scholarly journals Revisiting Controls on Shale Oil Accumulation in Saline Lacustrine Basins: The Permian Lucaogou Formation Mixed Rocks, Junggar Basin

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-25
Author(s):  
Chenjia Zhang ◽  
Jian Cao ◽  
Erting Li ◽  
Yuce Wang ◽  
Wenyao Xiao ◽  
...  
Keyword(s):  
Carbonate Rocks ◽  
Junggar Basin ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Shale Oil ◽  
Oil Accumulation ◽  
Hydrocarbon Generation Potential ◽  
Lucaogou Formation ◽  
Saline Lacustrine ◽  
Lacustrine Basins

Fine-grained mixed rocks in saline lacustrine basins are important targets for shale oil exploration. However, the controls on shale oil accumulation are complex due to the multi-source mixed deposition. This is a challenging issue in the study of shale oil. Here, we present a case study in the Middle Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin, northwestern China. Results show that the Lucaogou Formation consists mainly of carbonate rocks, dolomitic or calcareous mudstones, tuffaceous or silty mudstones, and siltstones. The dolomitic/calcareous mudstones ( TO C average = 6.44   wt . % ) and tuffaceous/silty mudstones ( TO C average = 4.83   wt . % ) have the best hydrocarbon generation potential and contain type I–II1 kerogens that are in the peak oil generation stage. However, the shale oil potential is highest for the carbonate rocks and siltstones with average oil saturation index (OSI) values of 315.03 mg HC/g TOC and 343.27 mg HC/g TOC, respectively. This indicates that hydrocarbon generation potential is not the main factor controlling shale oil potential. Micro-nanoscale pores are the main control. Abundant dissolution pores provide excellent reservoir space for near-source migration and accumulation of shale oil. Different mixing processes between lithofacies control the accumulation of shale oil, and shale oil productivity is the best when multi-facies deposition in transitional zones formed the mixed rocks (facies mixing). In addition, local accumulations of calcareous organisms and adjacent carbonate components on terrigenous sediments (in situ mixing) are also conducive to shale oil enrichment. This is an unusual and special feature of saline lacustrine shale oils, which is different from freshwater lacustrine and marine shale oils. Comprehensive assessment of source rock and reservoir is needed to robustly establish a widely applicable method to determine the shale oil potential in such basins.

scholarly journals First evidence of the early cretaceous oceanic anoxic events (MBE and OAE1a) in the southern Tethyan margin (NE-Tunisia): biostratigraphy and shale resource system

2021 ◽  
Vol 11 (4) ◽  
pp. 1559-1575
Author(s):  
Rachida Talbi ◽  
Ahlem Amri ◽  
Abdelhamid Boujemaa ◽  
Hakim Gabtni ◽  
Reginal Spiller ◽  
...  
Keyword(s):  
Black Shale ◽  
Saturation Index ◽  
Black Shales ◽  
Source Rocks ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Shale Oil ◽  
Hydrocarbon Generation Potential ◽  
Anoxic Events ◽  
Rock Eval

AbstractThe Jebel Oust region (north-eastern Tunisia) recorded two levels of marine black shale in the Lower Cretaceous marly series. Geodynamic evolution, biostratigraphic and Rock–Eval analysies allow classifying those black shales as unconventional shale oil resource systems that were deposited during two oceanic anoxic events: the Middel Barremian Event "MBE" and the Early Aptian Event "OAE1a". Paleogeographic evolution highlights two transgressive–regressive cycles: the first one is Valanginian-Early Barremian, and the second is Late Barremian–Early Aptian. Each black shale deposit occurs at the end of the transgression that coincides with the highest sea level. During the Barreman–Aptian interval, sedimentation was controlled by extensional faults in a system of tilted fault blocks which were reactivated several times. Kerogen is of type I, II origin in black shales and of type III origin in marls. Tmax values indicate "oil window" stage. Average transformation ratio is around 67% and 82%, respectively, in the Lower Aptian and Middel Barremian source rock related to the relatively high thermal maturity degree due to the deep burial of the later. Estimated initial hydrocarbon generation potential is moderate to high. Oil saturation index records an "oil crossover" indicating expelled and migrated hydrocarbons from the organic-rich to the organic-poor facies. The petroleum system of the two mature source rocks with a high hydrocarbon generation potential enclose all elements characterizing a "shale oil hybrid system with a combination of juxtaposed organic-rich and organic-lean facies associated with open fractures".

scholarly journals Origin of authigenic albite in a lacustrine mixed-deposition sequence (Lucaogou Formation, Junggar Basin) and its diagenesis implications

2021 ◽  
pp. 014459872110427
Author(s):  
Haiguang Wu ◽  
Junjun Zhou ◽  
Wenxuan Hu ◽  
Funing Sun ◽  
Xun Kang ◽  
...  
Keyword(s):  
Chemical Composition ◽  
Junggar Basin ◽  
Oil Reservoirs ◽  
Type I ◽  
Shale Oil ◽  
Type Ii ◽  
Lucaogou Formation ◽  
Shale Oil Reservoirs ◽  
Clastic Reservoirs ◽  
Organic Fluids

Authigenic albites occur widely in clastic reservoirs with important implications for diagenesis and reservoir formation. The middle Permian Lucaogou Formation in the Jimusaer Sag (Junggar Basin, NW China), where major exploration breakthroughs in shale oil have been achieved, reveals a new phenomenon that authigenic albites are abundant in unique mixed carbonate–volcanic–clastic sequences. This has not been reported in the literatures. To fill the knowledge gap, the origin of these authigenic albites and their relationship with dissolution pores (i.e. diagenesis implications) were investigated. Results show that two types (I and II) of authigenic albite were identified within the shale oil reservoirs. Euhedral Type I authigenic albites with 3–10 μm only occur in dolarenite intraclasts and are symbiotic with amorphous dolomite minerals with a pure chemical composition of >99% albite-end-member content. Larger Type II authigenic albites with 10–50 μm are widely distributed in reservoirs, primarily in dissolution pores, and coexist with authigenic dolomite minerals or dolomite overgrowths. Their chemical composition is less pure with anorthite-end-member contents that range from undetectable to 9.77%, with an average of 1.34%. A symbiotic relationship, pure chemical composition, size, and euhedral morphology indicate that Type I authigenic albites precipitated during syngenetic hydrothermal action. However, the morphology of dissolution pores, residual symbiotic “orthoclase”, impure chemical composition and carbon–oxygen isotope indicate that Type II were the products of the dissolution and reprecipitation of “perthite” crystal pyroclasts influenced by acid organic fluids in latter diagenesis. The differential dissolution of “orthoclase” and “albite” components in “perthite” crystal pyroclasts formed enormous intergranular secondary pores in the presence of dolomite minerals in the shale oil reservoirs.

scholarly journals Geochemical characterization and possible hydrocarbon contribution of the Carboniferous interval natively developed in the Chepaizi Uplift of Junggar Basin, northwestern China

2019 ◽  
Vol 38 (3) ◽  
pp. 654-681 ◽  
Author(s):  
Lixin Mao ◽  
Xiangchun Chang ◽  
Youde Xu ◽  
Bingbing Shi ◽  
Dengkuan Gao
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Junggar Basin ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Exploration Process ◽  
Potential Source ◽  
Hydrocarbon Generation Potential ◽  
Northwestern Region ◽  
Effective Source

Previous studies on Chepaizi Uplift mainly focused on its reservoirs, and the potential source rocks natively occurred was ignored. During the exploration process, dark mudstones and tuffaceous mudstones were found in the Carboniferous interval. These possible source rocks have caused great concern about whether they have hydrocarbon generation potential and can contribute to the reservoirs of the Chepaizi Uplift. In this paper, the potential source rocks are not only evaluated by the organic richness, type, maturity, and depositional environment, but also divided into different kinetics groups. The Carboniferous mudstones dominated by Type III kerogen were evolved into the stage of mature. Biomarkers indicate that the source rocks were deposited in a marine environment under weakly reducing conditions and received mixed aquatic and terrigenous organic matter, with the latter being predominant. The effective source rocks are characterized by the total organic carbon values >0.5 wt.% and the buried depth >1500 m. The tuffaceous mudstone shows a greater potential for its lower active energy and longer hydrocarbon generation time. Considering the hydrocarbon generation potential, base limits of the total organic carbon and positive correlation of oil–source rock together, the native Carboniferous mudstones and tuffaceous mudstones might contribute to the Chepaizi Uplift reservoirs of the northwestern region of the Junggar Basin, especially the deeper effective source rocks should be paid enough attention to.

Sign in / Sign up

Export Citation Format

Share Document