Journal of Petroleum Geology最新文献

{"title":"A Paleotectonic Atlas of the African Plate: Permian to Recent","authors":"Duncan S. Macgregor,&nbsp;Colin V. Reeves","doi":"10.1111/jpg.70000","DOIUrl":"https://doi.org/10.1111/jpg.70000","url":null,"abstract":"<p>The fragmentary release of petroleum data defining the deep structure and stratigraphy of African basins has been integrated with existing literature to compile 19 tectonic maps over key geological intervals from Permian to Recent times. African plate margins range in their age of opening from Late Triassic (off Lebanon), through Early/Middle Jurassic (Eastern Mediterranean, Central Atlantic, Somali Basin) and Cretaceous (West Africa) to ongoing (northern Red Sea). Their opening follows propagational trends, for example, from the eastern Mediterranean to Guinea and from the Somali Basin in a “smile” shape around southern Africa, eventually to Guinea. Just under half of African margins are rifted margins. North Africa margins are controlled initially by transforms, while volcanic rifted margins dominate in southern Africa. The most debated ocean, the eastern Mediterranean, is demonstrated through well and seismic interpretations to have commenced spreading in late Early to early Middle Jurassic times. Much of West African Cretaceous tectonics, including the generation of strike–slip fault systems, is related to the counter-rotation of Africa versus South America initiated through South Atlantic opening, partly driven by the Bouvet and Tristan Plumes. From the Aptian onward, Africa receives a series of transpressional shocks, largely derived from the Tethyan margin. The most pronounced such event occurs in the Santonian, which is a global-scale event, with? Turonian events in the Indian Ocean also affecting East Africa. Africa is segmented by many interior rifts, with these developed on all mapped intervals, though with peaks of activity in the Permian (South Africa), Late Triassic (North Africa), Early Cretaceous (Central Africa), and Neogene (East Africa). In the Early Cretaceous, a tensional regime is imposed which creates a series of NW-SE trending rifts across the plate: this switches gradually to a N-S rift trend in the Cenozoic. Passive rifts show a high degree of inheritance and can be orientated both perpendicular and parallel to associated strike–slip faults. This type of rift dominates in the Mesozoic, with active plume-related rifts becoming the principal type as mantle activity becomes a more dominant control in the Cenozoic. The Early Cretaceous Sirt Basin is viewed as an isolated plume-related rift, later evolving into a strike–slip associated rift. Analogue-driven hypotheses are proposed for the origin of the more poorly controlled African rifts, such as the Western Desert of Egypt. The formation of the various elements of petroleum systems are responses to these tectonics. For example, geographical trends in basin restriction and potential anoxia are observed to follow the propagational trends of continental breakup.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 4","pages":"231-279"},"PeriodicalIF":1.7,"publicationDate":"2025-08-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://onlinelibrary.wiley.com/doi/epdf/10.1111/jpg.70000","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145013047","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Magnetic Properties of Sandstones Within the Zone of Hydrocarbon Migration Near the Boundary of Dukla and Silesian Units (Western Carpathians, Poland)","authors":"Maciej Łoziński,&nbsp;Kamil Kobyliński,&nbsp;Radosław Staniszewski,&nbsp;Anna Wysocka,&nbsp;Anna Filipek","doi":"10.1111/jpg.70004","DOIUrl":"https://doi.org/10.1111/jpg.70004","url":null,"abstract":"<div>\u0000 \u0000 <p>This study represents the application of magnetic techniques in hydrocarbon prospection within the Outer Western Carpathian petroleum play, specifically focusing on the Eocene–Oligocene rocks of southeastern Poland. Magnetic minerals serve as a sensitive proxy for diagenetic processes, particularly concerning hydrocarbon generation, migration, and biodegradation. We investigated the magnetic characteristics of surface rock samples from Dukla and Silesian Units, which have been altered by hydrocarbons migrating through pore spaces and tectonic fissures. The magnetic mineralogy of 29 specimens was analyzed through thermal demagnetization (Lowrie's test), complemented by hysteresis loop and anhysteretic remanence susceptibility measurements to assess domain states and ultrafine grain size ranges. Scanning electron microscope analysis of mineral composition revealed that traces of bitumen and abundant pyrite were common in almost all samples. Ultrafine maghemite emerged as the predominant magnetic mineral within the host rock, with some samples exhibiting varying amounts of ultrafine magnetite, often associated with iron sulfides. Areas adjacent to calcite veins stained with hydrocarbons displayed enhanced magnetic properties, primarily due to increased magnetite content. Additionally, aggregates of barite were identified as accessory minerals within these veins. Our study indicates that detrital iron oxides underwent partial dissolution, leading to the formation of new authigenic minerals such as paramagnetic pyrite and, likely, ultrafine magnetite. These constituents were subsequently transformed partially or completely into maghemite during the oxidation stage of diagenesis. Importantly, the presence of hydrocarbon appears to facilitate the formation of ultrafine (&lt;100 nm) magnetic particles, with magnetite being particularly characteristic of tectonic migration pathways.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 4","pages":"307-324"},"PeriodicalIF":1.7,"publicationDate":"2025-08-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145013034","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evolution of Microporosity in Mature Mudstones of the Outer Carpathians, Poland","authors":"Olga Odrzygóźdź,&nbsp;Grzegorz Machowski,&nbsp;Mario Borrelli,&nbsp;Marta Waliczek,&nbsp;Edoardo Perri,&nbsp;Marek Szczerba,&nbsp;Mirosław Słowakiewicz","doi":"10.1111/jpg.70003","DOIUrl":"https://doi.org/10.1111/jpg.70003","url":null,"abstract":"<div>\u0000 \u0000 <p>The Polish Carpathian region has over 170 years of conventional hydrocarbon exploration history, with numerous discovered oil and gas fields. In recent years, increasing attention has been given to the potential for new, alternative hydrocarbon deposits. This study evaluates three types of mature mudstones from the Oligocene Menilite Beds, Krosno Beds and Grybów Beds, collected from boreholes in the Polish part of the Outer Carpathians, as potential unconventional source and reservoir rocks. X-ray diffraction (XRD), optical and scanning electron microscopy (SEM), N₂ adsorption and mercury injection capillary pressure (MICP) techniques were used to evaluate the pore system, organic matter and mineral composition in each lithofacies. The findings reveal that the Menilite Beds mudstone is thermally mature, with Type II/III kerogen. In contrast, the mudstones of the Grybów and Krosno beds are highly thermally mature, corresponding to the dry gas window stage, with kerogen Types IV and mixed III/IV, respectively. All three formations display a fair total organic carbon (TOC) value (0.7%–1.1%) but have low hydrocarbon generation potential (hydrogen index [HI] &lt; 85 mg HC/g TOC). Microscopic observations confirm the presence of both mineral and organic matter pores in all three mature mudstones. Samples are dominated by nanoporosity (average pore size &lt;14 nm), with low effective porosity values across all samples, ranging from 1.51% to 3.59%. Permeability is very low (0.029–0.081 mD). Nitrogen adsorption isotherms are type IV for all mudstones, with H3/H4 hysteresis loops, indicating slit- and wedge-shaped pores. The <i>S</i>_BET N₂ values range from 1.352 to 7.277 m²/g, with the highest values for Krosno Beds samples. The mudstones and claystones of the Menilite, Krosno and Grybów beds are primarily affected by compaction, with only a minor influence from cementation and dissolution. The evaluated mudstones do not qualify as effective shale oil/gas source rock; despite good thermal maturity, their hydrocarbon generation potential at the analysed depths is very low. It could be hypothesised that, given the overall volume of nanopores and their interconnectivity, such a potential unconventional hydrocarbon system may occur at greater depths or in regions where hydrocarbon generation potential has been documented, even at shallower depths.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 3","pages":"205-226"},"PeriodicalIF":1.7,"publicationDate":"2025-08-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144891659","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A New Saturated and Aromatic Hydrocarbon-Based Scheme to Decipher the Origin of Extracted Organic Matter in the Outer Carpathians: From the Jurassic to the Miocene","authors":"Mirosław Słowakiewicz","doi":"10.1111/jpg.70001","DOIUrl":"https://doi.org/10.1111/jpg.70001","url":null,"abstract":"<div>\u0000 \u0000 <p>In this review, published and new geochemical data characterising 17 potential source rocks for hydrocarbons in the Polish part of the Outer Carpathians have been used to establish a new scheme that can be useful for oil–source rock correlations. Rock and drill core samples, ranging in age from Jurassic to Miocene, were analysed using Rock-Eval pyrolysis. The results confirmed that the best source rock is shale from the Oligocene Menilite Beds, particularly the so-called deep shale, occurring at depths greater than 4000 m. The Palaeocene/Eocene mudstone interbeds in the Istebna Beds can serve as a source rock for natural gas, although only locally, due to their highly irregular geochemical parameters. Lower Cretaceous strata, specifically the fine-grained sediments of the Spas Shales, Lgota Beds and Veřovice Beds, appear to be significant for microbial generation of methane. Molecular analysis of extractable organic matter, combined with pyrolytic data, revealed a wide range of organic matter maturation stages, from immature to overmature. These analyses also identified rare zones of high maturity at shallow depths in source rocks, confirming the upwards displacement of once deeply buried strata in the Outer Carpathians. Additionally, the saturated and aromatic hydrocarbon-based compounds and their ratios revealed characteristic biomarkers and polycyclic aromatic hydrocarbons (PAHs) that differentiate various shale- (mudstone, claystone) or marl-rich formations within specific lithostratigraphic units. These chemical compounds serve as strong tools for deciphering the origin of oils in the Outer Carpathians, regardless of the organic matter's maturity level. This age-based molecular characterisation highlights the particular importance of higher plant-derived compounds, such as oleanane isomers, which are most abundant in the Oligocene samples but also present in Kimmeridgian shale. Aromatised terpenoid precursors, in turn, are abundant in shale from the Menilite Beds as well as in the Krosno and Istebna beds. Terrigenous organic matter is also accompanied by algal-derived components (e.g., dinosteroids) and bacterial contributions (e.g., hopanes). Finally, the analysed organic matter was deposited in sedimentary basins under varied redox conditions. Anoxic environments were confirmed by high bisnorhopane/C₃₀ hopane ratios, whereas oxic to suboxic conditions were indicated by high pristane/phytane ratios, suggesting a mixed oxic–anoxic water column.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 3","pages":"188-204"},"PeriodicalIF":1.7,"publicationDate":"2025-08-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144891641","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Characteristics of Tight Gas Accumulation and Main Controlling Factors of Differential Enrichment in the Shaximiao Formation, Yanjinggou Area, Southwest of the Western Sichuan Depression","authors":"Fengzan Zheng,&nbsp;Jianhui Zeng,&nbsp;Zaiquan Yang,&nbsp;Zhe Feng","doi":"10.1111/jpg.70002","DOIUrl":"https://doi.org/10.1111/jpg.70002","url":null,"abstract":"<div>\u0000 \u0000 <p>The Jurassic Shaximiao Formation in the southwest of the Western Sichuan Depression is an important tight gas reservoir. However, due to the strong heterogeneity of its reservoir properties and gas saturation, the factors influencing the differential enrichment of tight gas remain unclear. Based on logging, seismic, experimental, and drilling data, we have systematically studied the gas-bearing property characteristics, source rock characteristics, reservoir physical properties, fault characteristics, accumulation Period, and the factors controlling differential enrichment using the tight gas reservoir in the Yanjinggou area as a case. The study shows that the Shaximiao Formation is underlain by high-quality source rocks of the Xujiahe Formation (Upper Triassic) and capped by a regional seal of the Suining Formation (Jurassic). In the Yanjinggou area, anticline structures are well-developed, with sandbodies widely distributed and vertically stacked, and the overall reservoir is tight. The thickness and petrophysical properties of the reservoir display significant heterogeneity, which is controlled by the coupling of depositional and diagenetic processes. Gas layers are mainly found in channel sands trending NE-SW that exhibit superior reservoir properties. The fault–sand transport system is a crucial pathway for gas charging, migration, and accumulation, with structural highs and “V” shaped fault–sand configurations controlling the preferential enrichment zones. A tight gas accumulation model of “reservoir controlled enrichment, fault–sand controlled migration, and structural adjustment” was established. This model emphasizes that under the control of the fault–sand transport system, hydrocarbons initially migrate upward along faults into reservoirs that are separated from the source rocks, then laterally through the sandbodies. Favorable enrichment occurs in reservoir characterized by structural highs, good petrophysical properties, and greater thickness. The differential enrichment of tight gas in the Shaximiao Formation is controlled by a combination of factors, including the petrophysical properties and distribution of sandbodies and reservoirs, fault distribution, tectonic movement, and tectonically high positions. Comprehensive analysis indicates that the tight gas accumulation conditions in the Shaximiao Formation of the Yanjinggou area are favorable, providing a theoretical basis for predicting tight gas sweet spots in similar regions of the southwest of the Western Sichuan Depression.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 3","pages":"163-187"},"PeriodicalIF":1.7,"publicationDate":"2025-07-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144891794","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The Effect of Orogenesis on the Petroleum System in the Outer Carpathians","authors":"Piotr Such","doi":"10.1111/jpg.12884","DOIUrl":"https://doi.org/10.1111/jpg.12884","url":null,"abstract":"","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 3","pages":"159-162"},"PeriodicalIF":1.7,"publicationDate":"2025-06-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144891667","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Thermal History and Source Rock Maturity Modeling of the Akri-Bijeel Area, NW Zagros Fold Belt, Kurdistan Region, Northern Iraq","authors":"Ayad N. F. Edilbi,&nbsp;Stephen A. Bowden,&nbsp;Abdalla Y. Mohamed,&nbsp;David Muirhead","doi":"10.1111/jpg.12883","DOIUrl":"https://doi.org/10.1111/jpg.12883","url":null,"abstract":"<div>\u0000 \u0000 <p>The Akri-Bijeel area in the NW Zagros fold-and-thrust belt (Kurdistan region of northern Iraq) has been the focus of petroleum exploration, and its subsurface has been drilled extensively. This makes it possible to combine outcrop studies of this mountainous region with subsurface data. The region has five potential or regionally proven source rock units: the Ora Formation (Devonian–Carboniferous), the Baluti Formation (Upper Triassic), the Sargelu and Naokelekan Formations (Middle–Upper Jurassic), and the Chia Gara Formation (Upper Jurassic–Early Cretaceous). The area has a complex tectonic history, and it is therefore not necessarily clear when source rocks may have been active or inactive and therefore their generative potential. This makes basin modeling particularly useful as a tool to evaluate source rock thermal maturity and the timing of hydrocarbon generation and the amounts expelled. PetroMod version 2017 was used to reconstruct 1D burial and thermal history for four wells. The reconstructed burial and thermal history models were then calibrated against porosity, pressure, temperature, and vitrinite reflectance data. The results of constrained models show significant variations in heat flow through time, with high heat flows during Mesozoic rifting followed by low values, with sharp decreases in heat flow since the end of the Miocene. The present-day average geothermal gradient at Akri-Bijeel is low (18°C/km), with an average heat flow of 32 mW/m². The low heat flow can best be explained by the rapid deposition of a thick, cold Cenozoic sedimentary section, Zagros thrusting and accompanying uplift and exhumation, and the ongoing circulation of cold meteoric waters under hydrodynamic conditions. Thermal maturity modeling reveals that the present-day oil window extends from a depth of 860 m in well Bakrman-1 down to 5090 m in well Bijeel-1. The generation of hydrocarbons in the modeled source rocks (except for the Ora Formation) continued until it was halted by Zagros folding and thrusting in the Miocene, after which generation ceased or became negligible. Models predict that the majority of the oil discovered at Akri-Bijeel was generated by the Sargelu, Naokelekan, and Chia Gara Formations. On the basis of 1D basin modeling, the Paleozoic Ora Formation generated oil during the Early Triassic and is now in the gas window, and Jurassic source rocks generated oil during the Cretaceous. Volumetric calculations for the five source rock formations modeled in the area suggest that around 4.94 billion tons (or 36 billion barrels [bbl]) of petroleum have been expelled and charged to the reservoirs, indicating significant remaining potential for undiscovered resources.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 2","pages":"134-155"},"PeriodicalIF":1.8,"publicationDate":"2025-04-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143809482","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evaporite Collapse, Karst and Detrital Carbonate Breccias in the Zechstein Reservoir of the Alma Field, Central North Sea: Characterisation, Controls and Implications for Reservoir Quality","authors":"Peter Gutteridge","doi":"10.1111/jpg.12882","DOIUrl":"https://doi.org/10.1111/jpg.12882","url":null,"abstract":"<p>The Zechstein reservoir of the Alma field (originally Argyll, formerly Ardmore) comprises at least four Zechstein carbonate and evaporite sequences, the latter dissolved during Jurassic exposure, forming a series of collapse breccias that were modified by karst, erosion and faulting. It is essential to identify the different origins of these breccia bodies because these processes produce zones of excess permeability with contrasting stratiform and cross-cutting geometry. In core, these breccia bodies are distinguished by their clast assemblage and fabric, the relationship of clasts and matrix, the presence of sedimentary structures and the nature of their upper and lower boundaries. Predicting the distribution, architecture and reservoir quality of these geobodies is key to managing reservoir development programmes in similar carbonate fields affected by karst, collapse brecciation, reworking and faulting. It requires an understanding of the stratigraphy of the reservoir, particularly that of any internal aquicludes, mapping the palaeogeology of the top reservoir and understanding the onlap history of the exposure surface. The Alma reservoir contains a field-wide impermeable layer, the Sapropelic Dolomite deposited in a basinal setting that controlled the influx of meteoric water during exposure. The lower dolomite breccia, which underlies the Sapropelic Dolomite, represents a stratiform evaporite collapse breccia formed by dissolution in meteoric water that was introduced down-dip beneath the Sapropelic Dolomite. The upper dolomite breccia formed by dissolution of one or more evaporite units by direct infiltration of meteoric water from the top Zechstein surface. During the Jurassic, the top Zechstein surface was modified by karst, apart from the SW part of the Alma field, where the Zechstein was buried by the onlapping impermeable Triassic Smith Bank Formation. Core also shows that there is limited karst development over the sub-crop of the Sapropelic Dolomite. The Zechstein is partly onlapped by Jurassic detrital conglomerates reworked from the brecciated Zechstein and deposited in alluvial fan, shore face and low-energy subtidal settings along the western margin of the field. A well-preserved matrix pore system can be expected within collapse breccias and karst cavities where the Zechstein is overlain by Jurassic detrital sandstone and carbonate breccias. However, in areas onlapped by impermeable sediment, the karst and collapse breccias are likely to contain much poorer reservoir quality.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 2","pages":"111-133"},"PeriodicalIF":1.8,"publicationDate":"2025-03-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://onlinelibrary.wiley.com/doi/epdf/10.1111/jpg.12882","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143809944","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Source Rock Properties, Depositional Environment and Kerogen Degradation Kinetics of Lower Permian Shales from the Ib River Sub-Basin, Mahanadi Basin, Eastern India","authors":"Nihar Ranjan Kar,&nbsp;Devleena Mani Tiwari,&nbsp;John Buragohain,&nbsp;Bodhisatwa Hazra,&nbsp;E. V. S. S. K. Babu,&nbsp;Bala Subrahanyam Seetha,&nbsp;Mohana Krishna Reddy Mudiam,&nbsp;Abhayanand S. Maurya","doi":"10.1111/jpg.12881","DOIUrl":"https://doi.org/10.1111/jpg.12881","url":null,"abstract":"<div>\u0000 \u0000 <p>Lower Permian organic-rich shales and coals from the Ib River sub-Basin, part of the Mahanadi Basin in Eastern India, were studied using Rock-Eval pyrolysis, kerogen kinetics, biomarker, and organic carbon isotopic analyses to investigate the source rock characteristics, depositional environment, and thermal degradation kinetics of the sedimentary organic matter (OM). The samples are organically rich (&gt;5 wt% total organic carbon [TOC]) and possess higher hydrocarbon generation potential (&gt;54 mgHC/g rock). The primary contributors to the OM supply were identified as terrestrial plants, supplemented by emergent aquatic plants, resulting in a Type II–III kerogen. The broader activation energy indicates OM input from heterogeneous sources, whereas the earlier and faster kerogen transformation ratio (TR), along with a high hydrocarbon generation rate (HGR), suggests excellent kerogen quality. Despite the samples’ favorable source rock characteristics, their relatively low <i>T</i>_max values (&lt;435°C) indicate immaturity, limiting their potential for natural hydrocarbon production. Marine incursions have been identified in the Barakar Formation of the Ib River sub-Basin, accompanied by climatic fluctuations (inferred from <i>P</i>_aq, average chain length [ACL], and <i>δ</i>¹³C) that correspond to alternating dry and wet periods during the deposition of various lithotypes. The samples exhibit an abundance of even lower <i>n-</i>alkanes, indicating that the OM inputs are derived from aquatic vegetation rather than microbial activity. The gammacerane index (GI) averages ∼0.29 for the Barakar Formation and ∼0.24 for the Karharbari Formation, indicating greater water stratification and higher salinity in the Barakar Formation compared to the Karharbari Formation. Likewise, other key parameters such as tricyclic terpanes (TTs) and polyaromatic hydrocarbons (fluorenes [FLs], dibenzothiophenes [DBTs], and DBFs) differentiate certain Barakar samples as being deposited in a saline lacustrine environment, whereas the other Barakar samples and all Karharbari samples indicate a swampy, oxic environment. The pristane (Pr)/phytane (Ph) ratio supports this conclusion, indicating a reducing to oxidizing depositional setting for the Barakar Formation, while suggesting an oxic environment for the Karharbari Formation. Integrating all parameters, we conclude that the Barakar Formation was influenced by marine activities during Permian Period. Drawing on our research and prior studies, we propose two scenarios for marine interaction in the Ib River sub-Basin during the Permian Period: Either the region was covered by an extended marine embayment or marine influence extended to the NW-SE slope of the basin, notably affecting the Rewa region in the northwest.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 2","pages":"85-110"},"PeriodicalIF":1.8,"publicationDate":"2025-03-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143809836","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Geochemical Characteristics of Oils from the Orenburg Field in the SE Volga-Ural Basin, Russia: Implications for the Molecular Structure of a Marine Type II Kerogen","authors":"Mohammed Hail Hakimi,&nbsp;Muneer A. Suwaid,&nbsp;Shadi A. Saeed,&nbsp;Ameen A. Al-Muntaser,&nbsp;Mikhail A. Varfolomeev,&nbsp;Aliia N. Khamieva,&nbsp;Danis K. Nurgaliev,&nbsp;Mohammed A. Abdullah,&nbsp;Aref Lashin,&nbsp;Evgeniya V. Morozova,&nbsp;Bulat I. Gareev,&nbsp;Vitaly V. Andriyashin,&nbsp;Igor Ognev,&nbsp;Fatma Tahhan","doi":"10.1111/jpg.12877","DOIUrl":"https://doi.org/10.1111/jpg.12877","url":null,"abstract":"<div>\u0000 \u0000 <p>Six oil samples from an Upper Devonian carbonate reservoir in the Orenburg field in the SE Volga-Ural Basin (Russia) were analyzed geochemically, together with extracts of five core samples of the Domanik Formation source rock (Frasnian-Tournaisian) from a well located in the south of the basin. Biomarker analyses of saturated and aromatic oil fractions were combined with new data on the molecular structure of asphaltene in order to investigate source rock organic matter input, depositional environment, and thermal maturity. The studied oil samples have high API values (31°–37°) and saturated hydrocarbon contents up to 66%, suggesting that they were generated by a thermally mature source rock and consistent with high contents of С₆–С₁₄ <i>n-</i>alkanes relative to C₁₅₊ of the oil-asphaltene fraction. The molecular structure of asphaltene derived from pyrolysis-gas chromatograpy-mass spectrometry (Py-GC-Ms) analyses also suggests that the oils were generated by a source rock containing marine Type II kerogen, consistent with the H/C atomic ratio up to 1.25. Bulk kinetic analyses of the asphaltene showed a relatively broad range of activation energies between 40 and 58 kcal/mol and a frequency factor (A) of 12E+14/1 s. The biomarker characteristics of aliphatic and aromatic fractions in the studied oils suggest that they were generated by carbonate-rich source rocks containing organic matter of marine algal origin deposited under anoxic conditions. Furthermore, maturity-sensitive biomarker parameters show that the oils were generated at peak oil window maturities. Oil-source rock correlations of biomarker proxies indicated that the analyzed oils from the Orenburg field were mainly generated by carbonate-rich shaley source rocks in the Domanik Formation.</p>\u0000 </div>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"48 1","pages":"58-81"},"PeriodicalIF":1.8,"publicationDate":"2025-01-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143121334","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}