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.
Abstract The Amu Darya Basin (ADB) is a large hydrocarbon-bearing basin in Central Asia, distributed mainly in Turkmenistan and Uzbekistan. The Middle–Upper Jurassic succession is considered a potential source rock; however, its hydrocarbon generation potential remains controversial due to the generally low TOC values. This study examines the geochemical characteristics of source rocks from different lithofacies in the Middle-Upper Jurassic Callovian-Oxfordian strata of the ADB. Through geochemical analysis of drill cores, stratigraphic correlation, and basin modeling, high-quality source rocks in lagoonal facies were identified. This study investigates the formation environment of the source rocks and their significance for hydrocarbon exploration in the ADB. The results of this study reveal that the lagoon facies mudstone is the only effective source rock in the Callovian-Oxfordian strata. It is characterized by high organic matter content, with a maximum TOC of 6.35 wt.%, type II₁ kerogen, and maturity primarily within the oil window. In contrast, carbonate platform facies limestones and carbonate ramp facies argillaceous limestones generally have low organic content and cannot be considered effective source rocks. Kerogen maceral analysis, combined with sterane and terpane biomarker data, indicates that the organic matter in the high-quality lagoon facies source rocks of the ADB primarily originate from marine bacteria and algae, with minimal terrestrial organic matter input. However, the enriched carbon isotope values of the kerogen, along with relatively low hydrogen index and H/C atomic ratios, suggest that macrobenthic algae are the predominant source. The source rocks exhibits abnormally high pregnane and dibenzothiophene contents, and the characteristics of Pr/nC17 and Ph/nC18 indicate that development was in a shallow water environment with high salinity and weakly reducing conditions. The high-quality source rocks in the northeastern margin of the ADB began to generate oil in the early Late Cretaceous, matured in the late Cretaceous and early Paleogene, and are currently at peak of oil generation. The source rocks may therefore be a source of liquid oil, but not a direct source of gas condensate. The lagoon facies high-quality source rocks have formed two key reservoir-controlling models: hydrocarbon generation from overlying source rocks with downward migration into underlying reservoirs and lateral generation with lateral migration. These findings highlight the lagoon facies mudstone layer and high of the paleostructure around should be regarded as favorable exploration targets for oil in the ADB. These findings not only provide geological evidence for liquid hydrocarbon exploration in the Amu Darya Basin but also offer a model for predicting source rocks.
ABSTRACT Quaternary sequence stratigraphy, supported by an exceptional abundance of proxy data and well-constrained boundary conditions, provides an unprecedented opportunity to bridge the gap between quantified modern processes and the interpretation of the ancient sedimentary record. High-resolution subsurface data sets capture the complex interplay between sea-level changes and tectonic activity at subseismic scales, with temporal resolutions rarely achievable in older strata, revealing a largely unexplored hierarchy of hiatal surfaces and condensed intervals spanning 102- to 104-yr timescales within stratigraphic successions generally assumed to be continuous. Quaternary sequence stratigraphy not only provides a robust chronostratigraphic framework to serve as the basis for paleogeographic maps, but also delivers accurate three-dimensional reconstructions of shallow-subsurface stratigraphic architecture. Beyond its traditional applications in hydrocarbon exploration, Quaternary data sets support a wide range of practical applications, including carbon capture and storage site selection, groundwater reservoir characterization, reconstruction of contaminant migration pathways, seismic-hazard assessment, and infrastructure development, demonstrating their relevance for both geoscience research and societal challenges. GRAPHICAL ABSTRACT Graphical abstract titled Four panels. Panel A is labeled Alluvial plain. The vertical axis ranges from 0 meters to about 100 meters. Several channel shaped sediment bodies occur within layered deposits. The channels are labeled M I S 2, M I S 6, M I S 8, and M I S 5e. Groundwater emerges at the surface. Panel B is also labeled Alluvial plain. The vertical axis ranges from 0 meters to about 40 meters. A gas pump is shown on the ground surface above an incised channel. A vehicle appears beside an excavation that exposes layered deposits. The label M I S 3 slash 2 paleosol appears below the surface. Panel C is labeled Coastal plain. The vertical axis ranges from 0 meters to about 40 meters. A channel shaped depression is filled with sediment. The labels T S T, F S S T, and L S T appear within the section. Wavy vertical lines rise from below the surface and are labeled seismic waves. Panel D is labeled Shelf. The vertical axis extends from 0 meters at the top to 70 meters at the bottom. A sloping sediment body on the left contains the label H S T. Three wind turbines stand on the shelf surface near the center. A thin horizontal layer extends across the section below the water surface. An arrow points to this layer and labels it Condensed section. On the right, layered sediment units overlie bedrock. The upper unit is labeled T S T. The lower unit is labeled L S T. A fish appears in the water near the upper right corner.
ABSTRACT Hydrocarbon production from the Mississippian Caney Shale, Ardmore Basin, is highly influenced by the heterogeneous rock physical properties. This research aims to establish a petrographic model to better understand the potential diagenetic pathways and evolution of bulk physical properties among different lithologies in the Caney Shale. The lithological variation, primary grain assemblages, diagenetic features, and evolution of bulk petrophysical properties were investigated based on detailed petrographic, geochemical, and petrophysical analysis of 93 core plug samples. The results suggest that the Caney Shale comprises five major lithologies: massive argillaceous mudstone, planar-laminated argillaceous mudstone, planar-laminated siliceous mudstone, massive calcareous mudstone, and massive to wavy-laminated wackestone and packstone. The primary grains in massive argillaceous mudstone are extremely terrigenous-rich (82 to 95 vol. %), whereas variable content of biogenic carbonate or silica allochems can be observed from the other four lithologies. The variations of grain components (extrabasinal versus intrabasinal) among different lithologies are likely caused by periodic sea level changes and the relative distance to the provenance. Due to this variation in grain assemblage composition, the sample suite displays a corresponding evolution in diagenetic variety and petrophysical properties. Massive argillaceous mudstone dominated by extrabasinal grains underwent intense mechanical compaction, resulting in low bulk porosity and permeability, whereas samples from other lithologies with greater amounts of intrabasinal grains underwent considerable cementation, resulting in variable but overall higher porosity and permeability. This study provides an example of new perspectives for linking micrometer-scale petrographic features to the evolution of bulk physical properties in shale.
ABSTRACT With the gradual depletion of oil and gas resources in shallower strata (<4000 m), exploration toward ultradeep strata (>6000 m) is becoming inevitable. Recent 10,000-m drilling projects in China highlight the petroleum accumulation and enrichment model and reserve potential in ultradeep strata of cratonic basins. This study systematically summarizes 10,000-m deep petroleum geology model, based on recent research progress and exploration discoveries. The lower limit of liquid petroleum preservation depth in basins with low-geothermal gradient (e.g., Tarim Basin with 19.6°C/km) can reach 9000 m, breaking through conventional understanding of a 6000-m depth limit. Different hydrocarbon compounds exhibit distinct thermal stability in that saturated hydrocarbons are more resistant to cracking than aromatic hydrocarbons, whereas diamondoids accumulate during oil cracking and serve as reliable maturity markers. Recent ultradeep drilling confirms this expanded exploration potential. The research reveals preservation mechanisms for paleo oil pools (250 Ma hydrocarbon accumulation age) and gas pools (100 Ma hydrocarbon accumulation age), and thus redefines the ultimate lifespan of oil/gas pools. Experimental simulations have shown that caves and pores are influenced by only lithostatic pressure and can remain even at depths of 75,000 m, carbonate reservoirs therefore have no firmed depth limit. The flow and migration of hydrocarbon fluids in ultradeep strata differ significantly from the buoyancy-driven models in middle to shallow strata. These processes do not fully follow the buoyancy differentiation law and feature multioil-water interfaces in fracture-cavity type reservoirs. Flow and occurrence model of hydrocarbon fluids in heterogeneous reservoirs has thus been established, introducing the concept of large-area stratified cavity-fracture type bead-like pools without unified oil-water contacts. Ultradeep petroleum exploration has revealed oil fields with nearly 1000-m-high oil columns and a series of wells producing up to 1000 metric tons of oil per day (7330 BOPD), challenging traditional theories of petroleum accumulation that focus on high points of traps. These findings provide theoretical support for significant discoveries and strategic changes in ultradeep petroleum exploration and expand petroleum exploration space up to 10,000 m deep.
ABSTRACT Understanding reservoir fluid overpressure evolution is vital for characterizing petroleum accumulation and preservation in deeply buried reservoirs. This study integrates petrography, fluid inclusion (FI) microthermometry, Raman spectroscopy, thermodynamics, and basin modeling to constrain the diagenetic fluid history of the Ediacaran Dengying Formation, Sichuan Basin, South China. Petrographic observations reveal a complex cementation sequence from early calcite 1 and dolomite 1 to late-stage quartz and fluorite. In situ U-Pb dating of FI-hosted dolomite 2 (232.9 ± 7.4 Ma) identifies a 60-bar overpressure buildup during rapid late Permian burial. Intense peak overpressure (360–690 bar) occurred during quartz and fluorite precipitation under the Yanshanian compression regime, supported by fluorite dating of 106.8 ± 7.5 Ma. At trapping temperatures exceeding 200°C, thermochemical sulfate reduction (TSR) and oil cracking were responsible for fluid expansion and intense overpressure buildup. Since the Paleogene, major tectonic uplift and fluid drainage have caused overpressure to decrease from 367 to 0 bar. This integrated microscale–macroscale workflow links tectonic events to pore-fluid processes with global universality. The Triassic rifting triggered rapid source rock maturation and oil cracking, a mechanism that is highly similar to that of the Aquitaine Basin, France. Commonalities in methane reserves and H2S content between these basins suggest an intrinsic coupling between rapid maturation and TSR. Furthermore, the significant pressure attenuation observed implies that hydrocarbons may have remigrated to adjacent undiscovered reservoirs rather than simply leaking, offering a strategic new direction for deep-seated petroleum exploration deployment.
Abstract Marine dolomite reservoirs in the Sichuan Basin are key targets for gas exploration, yet their genetic types and impact on pore systems remain unclear. This study employs an integrated approach, combining petrological, geochemical (C-O-Sr isotopes, Fe-Mn trace elements), and petrophysical analyses to investigate the origins of dolomite and associated reservoir quality variations. Results reveal three primary genetic types: microbial, metasomatic, and hydrothermal. Metasomatic dolomite includes sub-types formed by evaporative reflux (from concentrated seawater brines), shallow-medium, and medium-deep burial sub-types (from Mg2+-enriched formation waters). Hydrothermal dolomite originates from Mg2+-enriched hydrothermal fluids or brines. Dolomitization impacts reservoir porosity-permeability both constructively and destructively. Early dolomitization preserves pores due to dolomite’s compaction resistance. Dolomites preserving original structures retain abundant existing pores, while dissolution-enlarged pores associated with post-dolomitization fluids significantly enhance reservoir capacity. Intercrystalline pores improve pore-throat connectivity, while dolomite’s brittleness promotes fracture development, boosting permeability. Conversely, over-dolomitization can destroy reservoir porosity-permeability. Penecontemporaneous granular cements may fill intergranular and intercrystalline pores, whereas burial-hydrothermal cementation occludes caves and fissures. Saddle dolomites can precipitate along faults or unconformities, often degrading reservoir space by filling fractures or dissolution pores. The study clarifies marine dolomite classification and reservoir characteristics in the Sichuan Basin, guiding further hydrocarbon exploration there.
Subsurface modeling is essential for characterizing resources such as hydrocarbon reservoirs, aquifers, mining ore bodies, and carbon sequestration sites, which is crucial for resource management amid uncertainty. Traditional geostatistical methods, while effective, face challenges in capturing the complexity of subsurface features, particularly in deepwater depositional systems where geological heterogeneity is significant. Recent advancements in machine learning (ML), including generative adversarial networks (GANs) and conditional GANs techniques, have shown promise in improving subsurface models by incorporating geological information and spatial patterns. However, the performance of ML models depends on high-quality training datasets, which are currently limited, especially for deepwater settings. To address this, we propose an open-source Python package, GeoRulesLobePy, for generating rule-based deepwater training images that integrate geological observations with Markov and morpho-dynamic rules. This package is designed to be user-friendly, computationally efficient, and capable of producing realistic geological models. GeoRulesLobePy simulates deepwater depositional processes by sequentially placing lobe elements within a 3D grid, following rules for geometry, stacking patterns, and facies trends. The methodology ensures that the generated models capture the hierarchical and heterogeneous nature of deepwater lobe complexes, making them suitable for training ML algorithms. This package was tested using scenarios from the Golo system in Corsica, France, and the Tanqua Karoo basin in South Africa, demonstrating its versatility and capability to produce realistic subsurface models. By providing an open-source tool for generating complex, rule-based training datasets, GeoRulesLobePy offers a tool for geoscientist to visualize their 2D observations in 3D, and creates a vast training data set for ML purposes..
ABSTRACT We present calculations of calcite solubility as a function of temperature from 50°C to 200°C (122°F to 392°F) using the trends of partial pressure of CO2 and salinity with temperatures typical of many petroleum-producing basins. These results are presented within the framework of a general review of what is known about subsurface calcite solubility and how this applies to processes of both burial cementation and dissolution causing changes in the porosity of petroleum reservoirs. Unlike quartz and most other common minerals, calcite has retrograde solubility (increasing with decreasing temperature) at constant p(CO2) and salinity, but the observed trends of basinal increase of these parameters with depth result in an overall positive correlation of calcite solubility with temperatures at >50°C. Nevertheless, retrograde solubility can still result in carbonate dissolution if water moves upward to lower temperatures while maintaining its composition, as might occur by flow along a fracture having nonreactive (carbonate-free) surfaces. This provides a plausible explanation for how the porosity of both carbonate and sandstone reservoirs can be increased by mesogenetic dissolution, but such situations may be exceptional rather than widespread. Various other proposed mechanisms for reservoir porosity increase by mesogenetic dissolution of carbonates are either implausible or limited to special local conditions that are unlikely to occur generally in petroleum basins. The example of burial karst in the deeper flanks of the Tengiz field (Kazakhstan) nevertheless shows that major burial dissolution is possible, although the mechanism for this is obscure.
Chinese offshore basins produced more than 1.6 million bbl of oil equivalent per day in 2024. They represent one of the largest offshore oil and gas production bases in the world and are a significant contributor to provide energy to fuel China's economic growth. This achievement has come from more than four decades of exploration and development efforts, led by China National Offshore Oil Company, in addition to Sinopec, China National Petroleum Corporation, and many international oil companies. There are seven Chinese offshore basins, including the Bohai Bay, South Yellow Sea, East China Sea, Pearl River Mouth, Qiongdongnan, Beibu Gulf, and Yinggehai. These offshore basins form a Cenozoic hydrocarbon complex, the evolution of which was driven by multiplate interactions. This study synthesizes decades of exploration achievements to elucidate genetic links and interactions between the Eurasian, Pacific, and Indo-Australian plates, leading to the development of continental rifts, back-arc and strike-slip basins. This tectonic framework controlled a strong spatial-temporal differentiation of petroleum systems. Eocene lacustrine shales form the primary oil-prone source rocks, whereas Oligocene-Miocene paralic strata are predominantly gas-prone. Consequently, hydrocarbon distribution is distinctly partitioned, with oil prevailing in the Bohai Bay Basin and shallow-water northern South China Sea, and natural gas dominating the East China Sea Basin, Yinggehai Basin, and deep-water of the northern South China Sea. Understanding the geological evolution history has been pivotal to the success of hydrocarbon discoveries and development in these Chinese offshore basins and can hopefully provide some lessons for oil and gas exploration and exploitation for other offshore basins around the world. (see the Graphical Abstract below)
Determining the sources of methane for hydrate formation critical to hydrate exploration and to understanding its implications for the global carbon cycle, climate change, ocean chemistry, and biosphere throughout Earth's history. However, quantifying the gas sources for ancient hydrate records presents a considerable challenge due to the absence of direct evidence. Authigenic carbonates (AC), formed through the anaerobic oxidation of methane (AOM), have partially retained the S13C signature of ancient hydrates, providing a unique opportunity to identify their gas sources. In this study, we simulate the variations in S13C values of AC precipitation associated with AOM under different AOM rates and specific methane source scenarios. Our findings suggest that the observed changes in S13CAC with heavy S18OAC (mostly ?2.0%o to 7.7%o) across global compilations associated with AOM are best explained by varying ratios of biogenic methane (BM) versus thermogenic methane (TM) and differences in AOM rates. Furthermore, our analysis indicates that TM contributions at half of the investigated gas hydrate seeps range from 17.3% to 81.5% (average 47.1%; n = 3) by volume. The compiled ages, coinciding with S13C values of AC, suggest that amplified methane release, associated with an increased contribution from TM at high AOM rates, preferentially occurred during interglacial periods over the past 150,000 yr. The previously underestimated role of TM, and its likely positive feedback in global warming, calls for a reevaluation of the impact of methane seeps on Earth's carbon cycle and climate through time.
Faults in porous sandstone were previously considered ill-suited for sealing hydrocarbons, which resulted in many promising fault-related hydrocarbon exploration targets being overlooked. This study investigates the sealing properties of faults within porous sandstone in the Bozhong subbasin using well drilling data and repeat formation test pressure measurements from both sides of the faults. The results demonstrate that the faults in the porous sandstone could seal hydrocarbons, with the maximum sealable hydrocarbon column height reaching 83 m and the buoyancy pressure reaching 0.223 MPa. Owing to the low clay content (<10%), high porosity (>15%), and moderate burial depth (1-3 km) of the host rock, cataclasis associated with fault deformation may generate low-permeability cataclasite, which is regarded as the most probable sealing mechanism for faults in porous sandstone. Increased effective fault normal stress during fault movements intensifies sandstone grain cataclasis, further reducing fault permeability and enhancing the fault sealing capacity. A positive correlation was identified between fault sealable buoyancy pressure and effective fault normal stress. These findings highlight the importance of considering stress effects, in addition to clay content, when evaluating the sealing capacity of faults in sand-mudstone sequences. Neglecting the role of stress may lead to underestimation of the fault sealing potential, particularly for faults in porous sandstones. More research is needed to evaluate the sealing capacity of faults in porous sandstone. In addition, data sharing and cooperation between industry and academia should be encouraged so that, in the long run, workflows can be developed specifically for faults in porous sandstones.
Until 2012, the western Myanmar waters area was deemed unattractive for hydrocarbon exploration due to the apparent absence of a nearby large river system; hence, there was a perceived low chance of finding reservoirs. This paradigm underwent a transformative shift during the last decade, with successful hydrocarbon exploration in offshore block A-6. This tract straddles the convergent zone between the Indian plate in deep water and the Myanmar platelets in shallow water. The Pyi Thar-ST1 gas discovery, drilled in shallow water in 2012, and the ultradeep-water gas discovery wells of Shwe Yee Htun-1 and Pyi Thit-1 (tested) between 2015 and 2018 have revealed a new hydrocarbon play, including a new reservoir fairway. Our integrated interpretation of two-and three-dimensional seismic data, well logs, petrography, heavy-mineral analysis, U-Pb zircon age dating, and regional geologic context indicates that a Pliocene-Pleistocene fan system received sediment from the proto-Ayeyarwady-Chindwin river, which flowed east to west through a wide breach in the unstable continental slope of block A-6 during the Late Miocene. This depositional system formed the Pliocene-Pleistocene Western Ayeyarwady fan (WAF), which includes gas-bearing sandstone within levee-channel complex systems. This paper further shows how the WAF system was isolated from the sediment supply of the Ayeyarwady River and its delta system by a Late Pleistocene uplift, resulting in its present position.
In conventional petroleum systems, carrier beds are traditionally regarded as pathways for petroleum migration. However, petroleum geologists are increasingly recognizing the exploration significance of carrier beds as potential reservoirs, introducing the concept of the carrier bed play. Research on these plays remains in its early stages, and the controlling factors and accumulation models still require systematic investigation. The academic community also needs more representative examples to strengthen the theoretical understanding of carrier bed plays. This study focuses on the silty shale of the Qiongzhusi Formation in the Jingyan-Qianwei area in the southwestern Sichuan Basin. We identify four lithofacies in the silty shale, with sedimentary textures driving differences in physical properties. Among them, the laminated siliceous silty shale with relatively low total organic carbon (TOC) content in the middle member of the Qiongzhusi Formation functions as a carrier bed. Natural gas enrichment in this interval depends on six factors: favorable physical properties, high feldspar content (average >20%) with well-developed laminations, moderate TOC content (commonly <0.5 wt. %), sufficient natural gas supply, an effective seal-reservoir configuration, and the absence of migration pathways that connect with conventional reservoirs (e.g., faults). The successful breakthrough of carrier bed plays in the Qiongzhusi Formation of the Jingyan-Qianwei area demonstrates the broad exploration potential of shallow-water depositional systems in the southwestern and central Sichuan Basin. Future exploration should prioritize shallow-water settings with stable tectonics, limited large-scale faulting, and proximity to deep-water source rocks. A comparison with well-known North American carrier bed plays (Mancos Shale play) shows that although the accumulation mechanisms are broadly similar across different petroleum systems, each exhibits unique characteristics. More studies are therefore needed to advance systematic knowledge of carrier bed play accumulation mechanisms.
Fluid diapirs are formed through the upward intrusion of fluids along fracture zones, with hydraulic fracturing and fluid charge occurring at the uplift point of the overpressure interface. The DF1-1 diapir is the most typical fluid diapir in the Yinggehai Basin, characterized by multilayer gas accumulation. In this study, petrographic observation, laser Raman spectroscopy analysis, microthermometry, approximate calculation of fluid inclusion capture pressure and natural gas characteristics have been integrated to delineate the natural gas dynamic accumulation process and summarize the accumulation model of DF1-1 diapir. Results suggest that four episodes of natural gas charging with distinct compositions have been documented. The first two episodes, dominated by hydrocarbon gases, occurred at 3.4 to 2.9 Ma and 1.8 to 0.4 Ma, respectively. The latter two episodes were characterized by dry gas and inorganic CO2, which occurred at 0.4 to 0 Ma. The paleopressure evolution of Huangliu Formation was reconstructed following a model of "pressurization-release-pressurization." Furthermore, the coupling relationship between the formation paleopressure evolution and the natural gas charge history was elucidated. Based on these analyses, this conformed to an overpressure-controlled episodic gas accumulation model, and the accumulation process can be summarized as follows: initially, gas accumulated in deep reservoirs, with formation pressure increasing to fracture pressure, leading to diapir opening and subsequent gas loss or adjustment to shallower reservoirs along diapiric faults for further accumulation. Simultaneously, gas filled the reservoir and episodic diapir activity in the later stages resulted in rapid gas charging. This process is the primary factor contributing to the heterogeneity of gas distribution.
Total organic carbon (TOC) is essential for evaluating shale gas reservoirs and estimating hydrocarbon reserves. Laboratory TOC measurements are accurate but time-consuming, costly, and often limited to specific depths. This study evaluates rock physics models for predicting TOC in the lower Goru Formation, Lower Indus Basin, Pakistan, where core samples are unavailable. The TOC data were derived from well cuttings to identify a well-log-based method producing TOC estimates comparable to laboratory results. Compressional and shear wave velocities from well logs were used, along with petrophysical and elastic properties from logs and literature. Individual models for TOC estimation, such as Kuster and Toks & ouml;z (KT) and self-consistent approximation (SCA), showed correlations between 55% and 75%. Combining KT and SCA models significantly improved TOC estimation, achieving correlations of 90% to 98% compared to laboratory data. The TOC showed a negative correlation with compressional and shear wave velocities but no clear relation with pore geometries or shale porosity. The variability in pore geometries in shale reservoirs allows flexibility in selecting pore aspect ratios, defined as the ratio of the short to long axis of pores, ranging from zero to one in this study. This variability supports the selection of appropriate aspect ratios for TOC estimation. Statistical analysis confirms the reliability of the combined models, though their applicability may vary with geological settings. This research addresses challenges in selecting input parameters for rock physics models with limited measured TOC and provides valuable insights into TOC estimation from wire-line logs, enhancing the understanding of shale gas reservoir characterization globally.
