Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan

Awan, Rizwan Sarwar; Liu, Chenglin; Aadil, N.; Yasin, Qamar; Salaam, Abdus; Hussain, Azkar; Shangfeng, Yang; Jadoon, Ashar Khan; Wu, Yuping; Gul, Muhammad Amar

doi:10.1016/j.petrol.2021.108404

Cited by 30 publications

(13 citation statements)

References 82 publications

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“…1 and 2 are composed mainly of thin laminae that vary between shale and fine silt with calcareous cement (Figure 11 (1-10) and Figure 12 (1,2). The organic matter is concentrated mainly in the shale laminae and is represented by alginite (41%) that is distinguished by its brown color in white light and bright yellow color in fluorescence mode (Figure 11 (1)(2)(3)6,7,11,12). The alginite extends in large sheets (<5 µm in thickness) parallel to the bedding plane (Figure 11 (1-3,6,7)).…”

Section: Organic Petrography and Microscopic Composition Of Organic Mattermentioning

confidence: 99%

“…The decline in petroleum has led to the search for unconventional resources based on fossil energy (e.g., oil shale, shale oil, shale gas) and non-fossil energy (e.g., wind energy and sun power). Black shale (organically rich) has become one of the important sources of unconventional oil/gas exploration [2]. Organic-rich shales are widely deposited in Cretaceous deep marine settings, especially in the Tethys region [3].…”

Section: Introductionmentioning

confidence: 99%

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Organic Petrographic and Geochemical Evaluation of the Black Shale of the Duwi Formation, El Sebaiya, Nile Valley, Egypt

et al. 2021

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This study evaluates the palynologic, organic, inorganic, and petrographic properties of organic-rich black shale (Mahamid Mine) in the El Sebaiya area, Nile Valley, Egypt. Black shale is composed of quartz (50%), calcite (10%), kaolinite (25%) and montmorillonite (15%). Organic and inorganic analyses revealed that this shale was deposited under oxic to anoxic marine conditions during strong chemical weathering. Black shale has poor to very good organic richness, and poor to fair hydrocarbon potential. Organic petrography indicates that the kerogen is mixed types II/III and III and is immature to marginally mature (%VRo is 0.44 and 0.53). Liptinite macerals consist of alginite, cutinite, and bituminite. The hydrocarbon products to be generated at higher maturity are expected to be oil and gas.

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Section: Organic Petrography and Microscopic Composition Of Organic Mattermentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Organic Petrographic and Geochemical Evaluation of the Black Shale of the Duwi Formation, El Sebaiya, Nile Valley, Egypt

et al. 2021

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“…The distribution of nalkane is often used to provide evidence related to the origin of OM. The presence of long-chain n-alkanes may specify the influence of land plants, while the short-chain suggests that the source of OM primarily emanates from algal/bacterial input (Awan, Liu, Aadil, et al, 2021;Peters, Peters, Walters, & Moldowan, 2005).…”

Section: Source Of Ommentioning

confidence: 99%

Sedimentary geochemistry of the Early Cambrian Niutitang Formation to reconstruct the palaeo‐depositional environments and to evaluate the organic matter enrichment mechanism from the Yangtze Block, South China

et al. 2021

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In the Yangtze Block, the Early Cambrian Niutitang Formation is mainly composed of mudstone, shale, and carbonates which are important for investigating the depositional environment and evolution of the Early Cambrian rocks. The Niutitang Formation in the study area has a greater geologic interest due to its polymetallic beds, depositional age, variation in environmental conditions, Cambrian explosion, organic matter (OM) enrichment, algal boom, etc. This research represents the sedimentary geochemistry of the Early Cambrian Niutitang Formation to reconstruct the palaeo‐depositional environment and to evaluate the OM enrichment mechanism by means of total organic carbon (TOC), biomarkers, carbon isotopes, mineralogy, scanning electron microscope, etc. Based on the variation in TOC content, the Niutitang Formation is divided into three parts (upper, middle, and lower). The majority of the samples from the middle part of the Niutitang Formation exhibit an excellent source of hydrocarbon (TOC > 4.0 wt%) relative to the upper and the lower part. The lighter carbon isotopic composition (<−30.7%) in these sediments reveals the presence of the I‐amorphous kerogen group. Moreover, these lighter δ13Corg values suggest the presence of type‐I oil‐prone kerogen. Saturated hydrocarbon in these rocks showed the dominance of short‐chain n‐alkanes maximizing at C18. The predominance of these n‐alkanes represents that the OM is chiefly derived from algal/bacterial input. Similarly, the dissymmetric V shape of C27‐C28‐C29 steranes with a predominance of C27 and the higher values of in all three parts reflects that the OM in these rocks is chiefly originated from the lower aquatic marine organisms. Based on the Pr/Ph ratio, it is predicted that the middle part of the Niutitang Formation was deposited in extreme anoxic conditions (Pr/Ph < 0.5), whereas the upper and lower parts were deposited in relatively less anoxic conditions. Some biomarkers have more stable stereochemistry, which cannot be affected by diagenetic processes. These stable configurations are utilized to measure the maturity of OM, that is, Ts/(Ts + Tm), C29ββ/(ββ + αα), C29αα20S/(20S + 20R) steranes, and homohopane C31 22S/(22S + 22R). These geochemical indices reveal that the Early Cambrian Niutitang Formation in the studied area is mature to the post‐mature in the gas generation phase. Moreover, the hydrothermal fluids rich in metallic elements (e.g., Mo, Zn, V, and U) from the deeper part of the Earth owing to elongational forces among Yangtze and Cathaysian plates over Early Cambrian time entered the oceanic basin via remnant features (fissure and cracks) and through upwelling phenomena interacted with shelf sediments. At the ocean's surface, these nutrient‐rich fluids enhanced the breeding and evolution of marine life (bio‐productivity), which created hypoxic water conditions suitable for the preservation of OM in these rocks.

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“…A lot of research has been done on tight sandstone reservoirs by many authors around the globe. Usually, the oil in a tight sandstone reservoir with permeability less than 0.1 mD and porosity less than 10% can be referred to as tight (sandstone) oil [1][2][3][4][5][6][7][8][9]. Recently, tight (sandstone) oil emerged as an important unconventional oil resource in the petroleum sec-tor.…”

Section: Introductionmentioning

confidence: 99%

Facies and Petrophysical Modeling of Triassic Chang 6 Tight Sandstone Reservoir, Heshui Oil Field, Ordos Basin, China

et al. 2021

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Tight sandstone reservoirs are widely distributed worldwide. The Upper Triassic Chang 6 member of the Yanchang Formation is characterized by low permeability and porosity. The facies model offers a unique approach for understanding the characteristics of various environments also heterogeneity, scale, and control of physical processes. The role of subsurface facies features and petrophysical properties was unclear. Notable insufficient research has been conducted based on facies and petrophysical modeling and that demands to refine the role of reservoir properties. To tackle this problem, a reservoir model is to be estimated using various combinations of property modeling algorithms for discrete (facies) and continuous (petrophysical) properties. Chang 6 member consists of three main facies, i.e., channel, lobe main body, and lobe margin facies. The current research is aimed at comparing the applicability and competitiveness of various facies and petrophysical modeling methods. Further, well-log data was utilized to interpret unique facies and petrophysical models to better understand the reservoir architecture. Methods for facies modeling include indicator kriging, multiple-point geostatistics, surface-based method, and sequential indicator simulation. Overall, the indicator kriging method preserved the local variability and accuracy, but some facies are smoothed out. The surface-based method showed far better results by showing the ability to reproduce the geometry, extent, connectivity, and facies association. The multiple-point geostatistics (MPG) model accurately presented the facies profiles, contacts, geometry, and geomorphological features. Sequential indicator simulation (SIS) honored the facies spatial distribution and input statistical parameters. The porosity model built using sequential Gaussian simulation (SGS) showed low porosity (74% values <2%). Gaussian random function simulation (GRFS) models showed very low average porosity (8%-10%) and low permeability (less than 0.1 mD). These methods indicate that Chang 6 member is a typical unconventional tight sandstone reservoir with ultralow values of petrophysical properties.

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Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan

Cited by 30 publications

References 82 publications

Organic Petrographic and Geochemical Evaluation of the Black Shale of the Duwi Formation, El Sebaiya, Nile Valley, Egypt

Organic Petrographic and Geochemical Evaluation of the Black Shale of the Duwi Formation, El Sebaiya, Nile Valley, Egypt

Sedimentary geochemistry of the Early Cambrian Niutitang Formation to reconstruct the palaeo‐depositional environments and to evaluate the organic matter enrichment mechanism from the Yangtze Block, South China

Facies and Petrophysical Modeling of Triassic Chang 6 Tight Sandstone Reservoir, Heshui Oil Field, Ordos Basin, China

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