Search Results (105)

The presence of source rock with a high concentration of kerogen is not a sufficient condition for petroleum formation, as maturation requires specific thermodynamic conditions. In this study, the artificial maturation of organic matter was investigated through hydrothermal treatment simulating the vaporization–condensation zones associated with in situ combustion and steam-assisted recovery processes. The experiments were conducted under an inert nitrogen atmosphere at 250–350 °C to reproduce oxygen-depleted thermal environments where hydrothermal reactions dominate. The results demonstrate that the bitumoid yield increases with temperature, reaching a maximum of 4.44 wt.% at 300 °C, followed by a decline at 350 °C due to secondary cracking. At the same time, gas generation increases significantly, with a more than five-fold rise in total gas yield between 250 and 350 °C. In parallel, the H/C atomic ratio of kerogen decreases from 1.17 in the initial sample to 0.52 at 350 °C, indicating progressive aromatization and advanced catagenetic transformation. These changes are accompanied by the conversion of high-molecular-weight kerogen into resins, asphaltenes, and subsequently lighter hydrocarbons. The study provides experimental evidence for the effectiveness of hydrothermal processes in inducing kerogen transformation under inert conditions, offering insights into the mechanisms governing artificial maturation in unconventional reservoirs. Full article

The onshore southern Lake Albert Rift Basin in Uganda represents a geologically complex and hydrocarbon-prone segment of the western branch of the East African Rift System. This study integrates seismic, well and geochemical data, and 2D Basin and Petroleum Systems modeling to reconstruct the petroleum system of the basin. Results highlight spatial variations in source rock maturity and indicate a predominantly oil-prone character. Migration modeling reveals hydrocarbon expulsion and vertical migration into both the overlying Middle—late Miocene Kakara and underlying early Miocene Kisegi sandstone reservoirs, facilitated by fault-controlled pathways. The late Miocene—early Pliocene Oluka Formation proves to be an effective regional seal, supported by its low modeled porosity, while overpressure zones enhance migration and accumulation efficiency. Present-day thermal maturity profiles and porosity–depth relationships indicate favorable conditions for hydrocarbon generation, migration, and preservation. These findings redefine our understanding of petroleum system dynamics in the Albert Rift and underscore the exploration potential of underexplored structural and stratigraphic traps in the southern sector of this rift and analogous rift settings. Full article

Hydrocarbon resource potential evaluation represents the primary and core component of whole petroleum system studies. However, compared with the substantial progress achieved in understanding hydrocarbon generation mechanisms, quantitative assessments of hydrocarbon generation amounts from source rocks in the Songliao Basin remain relatively limited. Given that the genetic method is capable of comprehensively reflecting both the intrinsic hydrocarbon generation potential and conversion efficiency of source rocks and is supported by robust geological principles, this study was conducted within a genetic framework. Stratigraphic data and lithological descriptions from more than 2000 wells in the northern Songliao Basin, logging data from 387 wells, and measured basic geochemical data from 201 wells were integrated. Combined with the ΔlogR method, original hydrocarbon generation potential restoration techniques, and results from thermal simulation experiments, the planar distributions of key geochemical parameters of the first member of the Qingshankou Formation were systematically characterized. On this basis, the hydrocarbon generation potential and total hydrocarbon generation amounts of different structural units within the Songliao Basin were quantitatively evaluated. The results indicate that the cumulative hydrocarbon generation of the first member of the Qingshankou Formation reached approximately 506.55 × 10⁸ t. Among the structural units, the Qijia–Gulong Sag contributed 266.13 × 10⁸ t, the Sanzhao Sag 132.71 × 10⁸ t, the Longhupao Terrace 66.81 × 10⁸ t, and the Daqing Placanticline 40.90 × 10⁸ t. These results demonstrate significant heterogeneity in hydrocarbon generation capacity among different structural units, with the Qijia–Gulong Sag identified as the most important hydrocarbon generation center in the study area. This study provides a critical quantitative foundation for whole petroleum system research in the northern Songliao Basin. It not only supplies essential data support for subsequent resource apportionment of conventional and shale hydrocarbons but also offers important constraints for analyses of reservoir-type distribution and hydrocarbon accumulation mechanisms. Full article

High-salinity water environments, e.g., saline lacustrine basins and lagoons, represent significant sedimentary settings on Earth. They serve not only as crucial archives of paleoclimate and paleoenvironmental evolution but also as favorable realms for the development of high-quality hydrocarbon source rocks. Although traditional views suggested that high salinity inhibits biological activity and is thus detrimental to source rock formation; recent hydrocarbon discoveries in formations such as the Leikoupo Formation (Sichuan Basin) and Majiagou Formation (Ordos Basin) in China have confirmed the exceptional hydrocarbon generation potential of source rocks in such settings. Focusing on major sedimentary basins in China, this review synthesizes how high-salinity settings critically control the integrated “generation-storage” sequence of hydrocarbon source rocks. Research indicates that moderate salinity can promote blooms of halophilic microorganisms, e.g., algae, cyanobacteria, resulting in high primary productivity. Concurrently, salinity-driven stable water stratification creates a strongly reducing bottom water environment, which greatly facilitates the preservation of organic matter, establishing a synergistic enrichment model of “high productivity—excellent preservation.” Products of high-salinity environments, such as evaporites, e.g., gypsum, halite, can act as catalysts, lowering the activation energy for hydrocarbon generation and enhancing hydrocarbon yield. Additionally, associated organic salts provide supplementary material for hydrocarbon generation. Regarding reservoir quality, the laminated structures formed in high-salinity settings, combined with organic–inorganic synergistic diagenesis, e.g., dolomitization, organic acid dissolution, and hydrocarbon-generation overpressure, collectively shape high-quality reservoirs with significant heterogeneity. Despite important progress, challenges remain, including the quantitative analysis of primary factors controlling organic matter enrichment, the threshold of salinity inhibiting biological communities, and the prediction of strongly heterogeneous reservoirs. Saline settings serve as critical carbon sinks in the geological carbon cycle through high primary productivity, enhanced preservation conditions, and distinctive mineral assemblages, playing a particularly important role in the formation of hydrocarbon source rocks and long-term carbon sequestration. Future research should integrate modern saline lake observations with high-resolution characterization techniques to deepen the understanding of the formation mechanisms of high-salinity source rocks, aiming to provide theoretical guidance and exploration targets for petroleum systems in similar geological settings worldwide. Full article

The Chang 8 Member in the Longdong area of the Ordos Basin hosts significant petroleum resources, demonstrating substantial potential for tight oil exploration and development. Astronomical forcing exerts a discernible influence on the evolution of its petroleum system. To elucidate the impact of Milankovitch orbital cycles on organic enrichment and the development of source rocks, reservoirs and cap rocks, we conducted a high-resolution cyclostratigraphic analysis of the Chang 8 Member stratigraphy. This study utilized gamma-ray (GR) well log series as the primary dataset. This lacustrine succession preserves distinct Milankovitch cycles, including ~405 ka long eccentricity, ~125 ka short eccentricity, obliquity, and precession periods, with eccentricity cycles showing particularly strong expression. These diagnostic eccentricity signals provided the framework for delineating high-frequency sequences. Subsequent astronomical tuning and base-level reconstruction constrain the depositional age of the Chang 8 Member to 242.22–241.23 ± 1.4 Ma. During this interval, the lacustrine system exhibited a pronounced trend of base-level fall followed by rise, punctuated by higher-frequency fluctuations. Milankovitch cycles govern the development of high-quality reservoirs and cap rocks and organic enrichment by modulating climate and lake-level fluctuations. These orbital forcings drive weathering processes, control fluvial sediment supply and lacustrine accommodation space, and influence biological productivity. Our results demonstrate a pronounced association between the long eccentricity cycle (~405 ka) and enhanced reservoir quality development, while the short eccentricity cycle (~125 ka) exhibits a stronger correlation with organic matter enrichment, cap rocks, and source rock formation. Ultimately, the interplay of eccentricity cycles jointly governs the formation of the hydrocarbon system within the continental Chang 8 Member. Full article

Knowledge of the trace element contents of petroleum can improve crude oil exploration and refining and aid environmental studies. Analytical challenges prompt experimentation with various digestion methods and analytical techniques, but the assessment of the efficiency of applied methodologies is hindered by the scarcity of multi-element standard reference materials. In this study, NIST SRM 1634c residual fuel oil and NIST RM 8505 crude oil were subjected to (i) hotplate acid digestion and (ii) one, two or three cycles of microwave acid digestion, and analyzed by ICP-MS. Comparison with the few available certificate values shows optimum recoveries for both reference materials with two and three cycles of microwave digestion. Hotplate digestion can also efficiently decompose petroleum, although this procedure requires more time and reagents than the microwave digestion. To better characterize the trace element composition of the two reference materials for future use in the community, we integrate our new results with a comprehensive compilation of published trace element data for both petroleum samples. Finally, we show that the V/Ni and V/(V + Ni) ratios commonly used for oil–oil and oil–source rock correlations remain sufficiently close to the expected ratios even in cases of incomplete digestion with lower recoveries for both elements. Full article

Despite complex geological conditions and limited exploration activity, the South Yellow Sea Basin has not yet yielded a commercial hydrocarbon discovery. Recent studies indicate substantial hydrocarbon potential within the Upper Sinian–Lower Silurian strata; however, the mechanisms controlling hydrocarbon accumulation in these sequences remain poorly understood. In this study, outcrop, drilling, organic geochemical, and seismic data from the Yangtze Plate are integrated using a land–sea comparison approach to evaluate petroleum geological conditions, identify key controlling factors, and predict hydrocarbon accumulation in the Upper Sinian–Lower Silurian sequences of the Laoshan Uplift. The results indicate that the Upper Sinian–Lower Silurian strata possess favorable petroleum geological conditions, including two effective source–reservoir–seal assemblages. Key controls on deep hydrocarbon accumulation include high-quality Lower Cambrian source rocks, early development of the Laoshan paleo-uplift, structural stable zones, and Lower Silurian detachment layers. Three hydrocarbon accumulation evolution models are proposed: (1) early stage lateral hydrocarbon supply from adjacent depressions, (2) early stage lower-source–upper-reservoir charging, and (3) late-stage deep-burial cracking with structural adjustment. These findings provide important guidance for deep hydrocarbon exploration the Upper Sinian–Lower Silurian sequences of the Laoshan Uplift in the South Yellow Sea Basin. Full article

The Nezamabad Fault System (NFS) in the Fars area of the Zagros Fold–Thrust Belt represents a persistent, basement-rooted transverse shear zone that fundamentally controls the regional hydrocarbon system. This study integrates seismicity distribution, isopach analysis, and tectono-stratigraphic modeling from the Triassic to the Cenozoic to unravel how recurrent basement reactivation governs trap evolution. Isopach maps reveal a pronounced southwest-thickening asymmetry, with Triassic successions exceeding 1400 m, indicating long-term differential subsidence during four key phases: (1) Triassic syn-rift salt accumulation (Dashtak Formation) forming the primary detachment; (2) Jurassic–Early Cretaceous passive subsidence promoting source rock deposition; (3) Mid-Cretaceous transpression enhancing reservoir dolomitization; and (4) Late Cretaceous–Cenozoic inversion generating hybrid traps. Seismicity analysis of over 240 events confirms the 256-km-long NFS is a crustal-scale structure, with most foci at 10–33 km depth and others extending to 150 km, implying lithospheric stress transfer. This deep-crustal activity has periodically reorganized stress, enhanced fracture permeability, and rejuvenated traps through seismic pumping and cross-scale mechanical coupling. The results demonstrate that hydrocarbons in the Fars area are not a passive outcome of folding but a dynamic expression of lithospheric coupling. The findings establish a predictive framework for identifying analogous basement-influenced petroleum systems in other foreland fold–thrust belts worldwide. Full article

This study provides the first comprehensive characterization and classification of organic microfacies within the globally significant Jurassic hydrocarbon source rocks of Iraqi Kurdistan. This study aims to resolve the knowledge gap in the Jurassic source rocks of northern Iraq by establishing the first organic microfacies classification scheme, utilizing an integrated petrographic and geochemical approach to reconstruct the regional paleoenvironmental evolution and confirm the source rock’s petroleum potential. The Middle–Late Jurassic Sargelu, Naokelekan, and Barsarin formations were investigated using samples from the Mangesh-1 and Sheikhan-8 wells. Using cluster analysis, we identified five distinct organic microfacies (A–E). Microfacies A (highly laminated bituminite), B (laminated/groundmass bituminite), C (laminated rock/lamalginite), and D (massive organic-matter-rich) show the highest hydrocarbon generation potential. The findings reveal a clear paleoenvironmental evolution: the Sargelu Formation was deposited in anoxic open marine conditions (microfacies C, D); the Naokelekan Formation represents a progressively restricted silled basin with intense anoxia leading to condensed sections dominated by microfacies A, which shows the highest source rock potential; and the Barsarin Formation reflects increasing restriction and hypersalinity, showing diverse microfacies (B, C, D, E) that captured variations in marine productivity and terrigenous influx. Principal component analysis (PCA) quantitatively modeled these paleoenvironmental gradients, aligning the distinct organic microfacies and their transitions with conceptual basin models. Geochemical analysis confirms that the organic matter is rich, predominantly Type II kerogen, and thermally mature, falling within the oil window. The presence of solid bitumen, both in situ and as evidence of migration (microfacies E), confirms effective hydrocarbon generation and movement. This integrated approach confirms the significant hydrocarbon potential of these Jurassic successions and highlights the critical role of specific organic microfacies in the region’s petroleum system, providing crucial guidance for future hydrocarbon exploration in northern Iraq. Full article

The Upper Cambrian–Lower Silurian sediments of the Baltic Basin represent organic-rich clastic and carbonate rocks that are a key exploration target for hydrocarbons in northern Pomerania, Poland. The source rocks contain an average total organic carbon (TOC) content of 4.1 wt% (range: 0.7–9.6 wt%). The organic matter is primarily in the early to mid-oil window; however, both more mature and overmature organic matter also occur (average Tmax: 445 °C; range: 427–488 °C; average Ro: 1.3%; range: 1.0%–1.8%). These organic-rich rocks were mostly deposited under dysoxic rather than anoxic conditions. Fossils of oxygen-dependent benthic fauna are widely distributed, even in the darkest (black shale) lithologies. Nevertheless, short intervals lacking benthic fossils indicate episodes of anoxic bottom-water conditions. The Furongian–Lower Llandovery source rocks exhibit a low sedimentation rate, ranging from 1 to 19 m/Ma. Geochemically, the organic matter is dominated by type II kerogen. Petrographically, the kerogen consists mainly of graptolites and algae. Due to the predominance of planktonic-origin fauna and thermal maturity, the kerogen is relatively hydrogen depleted (average Hydrogen Index, HI: 169 mg HC/g TOC; range: 1–340 mg HC/g TOC). The present day petroleum potential of these source rocks varies from fair to good and very good. Bitumen analysis revealed a dominance of kerogen components, with only minor admixtures of light and heavy oils. Full article

Bedding-parallel fractures represent a crucial flow-path network in shale oil reservoirs, yet their timing of opening and driving mechanisms remain subjects of long-standing debate. This study investigates the origin and opening mechanisms of bedding-parallel fractures within the Paleogene Funing shale oil reservoir of the Huazhuang area, Subei Basin, eastern China. A combination of petrography, fluid-inclusion analysis, PVTx paleo-pressure modeling, hydrocarbon generation history modeling, and reflectance measurements was employed. The results reveal the presence of abundant oil inclusions and bitumen within the bedding-parallel veins, indicating that the initiation of fracture was essentially synchronous with the oil emplacement. The studied Funing shale, with vitrinite reflectance values of 0.85% to 1.04%, is mature, identifying it as an effective oil-prone source rock. Thermal maturity of bitumen is comparable to that of the host shale, suggesting a local oil source. Homogenization temperatures (T_h) of coeval aqueous inclusions record fracture opening temperatures of approximately 100–150 °C, consistent with oil-window conditions. By integrating T_h data with burial history modeling, the timing of fracture formation and coeval oil injection is constrained to the peak period of local hydrocarbon generation, rather than the Oligocene Sanduo tectonic event. This indicates that fracture opening was primarily associated with hydrocarbon generation rather than tectonic compression. Petroleum-inclusion thermodynamic modeling demonstrates that the bedding-parallel fracture opening occurred under moderate to strong overpressure conditions, with calculated paleo-pressure coefficients of ~1.35–2.36. This finding provides direct paleo-pressure evidence supporting the mechanism of bedding-parallel fracture opening driven by fluid overpressure created during oil generation. These oil-bearing, overpressured fluids facilitated the initial opening and subsequent propagation of fractures along the bedding planes of shales. Concurrently, the precipitation of the calcite veins may have been triggered by pressure drop associated with the expulsion of some coexisting aqueous fluids. This study provides evidence addressing the debated mechanisms of bedding-parallel fracture opening in organic-rich shales, highlighting the critical role of oil generation-induced overpressure. Full article

The Lower Cretaceous Jiufotang Formation in the Fuxin Basin contains a proven petroleum system. However, its southern part remains underexplored due to limited drilling and fragmentary sedimentary studies. To address this issue, we conducted detailed sedimentological logging of the two typical outcrop sections, Pijiagou and Tanjiagou. Field observations, petrographic data, and grain-size analysis were integrated to decipher hydrodynamic conditions, calibrate microfacies associations, and reconstruct the sedimentary evolution through facies stacking pattern analysis. The results show that the Jiufotang Formation predominantly consists of calcareous fine-grained clastic rocks, with poorly sorted sandstones indicative of low-energy conditions. Sediment transport mechanisms include both traction and turbidity currents, with suspension being predominant. The succession records a depositional transition from fan-delta to lacustrine environments. Two subfacies, fan-delta front and shore-shallow lacustrine, were identified and subdivided into seven microfacies: subaqueous distributary channels, interdistributary bays, subaqueous levees, mouth bars, muddy shoals, sandy shoals, and carbonate shoals. The sedimentary evolution reflects an initial lacustrine transgression followed by regression, interrupted by multiple lacustrine-level fluctuations. The alternating depositional pattern of lacustrine and deltaic facies has formed complete source-reservoir-seal assemblages in the Jiufotang Formation in the study area, making it a potential favorable target for hydrocarbon accumulation. Full article

The Baorao Trough of the Jiergalangtu Sag, located in the central Erlian Basin, is rich in petroleum resources. However, due to a lack of systematic geochemical characterization and comparative studies with other source rocks, the hydrocarbon generation potential of its Jurassic strata remains unclear. In this study, 125 samples from the Baorao Trough were analyzed to evaluate their hydrocarbon generation potential, identify organic matter sources and depositional environments, and characterize hydrocarbon generation and expulsion. Results show that source rocks from the first member of the Tengge’er (K₁bt₁) Formation and the Aershan (K₁ba) Formation have high organic matter content, favorable kerogen types, and have reached low to medium maturity. In contrast, Jurassic source rocks are predominantly Type III kerogen and highly mature. K₁bt₁ was deposited in a weakly oxidizing to reducing, brackish environment, while K₁ba formed under weakly reducing, saline conditions. Jurassic source rocks also developed in weakly reducing, brackish to saline settings. Notably, saline and reducing environments promote the development of high-quality source rocks. The lower total organic carbon (TOC) threshold for effective source rocks in the study area is 0.8%, and the hydrocarbon expulsion threshold for vitrinite reflectance ratio (R_o) is approximately 0.8%. Accordingly, K₁bt₁ and K₁ba have undergone partial hydrocarbon expulsion but remain within the oil-generating window, indicating strong oil-generating potential. Jurassic source rocks likely experienced early thermal cracking of Type III kerogen, with generated oil migrating or escaping during early geological activity. However, some gas-generating potential remains. These findings provide significant evidence for assessing resource potential, predicting the distribution of high-quality source rocks and favorable exploration areas. Full article

In many scientific and engineering fields, such as hydrogeology, petroleum engineering, geotechnical research, and developing renewable energy solutions, fluid flow modeling in porous media is essential. In these areas, optimizing extraction techniques, forecasting environmental effects, and guaranteeing structural safety all depend on an understanding of the behavior of single-phase flows—fluids passing through connected pore spaces in rocks or soils. Darcy’s law, which results in an elliptic partial differential equation controlling the pressure field, is usually the mathematical basis for such modeling. Analytical solutions to these partial differential equations are seldom accessible due to the complexity and variability in natural porous formations, which makes the employment of numerical techniques necessary. To approximate subsurface flow solutions, traditional methods like the finite difference method, two-point flux approximation, and multi-point flux approximation have been employed extensively. Accuracy, stability, and computing economy are trade-offs for each, though. Deep learning techniques, in particular convolutional neural networks, physics-informed neural networks, and neural operators such as the Fourier neural operator, have become strong substitutes or enhancers of conventional solvers in recent years. These models have the potential to generalize across various permeability configurations and greatly speed up simulations. The purpose of this study is to examine and contrast the mentioned deep learning and numerical approaches to the problem of pressure distribution in single-phase Darcy flow, considering a 2D domain with mixed boundary conditions, localized sources, and sinks, and both homogeneous and heterogeneous permeability fields. The result of this study shows that the two-point flux approximation method is one of the best regarding computational speed and accuracy and the Fourier neural operator has potential to speed up more accurate methods like multi-point flux approximation. Different permeability field types only impacted each methods’ accuracy while computational time remained unchanged. This work aims to illustrate the advantages and disadvantages of each method and support the continuous development of effective solutions for porous medium flow problems by assessing solution accuracy and computing performance over a range of permeability situations. Full article

This study provides a detailed geochronological paragenesis of fracture systems from the Upper Jurassic petroleum source formation in NE Iraq, utilizing U-Pb dating, integrated with microprobe analyses and petrographic studies. Five fracturing stages are recognized (FI–FV), indicating significant tectonic and temperature changes from the Late Jurassic to Pliocene times (approximately 5.2–5.5 Ma). The burial history curve shows continuous subsidence events, starting with initial burial of the Barsarin Formation reaching depths of 1000–1200 m by 110 Ma, this depth interval coincides with the first fracturing stage (FI). The buffered system of FI by pristine facies and geometrical cross-cutting of FI with early stylolite formation show a prior formation of stylolite. Subsequent fracturing stages FII (28.6 ± 2 Ma, Oligocene) and FIII (19.83 ± 0.43 Ma, Early Miocene) were contemporaneous with tectonic deformation phases and hydrocarbon generation times. Microprobe and optical analyses demonstrate variations in mineralogical composition, particularly in FIV/FV-filled calcite and dolomite cements (12.2 ± 1.5 Ma and 5.5 Ma), highlighting the periods of conduit formation for the hydrocarbon migration. Backscattered electron (BSE) imaging reveals a textural alteration of these cements, especially those associated with fluorite precipitation, which further support the hydrothermal entrapment associated with the hydrocarbon migration. The hydrocarbon entrapment appeared in at least two episodes under subsurface setting under temperatures exceeding 100 °C. In summary, the significant meaningful ages and compositional analyses obtained from this study reveal crucial insights into the dynamics of fracture-filling cements and hydrocarbon entrapment mechanisms within the petroleum source rock formation. The novelty of these data would enhance our understanding of the complex relationship between structural geology and migration conduits, highlighting the influence of fracture-filling cements on hydrocarbon accumulation and reservoir quality as a main target for hydrocarbon field development. Full article