Geology and geochemistry of bitumen vein deposits at Ghost City, Junggar Basin, northwest China

1994 ◽  
Vol 131 (2) ◽  
pp. 181-190 ◽  
Author(s):  
John Parnell ◽  
Geng Ansong ◽  
Fu Jiamo ◽  
Sheng Guoying
Keyword(s):  
Crude Oil ◽  
Junggar Basin ◽  
Northwest China ◽  
Source Rocks ◽  
Late Triassic ◽  
Upper Permian ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Ghost City ◽  
Maturity Parameters

AbstractVeins of solid bitumen occur in Cretaceous sandstones at the northwest margin of the Junggar Basin, China. The bitumen has a low aromaticity and a composition comparable to gilsonite. The bitumen contains abundant steranes and terpanes, and β-carotane, although most n- and i- alkanes have been removed, which is characteristic of the local crude oil. The sterane and triterpane maturity parameters show that the bitumen, local crude oil, and source rocks are all mature. Bitumen–wallrock relationships suggest that the host sandstone was not completely consolidated at the time of emplacement of the bitumen veins, although bitumen emplacement was a relatively late diagenetic event. The burial history for the northwest Junggar Basin shows that hydrocarbon generation from the assumed upper Permian source rocks commenced in late Triassic/early Jurassic times and suggests that rapid hydrocarbon generation may have resulted in overpressure contributing to the bitumen emplacement.

Confined Pyrolysis for Simulating Hydrocarbon Generation from Jurassic Coaly Source Rocks in the Junggar Basin, Northwest China

2016 ◽  
Vol 31 (1) ◽  
pp. 73-94 ◽  
Author(s):  
Hao Xu ◽  
Xianghua Ding ◽  
Zhengjiang Luo ◽  
Cuimin Liu ◽  
Erting Li ◽  
...  
Keyword(s):  
Junggar Basin ◽  
Northwest China ◽  
Source Rocks ◽  
Hydrocarbon Generation

scholarly journals Evaluation of hydrocarbons generated from the Permo-Carboniferous source rocks in Huanghua Depression of the Bohai Bay Basin, China

2018 ◽  
Vol 36 (5) ◽  
pp. 1229-1244
Author(s):  
Xiao-Rong Qu ◽  
Yan-Ming Zhu ◽  
Wu Li ◽  
Xin Tang ◽  
Han Zhang
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Bohai Bay Basin ◽  
Important Conclusion ◽  
The North ◽  
Huanghua Depression ◽  
History Of

The Huanghua Depression is located in the north-centre of Bohai Bay Basin, which is a rift basin developed in the Mesozoic over the basement of the Huabei Platform, China. Permo-Carboniferous source rocks were formed in the Huanghua Depression, which has experienced multiple complicated tectonic alterations with inhomogeneous uplift, deformation, buried depth and magma effect. As a result, the hydrocarbon generation evolution of Permo-Carboniferous source rocks was characterized by discontinuity and grading. On the basis of a detailed study on tectonic-burial history, the paper worked on the burial history, heating history and hydrocarbon generation history of Permo-Carboniferous source rocks in the Huanghua Depression combined with apatite fission track testing and fluid inclusion analyses using the EASY% Ro numerical simulation. The results revealed that their maturity evolved in stages with multiple hydrocarbon generations. In this paper, we clarified the tectonic episode, the strength of hydrocarbon generation and the time–spatial distribution of hydrocarbon regeneration. Finally, an important conclusion was made that the hydrocarbon regeneration of Permo-Carboniferous source rocks occurred in the Late Cenozoic and the subordinate depressions were brought forward as advantage zones for the depth exploration of Permo-Carboniferous oil and gas in the middle-northern part of the Huanghua Depression, Bohai Bay Basin, China.

scholarly journals Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China

2018 ◽  
Vol 36 (4) ◽  
pp. 801-819 ◽  
Author(s):  
Shuangfeng Zhao ◽  
Wen Chen ◽  
Zhenhong Wang ◽  
Ting Li ◽  
Hongxing Wei ◽  
...  
Keyword(s):  
Natural Gas ◽  
Tarim Basin ◽  
Oil And Gas ◽  
Northwest China ◽  
Source Rocks ◽  
Coal Measure ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
Isotopic Analyses ◽  
Jurassic Coal

The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.

PETROLEUM SYSTEMS IN TASMANIA'S FRONTIER ONSHORE BASINS

2000 ◽  
Vol 40 (1) ◽  
pp. 26
Author(s):  
M.R. Bendall C.F. Burrett ◽  
H.J. Askin
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Late Triassic ◽  
Upper Permian ◽  
Lower Permian ◽  
Peak Oil ◽  
Petroleum Systems ◽  
Upper Proterozoic ◽  
Oil Seep

Sedimentary successions belonging to three petroleum su persy stems can be recognised in and below the Late Carboniferous to Late Triassic onshore Tasmania Basin. These are the Centralian, Larapintine and Gondwanan. The oldest (Centralian) is poorly known and contains possible mature source rocks in Upper Proterozoic dolomites. The Larapintine 2 system is represented by rocks of the Devonian fold and thrust belt beneath the Tasmania Basin. Potential source rocks are micrites and shales within the 1.8 km-thick tropical Ordovician Gordon Group carbonates. Conodont CAI plots show that the Gordon Group lies in the oil and gas windows over most of central Tasmania and probably under much of the Tasmania Basin. Potential reservoirs are the upper reefal parts of the Gordon Group, paleokarsted surfaces within the Gordon Group and the overlying sandstones of the Siluro-Devonian Tiger Range and Eldon Groups. Seal rocks include shales within the Siluro-Devonian and Upper Carboniferous-Permian tillites and shales.The Gondwanan supersystem is the most promising supersystem for petroleum exploration within the onshore Tasmania Basin. It is divided into two petroleum systems— the Early Permian Gondwanan 1 system, and the Late Permian to Triassic Gondwanan 2 system. Excellent source rocks occur in the marine Tasmanite Oil Shale and other sections within the Lower Permian Woody Island and Quamby Formations of the Gondwanan 1 system and within coals and freshwater oil shales of the Gondwanan 2 system. These sources are within the oil and gas windows across most of the basin and probably reached peak oil generation at about 100 Ma. An oil seep, sourced from a Tasmanites-rich, anoxic shale, is found within Jurassic dolerite 40 km WSW of Hobart. Potential Gondwanan 1 reservoirs are the glaciofluvial Faulkner Group sandstones and sandstones and limestones within the overlying parts of the glaciomarine Permian sequence. The Upper Permian Ferntree Mudstone Formation provides an effective regional seal. Potential Gondwanan 2 reservoirs are the sandstones of the Upper Permian to Norian Upper Parmeener Supergroup. Traps consisting of domes, anticlines and faults were formed probably during the Early Cretaceous. Preliminary interpretation of a short AGSO seismic profile in the Tasmania Basin shows that, contrary to earlier belief, structures can be mapped beneath extensive and thick (300 m) sills of Jurassic dolerite. In addition, the total section of Gondwana to Upper Proterozoic to Triassic sediments appears to be in excess of 8,500 m. These recent studies, analysis of the oil seep and drilling results show that the Tasmanian source rocks have generated both oil and gas. The Tasmania Basin is considered prospective for both petroleum and helium and is comparable in size and stratigraphy to other glaciomarine-terrestrial Gondwanan basins such as the South Oman and Cooper Basins.

Material Balance Method Combined with Hydrocarbon Generation Kinetics to Calculate the Efficiency of Hydrocarbon Expulsion

2014 ◽  
Vol 977 ◽  
pp. 73-77
Author(s):  
Ai Hua Huang ◽  
Min Wang ◽  
Shan Si Tian ◽  
Hai Tao Xue ◽  
Zhi Wei Wang ◽  
...  
Keyword(s):  
Material Balance ◽  
Order Reaction ◽  
Balance Method ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
First Order ◽  
Geochemical Parameters ◽  
Material Balance Method ◽  
Hydrocarbon Expulsion

In order to calculate the efficiency of hydrocarbon expulsion by material balance method, we analyzed and corrected the geochemical parameters of five source rock samples. The hydrocarbon generation kinetic parameters of these samples were calibrated by the model of limited parallel first order reaction, and then these were extrapolated with the burial history and thermal history, then we got the hydrocarbon-generating section. Combined with the corrected geochemical parameters calculate the generating hydrocarbon amounts and expulsive hydrocarbon amounts. The result shows that: expulsion efficiency of hydrocarbon source rocks in this research were mainly between 59.1% -91.8%. It is determined by maturity (Ro), type of organic matter and pyrolysis parameters S1、S2.

scholarly journals Analysis of Petroleum System for Exploration and Risk Reduction in Abu Madi/Elqar'a Gas Field, Nile Delta, Egypt

2012 ◽  
Vol 2012 ◽  
pp. 1-10 ◽  
Author(s):  
Said Keshta ◽  
Farouk J. Metwalli ◽  
H. S. Al Arabi
Keyword(s):  
Nile Delta ◽  
Organic Matter Content ◽  
Petroleum System ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Basin Modeling ◽  
Burial History ◽  
Gas Field ◽  
Upper Miocene ◽  
Migration Pathways

Abu Madi/El Qar'a is a giant field located in the north eastern part of Nile Delta and is an important hydrocarbon province in Egypt, but the origin of hydrocarbons and their migration are not fully understood. In this paper, organic matter content, type, and maturity of source rocks have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. Modeling of the empirical data of source rock suggests that the Abu Madi formation entered the oil in the middle to upper Miocene, while the Sidi Salem formation entered the oil window in the lower Miocene. Charge risks increase in the deeper basin megasequences in which migration hydrocarbons must traverse the basin updip. The migration pathways were principally lateral ramps and faults which enabled migration into the shallower middle to upper Miocene reservoirs. Basin modeling that incorporated an analysis of the petroleum system in the Abu Madi/El Qar'a field can help guide the next exploration phase, while oil exploration is now focused along post-late Miocene migration paths. These results suggest that deeper sections may have reservoirs charged with significant unrealized gas potential.

scholarly journals Rhenium–osmium (Re–Os) geochronology of crude oil from lacustrine source rocks of the Hailar Basin, NE China

2020 ◽  
Author(s):  
Qi-An Meng ◽  
Xue Wang ◽  
Qiu-Li Huo ◽  
Zhong-Liang Dong ◽  
Zhen Li ◽  
...  
Keyword(s):  
Crude Oil ◽  
Source Rocks ◽  
Radiometric Dating ◽  
Age Dating ◽  
Hydrocarbon Generation ◽  
Ne China ◽  
Petroleum Systems ◽  
Younger Age ◽  
Hailar Basin ◽  
Age Trends

Abstract Re–Os radiometric dating of crude oil can be used to constrain the timing of hydrocarbon generation, migration or charge. This approach has been successfully applied to marine petroleum systems; however, this study reports on its application to lacustrine-sourced natural crude oils. Oil samples from multiple wells producing from the Cretaceous Nantun Formation in the Wuerxun-Beier depression of the Hailar Basin in NE China were analysed. Subsets of the Re–Os data are compatible with a Cretaceous hydrocarbon generation event (131.1 ± 8.4 Ma) occurring within 10 Myr of deposition of the Nantun Formation source rocks. In addition, two younger age trends of 54 ± 12 Ma and 1.28 ± 0.69 Ma can be regressed from the Re–Os data, which may reflect the timing of subsequent hydrocarbon generation events. The Re–Os geochronometer, when combined with complementary age dating techniques, can provide direct temporal constraints on the evolution of petroleum system in a terrestrial basin.

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.

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