C and fluctuating pH conditions. During the Paleogene, Andean tectonism triggered migration of oxidized basinal brine containing dissolved leached Zn and Pb from the Los Molles Formation source rocks and S from the evaporites of the basin. This brine entered in the hydrocarbon reservoir of the Lajas Formation, resulting in the precipitation of sphalerite (δ34S +10.4 to +10.8‰) and galena (δ34S +5.2‰) by TSR at temperatures of 119–123 °C together with siderite. The Andean orogeny may also have triggered the migration of hydrocarbons + brines from the shallowest source rocks (Vaca Muerta Formation) and reservoir rocks (Mulichinco, Lajas and Lotena formations) into the red beds of the upper Cretaceous Neuquén Group, which became bleached as a result. Marcasite (δ34S −36.4 to 18.2‰) and pyrite (δ34S −60.2 to −24‰) precipitated by BSR, while calcite (δ13C −12.3 to −5.6‰) formed due to redox reactions accompanying formation of quartz overgrowths, clay mineral coatings (δD −92.4‰ to −82.8‰ and δ18O 16.2‰ to 18.40‰), and barite (δ34S −5.9‰). Quartz overgrowths and barite precipitated from brines (1.5–10 wt% NaCl equiv.) at temperatures of 91–120 °C, with barite precipitating close to the feeder zones. Calcite cements are more widespread and generated from several pulses of brine and hydrocarbons up flow, evidenced by the wide range of homogenization temperatures (100–185 °C) and diversity of UV fluorescence colors of hydrocarbon-rich fluid inclusions. In subsequent Miocene tectonic events, basinal brines were able to leach Cu from the underlying thick red beds of the basin, entering the Neuquén Group oil reservoir traps or carrier beds where they became reduced. Chalcopyrite and bornite precipitated at temperatures >100 °C close to the feeder zones at the expense of barite as a local sulfur source. Chalcocite group minerals (δ34S −21.3‰ to −7.3‰) precipitated outwards in pore spaces of the sandstones at lower temperatures (<100 °C) through BSR of sulfate in the mineralizing brines. Final exhumation of the Neuquén Group (Upper Miocene-Pliocene) promoted the infiltration of the meteoric water, the oxidation of the sulfides and formation of supergene FeCu, V and U minerals. Isotope geochemistry and fluid inclusion results combined with alteration and ore mineralogy document the processes controlling the distribution of base metals in the Huincul High region that can be applied to evaluate the metal potential in other areas of the Neuquén Basin and further extrapolated to similar geological systems elsewhere.

North Alaska Super Basin: Petroleum systems of the central Alaskan North Slope, United States

North Alaska Super Basin oil fields have produced more than 18 billion bbl of oil with at least 5 billion bbl remaining in existing fields, and estimated yet-to-find resources exceed 10 billion bbl in three prolific petroleum systems. Since discovery of the two largest United States conventional oil fields at Prudhoe Bay and Kuparuk River in the 1960s, technological advancements including three-dimensional seismic data with amplitude vs. offset analysis, horizontal and extended reach drilling, and identification of source rocks for light oils have enabled new discoveries including Willow and Pikka. Oil in the Prudhoe Bay field is interpreted as a mixture cosourced by lateral migration from Triassic Shublik Formation shale and carbonate, Lower Cretaceous highly radioactive zone (HRZ) shale, and Lower Jurassic Kingak Shale. The bulk properties of Prudhoe Bay main field oils are consistent with the modeled oil composition expelled within the fetch area, and the presence or quality of carrier beds apparently did not affect oil migration efficiency. The Shublik Formation is interpreted as the oil source for Kuparuk River field, the HRZ shale is interpreted as the oil source for Tarn field, and the Kingak Shale is interpreted as the oil source for Alpine field. Point McIntyre field is interpreted as sourced by the same three source rocks as Prudhoe Bay field, and Fiord field is interpreted as cosourced from Shublik and Kingak. West Sak field is interpreted as a mixture of moderately biodegraded oil that spilled from the Prudhoe Bay field and lightly biodegraded condensate that leaked from the underlying Kuparuk River field.

Characteristics and evaluation of the Upper Paleozoic source rocks in the Southern North China Basin

Abstract The Upper Paleozoic coal measure strata in the Southern North China Basin have good potential for unconventional oil and gas exploration. However, there has been no systematic evaluation of potential source rock in this area; this affects the estimation of potential resources and the choice of exploratory target layers. In this study, full core holes ZK0901 and ZK0401, which perfectly reveal Upper Paleozoic strata in the study area, systematically collected and analyzed the samples for total organic carbon, rock pyrolysis, chloroform bitumen “A,” organic maceral, vitrinite reflectance, and kerogen carbon isotopes. The results showed that in addition to coal rocks, mudstones and carbonate rocks are also potential source rocks in the Upper Paleozoic strata. Vertically, the source rocks are continuous in Taiyuan Formation, the lower part of Shanxi Formation, and Lower Shihezi Formation. The organic matter type in the Upper Paleozoic coal rocks and mudstone source rock belong to type III or II. This phenomenon is mainly attributed to the special transgressive–regressive sedimentary environment of the carbonate rocks. The higher degree of thermal evolution in the Upper Paleozoic source rocks may be related to the structure or a higher paleogeothermal gradient in this area. The coal layer and its upper and lower mudstone of the Shanxi Formation and Lower Shihezi Formation are the main target layers of unconventional oil and gas exploration. The results from this study can be used as a reference for the study on potential source rock for unconventional oil and gas exploration in the Southern North China Basin.

Source rock characterization and its influence on pore volumes in Lower Gondwana shale samples of Damodar Valley, India

This study aims to investigate the hydrocarbon potential and storage capacity of five shale samples collected from Barren Measure Formation of Damodar Valley in India. Characterization of source rocks was performed using rock eval pyrolysis and, pore volumes were measured using the MICP and low pressure CO2 adsorption methods. Results of pyrolysis show excellent TOC content ranging between 4.24% and 9.78%. Variation in Tmax values from 437 to 447 °C indicates that the thermal maturity is within the oil window range. Values of HI (110–211 mg HC/gm TOC) and OI (3–36 mg HC/gm TOC) indicate a mixture of Type II and Type III kerogen which, can be a good source rock for oil and gas. Pore spaces present within the rock act as storage for the generated hydrocarbons. Pore volume and pore-size are the major influential factors for the storage and production capacities of hydrocarbon reservoirs. Results of MICP experiments show high porosity values (≥13%) for all the samples. Macro and mesopore volumes calculated using the MICP method are varying within the range between 0.074 and 0.17 cc/mg. Low-pressure adsorption using CO2 gas was adopted to estimate the micropore volume of the samples. The volumes of micropores are varying between 2.3 cc/gm and 4.1 cc/gm. Pore volumes measured using both techniques were arithmetically summed up to calculate the total pore volume of the samples. Source rock characters shows a change in trend below 475 m. High pore volumes indicate a good storage capacity for the studied samples. Having the potential to be a good source rock for hydrocarbon and also containing higher pore volume to store hydrocarbon, Barren Measure shale can be considered as a good source as well potential hydrocarbon reservoir rocks among Indian shale formations.

Effective source rock selection and oil\u2013source correlation in the Western Slope of the northern Songliao Basin, China

This study considers the Upper Cretaceous Qingshankou Formation, Yaojia Formation, and the first member of the Nenjiang Formation in the Western Slope of the northern Songliao Basin. Dark mudstone with high abundances of organic matter of Gulong and Qijia sags are considered to be significant source rocks in the study area. To evaluate their development characteristics, differences and effectiveness, geochemical parameters are analyzed. One-dimensional basin modeling and hydrocarbon evolution are also applied to discuss the effectiveness of source rocks. Through the biomarker characteristics, the source–source, oil–oil, and oil–source correlations are assessed and the sources of crude oils in different rock units are determined. Based on the results, Gulong and Qijia source rocks have different organic matter primarily detrived from mixed sources and plankton, respectively. Gulong source rock has higher thermal evolution degree than Qijia source rock. The biomarker parameters of the source rocks are compared with 31 crude oil samples. The studied crude oils can be divided into two groups. The oil–source correlations show that group I oils from Qing II–III, Yao I, and Yao II–III members were probably derived from Gulong source rock and that only group II oils from Nen I member were derived from Qijia source rock.

Deep fluids and their role in hydrocarbon migration and oil deposit formation exemplified by supercritical СO2

ABSTRACTHydrocarbon migration mechanism into a reservoir is one of the most controversial in oil and gas geology. The research aimed to study the effect of supercritical carbon dioxide (СО2) on the permeability of sedimentary rocks (carbonates, argillite, oil shale), which was assessed by the yield of chloroform extracts and gas permeability (carbonate, argillite) before and after the treatment of rocks with supercritical СО2. An increase in the permeability of dense potentially oil-source rocks has been noted, which is explained by the dissolution of carbonates to bicarbonates due to the high chemical activity of supercritical СО2 and water dissolved in it. Similarly, in geological processes, the introduction of deep supercritical fluid into sedimentary rocks can increase the permeability and, possibly, the porosity of rocks, which will facilitate the primary migration of hydrocarbons and improve the reservoir properties of the rocks. The considered mechanism of hydrocarbon migration in the flow of deep supercritical fluid makes it possible to revise the time and duration of the formation of gas–oil deposits decreasingly, as well as to explain features in the formation of various sources of hydrocarbons and observed inflow of oil into operating and exhausted wells.

Bulk pyrolysis and biomarker fingerprints of Late Cretaceous Galhak Shale Formation in the northern Melut Basin, Sudan: implications on lacustrine oil-source rock

Organic-rich shale samples from the Late Cretaceous Galhak Formation were collected from one well location in the northern Melut Basin, Sudan, and analyzed by integrated organic geochemical and microscopic techniques. The study investigates the nature and preservation conditions of the organic facies and their relevance to petroleum resource potential. Judging from the high total organic contents (total organic carbon (TOC) > 2%), the analyzed Galhak shales are organically rich and include favorable source rocks. The organic richness in these shale sediments may be attributed to enhance the preservation of organic matter under suboxic conditions as implied from the n-alkanes and isoprenoid biomarkers. Biological markers, including of n-alkanes, isoprenoids, terpanes, and steranes, further suggest that the Galhak shale sediments were deposited in a relatively fresh lacustrine environment and received largely aquatic organic matter of plankton and bacteria with little terrestrial plant input. An abundance of aquatic-derived organic matter is consistent with types I and II kerogen as indicated by high Rock-Eval HI values of more than 400 mg HC/g TOC. The hydrogen-rich kerogen types I and II in the analyzed samples suggests an oil-prone source. According to the optical and geochemical maturity indicators, the organic matter in the Galhak oil shale is thermally immature; thus, they have not reached sufficient oil-window maturity for commercial oil generation. Therefore, the deeper parts of the Melut Basin, where the Galhak Formation reached high mature of peak-oil generation window, are recommended for further petroleum exploration and production.

Formation conditions and evolution of oil and gas source strata of the Laptev sea shelf ore and gas province

Introduction. To date, no unified well-established concepts have been developed regarding the oil and gas geological zoning of the Laptev Sea shelf, as well as other seas of the Eastern Arctic. Different groups of researchers define this region either as an independently promising oil and gas region [7, 8], or as a potential oil and gas basin [1].Aim. To construct spatio-temporal digital models of sedimentary basins and hydrocarbon systems for the main horizons of oil and gas source rocks. A detailed analysis of information on oil and gas content, the gas chemical study of sediments, the characteristics of the component composition and thermal regime of the Laptev sea shelf water area raises the question on the conditions for the formation and evolution of oil and gas source strata within the studied promising oil and gas province. The conducted research made it possible to study the regional trends in oil and gas content, the features of the sedimentary cover formation and the development of hydrocarbon systems in the area under study.Materials and methods. The materials of production reports obtained for individual large objects in the water area were the source of initial information. The basin analysis was based on a model developed by Equinor specialists (Somme et al., 2018) [14—17], covering the time period from the Triassic to Paleogene inclusive and taking into account the plate-tectonic reconstructions. The resulting model included four main sedimentary complexes: pre-Aptian, Apt-Upper Cretaceous, Paleogene, and Neogene-Quaternary.Results. The calculation of numerical models was carried out in two versions with different types of kerogen from the oil and gas source strata corresponding to humic and sapropel organic matter. The results obtained indicated that the key factor controlling the development of hydrocarbon systems was the sinking rate of the basins and the thickness of formed overburden complexes, as well as the geothermal field of the Laptev Sea.Conclusion. The analysis of the results obtained allowed the most promising research objects to be identified. The main foci of hydrocarbon generation in the Paleogene and Neogene complexes and the areas of the most probable accumulation were determined. Significant hydrocarbon potential is expected in the Paleogene clinoforms of the Eastern Arctic.

Reaction kinetic, maturity, burial and thermal histories modelling of cambay shale source rocks, Cambay Basin, Western India

The Cambay Shale Formation (CSF), the known source rock for conventional oil and gas, now becomes a key target for shale oil/gas exploration in the Cambay Basin. In the present study, maturity, wellbore temperature and kerogen kinetics data from the several locations in the Cambay Basin have been integrated into PetroMod®, a basin and petroleum system modelling (BPSM) software, to generate maturity profile, burial and thermal history in the Cambay Basin. The Optkin program optimised kerogen kinetic results indicated that the activation energy for the type III kerogens, which are prominently available in the basin, varies widely (44–72 kcal/mol). A sample from Mehsana-Ahmedabad Block shows a narrow activation energy range (40–50 kcal/mol), a characteristics of type II kerogen and the maximum (91%) of the initial petroleum potential is contributed by a single activation energy (46 kcal/mol). BPSM models indicate that the major portion of the CSF in the north of the basin is mainly under early and main oil generation window, where shale oil prospect can be explored. Compared to the north part of the basin where late oil and wet gas generation windows enter into the Olpad Formation at ~2700 m and ~3100 m respectively, the source rocks, i.e. CSF at the centre of the Broach block in the South Cambay Basin indicate the presence of late oil and wet gas generation windows at ~3100 m and ~3900 m, respectively. The models generated in the study area suggest that the deeper section of the South Cambay Basin may have prospective for shale oil/gas.

Characteristics of lacustrine deepwater fine-grained lithofacies and source-reservoir combination of tight oil in the triassic chang 7 member in Ordos Basin, China

The lithofacies characteristics of fine sedimentary rocks affect the hydrocarbon generation capacity and reservoir performance of tight oil and are closely related to the sedimentary environment. On the basis of field outcrops and core observations, combined with logging data, thin section identification, grain size analysis, organic carbon analysis and physical property tests, the fine sedimentary facies of the Chang 7 Member in the Ordos Basin are studied. Nine lithofacies types are identified in the study area, including planar and trough cross-bedding sandstone facies (Spt), massive bedding sandstone facies (Sm), slump deformation fine sandstone facies (Ssd), sand-mud interbedded facies (Sb), rippled siltstones facies (Fr), horizontal bedding mudstone facies (Mh), massive bedding mudstone facies (Mm), horizontal bedding shale facies (S) and tuff facies (T). Lithofacies types Spt, Ssd, Fr are developed in the gentle slope belt in the northeastern study area, which is a delta front-semi-deep lake sedimentary environment and mainly contains underwater distributary channel and estuary dam sedimentary microfacies types. Lithofacies types such as Sm, Sb, Mh and T are developed in the southwestern steep slope zone of the study area, which is a channel-type gravity flow sedimentary environment, and sedimentary microfacies types such as near-source channels, far-source channels and leading-edge dolomites are developed. In the vertical direction, during the Chang 73 sedimentation period, the lake surface area and water depth reached their maxima, and S and Mh lithofacies developed, which were conducive to the formation of high-quality hydrocarbon source rocks for tight oil. During the Chang 72-Chang 71 sedimentation period, the lake basin shrank, and the reducibility of the water body weakened. The delta front sand body composed of Spt lithofacies in the northeast and the sandy clastic flow sand body composed of Sm in the southwest constitute the main tight oil reservoirs. High-quality hydrocarbon-generating lithofacies and favourable reservoir lithofacies are spatially superposed and developed, forming two source-reservoir combinations in the Chang 7 tight oil source-reservoir formation and near source-reservoir formation.

Индикаторные признаки карбонатных микробиолитов черносланцевых формаций: изотопный состав и биомаркеры

Carbonate rocks represented by nodules, lenses, layers of different morphology and length are typical for the black shale formations of different ages. They are of the greatest interest in oil source rocks as indicators of complex and not always unambiguously interpreted geological processes. A special place among these sedimentary bodies is occupied by microbialites, which indicate suppression of development of marine organic biocenoses, and often reflect emanation processes in ancient strata. Proof of these phenomena is fundamentally important for predicting and assessing the oil and gas potential of unconventional reservoirs. On the example of carbonate solids of Triassic and Jurassic black shale formations, we present a complex analytical method to determine the microbial biochemical genesis of rocks on the base of the isotopic composition of carbon and oxygen, together with the hydrocarbon molecular markers of organic matter. The geochemical features of the isolated microbialites suggest that they are resulted from a complex history of black shale formations, which reflects both background lithogenetic transformations and superimposed processes, including high-temperature hydrothermal ones.

Mathematical modeling of the electromagnetic influence on the oil-source rocks taking into account the phase transitions

Mathematical modeling of the electromagnetic influence on the oil-source rocks taking into account the phase transitions

Нефтегазоносность глубокопогруженного ордовикско-нижнедевонского нефтегазоносного комплекса юго-востока Тимано-Печорской нефтегазоносной провинции

The article is devoted to the assessment of the oil and gas potential of the deep Ordovician-Lower Devonian oil and gas complex in the south-east of the Timan-Pechora oil and gas province. Within the Upper Pechora Basin of the Pre-Ural trough and in the south of the Pechora-Kolva aulacogen, several wells were drilled with a depth of more than 5 km, some of which entered the Lower Paleozoic deposits. These strata are difficult to access and poorly studied, and the prospects for their oil and gas potential are unclear. The article describes the composition of the complex, gives geochemical characteristics, describes reservoir properties, and presents the results of 1D and 2D basin modeling. Models of the zoning of catagenesis are presented. The oil and gas complex includes a variety of oil and gas source rocks. It is possible to allocate collectors, as well as the seals. In the Lower Paleozoic sediments, the processes of oil, gas and gas condensate generation took place, which could ensure the formation of deposits both in the deep strata of the Lower and Middle Paleozoic, and in the overlying horizons. The generation and accumulation of hydrocarbons in deep-buried sediments occurred at a favorable time for the formation of deposits. However, it is considered that the scale of hydrocarbon generation for the Lower Paleozoic deposits is not high.

Substantial maturity influence on carbon and hydrogen isotopic composition of n-alkanes in sedimentary rocks

Carbon (δ13C) and hydrogen (δ2H) compound-specific isotope analyses on sedimentary hydrocarbons are widely used for ecological reconstructions and oil-source rock or oil-oil correlations. However, the effects of thermal alteration on isotopic composition are not fully understood, potentially imparting a bias on interpretation of older and more mature sedimentary sequences. We measured δ13C and δ2H of n-alkanes in 23 extracted bitumens from the 1.64 Ga Paleoproterozoic Barney Creek Formation in the southern McArthur Basin, Australia. The samples cover a wide range of thermal maturities with calculated vitrinite reflectance (Rc) values from 0.4% to 1.3%. Our results illustrate that while δ13C of kerogen remains relatively constant, the δ13C and δ2H of n-alkanes have a strong positive correlation with thermal maturity. Average δ13Calk increase by 6.8‰ and δ2Halk by 69‰ among the samples in the analysed maturity range. At the same time, the carbon isotopic offset between n-alkanes and kerogen (Δδ13Calk–ker) climbs from 1.3‰ to 8.5‰ with increasing maturity. Therefore, the substantial maturity influence on stable carbon and hydrogen isotopes of n-alkanes must be considered in palaeoecological and petroleum correlation studies. In the initial stages of maturation, n-alkanes from the Barney Creek Formation display increasingly positive “isotope slopes” in plots of δ13Calk against carbon number. However, with further maturation, the slopes became increasingly negative. The isotope slope inversion indicates that the dominant mechanisms for n-alkane generation and degradation changed during the progression from early diagenesis to metagenesis. Numerical models suggest that the formation of positive and negative isotope slopes may be driven by the balance of the formation of n-alkanes from kerogen and their subsequent degradation, and by dependence of the degradation rate constant k on n-alkane chain length.

Local high-salinity source rock and origin of crude oil in the xianshuiquan structure in the northwestern Qaidam Basin, China

Despite its importance as an oil-bearing structure in the northwest Qaidam Basin, the development characteristics of source rocks and the origin of crude oil in the Xianshuiquan structure have not been clarified. Based on total organic carbon, extracted chloroform bitumen “A”, kerogen maceral, vitrinite reflectance, light hydrocarbon, biomarker compositions and seismic profiles, comprehensive analyses are performed on the origin and accumulation of crude oil in the Xianshuiquan structure. The results show that: 1) unlike the conclusions of existing research in the northwest Qaidam Basin, the Upper Youshashan (N21) member of the Xianshuiquan structure developed a set of high-salinity source rocks with a hydrocarbon generation capacity; 2) the crude oil in the shallow members (above the Lower Youshashan (N1) formation) of the Xianshuiquan structure originated from the N21 high-salinity source rock that developed locally in the Xianshuiquan structure, rather than from the generally believed N1 source rock; 3) two sets of fault systems were developed in the Xianshuiquan structure and formed two types of petroleum system, deep and shallow, and the crude oil generated from the Upper Ganchaigou (E32) and N1 source rocks did not migrate into the shallow members for accumulation. 4) The light hydrocarbons of crude oil are lost seriously and the preservation conditions of crude oil in the Xianshuiquan structure are poor. According to the above results, the hydrocarbon accumulation model of the Xianshuiquan structure is established, and it is proposed that the deep members of the Xianshuiquan structure have considerable exploration and development prospects. These results are of great significance to the exploration and development of the northwestern Qaidam Basin.

Characteristics and formation of sinian (Ediacaran) carbonate karstic reservoirs in Dengying Formation in Sichuan Basin, China

The Gaoshiti-Moxi Gas Field has been discovered recently in the central part of Sichuan Basin, which might be the biggest gas field in China. In this gas field, a large amount of gas is from Neoproterozoic Sinian (Ediacaran) karstic carbonate rocks. The gas was originated from cracking of oil, and the oil source rocks are the Sinian and Cambrian strata. In this study, the characteristics of these carbonate reservoir rocks have been studied based on subsurface data and outcrop observation. The carbonate rocks are at the Sinian Dengying Formation, and the reservoir properties are controlled by sedimentary facies and diagenesis. The Dengying Formation is composed of algal mounds and grainstone build-ups, which were developed in a restricted platform setting from glacial period to interglacial period. Due to tectonic movement and eustatic cycle in Sichuan Basin during Neoproterozoic Era, five sedimentary cycles of transgression and regression have been developed in the Dengying Formation. According to the sedimentary facies and carbon-oxygen isotope variation, five sedimentary cycles have been recognized. Due to the penecontemporaneous dolomitization, together with hypergene karstification and late burial dissolution, the reservoir properties of the carbonates rocks have been improved greatly.

Evaluation of sedimentary features and biomarkers in the Paleogene Niubao formation in the Lunpola basin, Tibetan plateau: implications for the oil source rocks and exploration

The Paleogene Niubao formation is mainly exposed in the central part of the Lunpola basin in the hinterland of the Tibetan Plateau and has high potential for oil and gas exploration and development. The biomarkers of source rocks are systematically studied by selecting representative samples. The middle and upper Niubao formation contain rhythmically inter-bedded mudstone and sandstone that show periodic variations characteristic of the lake water environment. Additionally, the large volumes of muddy dolomite in the upper Niubao formation (UNF) are associated with high salinity in the lake environment under a hot and arid climate. The organic geochemical analysis shows that the middle Niubao formation (MNF) and UNF have high organic abundance (total organic carbon (TOC) contents of 1.48–8.96% in the MNF and 1.52–12.83% in the UNF) and type I–II kerogen. The analysis shows that the UNF was deposited in a persistent, anoxic, stratified and highly saline paleo-lake environment, which was beneficial to the preservation of organic matter. The high phytoalkane and γ-paraffin contents in the UNF indicate a strongly reducing and highly saline lacustrine depositional environment. The high pregnane contents and ascending sterane in the source rocks in the MNF indicate high maturity, and the distribution of n-alkanes and regular sterane indicates the input of some terrestrial organic matter. The high maturity indicates that the source rock in the MNF may represent the main hydrocarbon-generating layer in the basin.

How Can Deep Geothermal Projects Provide Information on the Temperature Distribution in the Upper Rhine Graben? The Example of the Soultz-Sous-Forêts-Enhanced Geothermal System

The Upper Rhine Graben (URG) hosts thermal anomalies that account for the development of oil fields. Recently, a geothermal power plant has been installed in this area. Data obtained in this framework provide an insight into the temperature distribution in the URG. The present thermal gradient at Soultz-sous-Forêts is not linear: nearly 90 °C/km down to 1400 m depth, then about 12 °C/km from that depth down to 5000 m. The combination of temperature conditions and natural fluid circulation in fracture networks has led to the hydrothermal alteration of the granite into mineral assemblages such as those including illite, quartz and calcite. Illite is locally impregnated with organic matter of two kinds: a mature type derived from oil source rocks and a less mature type derived from surficial sedimentary layers indicating the km-scale of transfer. Newly formed crystals of quartz and calcite from around 2000 m depth record a fluid temperature range of 130 to 170 °C, consistent with modelling and the temperatures measured at present in the drill-holes at this depth. In such hydrothermally altered zones, local variations of temperature are encountered indicating current fluid flows that are being sought for geothermal purposes.