ABSTRACT Early carbonate cement is common and widely distributed in clastic rocks and has a complex impact on the quality of clastic reservoirs. At present, although there are studies indicating that early formation of carbonate cement can protect reservoirs to a certain extent, there is no empirical evidence to prove it. Early carbonate is the most abundant cement in the Cretaceous continental ultradeep clastic sandstone in the Kuqa depression. The petrographic characteristics, spatial distribution, and geochemical characteristics of early carbonate cements in the Cretaceous sandstone reservoir are systematically investigated to discuss the origin, distinct distribution, and multifaceted impact on ultradeep clastic reservoirs. During the early Paleogene, meteoric water leached the Paleogene carbonate rocks, providing material for early carbonate cements. Affected by lateral recharge of meteoric water, the vertical recharge of seawater, and the normal-graded sequence, early calcite and dolomite cements with significantly spatial different distribution characteristics were precipitated in the ultradeep clastic reservoirs. Due to the differences in the content and compaction resistance of early calcite and dolomite, their impact on reservoir quality is opposite. Early calcite occupies the reservoir space to varying degrees and has weak compaction resistance, seriously damaging the reservoir quality. Early dolomite has a relatively low content and strong compaction resistance, which can effectively protect the reservoir during deep burial and strong lateral compression processes. This study provides a good example of the positive effect of early carbonate cements on the formation and development of high-quality reservoirs.

ABSTRACT The Greasy Ridge oil field of southern Ohio is an anomaly because of its accidental discovery and geographic isolation from other oil fields in the Lower–Middle Pennsylvanian Pottsville, New River, and Lee Sandstone play. This study examines its origin within the context of the Devonian shale–middle–upper Paleozoic petroleum system using a robust data set, including geophysical well logs, cores, seismic profiles, and nearby correlative outcrops. Deposition of the reservoir sand occurred under fluvial and tidal influence in distributary channels of a southwest-prograding, tide-dominated delta. Outcrop analogues reveal northeast, southwest, and bipolar paleocurrents. Reservoir facies occur in the highstand systems tract of a fourth-order (cyclothemic) depositional sequence. Petrographic analysis indicates it consists of fine-grained quartz arenite-sublitharenite, with most porosity formed by mesogenetic dissolution of feldspar and carbonates. Reservoir heterogeneity results from variations in shale content and secondary porosity. The main source rock was the lower Huron Shale Member, which underlies the field. The Betsie Shale formed a seal. The combination trap resulted from the coincidence of channel sandstone facies with two positive flower structures and structural closure produced by Permian wrench faulting and updip change to impervious, delta plain facies. Seismic profiles indicate two basement faults beneath the flower structures paralleling the Rome trough. The critical moment for generation, migration, and hydrocarbon entrapment occurred during the Early Triassic. These findings differ from earlier studies and should be helpful in discovering and developing other oil fields in Pennsylvanian strata along the basin margin and elsewhere in similar settings.

ABSTRACT Assessing fracture network connectivity in reservoirs remains challenging because of the complexity of fracture networks at various length scales. Outcrop studies are essential for understanding subsurface fracture networks because intersecting fracture sheets’ length, orientation, height distribution, and, therefore, network connectivity and intensity are difficult to measure from wellbores and are typically below seismic resolution. Nevertheless, fracture network connectivity is a crucial parameter and a critical factor in understanding, evaluating, and predicting fluid flow behavior in numerous industries, including petroleum, geothermal, and geological disposal. Although using topology to assess the connectivity of fracture networks has recently gained popularity in structural geology, no study has been conducted to investigate the impact of textural variation on the connectivity of fractured carbonates. This contribution aims to use the fracture network topology (nodes, branches, and lines) at outcrop scale to assess the connectivity and intensity of fracture networks in different carbonate textures from the Ozark Plateau, Arkansas. We used thin sections to determine the type of carbonate texture using the Dunham classification scheme, allowing us to compare the connectivity and intensity of fracture networks to carbonate texture. Results show that mud-supported carbonate textures have higher connectivity and intensity than grain-supported carbonates. The variation in connectivity is due to the variation in the percentage of connected nodes and branches in the carbonate type. Results of this study show that topology is an effective method to assess the impact of textural variation on the connectivity and intensity of fractured carbonates.

ABSTRACT Asphaltene is important for hydrocarbon generation and source correlation. In this study, we compared the pyrolysis yields and phase kinetic differences of a pair of Qianjiang shale samples previously classified as source-rock and hybrid source-reservoir samples, respectively. A novel technique, thermovaporization/pyrolysis two-dimensional gas chromatography time-of-flight mass spectrometry (Tvap/Py-GC×GC-TOF-MS), was developed for source correlation purposes. This technique identified significant differences in the overall composition of pyrolysis yields from asphaltenes, resins, and thermally extractable free petroleum; therefore, asphaltene pyrolysates could not be readily correlated to those of resins or free petroleum. However, closer examination of covalently bound steranes and terpanes from resin pyrolysates revealed a high correlation between the genetically paired reservoir and source-rock samples. Given that asphaltene is the petroleum fraction least overprinted by migrated oil, its covalently bound biomarkers are likely diagnostic of its real source input. Thus, Tvap/Py-GC×GC-TOF-MS can effectively identify nonindigenous petroleum. Because fractionation led to the migrated resins and asphaltenes being less polar, progressive cracking of the migrated petroleum in the reservoir occurred with greater thermal stress than expected in the source rock. More important, the hydrocarbon generation potential of polar fractions was greater than that of kerogen in the Qianjiang shale samples. Therefore, the use of whole-rock samples rather than solvent-extracted rocks is recommended for kinetic measurements of hypersaline source rocks.

ABSTRACT Crystalline rocks underlying basins, with their lack of primary porosity, are unconventional traps for hydrocarbon exploration. The Bozhong (BZ) 19-6 large gas field in the Bohai Bay Basin, China, is a rare, newly discovered, deep-buried crystalline basement play with a productive zone of more than 1000 m, which provides an excellent opportunity to investigate the formation mechanisms for this large-scale reservoir. For the BZ19-6 field, the tectonic compression during the Triassic Indosinian Orogeny movements induced east-west–trending fractures. A high abundance of these fractures, which have the highest density in the hinge zone of the thrust fold, is the prerequisite condition for the formation of the huge reservoir. Later, during the Cenozoic extensional episode, many of these fractures reopened or were enhanced to create storage spaces. The probability of fracture generation is mineral dependent, in which the metamorphic granite with felsic minerals exceeding 70% tends to be more brittle and forms a higher density of fractures. Before the Cenozoic, the basement had undergone an episode of exposure to subaerial and vadose weathering. The upper portion of this unconventional secondary reservoir, generally within 300 m below the exposure-caused unconformity, is optimized by the feldspathoid dissolution due to depth-dependence weathering. However, the space created by fractures is significant down to a depth of up to 1000 m below the unconformity. It is important to note that, due to the natural compaction resistance of the crystalline rocks, the fracture-related secondary spaces in the basement are conducive to being maintained independent of the later depth of burial.

ABSTRACT We used new ocean-bottom-node seismic data to obtain high-resolution images of a gas-bearing structure that holds one of China’s largest offshore gas reservoirs in the South China Sea. This structure, Dongfang 1-1, comprises clustered high-angle fractures in Miocene source rock intervals, with minimal disruption to stratigraphic layering. Seismic reflections within the structure are continuous without indicators of massive mud intrusion into the overlying sediments; therefore, a mud diapir model is unlikely to be applicable. We interpret that this structure formed from coalescing hydraulic fractures during upward propagation, driven by fluid overpressure from natural gas generation. These fracture networks serve as highly efficient pathways for gas-bearing fluids to bypass the 660-m-thick sealing sequences and accumulate in the Pliocene structural trap. Our results provide new insights into the formation mechanism of the Dongfang 1-1 structure and an exciting opportunity for further exploration of subsurface fluid migration in deep overpressured strata.