Source Rock Evaluation and Hydrocarbon Generation Model of a Permian Alkaline Lakes—A Case Study of the Fengcheng Formation in the Mahu Sag, Junggar Basin

The alkaline lake source rocks of the Fengcheng Formation are developed in the Mahu Sag of the Junggar Basin. Different from traditional continental fresh water and saltwater lake source rocks, alkaline lake source rocks lack targeted evaluation criteria, and it is unknown whether their hydrocarbon generation models are consistent with traditional models. Therefore, in the present study, evaluation standards and hydrocarbon generation models of alkaline lake source rocks are discussed based on geological and organic geochemical data and a systematic summary of the geochemical characteristics of the Fengcheng Formation source rocks. The Fengcheng Formation source rocks are mainly diamictite with mixed argillaceous rock and dolomite; most total organic carbon (TOC) values range from 0.2–1.4%; and the kerogen is primarily oil-prone type II, reaching low- to high-maturity stages. Based on the types of organic matter in source rocks and the relationships between organic matter abundance parameters, the evaluation standard of alkaline lake source rocks is proposed. The Fengcheng Formation is mainly composed of good to excellent source rocks (55.5%) with high hydrocarbon generation potential. The single-peak hydrocarbon generation model of the Fengcheng Formation is similar to that of traditional freshwater or saltwater lakes, with a high hydrocarbon generation rate, two to five times that of the traditional model; its main particularity is in the formation of naphthenic crude oil from the kerogen of bacteria and algae. A new understanding of the hydrocarbon generation potential and model of alkaline lake source rocks in the Fengcheng Formation can provide support for tight oil and shale oil exploration in the Mahu Sag.

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Organic petrology, geochemistry, and hydrocarbon generation capacity of Permo–Carboniferous source rocks in the Mahu Sag, northwestern Junggar Basin, China

Energy Exploration & Exploitation ◽

10.1177/01445987211023856 ◽

2021 ◽

pp. 014459872110238

Author(s):

Zhijun Qin ◽

Dongming Zhi ◽

Kelai Xi

Keyword(s):

Organic Matter ◽

Higher Plants ◽

Sedimentary Environment ◽

Junggar Basin ◽

The Other ◽

Source Rocks ◽

Western China ◽

Geochemical Data ◽

Lower Permian ◽

Hydrocarbon Generation

The Mahu Sag in the Junggar Basin, China, is a hydrocarbon-rich sag. Abundant hydrocarbon source rocks were developed in the late Paleozoic there across the Carboniferous–Permian boundary. However, studies of the source rocks have focused mainly on the lower Permian Fengcheng Formation. Here we compare the Fengcheng Formation with other Carboniferous rocks and those of the lower Permian Jiamuhe and middle Permian Lower-Wuerhe formations. Based on organic petrological and geochemical data, the organic matter precursors, sedimentary facies, and resource potential of these source rocks were investigated. The bio-precursors of Carboniferous, Jiamuhe, and Lower-Wuerhe Formations were dominantly estuarine higher plants, Nematothallus -higher plants, and spores, respectively. The bio-precursors of Fengcheng Formation were mainly bacteria and algae, and the organic matter is abundant, with a high hydrocarbon-generating capacity and significant shale oil potential. In contrast, the other three formations contain poor-quality source rocks, although the Lower-Wuerhe Formation has a higher organic matter abundance than the Jiamuhe Formation. The Carboniferous organic matter contains mainly type II kerogen, whereas the Jiamuhe and Lower-Wuerhe formations contain type III kerogen. The thermal maturities determined from Tmax values is larger than those indicated by biomarkers. The biomarkers show that the three studied formations contain a mixture of terrestrial higher plants and bacteria–algae, with the contribution of green algae being higher than that of bacteria in most samples. However, the ratio of algae to bacteria is lower than that of the Fengcheng Formation. The Fengcheng Formation was deposited in a strongly reducing, high-salinity, and water-stratified sedimentary environment. The other three formations were deposited in an oxidizing–reducing, low-salinity, and water-unstratified environment. They are characterized by the predominance of mudstone over carbonate rocks and the descending distribution type of tricyclic terpenes. Our results provide a basis for research on upper Paleozoic source rocks in western China, and useful information for oil and gas exploration in the Mahu Sag.

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

Energy Exploration & Exploitation ◽

10.1177/0144598719892901 ◽

2019 ◽

Vol 38 (3) ◽

pp. 654-681 ◽

Cited By ~ 2

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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Petroleum Geochemistry of the Loperot-1 Well in Lokichar Basin, Kenya

10.2118/afrc-2557372-ms ◽

2016 ◽

Cited By ~ 1

Author(s):

David M. Katithi ◽

David O. Opar

Keyword(s):

Organic Matter ◽

Source Rock ◽

Shale Gas ◽

Source Rocks ◽

Geochemical Data ◽

Mature Stage ◽

Type I ◽

Hydrocarbon Generation ◽

Gas Generation ◽

Gas Targets

ABSTRACT The work reports an in-depth review of bulk and molecular geochemical data to determine the organic richness, kerogen type and thermal maturity of the Lokhone and the stratigraphically deeper Loperot shales of the Lokichar basin encountered in the Loperot-1 well. Oil-source rock correlation was also done to determine the source rocks’ likelihood as the source of oil samples obtained from the well. A combination of literature and geochemical data analyses show that both shales have good to excellent potential in terms of organic and hydrogen richness to act as conventional petroleum source rocks. The Lokhone shales have TOC values of 1.2% to 17.0% (average 5.16%) and are predominantly type I/II organic matter with HI values in the range of 116.3 – 897.2 mg/g TOC. The Lokhone source rocks were deposited in a lacustrine depositional environment in episodically oxic-dysoxic bottom waters with periodic anoxic conditions and have Tmax values in addition to biomarker signatures typical of organic matter in the mid-mature to mature stage with respect to hydrocarbon generation and immature for gas generation with Ro values of 0.51 – 0.64%. The Loperot shales were shown to be possibly highly mature type II/III source rocks with TOC values of 0.98% – 3.18% (average 2.4%), HI of 87 – 115 mg/g TOC and Ro of 1.16 – 1.33%. The Lokhone shale correlate well with the Loperot-1 well oils and hence is proposed as the principal source rock for the oils in the Lokichar basin. Although both source rocks have good organic richness to act as shale gas plays, they are insufficiently mature to act as shale gas targets but this does not preclude their potential deeper in the basin where sufficient gas window maturities might have been attained. The Lokhone shales provide a prospective shale oil play if the reservoir suitability to hydraulic fracturing can be defined. A basin wide study of the source rocks thickness, potential, maturation and expulsion histories in the Lokichar basin is recommended to better understand the present-day distribution of petroleum in the basin.

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Hydrocarbon generation potential evaluation of coal shale gas of Permo-Carboniferous in Jiyang Depression

Journal of Geological Research ◽

10.30564/jgr.v1i2.893 ◽

2019 ◽

Vol 1 (2) ◽

Author(s):

Pingping Li ◽

Dawei Lv ◽

Huiyong Wang ◽

Changyong Lu

Keyword(s):

Organic Matter ◽

Shale Gas ◽

Source Rocks ◽

Maturity Stage ◽

Hydrocarbon Generation ◽

Gas Generation ◽

Jiyang Depression ◽

Hydrocarbon Generation Potential ◽

Hydrocarbon Source Rocks ◽

Generating Capacity

This paper studied the residual strata distribution of Carboniferous-Permian in Jiyang Depression, the organic geochemical characteristics of shale and the correlation of hydrocarbon-generating potential of shale by applying geochemistry, petroleum geology and coal geology, for study hydrocarbon generation potential of Permo-Carboniferous coal shale in Jiyang Depression. The results show that the thickness of Carboniferous-Permian residual strata in Jiyang Depression is generally 200-800 m, the thickest can reach 900 m; coal shale has good organic matter abundance and is type III kerogen, which is conducive to gas generation, and organic matter maturity reaches maturity-higher maturity stage; Benxi Formation and Taiyuan Formation have better hydrocarbon generation potential; medium to good hydrocarbon source rocks can be found in every sag of Shanxi Formation hydrocarbon source rocks, but the scope is limited, and the overall evaluation is still medium. Compared with other areas in China, it is found that the hydrocarbon-generating capacity of coal-bearing shale of Carboniferous-Permian in Jiyang Depression is generally at a medium level, which has a certain shale gas exploration potential.

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Modeling Hydrocarbon Generation of Deeply Buried Type Ⅲ Kerogen: A Study on Gas and Oil Potential of Lishui Sag, East China Sea Shelf Basin

Frontiers in Earth Science ◽

10.3389/feart.2020.609834 ◽

2021 ◽

Vol 8 ◽

Author(s):

Jinliang Zhang ◽

Yang Li ◽

Jinshui Liu ◽

Xue Yan ◽

Lianjie Li ◽

...

Keyword(s):

Organic Matter ◽

Source Rocks ◽

Hydrocarbon Potential ◽

Generation Model ◽

Hydrocarbon Generation ◽

Type Ii ◽

The West ◽

Organic Matter Sources ◽

Type Iii

The hydrocarbon generation model and hydrocarbon potential are investigated in the Lishui Sag, based on gold-tube pyrolysis experiments of deeply buried type Ⅲ kerogen. From this, we discuss the classification of kerogen types of source rocks with mixed organic matter sources. The hydrocarbon generated from the source rocks of the Lingfeng Formation and Yueguifeng Formation is dominated by natural gases with little oil in the West subsag, and the hydrocarbon generation model of the Lingfeng Formation is similar to that of Yueguifeng Formation, but the gas potential of Lingfeng Formation is higher than that of Yueguifeng Formation. The hydrocarbon potential of the Yueguifeng Formation in the East subsag is much higher than the West subsag, and it has considerable oil potential. Macerals diversity of source rocks is responsible for the difference of hydrocarbon generation characteristics for type Ⅲ kerogen in the Lishui Sag. It is not rigorous to evaluate the hydrocarbon potential of kerogen only based on pyrolysis parameters. Application of kerogen type index (KTI) can improve the accuracy of the classification of kerogen types with mixed organic matter sources. According to the classical kerogen classification template, the selected samples belong to type III kerogen. In this article, the selected samples were further subdivided into type III and type II/III based on the KTI value. Type III kerogen (0.5 ≤ KTI < 1.5) mainly produces gas, and type II/III kerogen (1.5 ≤ KTI < 5) mainly produces gas, but its oil potential is higher than that of type III.

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Climate-Provenance Effect on the Organic Matter Enrichment of the Chang 9 Source Rocks in the Central Ordos Basin, China

Geofluids ◽

10.1155/2021/1233879 ◽

2021 ◽

Vol 2021 ◽

pp. 1-10

Author(s):

Ling Ma ◽

Zhihuan Zhang ◽

Weiqiu Meng

Keyword(s):

Organic Matter ◽

Chemical Weathering ◽

Ordos Basin ◽

Source Rocks ◽

Sediment Provenance ◽

Type I ◽

Hydrocarbon Generation ◽

Hydrocarbon Generation Potential ◽

Primary Producer ◽

Geochemical Analyses

The Upper Triassic Chang 9 organic-rich sediments have been considered as effective hydrocarbon source rocks for the Mesozoic petroleum system in the Ordos Basin. Previous studies on the Chang 9 member mostly focused on the influence of their paleoproductivity and paleoredox conditions on the organic matter (OM) enrichment, whereas there are few studies on the influence of the paleoclimate condition and sediment provenance on the OM enrichment. In this study, a series of geochemical analyses was performed on the Chang 9 core samples, and their hydrocarbon generation potential, paleoclimate condition, and sediment provenance were assessed to analyze the effect of paleoclimate-provenance on OM enrichment. The Chang 9 source rocks are characterized by high OM abundance, type I−II OM type, and suitable thermal maturity, implying good hydrocarbon generation potential. Based on the C-values and Sr/Cu ratios, the paleoclimate condition of the Chang 9 member was mainly semihumid. In addition, the Th/Co vs. La/Sc diagram and negative δEuN indicate that the Chang 9 sediments were mainly derived from felsic source rocks. Meanwhile, the paleoweathering intensity of the Chang 9 member is moderate based on moderate values of CIA, PIA, and CIW, which corresponds to the semihumid paleoclimate. The relatively humid paleoclimate not only enhances photosynthesis of the primary producer, but also promotes chemical weathering intensity, leading to suitable terrestrial clastic influx to the lacustrine basin, which is beneficial for OM enrichment.

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Use of petrological and organic geochemical data in determining hydrocarbon generation potential of coals: miocene coals of Malatya Basin (Eastern Anatolia-Turkey)

International Journal of Coal Science & Technology ◽

10.1007/s40789-020-00376-3 ◽

2020 ◽

Author(s):

Nazan Yalcin Erik ◽

Faruk Ay

Keyword(s):

Organic Matter ◽

Vitrinite Reflectance ◽

Hydrogen Index ◽

Quality Data ◽

Geochemical Data ◽

Mineral Matter ◽

Hydrocarbon Generation ◽

Thermal Maturity ◽

Hydrocarbon Generation Potential ◽

Northern District

AbstractWith this study, the hydrocarbon generation potential of Miocene aged coals around Arguvan-Parçikan in the northern district of Malatya province was evaluated with the aid of petrological and organic geochemical data. According to organic petrography, coal quality data, and low thermal maturity, the Arguvan-Parçikan coals are of high-ash, high-sulfur subbituminous B/C rank. The organic fraction of the coals is mostly comprised of humic group macerals, with small percentages derived from the inertinite and liptinite groups. The mineral matter of the coals is comprised mainly of calcite and clay minerals. The total organic carbon (TOC, wt%) values of the shale and coal samples are between 2.61 wt% and 43.02 wt%, and the hydrogen index values are between 73 and 229 mg HC/g TOC. Pyrolysis (Tmax, PI), huminite/vitrinite reflectance (Ro, %), and biomarker ratios (CPI, Pr/Ph ratio, Ts/(Ts + Tm) ratio, C32 homohopane ratio (22S/22S + 22R) and C29ββ/(ββ + αα sterane ratio) indicate that the organic matter of the studied coals is thermally immature. When all these data are taken together, Miocene aged coals around Arguvan are suitable for hydrocarbon generation, especially gas, in terms of organic matter type (Type III and Type II/III mixed), organic matter amount (> 10 wt% TOC), however, low liptinitic macerals (< 15%–20%), low hydrogen index (< 200 mg HC/g TOC) and low thermal maturity values inhibit the hyrocarbon generation.

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