Seismic data from the northern part of the West Siberian Basin and the Enisey-Khatanga Trough indicates the presence of up to 15 km-thick Paleozoic sediments underlying the Mesozoic overburden. This finding challenges the traditional notion that folded Paleozoic rocks constitute the economic basement of the basin. The Paleozoic section comprises evaporitic units, most likely of Ordovician age, which were deposited in troughs formed during the Early Paleozoic Uralian rifting. A reinterpretation of the geological structure suggests that salt tectonics has significantly influenced the subsurface architecture of these regions. Seismic evidence for salt diapirs includes (1) significant heights of salt structures (5 km or more), (2) seismic transparency, (3) minibasin tectonostratigraphic successions flanking the salt structures, and (4) radial fault systems in the overlying deposits. Additional evidence for the occurrence of salt diapirs includes magnetic, gravimetric, thermal, electrical, and topographic anomalies. Minibasin tectonostratigraphic successions suggest that diapirism began soon after salt deposition, preceding the onset of the Late Paleozoic compression. Far-field intracratonic deformations modified salt structures during the Mesozoic-Cenozoic, including extensional episodes in the Early Triassic and Early-Middle Jurassic and contractional episodes in the Late Triassic, Early Cretaceous, and the Late Cenozoic. These events led to folding of post-salt strata, which was accompanied by continuous differential compaction and Quaternary post-glacial rebound of diapirs. These processes amplified anticlines in post-salt Cretaceous reservoirs, which host giant gas accumulations. The thick and thermally mature Paleozoic deposits include source rocks, which likely significantly contributed to the region's hydrocarbon potential. The upward migration of hydrocarbons through salt structures, from the deeply buried Paleozoic section into the Mesozoic overburden, provides a plausible explanation for the longdebated origin of the abundant gas content in Cretaceous deposits.
Chlorite can strongly affect the quality of clastic sandstone reservoirs and may also impact the potential of geologic sequestration of CO2 in deep saline aquifers. However, there is a lack of quantitative evaluation of the effect of chlorite on CO2 sequestration in sandstones to date. Here we applied a suite of analytical techniques including petrographic and petrological analysis, X-ray diffraction measurement, petrophysical analysis, and CO2-fluid-rock reactive-transport simulations to investigate the impact of chlorite on both reservoir quality and CO2 geological sequestration in the Upper Permian sandstones in the northeastern Ordos Basin, China. Three types of chlorite are present in the reservoir sandstone: grain-coating, pore-throat-blocking, and pore-filling. Grain-coating chlorite sandstones feature thin chlorite wrapping on sand grain surfaces that effectively prevent quartz cementation, thus preserving good reservoir porosity and permeability. Pore-throat-blocking chlorite sandstones generally exhibit high porosity but low permeability with the thick chlorite coatings inhibiting quartz cement growth and preserving porosity while blocking pore throats and reducing permeability. Pore-filling chlorite sandstones are characterized by both low porosity and low permeability due to extensive chlorite filling of the pore spaces as matrix. Reactive transport simulations demonstrate that high-porosity and -permeability reservoir sandstones may not always be the most favorable sandstone type for CO2 geological sequestration when considering the key geochemical sequestration mechanisms (i.e. dissolution and mineral trapping). When disregarding the impact of chlorite on reservoir quality, pore-filling chlorite sandstones, with their high chlorite content, are most suitable for CO2 sequestration due to their greater capacity for trapping CO2 via mineralization. However, when both chlorite abundance and reservoir quality factors are considered, pore-throat-blocking chlorite sandstones would possess the largest total CO2 sequestration capacity.
Methane hydrate (MH) is an abundant unconventional gas resource whose safe and efficient exploitation is essential for easing the energy crisis and facilitating carbon-neutral targets. Here we employ transparent microfluidic chips to capture the pore-scale dynamics of MH decomposition driven by (i) controlled thermal stimulation and (ii) pressure drawdown. In both modes, decomposition initiates in the porous hydrate and lags in the crystalline hydrate, confirming the higher thermodynamic stability of crystalline hydrate. Under depressurisation (outlet pressure 1.0 bar, inlet pressure 96.0 bar), three successive stages are identified. Stage I: continuous-phase porous hydrate decomposes first; liberated methane then impinges on intact crystals, triggering secondary nucleation, flow deceleration and partial channel blockage. Stage II: alternating episodes of rapid decomposition and re-formation produce a prolonged stagnation period in which porous and crystalline hydrate repeatedly form and dissolve. Stage III: hydrate re-formation and decomposition occur in quick succession, repeatedly obstructing and reopening pore throats, generating abundant micro-/nano-bubbles (ranging from 2.26 to 37.8 mu m) and ultimately leading to complete hydrate dissociation. Each of the three stages lasts approximately 20, 1150 and 170 min, respectively. Simultaneous evolution of the outlet pressure reveals that the pore-pressure field evolves in concert with the process of hydrate decomposition. During Stages I-II, the decomposition front remains near the outlet, connectivity is poor, and newly formed hydrate sustains a high differential pressure. Once the front advances toward the inlet (Stage III), connectivity improves rapidly; vigorous gas-liquid flow and cyclic hydrate conversion induce a step-wise pressure decline until full decomposition is achieved. This work presents the first direct, time-resolved visualization of MH breakdown at the pore scale, elucidating the interplay of thermal, hydraulic and phase-change processes governing gas production. These insights provide a quantitative framework for optimising temperature-pressure protocols in field-scale MH exploitation.
Digital Outcrop Models (DOMs), empowered by advanced digital techniques, have revolutionized the study of outcrop analogs for petroleum reservoir characterization by enabling the extraction of key quantitative parameters for modeling. The limited availability of subsurface data often constrains reservoir characterization, making outcrop analogs essential tools for improving geological models. The analogs bridge the gap between borehole-derived information and regional-scale seismic data, providing crucial mesoscale insights. In this context, this study proposes an integrative workflow combining high-resolution sequence stratigraphy (HRSS) with digital techniques to enhance the understanding of depositional settings and extract data from the Balbuena III Sequence of the Salta Basin, Argentina, a well-established stratigraphic basin analog for Brazilian pre-salt carbonate reservoirs. The workflow combines traditional field-based methods with advanced digital techniques applied to photogrammetric data, including Local Binary Pattern (LBP) analysis and Convolutional Neural Networks (CNNs). LBP analysis correlated with stratigraphic interpretation demonstrated promising potential for characterizing the high-frequency cyclicity observed in the study area. CNN-based segmentation classified and delineated eleven lithofacies, including carbonate, siliciclastic, mixed, and volcanic facies. This segmentation allows for the generation of lithofacies-classified 3D point clouds and a detailed spatial representation of facies distribution across the outcrop. Digital approaches enable more in-depth analysis by increasing efficiency, accuracy, and the capacity to analyze large datasets. By combining digital and traditional methods, this work improves the analysis of outcrop analogs, which contributes to more accurate geological modeling and enhances the predictive capability of petroleum fields and hydrocarbon recovery.
Gas hydrates have been identified in the Cauvery-Mannar Basin, a passive rift setting largely devoid of recent tectonic activity as evidenced by seismic data. This study provides novel insights into gas migration pathways from deep-seated reservoirs to the shallow subsurface, with particular emphasis on the role of seismic chimneys as focused conduits for fluid and gas transport. The Bottom Simulating Reflector (BSR), a key seismic indicator of gas hydrates, is observed intermittently across multiple seismic profiles, underlain by extensive gas-charged sediments. A prominent feature in one of the seismic profile is a chimney-like structure, similar to 650 m tall and 1000 m wide, originating from deeper gas-rich strata at depth. Formed through overpressure-induced hydrofracturing, the chimney acts as a conduit for vertical gas migration from deep-seated gas reservoirs to the Gas Hydrate Stability Zone (GHSZ). At the base of GHSZ, hydrates form impermeable layers that restrict vertical migration of free gas and promote lateral migration. Amplitude variation with angle (AVA) analysis reveals strong Class III anomalies in the updip direction of BSR, indicating preferential lateral gas migration along the base of GHSZ. Class IV anomalies observed in the updip region may signify high-concentration gas hydrates or fracture-filled deposits formed through focused gas accumulation. In this tectonically quiescent setting, hydrostatic pressure gradient drives both vertical and lateral gas migration, transporting gas from deep reservoirs to the shallow subsurface in the Mannar basin. These findings have important implications for understanding gas hydrate systems in other passive continental margin environments.
Stringers are disrupted rock bodies commonly enclosed within salt diapirs. Traditionally, they have been regarded as a risk factor in the energy exploitation of salt structures due to their heterogeneity and general sub-seismic scale, which hinder their detailed identification. Nevertheless, rock units in stringers may exhibit sufficient permeability and temperature to act as potential reservoirs, for instance, in geothermal energy. Despite this possibility, studies regarding the reservoir potential of intrasalt stringers remain scarce. The well-exposed Estopany & agrave; Salt Wall in the South-Central Pyrenees contains abundant Muschelkalk carbonate stringers, providing an excellent opportunity to study the geological controls on their reservoir properties. Four lithofacies within two stratigraphic intervals were identified. Depositional lithofacies (DLF-1 and DLF-2) preserve original rock textures, whereas alteration lithofacies (ALF-1 and ALF-2) result from intense brecciation, cementation, and dolomitization-dedolomitization affecting the depositional facies. Thermophysical analyses of 30 samples reveal limited variation in mineral density (2.61-3.00 g cm(-3)), bulk density (1.92-2.95 g cm(-3)), and thermal conductivity (2.37-3.48 W m(-1) K-1), with the latter being primary controlled by rock mineralogy. In contrast, connected porosity (0.33-29.20 %), permeability (<0.001-19.85 mD; <10(-18)-10(-14) m(2)), P-wave velocity (3.7-6.4 km s(-1) dry; 3.7-6.5 km s(-1) saturated conditions), and specific heat capacity (640-804 J kg(-1) K-1) show greater variability. Property cross-plots indicate that porosity percentage and distribution are the main factors controlling the observed thermophysical behavior, which is ultimately linked to rock texture. The area and scarce thickness of porous and permeable intervals (estimated at reservoir volumes of 0.14-4.6 km(3)), likely preclude the limited reservoir use of the studied stringers. However, petrographic evidence from them highlights interesting processes such as brecciation and dolomitization that may have enhanced the permeability and thermal conductivity in the past, while subsequent cementation and dedolomitization reduced reservoir quality. Accordingly, although current outcrop conditions show diminished reservoir potential, higher porosity-permeability values may be preserved in the subsurface. Overall, this study establishes a conceptual model for the geological controls, limitations, and potential of intrasalt carbonates as unconventional reservoirs, providing comprehensive petrological and thermophysical data that can guide their exploration for geothermal production in salt diapir settings.
Understanding the deformation sequences of fold-and-thrust belts is crucial for deciphering orogenic processes and evaluating resource potential. Previous studies document that the thin-skinned eastern Sichuan fold-and-thrust belt, between the Tibetan Plateau and the Jiangnan-Xuefeng orogen, evolved through stepwise progressive deformation propagation in the Mesozoic and subsequent reactivation in the Cenozoic. However, recent U-Pb dating of syn-tectonic calcite veins and statistical analysis of thermochronological data reveal an out-of-sequence deformation history, contradicting the prevailing progressive deformation process. This study integrates multidisciplinary approaches including seismic section interpretation, apatite fission-track analysis and sequential cross-section restoration, to investigate its deformation sequences and controlling factors. The results show distinct deformation sequences during three deformation stages. The first deformation stage commenced at 135 Ma with the formation of the Qiyueshan anticline along the southeastern margin, followed by the development of the Huayingshan Fault-related fold at similar to 120 Ma along the northwestern margin. Deformation propagated from its southeastern and northwestern boundaries to the center along the Cambrian Longwangmiao-Gaotai Formation evaporites until 100 Ma. This produced tectonic wedges and fault-propagation folds under the NW-directed compression from the Paleo-Pacific subduction and SE-directed counterforce along the pre-existing Huayingshan Fault. The second stage involved NW-directed stepwise progressive deformation propagation with hybrid thrust sequence along the Silurian shales from 100 Ma to 70 Ma, reactivating earlier thrusts and tectonic wedges under continued compression from the Paleo-Pacific subduction. The third stage is characterized by regional simultaneous uplift with limited deformation from 20 Ma to the present, as rigid basement and discontinuous d & eacute;collements impeded SE-directed compression from the eastward growth of the Tibetan Plateau in the Cenozoic. These results indicate that the deformation sequences and patterns of eastern Sichuan fold-and-thrust belt were controlled by pre-existing structures, basement properties, multiple d & eacute;collements and convergence direction. This finding provides valuable insights for resource exploration in the study area and enhances our understanding of intracontinental orogenic deformation processes globally.
Fracture development and distribution within the BZ19-6 South (BZ19-6S) conglomerate reservoirs is dominantly controlled by Cenozoic multiphase strike-slip stress regimes, critically influencing hydrocarbon migration, accumulation, and sweet-spot distribution. This study characterizes these complex fracture systems by first reconstructing strike-slip superimposed activity during three key tectonic periods (middle Eocene, Oligocene, present-day) using balanced cross-sections, throw-depth plots, and growth indices integrated with regional dynamics. A 3D geological model was then constructed from seismic data, sedimentary microfacies, and paleo-tectonic restorations. Concurrently, a heterogeneous geomechanical model was developed using well logs and rock mechanics tests. Finite element simulations, constrained by loading stress magnitudes from acoustic emission experiments (as boundary conditions), reconstructed paleo- and present-day tectonic stress fields for each period. By considering the principles of fracture mechanics with wellbore fracture statistics, models for tensile/shear failure rates and linear fracture density were established to quantify fracture evolution. Validation against exploration-well data confirmed prediction accuracy, thereby guiding new well placement in high-fracture zones. Key findings: (1) Distinct strike-slip superimposed patterns across periods generated superimposed structural styles with variable geometries and intensities; (2) The Middle Eocene-Oligocene fractures were primarily controlled by burial depth, whereas present-day fractures are jointly co-governed by burial depth and strike-slip faults. This study advances deep reservoir fracture prediction through high-resolution tectonic staging and stress superposition analysis, providing a quantitative framework for fracture evaluation and reservoir development.
Mud volcano systems release methane (CH4) and carbon dioxide (CO2), which are not only potential energy resources but also key greenhouse gases influencing global climate change. However, the formation mechanisms and geochemical characteristics of gases emitted from mud volcanoes-shaped by both thermogenic and microbial processes-are still not well understood. In this study, representative terrestrial mud volcanoes from the Junggar Basin (Northern Tianshan) and the Kuban Basin (Northern Caucasus), were investigated through stable isotopes of CH4-H2O, CH4-CO2, and CO2-DIC systems, aiming to elucidate water-gas interactions and gas generation pathways. The hydrogen isotopic compositions of CH4-H2O system reveal clear regional differences between Junggar and Kuban mud volcanoes. The Junggar samples are characterized by strongly depleted delta DCH4, and highly negative Delta D(CH4-H2O) values, indicating extensive microbial overprinting under low-temperature conditions. In contrast, the Kuban samples exhibit a wider range of Delta D values, suggesting spatial variability in microbial influence, potentially limited by localized rapid gas ascent or open systems. Carbon isotope data reveal a mixed-origin pattern, with varying contributions from both thermogenic and microbial processes. A small number of samples (e.g., Western Tsymbaly) display isotopic characteristics consistent with microbial CO2 reduction. In contrast, other samples exhibit isotopic discrepancies among CH4, CO2, and DIC, suggesting that CH4 and CO2 were influenced by different formation mechanisms or geochemical processes. Overall, methane in both regions has primarily thermogenic sources, but has undergone varying degrees of secondary microbial alteration in the shallow subsurface (e.g., through acetate fermentation or anaerobic methane oxidation). These findings support a model of thermogenic dominance with microbial overprinting. This study highlights the value of multi-parameter isotope approaches in unraveling the complex formation and transformation mechanisms of CH4 and CO2 in active mud volcano systems and provides valuable geochemical constraints for gas origin tracing and natural gas exploration.
Lacustrine source-to-sink systems offer essential insights into sediment generation, transport, and deposition processes. However, the dynamics of ancient lacustrine source-to-sink systems, especially in rift basins, remain poorly understood due to limited well data. In this study, we use high-resolution 3D seismic data, supplemented by limited well information, to reconstruct the source-to-sink architecture and evolution on the southern slope of the Bozhong Depression, Bohai Bay Basin, China. The system consists of granite-dominated catchments, incised paleovalleys, and sedimentary fans that evolved from confined deltas to braided river deltas. Quantitative morphometric (e.g. fan area, catchment area, and catchment relief) analysis reveals a two-stage depositional evolution, driven by topographic slope variations and lake-level fluctuations. We identify two types of catchment-to-fan coupling, confined and unconfined, each reflecting distinct topographic and hydrodynamic controls. These findings refine our understanding of sediment routing in lacustrine rift basins and offer predictive value for reservoir characterization in similar tectonic settings.
Natural hydrogen (H2) holds promising potential as a clean energy source, but its exploration remains challenging due to limited knowledge and a lack of quantitative tools. In this context, identifying active H2 seepage areas is crucial for advancing exploration efforts. Here, we focus on sub-circular depressions (SCDs) that often mark high H2 concentration in soils, thought to correspond to deeper fluxes seeping at the surface, making them promising targets for exploration. Coupling open-access Google Earth (c) images and in-field H2 measurement data, an artificial intelligence model was trained to detect seepage zones. The model achieves an average precision of 95 %, detects and maps seepage zones in new regions like Kazakhstan and South Africa, highlighting its potential for global application. Moreover, preliminary spatial analyses show that geological features control the distribution of H2-SCDs that can emit billions of tons of H2 at the scale of a sedimentary basin. This study paves the way for a faster and more efficient methodology for selecting H2 exploration targets. Plain Language Summary. Natural hydrogen is a promising clean energy source, but it remains difficult to explore due to a lack of accessible tools. In this study, we used free satellite images (Google Earth (c)) and in-field hydrogen measurements to identify specific surface features-small sub-circular depressions (SCDs)-that often mark areas where hydrogen is seeping from underground. We trained an artificial intelligence model to detect these depressions, using a dataset of confirmed hydrogen-emitting SCDs collected across five countries. Thanks to this diversity in the training data, the model can be applied at a global scale, having learned to recognize a wide variety of structures associated with hydrogen seepage. To validate its effectiveness, the model was tested on two random regions-in Kazakhstan and South Africa-and successfully identified over a thousand new potential hydrogen-emitting depressions. With an average precision of 95 %, this tool offers a fast and reliable way to map natural hydrogen seepage zones, helping guide future exploration efforts worldwide.
Brine pools are underwater hypersaline and often anoxic lakes, which occur abundantly in the Gulf of America (Gulf) due to its complex geological and structural setting, particularly because of the presence of the buried Louann salt deposit. Fluids migrating upward dissolve this salt, and the resulting brine ascends until it is expelled at the seafloor through cold seeps. In instances where the brine accumulates without significant overflow, brine pools are formed. These extreme environments host interconnected communities of bacteria and archaea, and at their edges, chemosynthetic communities thrive, forming extensive mussel beds. By studying the variable geochemical gradients and biological settings of the Gulf brine pools, researchers have significantly advanced our understanding of these extreme environments. However, due to the limited accessibility of these sites, brine pools remain understudied compared to more accessible locations, leaving many questions unanswered. This review synthesizes current knowledge of Gulf brine pools, providing a standardized foundation for future exploration, assessments of critical minerals, and research efforts, which could shed light on the habitability limits on our planet and inform the search for life in similar environments within our solar system.
We employed a site screening framework to select potential CCS sites within the Early Miocene formations of the eastern Gunsan Basin in the Yellow Sea, offshore South Korea, by incorporating subsurface data. The site screening process, comprising stratigraphic and structural interpretation, gross depositional environment mapping, and common risk segment mapping, revealed three potential areas for CO2 geological storage: SA1, SA2, and SA3 in the north, center, and south, respectively. SA1 was the most favorable site, considering its substantial sand potential and geologically stable environment. Prospective CO2 storage resources for SA1 were estimated using geological static modeling and the CO2-SCREEN tool, yielding a best estimate (P50) in the range of 420-459 MtCO2. Pressure-constrained storage resource was also evaluated using EASiTool V5.0, which accounts for realistic injectivity and operational limitations, resulting in a more conservative P50 estimate of 91.9 MtCO2. This study highlights significant potential for CO2 storage in the Early Miocene formation of the eastern Gunsan Basin, to secure additional CO2 storage resources and achieve the 2030 nationally determined contribution and 2050 net zero greenhouse gas emission targets. The applied site screening framework can serve as a transferable approach for evaluating CO2 storage in offshore basins globally.
Hydrocarbon seepage at the Earth's surface provides crucial insights into subsurface petroleum systems. This study investigates the role of seismic cycle dynamics in controlling vertical hydrocarbon migration by studying the Ragusa Oil Field, a long-exploited petroleum district in the Hyblean foreland domain of south-eastern Sicily (Italy). Inspired by oil spilling in the area that followed a seismic sequence in February 2016, a multiscale structural analysis was undertaken to explore the relationship between fault activity and oil mobilization. This study integrates mesoscale structural measurements, microstructural analysis of bitumen-bearing fault breccias, and 3D Dilation Tendency modelling under paleo- and present-day stress conditions to build a dynamic model of upward hydrocarbon migration and seepage at the Earth's surface during the seismic cycle in carbonate-hosted normal faults in a foreland setting. Evidence from abandoned asphalt mines and active seep sites reveals both stratigraphic layer-impregnation and localized fault/fracture-controlled oil pathways. Field observation and Dilation Tendency analysis indicate that vertical hydrocarbon migration may predominantly occur by fractures instability during seismic rupture allowing overpressured fluids to migrate vertically, mainly at fault intersections. These findings highlight the role of seismic deformation in controlling fractures instability and transient permeability changes which, in turn, facilitate hydrocarbon mobilization and leakage. Calcite clast aggregates within hydrocarbon-filled voids observed during microstructural investigations confirm episodic, pressure-driven fluidization consistent with co-seismic mobilization. Stratigraphic evidence of repeated seepage events in Quaternary alluvial deposits supports a model of cyclic hydrocarbon migration linked to stress variations during the seismic cycle. The novelty of this paper is that we document an hydrocarbon seepage process associated with modern seismicity, filling the gap of previous observations of hydrocarbon seepage speculatively associated with fossil earthquakes without a direct cause-effect link.
Submarine canyons are key elements of the evolution of convergent margins. Their infilling can be mud-prone and thus represents a good seal if they cut through reservoir series, this erosion phase may be enhanced by tectonic activity. The present study focuses on the Western Alpine Foreland Basin where we use the outcrops of the Schistes a` Blocs Formation to study the syn-tectonic evolution of a Lower Oligocene submarine canyon that cuts through the Annot Sandstones Formation. The Intra Schistes a` Blocs Erosion Surface (ISaBES) has been mapped in the field. Airborne and drone pictures were also used. Moreover, the deposition model and the stratigraphic architecture of the canyon-fill were reconstructed from the analysis of seven sedimentary logs cumulating 410 m of series, particularly crossing the under described Schistes Bruns Member. The sedimentary system of this lower unit of the canyon-fill has been also constrained by the measurement of paleocurrents, and the provenance analysis of detrital zircons from four samples. The paleocurrent measurements on the unidirectional ripples deposited within the Schistes Bruns Member is witness of a turbulent flow rebound against the steep northern flank of the canyon, during the construction of internal levees which often experimented gravity collapse. Slumping of internal levees improves the seal properties of the canyon-fill, while the canyon thalweg was dominated by by-pass processes. Detrital zircons reveal that the provenance of the Schistes Bruns Member is sourced by the same sedimentary system of the Annot Sandstones Formation. Thus, we interpreted that both the canyon excavation and the sediment by-pass within its thalweg during the deposition of the Schistes Bruns Member, were triggered by an increase in basin slope related to the tectonic evolution of the accretionary prism. Finally, the ISaBES is a composite and diachronous surface resulting both from the morphology of the internal levees, and from their reworking during the deposition of the olistostromes of the Schistes a` Blocs Exotiques Member, that predates the emplacement of the Alpine nappes within the foreland basin.
The topography of the Mozambique Coastal Plains is characterized by several grabens developed over a Mid Jurassic (Oxfordian - Kimmeridgian) volcano-sedimentary sequence, which forms the acoustic basement. These grabens, including the Zualane Graben are collectively termed the Inner Graben System (MCP Graben System in this study), strike predominantly NNW-SSE and N-S, and less commonly E-W. Most of them formed during Gondwana fragmentation from Upper Jurassic (Kimmeridgian-Tithonian?) to Lower Cretaceous (Berriasian to Hauterivian?-Barremian) times. The youngest grabens have a Late Miocene age. Often the upper part of the acoustic basement, named Stormberg volcanics, form buried volcanoes characterized by conical shapes and positive magnetic anomalies. Some of these volcanoes are aligned along the shoulders of the West and East Changani Grabens suggesting an off-rift volcanism setting. During the development of the western branch of the East African Rift System the Zualane Graben suffered an eastward horizontal displacement of approximately 20 km and was split into two segments, the Southern and Northern Zualane Graben. A stratigraphic comparison of the Zualane, Mazenga and Xai-Xai grabens revealed that all three were affected by multiple rifting events. This suggests that the grabens developed along a potential paleo Late Jurassic rifting axis, which has a N-S orientation, located along the eastern margin of the Mozambique Coastal Plains. Oil inclusions and gas shows were reported from two wells of the drill sites, and recent gas discoveries in the neighboring PT5-C concession, indicate that matured source rocks do exist in the study area or in the vicinity.
This study presents the first comprehensive chronostratigraphic framework for the Miocene sediments in the entire Ulleung Basin by integrating zircon U-Pb geochronology, seismic stratigraphy, and petrophysical analyses. The comparison between zircon dating and biostratigraphic constraints enhances the precision of stratigraphic correlations. Total eight maximum depositional ages derived from conventional and sidewall cores from the basin provide refined temporal resolution for key stratigraphic units, enabling a more accurate reconstruction of sedimentary processes and basin evolution during the Miocene. Petrophysical analyses along the synchronous horizons of maximum depositional ages reveal significant variations in shale volume, effective porosity, and Net-to-Gross ratio, reflecting the influence of depositional environments and diagenetic modifications on rock properties. In particular, porosity variations are predominantly influenced by depositional ages and environments as well as burial diagenesis. The results of this study enhance our understanding of the geological history and resource potential in the Ulleung Basin, serving as a foundation for future research on regional stratigraphy, hydrocarbon exploration, and reservoir characterization. Furthermore, this study highlights the importance of integrating high-resolution geochronological methods with petrophysical evaluations to enhance assessments of hydrocarbon resources and CO2 storage capacity.
Pre-salt reservoir quality prediction is a complex task that demands alternative studies to better estimate its physical properties. The Barra Velha Formation (Aptian) in the Sapinho & aacute; field, Santos Basin, presents carbonate rocks with a high degree of heterogeneity in their lateral and vertical distributions. Wells are confined mostly to the structural high area, and the seismic lacks vertical resolution; thus, forward stratigraphic modeling can be a good alternative to represent this complex depositional system at a sub-seismic scale. The simulation was performed in the software StratBR, a stratigraphic forward-modeling software developed by Petrobras that performs rule-based simulations. The simulation consisted of 200 time steps ranging from the base of the Barra Velha Formation (123 Ma) to its upper limit at the salt base (113 Ma). Water depth and wave energy were used as proxies for facies association distribution, filling the available depositional space for each time step, calculated by the backstripping method. This simulated facies association model was then used to calculate porosity properties with the fuzzy method, using each facies association porosity distribution and patterns of spatial porosity variation as inputs. The facies association model is compatible with the geometry and depositional patterns observed in the seismic, with a mean well accuracy of 56.28%. The porosity model reproduced spatial property changes, both laterally and vertically, throughout the study area. Both models operate at sub-seismic scale and provide complementary results for the characterization and prediction of essential properties in future oil and gas exploratory prospects.
Understanding the occurrence and enrichment mechanisms of shale oil is essential for the effective exploration of continental basins with complex reservoir characteristics. In this study, an integrated approach combining nuclear magnetic resonance (NMR) with fluid restoration techniques, Rock-Eval pyrolysis, total organic carbon (TOC) analysis, X-ray diffraction (XRD), crude oil composition analysis, and microscopic observation was used to investigate the shale in the Erennaoer Depression of the Erlian Basin. Based on the innovative in-situ fluid content characterization method, the shale micromigration characteristics were quantitatively analyzed by micromigrated hydrocarbons (Delta Q). The coupling relationship between shale pore fluid content, pore structure, and mineral composition was analyzed, elucidating the shale pore fluid occurrence mechanisms. Three dominant shale lithofacies, felsic-rich, felsic, and calcareous, were identified, with interparticle pores at quartz grain edges serving as the primary storage space. Shale oil occurrence is jointly governed by lithofacies, pore structure, and hydrocarbon micromigration. While most samples exhibit minimal micromigration (-200 mg/g TOC < Delta Q < 107 mg/g TOC), interlaminar redistribution is common. In organic-lean shales (TOC < 0.7 %), hydrocarbon generation capacity limits oil content, and no extra-micromigration occurs. In organic-rich shales (TOC >0.7 %), excess hydrocarbons are expelled and stored in interparticle pores of quartz laminae, with free oil content positively correlated with the development of meso- to macropores. Notably, felsic-rich shales with low clay content show evidence of intra-micromigration and preferential accumulation of light-saturated hydrocarbons (C-14-C-18), resulting in Delta Q < -200 mg/g TOC, OSI > 200 mg/g TOC, and T-max < 425 degrees C. These hydrocarbons form multi-scale source-reservoir coupling systems through selective micromigration into adjacent quartz laminae and felsic-rich shale interbeds with low clay, while heavier fractions remain in organic-rich layers. These findings provide new insights into the spatial distribution of shale oil and identify favorable sweet spots in the Erlian Basin, offering a foundation for resource assessment and development strategies in similar shale oil basins.
This study evaluates the source rock potential, organic matter input, and depositional environments of Mioceneaged sediments in the eastern Nordic Seas. It focuses on ODP/IODP Sites 909, 985, and U1572, two exploration wells (7316/5-1 and 6608/10-1), and oil seeps offshore western Svalbard. Integrated marine palynological, biomarker, and geochemical analyses indicate a mainly Early to Middle Miocene age and a mixed terrestrialmarine origin of the sedimentary organic matter and associated oil seeps. Angiosperm-derived biomarkers, especially triterpenoids like oleananes and oleanenes, are abundant and help link seeping oils to deltaic terrestrial sources. Depositional settings ranged from oxic in the Fram Strait (Hole 909C) to dysoxic or anoxic in southern Sites (Holes 985A and U1572B), influenced by the semi-enclosed Nordic Seas. Geochemical indicators such as sulfur content, TOC/S ratios, and Pr/Ph values reflect variations in bottom water oxygenation and sediment conditions. Terrestrial organic input is linked to Miocene deltaic systems, likely formed by tectonic uplift in East Greenland, the Barents Sea, and central Norway. Basin modeling in the southwestern Barents Sea, using seismic and well data, shows that Miocene source rocks have reached maturity levels sufficient for hydrocarbon generation, especially beneath thick Plio-Pleistocene glacial overburden. The presence of oleanene and oleanane in both boreholes and oil seeps supports the conclusion that these Miocene source rocks are regionally widespread and part of an active petroleum system.
