ABSTRACT The analysis of geological and petrophysical properties is fundamental for evaluating the heterogeneous and complex nature of carbonate reservoirs, such as those of the Brazilian subsalt. Although porosity and permeability are routinely quantified at the core scale, the relationship between pore geometry and these properties remains complex and highly variable in carbonate systems. This study investigates how pore-scale geometric attributes derived from thin sections relate to porosity and permeability measured in corresponding core plugs from the Barra Velha Formation, Santos Basin. Digital image analysis (DIA) was applied to 355 blue-epoxy–impregnated thin sections to quantify total optical porosity (TOP) and pore geometry parameters, including aspect ratio, gamma (circularity), pore structure complexity (perimeter over area [PoA]), and dominant pore size (DomSize). Facies (F1–F5) and pore types were identified qualitatively to support geological interpretation, and routine core analyses were obtained from 304 core-plug samples. Permeability was initially estimated using the Kozeny equation and subsequently refined through facies-specific multivariate linear regression (MLR) models incorporating TOP and geometric parameters. The results indicate that facies F1, F2, and F4 exhibit higher porosity and permeability associated with interparticle and vuggy pore systems, whereas facies F3 and F5 display lower permeability linked to intraparticle and moldic pores and stronger diagenetic modification. Silicification locally reduces porosity, while, in some cases, increasing DomSize through selective dissolution. Overall, permeability is primarily controlled by DomSize and PoA. Facies-specific MLR models significantly outperform Kozeny-based estimates, highlighting the potential of DIA as a cost-effective tool for core-scale reservoir characterization in complex carbonate reservoirs.
Abstract Carbonate sediments record both environmental conditions during deposition along with secondary diagenetic processes. This study investigates how basin restriction, meteoric fluids, and other diagenetic processes contribute to the resulting sediment chemistry and porosity in the Grayburg-San Andres (GRBG-SADR) redisposal reservoir in the Midland Basin of West Texas. Two cores with locations selected in shelfal versus basinal sedimentary environments were described and analyzed for their stable isotope values of carbon and oxygen (δ13Ccarb, δ18Ocarb), chromium-reducible sulfur (δ34SCRS), water-soluble sulfate (δ34SWSS), and of carbonate-associated sulfate (δ34SCAS). Together with mineralogy and lithofacies, the data support a conceptual model for water flow dynamics that suggest an anti-estuarine basin setting for the Midland Basin. Our study shows that the combination of arid climatic conditions, high biologic productivity, and restricted oceanographic setting in the equatorial Midland Basin led to basin-wide δ13C increase of up to +3 ‰. The low δ34Spyr mean value of -29.4 ‰ in deep water deposits indicates open-system conditions for sulfur cycling, implying a sluggish thermohaline circulation did not lead to the development of a stagnant anoxic bottom water layer. Instead, water circulation proceeded and ensured continuous input of oxygenated open marine water. As a result, dissolved sulfate in the basin recorded an open marine δ34S signal of +10 ‰ to +12 ‰. The combination of carbonate mineralogy, post-depositional dolomitization, phase-dependent carbonate dissolution, and meteoric alteration of strata resulted in high porosity (reservoir quality), a significant contributing factor for why the GRBG-SADR Formations are a target for saltwater disposal in the Midland Basin of West Texas.
Abstract The topic of shale petroleum systems holds significant prominence within the international petroleum industry. Lithofacies analysis provides a fundamental basis for understanding shale heterogeneity and identifying favorable exploration targets. However, the coexistence of multiple lithofacies classification schemes has hindered the comparability of results and constrained the development of a unified understanding of lithofacies diversity across different shale systems. Herein, we select shales from three distinct sedimentary systems (marine, marine-continental transitional, and lacustrine) in the two boreholes in the Sichuan Basin as our focal subjects. The lithofacies diversity of the shales has been captured based on mineralogy, TOC content, and sedimentary texture. The type of favorable exploration lithofacies (lithofacies assemblages) are summarized. Our results underscore that 12 lithofacies are identified within the three shale systems. The pore systems of different sets of shales are diverse, organic matter associated pores dominate the pore system of the shales of the Longmaxi formation. By contrast, clay mineral-associated pores dominate the shales of the Longtan formation and the Da’anzhai member. For the physical properties of the Longmaxi formation, the TOC content emerges as the major driver for pore development. Although TOC content does influence the Longtan formation and the Da’anzhai member shales, the clay mineral content remains the main influence on pore development. When integrating storage capacity, hydrocarbon content, and mineral composition, the laminated organic-rich siliceous shale within the Longmaxi formation emerges as the most promising exploration lithofacies. In the Longtan formation and the Da’anzhai member, the lithofacies assemblages constituted by organic-rich argillaceous shale interspersed with adjacent sandstones or carbonate interlayers emerge as favorable exploration targets. This study represents an attempt to describe lithofacies diversity across various shale systems using a unified lithofacies classification framework. The results enhance our understanding of lithofacies heterogeneity within the shale systems of the Sichuan Basin and provide theoretical support for future hydrocarbon exploration. Furthermore, this work offers a framework for systematically characterizing shale system heterogeneity, serving as a valuable reference for shale exploration in petroliferous basins worldwide.
ABSTRACT Astronomically forced climate cycles and hyperpycnal flow deposits are the forefront of contemporary geological research. Climate significantly influences the formation of hyperpycnal flows, with these changes being driven by astronomical cycles. However, the relationship between astronomical cycles and hyperpycnal flows has not been sufficiently explored. Additionally, although hyperpycnal flows can transport terrigenous clastic particles to the deep-water areas of basins, their impact on organic matter enrichment remains inadequately studied. Therefore, this study analyzed the characteristics of hyperpycnal flow deposits within the Chang 7 Oil Member (Chang 7 Member) in the southern Ordos Basin, assessed their frequency of occurrence, and investigated their correlation with long-eccentricity cycles. By examining the geochemical signatures and sedimentary accumulation rates (SARs) of different genetic types of deposits, this study also explored the controlling factors of hyperpycnal flows on organic matter enrichment. The analysis indicates that hyperpycnal flows within the Chang 7 Member exhibit periodic development, significantly influenced by long-eccentricity cycles. Hyperpycnal flows not only transport nutrients into the lake basin but also increase SARs, thereby facilitating the rapid burial of organic matter and promoting its enrichment. These findings underscore the significant role of astronomical cycles in governing the development of hyperpycnal flows and highlight their positive influence on organic matter enrichment.
ABSTRACT We introduce a new rule-based algorithm called GEOPARD, which models shoreface deposits by following geological principles. In this algorithm, the outcomes of geological processes are represented as rules that are integrated into the core of a standard geostatistical modeling framework. The GEOPARD builds on the stochastic object-based facies modeling technique and incorporates a Bayesian framework for conditioning to data and reducing uncertainty. This paper outlines the geological prior model of the GEOPARD algorithm, which generates facies geometries and controls object placement using geological rules. Specifically, the algorithm builds up a parasequence by stacking a succession of prograding shoreface bedsets, bounded by small-scale hiatus, until a final point of maximum shoreline advance. Model parametrization closely follows the geological conceptual model. The rules are implemented as a series of fully automated modeling steps, mapping the wide variety of facies geometries typically associated with shallow-marine deposits. The functionality of GEOPARD is demonstrated through a series of scenarios, including the reproduction of features observed in an outcrop analogue and benchmarking against the truncated Gaussian simulation method. Key modeled features include sand-body thickness, lateral extent of facies, overall parasequence geometry, and the spacing and dip of bedset bounding surfaces.
