Oil Source Rocks Research Articles

Fine-grained gravity flow sedimentation and its influence on development of shale oil sweet sections in lacustrine basins in China

The geological conditions and processes of fine-grained gravity flow sedimentation in continental lacustrine basins in China are analyzed to construct the model of fine-grained gravity flow sedimentation in lacustrine basin, reveal the development laws of fine-grained deposits and source-reservoir, and identify the sweet sections of shale oil. The results show that fine-grained gravity flow is one of the important sedimentary processes in deep lake environment, and it can transport fine-grained clasts and organic matter in shallow water to deep lake, forming sweet sections and high-quality source rocks of shale oil. Fine-grained gravity flow deposits in deep waters of lacustrine basins in China are mainly fine-grained high-density flow, fine-grained turbidity flow (including surge-like turbidity flow and fine-grained hyperpycnal flow), fine-grained viscous flow (including fine-grained debris flow and mud flow), and fine-grained transitional flow deposits. The distribution of fine-grained gravity flow deposits in the warm and humid unbalanced lacustrine basins are controlled by lake-level fluctuation, flooding events, and lakebed paleogeomorphology. During the lake-level rise, fine-grained hyperpycnal flow caused by flooding formed fine-grained channel–levee–lobe system in the flat area of the deep lake. During the lake-level fall, the sublacustrine fan system represented by unconfined channel was developed in the flexural slope breaks and sedimentary slopes of depressed lacustrine basins, and in the steep slopes of faulted lacustrine basins; the sublacustrine fan system with confined or unconfined channel was developed on the gentle slopes and in axial direction of faulted lacustrine basins, with fine-grained gravity flow deposits possibly existing in the lower fan. Within the fourth-order sequences, transgression might lead to organic-rich shale and fine-grained hyperpycnal flow deposits, while regression might cause fine-grained high-density flow, surge-like turbidity flow, fine-grained debris flow, mud flow, and fine-grained transitional flow deposits. Since the Permian, in the shale strata of lacustrine basins in China, multiple transgression-regression cycles of fourth-order sequences have formed multiple source-reservoir assemblages. Diverse fine-grained gravity flow sedimentation processes have created sweet sections of thin siltstone consisting of fine-grained high-density flow, fine-grained hyperpycnal flow and surge-like turbidity flow deposits, sweet sections with interbeds of mudstone and siltstone formed by fine-grained transitional flows, and sweet sections of shale containing silty and muddy clasts and with horizontal bedding formed by fine-grained debris flow and mud flow. The model of fine-grained gravity flow sedimentation in lacustrine basin is significant for the scientific evaluation of sweet shale oil reservoir and organic-rich source rock.

Sedimentology and geochemistry of Eocene source rocks in the east China sea: Controls on hydrocarbon generation and source rock preservation

As an important source rock for oil and gas generation, coal measure source rock has attracted much attention due to its high hydrocarbon generation potential. Therefore, we conducted a comprehensive evaluation of the source rocks based on organic geochemical and petrological data to clarify the sedimentary, geochemical, and hydrocarbon generation characteristics of the coal measure source rocks of the Pinghu Formation in the Xihu Depression. The source rocks were deposited in a shallow freshwater sedimentary environment with weak reduction-oxidation conditions. The organic matter is mainly derived from terrestrial higher plants, with less contribution from phytoplankton and bacteria. Compared to carbonaceous mudstone and mudstone, coal was deposited in an environment with stronger oxidation conditions, and stronger bacterial transformation. Within the study area, sag A receives relatively high contributions from phytoplankton and high liptinite content, whereas sag C receives the largest contribution from terrestrial higher plants. Sag A is dominated by source rocks with a relatively high oil generation potential and oil reservoirs, whereas other regions have limited oil generation capacity and are characterized by gas reservoirs and condensate gas reservoirs. The E2p2 member, with more terrestrial organic matter input, has a higher TOC content and hydrocarbon generation potential than the E2p1 and E2p3 members. Thick organic-rich mudstone is developed in the E2p2 member due to a high accommodation space, abundant terrestrial organic matter, corresponding to a high relative base-level. The vast intertidal setting is conducive to the development of peatlands, developing widely distributed carbonaceous mudstone and coal. The study interval is characterized by a coal measure source rock development model of ‘strong supply - rapid burial - facies-controlled’ in the Xihu Depression.

First Results of U–Th/He Dating of Epigenetic Pyrite from Rocks of the Bazhenov Formation, Western Siberia

The U–Th/He method has been applied for the first time to determine the age of epigenetic pyrite from the oil source rocks of the Bazhenov Formation, Western Siberia. The possibility to date the post-sedimentation processes in a sedimentary basin by authigenic pyrite using the U–Th/He method is shown. The U–Th/He isochrone age of pyrite (n = 7) from the dolomites of the Bazhenov Formation within the Frolovskaya megadepression is much younger than the sedimentation age and corresponds to the Santonian–Cenomanian stages of the Upper Cretaceous (90 ± 8 Ma).

Characteristics and Paleoenvironment of High-Quality Shale in the Triassic Yanchang Formation, Southern Margin of the Ordos Basin

A set of high-quality lacustrine shales at the bottom of the Chang 7 member of the Yanchang Formation in the Ordos Basin is one of the main source rocks of tight oil and gas and shale oil in the Yanchang Formation. Based on outcrop, core, drilling and seismic data, by the quantitative characterization of outcrops, fine characterization of logging facies and seismic facies, and geochemical tests, the lithofacies types, geophysical response characteristics and organic geochemical characteristics of this high-quality shale are clarified, and the formation paleoenvironment, including redox conditions, paleoclimate, paleosalinity and paleowater depth, is analyzed. The high-quality shale at the bottom of the Chang 7 member is divided into three lithofacies types: black shale, dark massive mudstone and silty mudstone. The organic matter in black shale is mainly interbedded or stratified, the organic matter in dark massive mudstone is dispersed and the organic matter content in silty mudstone is lower. The shale shows high gamma (more than 260 API), a high acoustic time difference (more than 280 μs/m), a high resistivity (more than 330 Ω m) well-logging phase and strong-amplitude parallel–subparallel seismic phase characteristics. Based on the logging and seismic facies characteristics, the plane distribution range of this set of shales is defined. The sedimentary thickness gradually increases from the edge (5–10 m) to the center of the basin, among which the Jiyuan–Huachi–Yijun black shale has the largest thickness (more than 30 m). This set of high-quality shales was mainly formed under a warm and humid paleoclimate, in water depths of 60–120 m, and in an anaerobic reducing and continental freshwater paleoenvironment. The fine identification, distribution range and formation conditions of black shale lithofacies are of practical significance for predicting the distribution of favorable lithofacies of shale oil and gas and the deployment of horizontal wells.

Deciphering the laminated botryococcus-dominated shales in saline lacustrine basin, Western Qaidam Basin, NW China: Implications for shale oil potential

Given the high lipid content and potentially huge biomass, the explosive occurrence Botryococcus is regarded as a significant marker of high-quality oil source rocks in petroliferous basins. However, they are rarely discovered in saline lacustrine source rocks, and the formation mechanism of these alga-rich shales remains uncertain. In this study, abundant Botryococcus fossils were firstly found, accounting for an average of 43.5% of the total organic debris from the upper Xiaganchaigou Formation in the Yingxiongling and Zhahaquan hydrocarbon-rich sags of the western Qaidam Basin. The Botryococcus-dominated palynofacies assemblages were usually interpreted as derived from a distal oxic shelf environment. These Botryococcus-dominated sediments were characterized by a perfect laminated texture and composed of detrital, carbonate, and clay laminae. The Botryococcus fossils exclusively occur in the detrital laminae with large-grained quartz and feldspar and low carbonate content, possibly reflecting increased river input under relatively heavy precipitation. The cyclothymic deposition between these Botryococcus-rich detrital laminae and other laminae probably indicates that sufficient terrestrial nutrient inputs and lake salinity decreases driven by periodic heavy precipitation result in Botryococcus bloom under fresh or brackish water environments. These Botryococcus-dominated shales in the western Qaidam Basin usually have a high oil-prone hydrocarbon generation potential, as evidenced by their organic geochemistry parameters. These sediments have biomarker features extremely similar to crude oil with a high relative abundance of C20–C24 tricyclic terpanes, phytane, C27ααR sterane, and a unimodal distribution of n-alkanes with the maximum at n-C18. Therefore, these Botryococcus-dominated shales are possibly important oil sources of these prolific oil sags. Additionally, these high-quality source rock sequences can reach a few tens of meters in thickness and evidently have significance for future shale oil resources.

Geodynamic control on the petroleum habitat of the Uralian Foreland

A comparative study of the Uralian Foreland in the Timan-Pechora and Volga Urals basins reveals considerable differences in structure and petroleum habitat. These differences were in large measure controlled by their geodynamic settings. A typical scenario of the continental marginal basin which subsequently was modified in the foredeep basin took place in the Timan-Pechora basin. The sedimentary fill of the basin is made up of the Phanerozoic deposits only. The principal oil source rock is provided by the prolific Domanik Suite broadly developed in is eastern part of the basin. The mature Domanik source rocks charged the majority of oil and gas fields of the Timan-Pechora Basin. In the Volga Urals basin the sedimentary fill includes two overlapping foredeep sequence – Riphean and Paleozoic, of which the Riphean one is much thicker. The Riphean depocenters were subjected to structural inversion during the docking of the Magnitogorsk island arc to the Uralian margin in the Middle Devonian-Frasnian. The inversion was accompanied by the thickening of the Riphean section due to the reactivation of the pre-existing Precambrian deformation and caused the regional uplift in the Southern Uralian Foreland. This uplift led to shifting of the Domanik troughs to the westerly outboard part of the Volga-Uralian Basin. The Domanik source rock remained immature over much of the Southern Uralian Foreland which is interpreted to be a result of the inversion of the Riphean depocenters and related regional uplift. It is proposed that the enormous clustering of large oil deposits in the Paleozoic section of the south-eastern part of the Volga Uralian Basin was to a much extent produced by the charging from the multi-kilometer thick Riphean section of the Southern Uralian Foreland.

Revealing continuous hydrocarbon generation and shale oil accumulation of saline lacustrine source rocks by sequential extraction

Saline lacustrine fine-grained rocks are important hydrocarbon source rocks and host large shale oil accumulations worldwide. However, the specific process and mechanism of hydrocarbon generation and accumulation in such rocks are not clear. Sequential extraction is a method to chemically separate different hydrocarbon fractions in sedimentary rocks, commonly as free, adsorbed and retained hydrocarbons, and thus can theoretically record the entire process of hydrocarbon generation and accumulation. To test this hypothesis, here sequential extraction was carried out on source rock samples with varying maturities from the alkaline lacustrine strata of the Lower Permian Fengcheng Formation, Mahu Sag, Junggar Basin, northwest China. The 17β-ethylandrostane/C29-sterane ααα20R and tricyclic terpane/pentacyclic triterpane ratios vary with maturity. In contrast, some biomarker parameters are not significantly affected by thermal maturity, including pristane/phytane, β-carotane index (β-carotane/main peak n-alkane), sterane/hopane, 7-+8-methyl index (7-+8-monomethyl heptadecane/main peak n-alkane), and C28/C29 regular sterane values, and can thus be used for oil–source rock correlations. The low-maturity source rocks have undergone one stage of hydrocarbon generation and associated shale oil accumulation, whereas source rocks with relatively high maturity have experienced multi-stage hydrocarbon generation and associated shale oil accumulation. In the early stages, cyanobacteria were the main bioprecursor to hydrocarbons and, with increasing maturity, Dunaliella gradually became the more important bioprecursor. Hydrocarbon generation by these alkaline lacustrine source rocks involved multiple sources and stages, which accounts for the abundant shale oil resources in the Mahu Sag with one-billion-ton reserves. This might be general for saline lacustrine source rocks worldwide, which can generate both conventional and unconventional hydrocarbons in large scales. Compared with conventional thermal modeling to constrain the generation history of hydrocarbon source rocks, a unique advantage of sequential extraction is its ability to characterize the entire history of hydrocarbon generation under geological conditions.

Dominance of Phycosiphon incertum vs Zoophycos in shelf environment: example from the transgressive Palermo Aike black shale deposits of the Austral-Magallanes Basin, Argentina

The Zoophycos ichnofacies and its main components, Zoophycos isp., Phycosiphon incertum and Chondrites isp. have been related to marine environments of low energy and oxygen. This situation is very common in shelf environments of the past, the most important oil source rocks and/or unconventional reservoir. The Early Cretaceous Palermo Aike Formation of the Austral-Magallanes Basin (Southern Argentina) records marine sedimentation, composed mainly by black shales, with subordinate fine-grained sandstones, and redeposited tuff, deposited in a shelf environment. This succession is the main source rock and constitute a latent unconventional reservoir of the basin. In this paper we present the sedimentological and ichnological study of two well cores from the Tierra del Fuego area. These cores record the initial stage of the marine transgression, and the development of a distal shelf environment, with an alternation of black shales and, fine-grained tuff sandstones hyperpycnal deposits. The ichnological content that records this transgression shows three different ichnofacies: i) autochthonous Cruziana ichnofacies represented by Thalassinoides isp., Teichichnus isp., Planolites isp., Chondrites isp. and Rizocorallium isp. This trace fossil association is rapidly replaced by ii) Zoophycos ichnofacies represented by Phycosiphon incertum, Chondrites isp., and small Zoophycos isp. Finally, another allochthonous Cruziana ichofacies is observed related to the low-density turbiditic deposits, composed by Thalassinoides isp., Gyrolithes, Teichichnus isp., Scolicia isp. and Haenzchellinia isp. In the Santa Cruz area, a large Zoophycos isp. dominance is observed in the fine-grained deposits, occasionally interbedded with coarser-grained low-density turbiditic deposits with doomed pioneers. In the study area (Tierra del Fuego), on the contrary, a dominance of Phycosiphon incertum is observed instead of Zoophycos isp. which when is present have very poor development in size. This could be due to the fact that low-density turbiditic flows are very frequent in the study area, which generates a very unstable environment that does not allow the development of large Zoophycos isp. This environmental differences between the outcrops of Santa Cruz in the north of the basin and the subsurface study area in Tierra del Fuego may be triggered due to climatic, volcanic, or tectonic allogenic control factors.

Delineation and quantification of effective source rocks using 3D geological modeling in a lacustrine basin

The identification and quantification of effective source rocks are critical for hydrocarbon exploration, but traditional methods have limitations in lacustrine basins due to their complexity and heterogeneity. For example, geochemical analysis is constrained by the number and distribution of samples, well logging methods can only reflect local information, and seismic inversion methods are limited by the quality and resolution of data. We propose a geological modeling approach that combines geophysical techniques and geological and geochemical data to delineate effective source rocks and quantify hydrocarbon resource potential. The workflow includes mudstone classification, geochemical data analysis, building predictive models, constructing 3D geological models, filtering effective source rocks, and basin simulation. Taking the Fushan Depression, South China Sea, as an example, we estimate the total volume of effective oil source rocks at 323.48 km3 and effective gas source rocks at 67.43 km3, and identify favorable areas for conventional and unconventional hydrocarbon exploration. The results demonstrate that our proposed approach enables precise delineation of the spatial distribution of effective hydrocarbon source rocks and quantification of their potential for hydrocarbon generation and expulsion. Our study constitutes a reference case for assessing effective source rocks in other lacustrine basins due to the successful integration of multiple available of data and its practical applications.

Structural and Crystal-Chemical Features of Mixed-Layer Illite-Containing Minerals from Catagenetically Altered Upper Jurassic Oil-Source Rocks

Structural and Crystal-Chemical Features of Mixed-Layer Illite-Containing Minerals from Catagenetically Altered Upper Jurassic Oil-Source Rocks

Organic petrographic, geochemical, and sequence stratigraphic analyses for evaluating the hydrocarbon potential of Middle Jurassic–Lower Cretaceous rocks in Shushan Basin, northwestern Egypt

Integrated organic petrographic and geochemical analyses were made on organic-rich marine carbonate and mixed clastic-carbonate rocks of Middle–Late Jurassic and Early Cretaceous age from the Shushan Basin, Egypt to evaluate their hydrocarbon potential. Analyses allowed the identification of depositional settings, paleoclimate, and three third order genetic stratigraphic sequences (SQ) with deposits assigned to highstand (HST), lowstand (LST) and transgressive systems tracts (TST). Deposition of the source rocks in the rifting Shushan Basin resulted from the interaction between Neotethyan sea level changes, tectonic, and climate. The good reducing conditions developed during the Neotethyan Middle–Late Jurassic (Bajocian–Kimmeridgian) second order sea level rises and the climatically induced carbonate sedimentation resulted in the deposition of the organic-rich carbonates of the Khatatba Formation (SQ 1, early–middle TST) in inner–middle shelf settings under anoxic–dysoxic conditions. The Late Jurassic (late Kimmeridgian) uplifting resulted in the deposition of the organic-lean mixed clastic–carbonate strata of the Masajid Formation (SQ 1, latest TST) in the same shelfal and reducing conditions, which experienced a notable dilution of organic matter. The late TST deposits of SQ 1 are good to very good oil-producing source rocks, where they show average good to very good generative potential of late mature (late oil-to early wet gas-window) highly oil-prone organic matter. The Early Cretaceous (Valanginian–Albian) uplifting associated with the rifting of the Shushan Basin overprinted the Neotethyan late Valanginian–Hauterivian second order sea level rises, Aptian second order highstand sea level, and Albian second order sea level rise. The coeval climatic shift toward more humid conditions resulted in the clastic-dominated deposition of the organic-lean regressive units of SQ 2 (HST and LST of Alam El Bueib, Alamein, and Dahab formations) and SQ 3 (HST and LST of the lower–upper Kharita Formation) in marginal marine settings under anoxic–dysoxic to oxic conditions. The HST and LST deposits of the SQ 2 and SQ 3 show poor to good organic richness of early–mid mature (early–peak oil-window) oil/gas-prone and gas/oil-prone organic matter, respectively and exhibit average fair oil source rock potential with no gas generation.

Structural and Сrystal-Сhemical Features of Mixed-Layer Illite-Containing Minerals from Diagenetically Altered Upper Jurassic Oil Source Rocks

Illite-smectite (I-S) minerals from the Upper Jurassic oil-bearing rock shales of Denmark and the North Sea were studied by a complex of diffraction and spectroscopic methods. Detailed structures were identified to reveal the mechanism of diagenetic transformation of these shales. Usually, in oil-bearing rocks of sedimentary basins, oil generation occurs simultaneously with the I-S diagenetic transformation. The results obtained demonstrate the relationship between these two reactions: NH3 molecules released from kerogen during ma-ximum oil formation are fixed as NH4 ammonium cations in smectite or vermiculite interlayers, forming mica or tobelite structural fragments. As a result of this solid-phase transformation, mixed-layer structures are formed, consisting of layers of illite, tobelite, smectite and vermiculite (I-T-S-V).

Geochemistry of an unconventional, saline lacustrine petroleum system: Dongpu depression, Bohai Bay Basin, China

Inter-salt shales are both important organic-rich sediments and shale oil exploration targets. This paper examines the controls on the composition of retained fluids in an inter-salt lacustrine shale oil system based on geochemical analysis of 125 samples with vitrinite reflectances of approximately 0.9% Ro from a 50 m shale-rich sequence between two evaporites. Core samples were immediately stored at −50 °C to reduce the evaporative loss of hydrocarbons. The sequence is highly heterogeneous and includes siltstone, argillaceous mudstone, calcareous mudstone, dolomitic mudstone, and argillaceous dolomite. Source rock samples with higher TOC contents (>1.0 wt%) and higher genetic potentials (S1 + S2 > 2.0 mg HC/g rock) are typically calcareous mudstone, dolomitic mudstone, and argillaceous dolomite, and contain predominantly type II kerogen. Salinity controlled both bottom water deoxygenation and the development of carbonate minerals, and the increase in aquatic organisms (including prokaryotes and eukaryotes) leads to a positive relationship between OM richness and quality. High TOC (>2.0 wt%) samples contain oil-prone kerogens and have high absolute contents of liquid hydrocarbons (S1-1 > 0.2 mg HC/g rock, S1-2 > 1.0 mg HC/g rock), and high relative contents of liquid hydrocarbons [(S1-1 + S1-2)/(S1-1 + S1-2 + S2-1) > 0.45]. The amount of oil retained in source rock horizons is mainly controlled by the sorptive properties of the solid phase organic matter. Oils (S1) within siltstones are derived from adjacent source intervals; multi-stage temperature pyrolysis shows that they are lighter – and thus more readily produced - than the oils retained within the source intervals. Although the absolute amounts of oil in siltstones are lower than those in the source intervals, a smaller fraction is sorbed on solid phase organic matter, so that there are similar amounts of moveable oil in siltstones and source rocks. Interbedded siltstones, organic-rich calcareous mudstones, dolomitic mudstones, and argillaceous dolomites are all favourable intervals for inter-salt shale oil development.

Evolution of the Pristane/Phytane Ratio with Maturity of Lacustrine Source Rocks: Implications of a Thermal Simulation Experiment

The pristane/phytane ratio (Pr/Ph) of source rocks has been extensively used for the identification of paleosedimentary environments and oil–source rock correlations. However, the influences of maturity on the Pr/Ph ratio are not fully understood, which largely limits the applicability of this parameter under geological conditions. Based on a thermal simulation experiment performed on typical lacustrine source rock samples and systematic research on geological source rock samples, the evolution of the Pr/Ph ratio with increasing maturity was investigated in this study. The results indicate that the Pr/Ph ratios of the two source rock extracts progressively decrease with increasing maturity, and the decrease in this parameter is more significant for shallow lacustrine samples than for deep lacustrine samples. The Pr/Ph ratios of the two types of source rocks are different at the oil generation stage with EasyRo less than 1.02% but are similar at the oil cracking stage with EasyRo larger than 1.02%. The Pr and Ph of source rocks are contributed by both biogenic and thermal origins, which are largely determined by the sedimentary environment and maturity, respectively, and the contributions of the two origins are diverse at different maturity stages. The Pr/Ph ratio is mainly controlled by the sedimentary environment at the diagenetic stage, by both sedimentary and thermal maturity at the oil generation stage, and by thermal maturity at the oil cracking stage. The Pr/Ph ratio of source rocks can be used to identify sedimentary environments and oil–source rock correlations at diagenetic and oil generation stages.

Correlation of Neogene Oil and Paleogene Source Rocks in the Middle Huanghekou Sag, Bohai Bay Basin

Several billion-ton Neogene oil fields have been successfully discovered in the middle Huanghekou sag over the past few years. However, the source of the crude oil needs to be clarified, and the relevant oil-source correlation was less carried out. Six source rocks of the third member of the Paleocene Shahejie Formation (Es3) from five wells and sixteen Neogene crude oil samples from nine wells in the middle Huanghekou sag were investigated for the oil-source correlation with the biomarkers and carbon and hydrogen isotopes of saturated hydrocarbon monomers. The distribution characteristics of n-alkanes, C19/C23 ratio of tricyclic terpanes, long-chain tricyclic terpene ratios (ETR), C24 tetracyclic terpane to C26 tricyclic terpene, and distribution characteristics of conventional steranes suggest that the Es3 parent material is of a mixed-source input from terrestrial higher plants and aquatic phytoplankton. The gammacerane to C30 hopane ratio is low, ranging from 0.094 to 0.134, with a mean value of 0.118; the Pr/Ph ratio is less than 1.5. The Neogene oils show the characteristics of a saturated hydrocarbon biomarker similar to Es3. The carbon and hydrogen isotopes of saturated hydrocarbon monomers also corroborate the oil-source correlation from the depositional environment and parent material source, which characterize the low salinity of the water during the Es3 sedimentary period, which was a brackish or a freshwater delta deposition under weak oxidation–weak reduction conditions. The parity dominance of CPI and OEP values (both greater than 1), higher ratios of Ts/Tm (1.174 to 1.383, mean 1.278) and the C29Ts/C29 norhopane, high values of diahopane and diasterane contents (C30diaH/C30H, C27diaS/C27S), and hopane and sterane isomerization parameters (%22S, %20S, %ββ) confirm that the Es3 source rock samples are mature enough to provide crude oil for the middle Huanghekou sag. The biomarker characteristics of regional Neogene crude oil are significantly different from those of Es4 source rocks in the surrounding depressions (sags), indicating the Es4 strata’s absence in the middle Huanghekou sag. Suitable traps need to be discovered around the hydrocarbon-generating center of the Es3 source rock for oil and gas exploration in the future.

Oil generation and expulsion modeling of the syn-rift Salif oil-source rock in the Tihamah Basin, Yemeni Red Sea: Implications for shale oil exploration

The Miocene Salif Formation is an oil-source rock within the Tihamah Basin, southern Red Sea of Yemen. The Salif shale beds are characterized by high organic carbon content (TOC) up to 5.59% and high oil saturation index (OSI) (30 < OSI <260 mg HC/g TOC). However, most of the Salif shale samples exhibit OSI values of >100 mg HC/g TOC, indicating a thermally mature and oil-saturated source rock system with high oil-bearing potential. This finding is supported by the vitrinite reflectance values, representing mature oil generation window. Therefore, the shale oil potential of the Salif source rock system is studied for the first time by integrating geochemical data and geological information into a 1-D modelling scheme. The models reconstructed for the thermal and burial history infers that the Salif source rock system is located within the late oil-window from the Late Pliocene to present-day. Kerogen to oil conversion and the timing of petroleum generation and expulsion are also simulated by the 1-D models, showing that 10–50% of the total kerogen is converted into oil during the early Pliocene to the Pleistocene, which is consistent with the peak-late mature oil-window (0.70–1.26 %Ro). The models also exhibited that limited oil was expelled from the Salif source rock system since the Pleistocene-present-day as demonstrated by the TR ratio of up to 55%. The integration of source rock evaluation and modeling approach concludes that the Salif source rock provides a good potential for possible oil production, where suitable reservoir characteristics do occur.

Geochemical and Tectonic Characterization of Oil–Source Rocks in the Shadegan Oilfield, Dezful Embayment, SW Iran

Geochemical methods allow us to develop a systematic understanding of petroleum system elements. Geochemical analyses were done out on the shale samples of the Pabdeh and Asmari Formations and on the Asmari reservoir oil samples in the Shadegan oilfield, southwest Iran. Rock–Eval pyrolysis, gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) data were utilized. Oil–oil and oil–source correlations using GC and GC–MS analyses indicated that the Pabdeh Formation and the Asmari Formation basal shale layer are two possible sources of Asmari reservoir oil. The results of Rock–Eval pyrolysis revealed the values of the organic matter in the samples of the Asmari Formation basal shale layer are consider poor to fair in total organic carbon content. Therefore, this layer cannot be known as the source rock for the oil in the Asmari reservoir. Based on the thermal maturity parameters including the sterane isomerization ratios and homohopanes isomerization ratio together with Rock–Eval data and 1D burial history model, both Pabdeh and Kazhdumi Formations are in the maturity levels for oil generation. Different biomarker ratios in two oil samples (for well numbers 4 and 17) compared to samples from the Shadegan oilfield, revealed that the oil of these two wells originated from carbonate source rock(s) unlike oils of other wells that originated from a shaly source rock. Oil migration from adjacent oilfields with carbonate source rock (e.g., the Maroon, Ahvaz and Mansouri oilfields) into these wells through natural fractures in paleohighs is considered as one of the controlling factors of observed difference in biomarker ratios.

Development of a geodatabase for retrieval of geochemical data from oil wells: A case study from the Gachsaran oilfield; SW Iran

Managing geochemical data is crucial in the petroleum industry, as the exploration and development of oilfields typically require a large volume of data from geochemical analyses. Specifically, geochemical data relevant to oil wells, source rocks, and reservoir rocks are often related to location dimensions. Therefore, the geodatabase can be a powerful tool in collecting, storing, retrieving, processing, and analysis of these data. In this study, a novel geodatabase approach was utilized to store, display, and present geochemical data of petroleum samples from oil wells. The geodatabase scheme comprised two types of data layers: spatial data (e.g., oil well, oilfield boundary, formations including source rocks/reservoir rocks and sector) and non-spatial data (e.g., oil samples and geochemical information). The PostgreSQL/PostGIS object-relational database management system was used to design and implement the geodatabase, while QGIS was employed to connect to the database and visualize the geometrical data of the Gachsaran oilfield. The QGIS Data Plotly plugin was then used to interpret geochemical data. According to the findings of this study, the PostgreSQL/PostGIS open-source database is a suitable method for spatial data management of oil well geometrical data. In addition, the geochemical evaluation of possible source rocks and determination of geochemical characteristics of reservoir oil were analyzed using this geodatabase. Moreover, integrating oil geochemical data into a geodatabase prevents the scattering of geochemical data and facilitates data interpretation.

Paleo-productivity and petroleum source evaluation of the Nkporo and Awgu shales, Lower Benue Trough, Nigeria: Insight from inorganic geochemistry

The petroleum paleo-productivity and generative potential of the Nkporo and Awgu shales in the Lower Benue Trough (LBT) were studied. Major oxides were determined using Spectro Ciros Inductively-coupled plasma optical emission spectrometer (ICP-OES) while trace and rare earth elements were determined using an ELAN 9000 Inductively-coupled plasma mass spectrometer (ICP-MS). The shales have Co/Ni ratios greater than 0.1 suggesting oil source rocks with more marine source input due to brief marine incursion in the transition zone after deposition. The very low Ni values and moderate V values, and a lack of correlation between the TOC and sulphur content, suggests that the organic matter is of terrestrial Type Ⅲ; and the very low paleo-productivity (Ba/Al and P/Ti ratios) suggests that the organic matter is of terrestrial origin. The low V/Ni values of the Nkporo and Awgu shales (Av. ≈ 4) and the high metal concentrations indicate a matured status. From the K/Rb ratios of the Nkporo (191–259) and Awgu shales (198–261), it can be deduced that the organic matter within the shales experienced a considerable loss of K and the shales are mature to generate gaseous hydrocarbons.

Coaly and lacustrine hydrocarbon source rocks in Permo-Carboniferous graben deposits (Weiach well, Northern Switzerland)

Permo-Carboniferous graben sediments in the North Alpine Foreland Basin (NAFB) include Upper Carboniferous (Stephanian) coal-measures and lower Permian (lower Autunian) lacustrine shales with high organic matter contents. Coals are probably the source for a gas accumulation in Switzerland, while the bituminous shales are potential source rocks for oil. In order to study the hydrocarbon potential of coal and bituminous shales and to contribute to the understanding of their depositional environment, 90 core samples from the Weiach-1 well (northern Switzerland) were investigated using organic petrographic, palynofacies, Rock-Eval pyrolysis, and geochemical techniques (incl. biomarker analysis and compound-specific carbon isotopy). Carboniferous coal seams are up to 10 m thick and were deposited in low-lying freshwater mires. They contain a significant gas potential and reached a maturity stage related to the onset of gas generation. Sapropelic rocks were not observed in the coal-bearing succession. Organic matter-rich Permian shales (Autunian shales) were deposited in anoxic lakes with a stratified water column. The organic matter is of mixed aquatic and terrigenous origin. δ13C values of chlorophyll-derived isoprenoids provide evidence for reworking of organic matter in the water column. The Autunian shales have a strongly varying, but locally very good oil potential. They reached early oil window maturity, but did not yet generate significant amounts of hydrocarbons. The main shale interval in the studied borehole is about 12 m thick and will generate about 0.35 tHC/m2 when mature. A comparison with literature data shows that it is possible to distinguish oils generated from Permian, Jurassic and Oligocene source rocks based on biomarker ratios and isotope data.