Oil charging history and pathways of the Ordovician carbonate reservoir in the Tuoputai region, Tarim Basin, NW China

Fang, Ronghui; Li, Meijun; Hai-tao, LU; Wang, T. G.; Yuan, Yuan; Liu, Yongli; Ni, Zhiyong

doi:10.1007/s12182-017-0196-8

Cited by 14 publications

(10 citation statements)

References 46 publications

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“…Fluid inclusions (FIs) recorded the chemical compositions of paleo-geofluids and could provide important information for the relevant physicochemical conditions (e.g., temperature, pressure, pH, Eh) of geological processes (e.g., Roedder and Bodnar 1980;Bergman and Dubessy 1984;Roedder 1984;Petrychenko et al 2005). In the field of petroleum geology, in combination with the construction of burial history, microthermometric analyses of FIs hosted in authigenic reservoir cements have been applied to investigate the hydrocarbon accumulation process, including the timing and the temperature-pressure (T-P) conditions (e.g., Burruss et al 1983;Bodnar 1990;Thiéry et al 2000;Munz 2001;Cao et al 2006;Guo et al 2012;Cui et al 2013;Li et al 2015;Chen et al 2016;Fang et al 2017). Methane (CH 4 ) and carbon dioxide (CO 2 ) are common components in the vapor phase of hydrocarbon-bearing FIs trapped under elevated T-P conditions (e.g., Pironon et al 2001;Dutkiewicz et al 2003;Lüders et al 2012).…”

Section: Introductionmentioning

confidence: 99%

In situ Raman spectroscopic quantification of CH4–CO2 mixture: application to fluid inclusions hosted in quartz veins from the Longmaxi Formation shales in Sichuan Basin, southwestern China

et al. 2019

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We re-evaluate the Raman spectroscopic quantification of the molar ratio and pressure for CH 4 -CO 2 mixtures. Firstly, the Raman quantification factors of CH 4 and CO 2 increase with rising pressure at room temperature, indicating that Raman quantification of CH 4 /CO 2 molar ratio can be applied to those fluid inclusions (FIs) with high internal pressure (i.e., > 15 MPa). Secondly, the v 1 (CH 4 ) peak position shifts to lower wavenumber with increasing pressure at constant temperature, confirming that the v 1 (CH 4 ) peak position can be used to calculate the fluid pressure. However, this method should be carefully calibrated before applying to FI analyses because large discrepancies exist among the reported v 1 (CH 4 )-P curves, especially in the highpressure range. These calibrations are applied to CH 4 -rich FIs in quartz veins of the Silurian Longmaxi black shales in southern Sichuan Basin. The vapor phases of these FIs are mainly composed of CH 4 and minor CO 2 , with CO 2 molar fractions from 4.4% to 7.4%. The pressure of single-phase gas FI ranges from 103.65 to 128.35 MPa at room temperature, which is higher than previously reported. Thermodynamic calculations supported the presence of extremely high-pressure CH 4 -saturated fluid (218.03-256.82 MPa at 200 °C), which may be responsible for the expulsion of CH 4 to adjacent reservoirs.

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Section: Introductionmentioning

confidence: 99%

In situ Raman spectroscopic quantification of CH4–CO2 mixture: application to fluid inclusions hosted in quartz veins from the Longmaxi Formation shales in Sichuan Basin, southwestern China

et al. 2019

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“…The Tuoputai area is located in the southwestern part of the Akekule High in the Tabei Uplift within the Tarim Basin (Figs. 1a, b) and is surrounded by the Halahatang Depression to the west and Manjiaer Depression and Shuntuoguole Low Uplift to the south (Fang et al, 2017). The Akekule High is a long-term paleo-uplift formed in the pre-Sinian metamorphic basement that has experienced multiple tectonic movements and superposed deformation in the Caledonian, Hercynian, Indosinian-Yanshanian, and Himalayan stages (Jin et al, 2009;Fang et al, 2016).…”

Section: Geological Settingmentioning

confidence: 99%

“…The stratigraphic burial and geothermal histories were reconstructed by PetroMod 1D numerical modeling. In order to ensure the accuracy of the modeling, optimization processes were performed until the measured and calculated vitrinite reflectance values matched (Fang et al, 2017) (Fig. 7).…”

Section: Fluid Inclusion and Oil Filling Historymentioning

confidence: 99%

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Geochemical Characteristics and Migration Pathways of Ordovician Carbonate Oil Reservoirs in the Tuoputai Area, Tarim Basin, Northwestern China

Liu

Shen

Cheng

et al. 2021

Acta Geologica Sinica (Eng)

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Exploration potential is huge and the oil resources are rich in the Ordovician reservoirs of the Tarim Basin. However, the mechanism of hydrocarbon accumulation is complex and not yet fully understood. In the Tuoputai area, the hydrocarbon migration pathways and characteristics of deep hydrocarbon accumulation are revealed through analyses of the physical data of rich oil and gas, the geochemical parameters of oil, and fluid inclusions. The results show that the Ordovician oils in the Tuoputai area have the same geochemical characteristics as the mixed oil from the Lower Cambrian source rock and the Middle–Upper Ordovician source rock. The Ordovician reservoirs have been charged three times: in the late Caledonian, late Hercynian, and Himalayan stages. Oil charging occurred in the Hercynian stage, in particular, as it is the main filling period of hydrocarbon. The north‐northeast (NNE)‐trending TP12CX major fault, active in in these times and is dominant migration channel of hydrocarbon, but there is segmentation affected by the difference of activities. Oil maturity is higher in the south than in the north and is abnormally high near the major fault. Parameters related to migration indicate that oil migrated northeastward along the NNE‐trending TP12CX major fault and adjusted laterally along the secondary faults and weathering crust, forming the present characteristics of oil and gas distribution.

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“…Carbonate source rocks are subdivided into marine and continental end members. Taking China as an example, marine carbonate source rocks were developed in the Sichuan, Tarim, and Ordos basins, which are old, have been deeply buried and contain relatively low amounts of organic matter due to high thermal evolution (Wang et al 1995;Zhao et al 2005;Fang et al 2017). In contrast, the Paleogene Bohai Bay Basin and the western Qaidam Basin are associated with lacustrine carbonate source rocks (Wang et al 2010) that are similar to those outside of China.…”

Section: Representative Examples Of Carbonates As Hydrocarbon Source mentioning

confidence: 99%

A review of carbonates as hydrocarbon source rocks: basic geochemistry and oil–gas generation

et al. 2019

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Carbonates have been known to act as hydrocarbon source rocks, but their basic geochemical and associated hydrocarbon generation characteristics remain not well understood as they occur with argillaceous source rocks in most cases, and the hydrocarbon generation from each rock type is difficult to distinguish, forming one of puzzling issues within the field of petroleum geology and geochemistry. To improve the understanding of this critical issue, this paper reviews recent advances in this field and provides a summary of key areas that can be studied in future. Results show that carbonate source rocks are generally associated with high-salinity environments with low amounts of terrestrial inputs and low dissolved oxygen contents. Petrographically, these source rocks are dark gray or black, fine-grained, stratified, and contain bacterial and algal bioprecursors along with some other impurities. They generally have low organic matter contents, although these can vary significantly in different cases (e.g., the total organic carbon contents of marine and lacustrine carbonate source rocks in China are generally 0.1%-1.0% and 0.4%-4.0%, respectively). These rocks contain type I and type II kerogen, meaning there is a lack of vitrinites. This means that assessment of the maturity of the organic matter in these sediments needs to use non-traditional techniques rather than vitrinite reflectance. In terms of molecular geochemistry, carbonate source rocks have typical characteristics indicative of generally reducing and saline environments and lower organism-dominated bioprecursors of organic matter, e.g., high contents of sulfur compounds, low Pr/Ph ratios, and dominance of n-alkanes. Most of the carbonate source rocks are typically dominated by D-type organic facies in an oxidized shallow water mass, although high-quality source rocks generally contain A-and B-type organic facies in saline lacustrine and marine-reducing environments, respectively. The hydrocarbon generation model for the carbonate source rocks can involve early, middle, and late stages, with a diversity of hydrocarbons within these rocks, which can be aggregated, adsorbed, enclosed within minerals, or present as inclusions. This in turn implies that the large-scale hydrocarbon expulsion from these rocks is reliant on brittle deformation caused by external forces. Finally, a number of aspects of these source rocks remain unclear and need further study, including the effectiveness of carbonates as hydrocarbon source rocks, bioprecursors, and hydrocarbon generation models of carbonate source rock, and the differences between marine and lacustrine carbonate source rocks.

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Oil charging history and pathways of the Ordovician carbonate reservoir in the Tuoputai region, Tarim Basin, NW China

Cited by 14 publications

References 46 publications

In situ Raman spectroscopic quantification of CH4–CO2 mixture: application to fluid inclusions hosted in quartz veins from the Longmaxi Formation shales in Sichuan Basin, southwestern China

In situ Raman spectroscopic quantification of CH4–CO2 mixture: application to fluid inclusions hosted in quartz veins from the Longmaxi Formation shales in Sichuan Basin, southwestern China

Geochemical Characteristics and Migration Pathways of Ordovician Carbonate Oil Reservoirs in the Tuoputai Area, Tarim Basin, Northwestern China

A review of carbonates as hydrocarbon source rocks: basic geochemistry and oil–gas generation

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