Abstract The architecture and quality of lacustrine turbidites that act as petroleum reservoirs are less well documented. Reservoir architecture and multiscale heterogeneity in turbidites represent serious challenges to production performance. Additionally, establishing a hierarchy profile to delineate heterogeneity is a challenging task in lacustrine turbidite deposits. Here, we report on the turbidites in the middle third member of the Eocene Shahejie Formation (Es3), which was deposited during extensive Middle to Late Eocene rifting in the Dongying Depression. Seismic records, wireline log responses, and core observations were integrated to describe the reservoir heterogeneity by delineating the architectural elements, sequence stratigraphic framework and lithofacies assemblage. A petrographic approach was adopted to constrain microscopic heterogeneity using an optical microscope, routine core analyses and X-ray diffraction (XRD) analyses. The Es3m member is interpreted as a sequence set composed of four composite sequences: CS1, CS2, CS3 and CS4. A total of forty-five sequences were identified within these four composite sequences. Sand bodies were mainly deposited as channels, levees, overbank splays, lobes and lobe fringes. The combination of fining-upward and coarsening-upward lithofacies patterns in the architectural elements produces highly complex composite flow units. Microscopic heterogeneity is produced by diagenetic alteration processes ( i . e ., feldspar dissolution, authigenic clay formation and quartz cementation). The widespread kaolinization of feldspar and mobilization of materials enhanced the quality of the reservoir by producing secondary enlarged pores. In contrast, the formation of pore-filling authigenic illite and illite/smectite clays reduced its permeability. Recovery rates are higher in the axial areas and smaller in the marginal areas of architectural elements. This study represents a significant insight into the reservoir architecture and heterogeneity of lacustrine turbidites, and the understanding of compartmentalization and distribution of high-quality sand reservoirs can be applied to improve primary and secondary production in these fields.
The upper Turonian–Maastrichtian Kawagarh Formation represents a thick sequence of carbonates in the Kalachitta Range, Pakistan and it is the only stratigraphic record of Late Cretaceous sedimentation in northwestern Lesser Himalayas. Global sea-level marks a gradual fall of ∼40 to 50 m during the deposition of the Kawagarh Formation. This study is based on detailed outcrop and petrographic investigations of six stratigraphic sections exposed in Kalachitta Range. Carbonate grains are dominantly composed of pelecypods, oysters, trigonia and plankton distributed in a micritic groundmass. Five microfacies, (1) Planktonic Mudstone, Wackestone and Packstone Microfacies, (2) Pelecypodic Planktonic Mudstone and Wackestone Microfacies, (3) Pelecypodic Wackestone and Packstone Microfacies, (4) Marl Microfacies and (5) Dolostone Microfacies, were identified using distribution of faunal types and matrix. Based on faunal paleoecology, microfacies analysis and sedimentary structures, a shallow open-marine, northward-dipping ramp model has been proposed for the deposition of the Kawagarh Formation beginning with a transgressive cycle, which also corresponds to global sea-level rise, and possibly terminated by uplift owing to initial collision of the Indian Plate with the Kohistan-Ladakh Arc at the end of the Cretaceous.KEYPOINTSPaleontological and paleoecological evidence is used to develop a shallow, open-marine ramp deposition model for the Kawagarh Formation.The initiation of Kawagarh sedimentation with transgression in the late Turonian synchronise with global sea-level curve. Sedimentation was terminated by initial collision of the Indian Plate with the Kohistan-Ladakh Arc.
A recent hydrocarbons discovery in 2021 in the Kawagarh Formation has brought attention to the significance of sedimentology and specifically diagenesis for understanding and characterizing the reservoir properties. The diagenetic history and multiscale processes that contributed to diagenesis were vaguely known. This study aimed to reconstruct various diagenetic phases, paragenetic sequences, and the interrelationship of these phases in the Kawagarh Formation. The diagenetic processes were identified and characterized through an integrated methodology utilizing the outcrop, petrographic, and geochemical analyses. Early calcite cementation was found to occur in the early stages of marine burial diagenesis involving pore fluid originating from the dissolution of aragonite in interlayer marl/mudstone beds and reprecipitating as microspar in adjacent limestone beds. The absence of mechanical compaction in wackstone and mudstone facies and the presence of late compaction in lithified packstones clearly imply that early calcite cementation occurred prior to compaction. Dolomitization with stylolites coupled with significant negative oxygen (δ18O) isotope values implies a fault-related hydrothermal dolomitization model. Uplift introduced the fractures and low Mg fresh fluids to the system which caused calcitisation in shallow burial settings. The depleted δ13C and negative δ18O values indicate the mixing of surface-derived waters with hot burial fluids during the calcitization. This study offers valuable insights into several aspects related to the formation and the basin itself, including burial depths, fluid influx, and geochemical gradients. It also sheds light on the evolution of reservoir properties such as porosity and permeability in dolomitization fronts. Such insights can be used to gain a deeper understanding about the burial history, basin evaluation, and reservoir characterization for hydrocarbon exploration.
Abstract Scaling porosity of sedimentary rocks from the scale of measurement to the scale of interest is still a challenge. Upscaling of porosity can assist to accurately predict other petrophysical properties of rock at multiple scales. In this study, we use the two-dimensional (2D) scanning electron microscope (SEM) and three-dimensional (3D) X-ray micro-computed tomography (micro-CT) image to upscale porosity from the image scale to the core plug scale. A systematic imaging plan is deployed to capture rock properties of a carbonate and a sandstone sample, which are sensitive to the fractal nature of these rocks. Image analysis records wider pore spectrum (0.12–50 µm) in the carbonate sample than in sandstone (0.12–30 µm). The fractal dimensions are also higher in the carbonate than in the sandstone sample. Median, volume-weighted average of pore radius, and fractal dimensions derived from the image analysis are used as inputs in this equation. The results of the present study using this equation yielded to the best results on a resolution of 2.5 µm/voxel in the sandstone and 2.01 µm/voxel resolution in the carbonate sample for 3D micro-CT images, where fractal-scaling porosity matches well with the porosity measured at the core plug scale. The 2D SEM images provided a good estimation of porosity in the sandstone sample, where micro-CT imaging techniques could not capture the full pore spectrum. The fractal porosity equation showed promising results and offers a potential alternative way to estimate porosity when there are no routine core measurements available.
Abstract The main reservoir in Huizhou sub-basin is Zhujiang Formation of early Miocene age. The petrophysical analysis shows that the Zhujiang Formation contains thin carbonate intervals, which have good hydrocarbon potential. However, the accurate interpretation of thin carbonate intervals is always challenging as conventional seismic interpretation techniques do not provide much success in such cases. In this study, well logs, three-layer forward amplitude versus offset (AVO) model and the wedge model are integrated to analyze the effect of tuning thickness on AVO responses. It is observed that zones having a thickness greater than or equal to 15 m can be delineated with seismic data having a dominant frequency of more than 45 Hz. The results are also successfully verified by analyzing AVO attributes, i.e., intercept and gradient. The study will be helpful to enhance the characterization of thin reservoir intervals and minimize the risk of exploration in the Huizhou sub-basin, China.
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