performance.Class I cap rocks present the best sealing capacity because they underwent intense mechanical compaction, abundant chemical compaction and calcite cementation, which contributed to the heterogeneous pore structures with poor pore connectivity.A four-stage conceptual model of pore evolution of cap rocks is presented to reveal how the diagenetic evolution of cap rocks determines the heterogeneity of their sealing capacity in carbonate reservoirs.

ABSTRACT Continental shales with abundant oil resources often have poor brittleness, which hinders their successful development. To find favorable areas for shale oil development, a comprehensive analysis of the relationships among shale oiliness, fracability, and paleoclimate was conducted for the Biyang depression, where the first breakthrough in the development of continental shale oil in China was made. A number of different analytical techniques were used, including major and trace element analyses, bulk mineralogy, and scanning electron microscopy–energy-dispersive spectroscopy–cathodoluminescence. The results reveal that the paleoclimate during the deposition of the Hetaoyuan Formation can be divided into three stages: arid, semiarid, and humid. In the arid and semiarid paleoclimate stages, water salinity and productivity were high, which resulted in shales with strong hydrocarbon generation abilities and a high degree of oiliness. In addition, the rivers had relatively limited ability to carry terrigenous detrital minerals (clay and feldspar) into the lakes. Authigenic quartz (partly from hydrothermal activity), calcite, and dolomite formation was comparatively high. Thus, the brittleness index values of the shales formed under arid and semiarid paleoclimates are high. In the shales deposited under arid and semiarid paleoclimates, cryptocrystalline/microcrystalline, authigenic quartz can be identified by its morphology, associated minerals, and cathodoluminescence. With increasing depth, the resin, asphaltene, and wax contents of the shale oil decrease and the mobility of the shale oil improves.

ABSTRACT The Upper Cretaceous Paaratte Formation, Otway Basin, Australia, is a deltaic reservoir-seal succession and currently the target for field-scale CO2 injection research experiments of the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) (now CO2CRC Ltd.) Otway Project. A relatively homogeneous ∼7-m-thick injection interval was identified for stage 2 CO2 injection experiments by analysis of wire-line and core log data. Core from above, below, and through the injection zone was sampled to quantify the effects of CO2 storage on physical and chemical heterogeneities to determine storage efficiency. The injection interval consists of two distinct yet related facies associations of a marine tract of an upper-deltaic, depositional environment. They exhibit broadly similar bulk petrophysical reservoir properties, though their mineralogy and fine-scale sedimentary fabrics differ. A dolomitic horizon above the reservoir constitutes an intraformational barrier. Early diagenetic alterations (ca. 80 Ma) occurred within distributary delta channel and mouth-bar sandstones. These alterations include formation of early authigenic clays that inhibited quartz overgrowth development while simultaneously preserving intergranular porosity. Primary dolomitic cement was precipitated from anoxic organic fluids passing through proximal, mouth-bar sandstones, along with processes such as quartz dissolution and minor kaolin precipitation until maximum burial (ca. 40 Ma). Mineralogical markers constrained the position (proximal-to-distal and lateral) within the deltaic depositional tract, and low-resolution sedimentation rates derived from palynological dating provided information to estimate the spatial scale of delta facies. Clarification of the lithological heterogeneity within the injection zone has helped to determine CO2 storage efficiency by establishing an in-depth assessment of sequence stratigraphic and depositional facies architecture.

<p>The middle Eocene Dongying sag in the Bohai Bay Basin of China has an estimated shale oil resource of approximately 1.1 billion t (8.06 billion bbl); flows of shale oil have been produced in the succession from tens of wells, where the daily production of a single well generally varies between 10 and 100 t (73.3–733 bbl). Therein, the mudrock successions composed of meter-scale mudstone–limestone couplets are the most important shale oil-producing layers. The controls on the deposition of the meter-scale mudstone–limestone couplets, however, remain enigmatic, constraining the analysis of lithofacies and, therefore, sweet spot distributions. Here, we analyze three continuously cored organic-rich successions of mudstone–limestone couplets (371 m [1217 ft] in total) in the middle Eocene Dongying sag, accompanied by decimeter- to meter-scale sampling and testing of mineralogy, organic geochemistry, and paleontology of the rocks. Our integrated cyclostratigraphic analysis shows that the observed mudstone–limestone couplets occur at periods that coincide with Milankovitch periodicities; 21-k.y. precession cycles are the main driver of the meter-scale mudstone–limestone couplets, with additional imprints of 41-k.y. obliquity cycles. Specifically, precession minima are associated with high summer insolation and consequently high summer monsoonal precipitation, which increased river discharge and terrigenous input to the basin, resulting in the deposition of siliciclastic-rich mudstones. In the study, low summer insolation during precession maxima led to decreased summer monsoonal precipitation, lower river discharge and terrigenous input, and increased lake water salinity, resulting in the deposition of authigenic lime mudstones. The shale reservoir quality kept pace with the orbital climate changes; compared with lime mudstones deposited during precession maxima, mudstones deposited during precession minima had higher total organic carbon, porosity, and oil content, but lower brittleness.</p>

Abstract The ca. 1.5–1.3 Ga Roper Group of the greater McArthur Basin is a component of one of the most extensive Precambrian hydrocarbon-bearing basins preserved in the geological record, recently assessed as of 429 million bbl oil (68 million cubic meters of oil) and between 8 and 118 TCF (222.56 billion cubic meters) of gas (in place). It was deposited in an intracratonic sea, referred to here as the McArthur-Yanliao gulf. The Velkerri Formation forms the major deep-water facies of the Roper Group. Trace metal redox proxies from this formation indicate that it was deposited in stratified waters, in which a shallow oxic layer overlay suboxic to anoxic waters. These deep waters became episodically euxinic during periods of high organic carbon export. The Velkerri Formation has organic carbon contents that reach ∼10 wt. %. Variations in organic carbon isotopes are consistent with organic carbon enrichment being associated with increases in primary productivity and export, rather than flooding surfaces or variations in mineralogy. Although deposition of the Velkerri Formation in an intracontinental setting has been well established, recent global reconstructions show a broader mid to low latitude gulf, with deposition of the Velkerri Formation being coeval with the widespread deposition of organic-rich rocks across northern Australia and northern China. The deposition of these organic-rich rocks may have been accompanied by significant oxygenation associated with such widespread organic carbon burial during the Mesoproterozoic.

Abstract Extensive, thick, and heterogeneous lacustrine shales occur globally with some regarded as source rocks, but which facies are the key contributors remains unclear. Previous studies have considered that all of the heterogeneous shales were source rocks in the Dongpu depression, but exploration does not support this assumption. Based on 40 yr of geochemical data collection, this study investigated the hydrocarbon generation and expulsion potential of these shales. The results show that laminated shales, though relatively limited in thickness and area, contain much higher organic matter contents and more oil-prone organic matter. Thermal simulation analysis shows that hydrocarbon generation and expulsion potential of laminated shales are much higher and more favorable for hydrocarbon expulsion. Oil-source correlation analyses between oil and shales indicate that northern oils feature pristane/phytane ratios (Pr/Ph) less than 0.7, gammacerane (gammacerane/C30-hopane) indices greater than 0.5, and L-shaped distributions of ααα-C27-20R, ααα-C28-20R, and ααα-C29-20R regular steranes, and are similar to the biomarker characteristics of northern laminated shales with total organic carbon (TOC) contents greater than 1 wt. %. In contrast, northern massive shales are characterized by a high Pr/Ph and low gammacerane index. Southern oils feature Pr/Ph greater than 0.7, gammacerane indices less than 0.5, and L-shaped distributions of regular steranes that are similar to the biomarker characteristics of southern laminated shales. Southern massive shales were characterized by high Pr/Ph, low gammacerane indices, and reversed L- and V-shaped distributions. Laminated shales with TOC contents greater than 1 wt. % are the key source rocks in these heterogeneous Paleogene shales.

ABSTRACT Quantifying the amount of gas hydrate in a reservoir provides valuable insight on gas hydrates’ potential as a resource and their contribution to the global carbon cycle. We develop a new method to estimate hydrate saturation from density-sensitive x-ray computed tomography (XCT) scans of pressure cores from the northern Gulf of Mexico (Green Canyon Block 955). Although several studies have used XCT to quantify gas hydrate in the fractures of fine-grained sediments, our study is one of the few to use XCT for coarse-grained (sand and silt) reservoirs. We calibrate our new method with grain density and quantitative degassing measurements from the same intervals. This paper uses the density difference between gas hydrate (0.924 g/cm3) and pore-water brine (1.035 g/cm3) and assumes these changes linearly affect the XCT measurements allowing for estimates of hydrate saturation. Overall, the XCT calculations agree with the hydrate saturation from quantitative degassing. For example, in core H005-3FB-3, quantitative degassing indicated a hydrate saturation of 88% ± 3.5%, whereas the XCT calculations yielded a saturation of 90% ± 4.8%. These results are encouraging because they suggest that XCT analysis has the potential to nondestructively estimate hydrate saturation.