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.
