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Article

Gas Generation Potential of Permian Oil-Prone Source Rocks and Natural Gas Exploration Potential in the Junggar Basin, NW China

by
Abilimit Yiming
1,
Xiujian Ding
2,*,
Liangrong Qian
2,
Hailei Liu
1,
Maoguo Hou
2 and
Zhongfa Jiang
1
1
Research Institute of Exploration and Development, PetroChina Xinjiang Oilfield Company, Karamay 834000, China
2
School of Geosciences, China University of Petroleum, Qingdao 266580, China
*
Author to whom correspondence should be addressed.
Appl. Sci. 2022, 12(22), 11327; https://doi.org/10.3390/app122211327
Submission received: 27 August 2022 / Revised: 6 November 2022 / Accepted: 6 November 2022 / Published: 8 November 2022
Browse Figures
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Abstract

:
The Junggar Basin, where twenty-seven oil fields and five gas fields have been discovered, is a typical “oil basin” with proven ratio of natural gas of 5.3%. The amount of natural gas from Permian source rocks has been found in the western margin of the basin, but no large-scale natural gas reservoir has been discovered. The key to natural gas exploration is whether Permian oil-prone source rocks have large gas generation potential. Based on the comprehensive analysis of geochemical features and hydrocarbon generation simulation experiments, it is proved that the gas generation intensity could meet the standard of medium to large gas-fields (20 × 108 m3/km2) at a depth of more than 6500 m. In the Penyijing and Shawan Sags, the burial depth of the Fengcheng Formation source rocks is between 8500 m and 10,000 m, respectively. It could be concluded that the Permian source rocks in the Penyijingxi and Shawan Sags have relative higher gas generation potential. In addition to high natural gas generation potential, two sets of effective reservoirs (wreathing volcanic rocks and secondary dissolution of sandy conglomerates) and thick caprocks with overpressure are developed in the most areas of Junggar Basin. Recently, natural gas reservoirs have been discovered and industrial natural gas had been obtained around the Penyijingxi Sag, Shawan Sags, and the Southern margin of the Junggar Basin. Our research results and natural gas exploration practice show that the Junggar Basin have relatively large natural gas exploration potential.

1. Introduction

The Junggar Basin is one of the large petroliferous basins in northwestern China [1,2]. More than sixty years of petroleum exploration show that the Junggar Basin is rich in oil and poor in natural gas [3]. Currently, twenty-seven oil fields and five gas fields have been discovered, and the proven ratio of natural gas discoveries is only 5.3%.
In the Junggar Basin, it had been found that the natural gas mainly comes from Carboniferous, Permian, and Jurassic source rocks ([1]. The Carboniferous source rocks were deposited primarily on residual sea and its distribution was limited [4,5], which makes the gas generation potential of the Carboniferous source rocks relatively minor. Due to the shallow burial depth, the Jurassic source rocks have low organic maturity (Ro < 0.7%) and limited gas generation potential. Neither the Carboniferous nor the Jurassic source rocks have the potential to generate a large gas field, the gas generation potential of Permian source rock are therefore the critical factor to natural gas exploration in the Junggar Basin.
Natural gas sourced from Permian source rocks has been found in the Mahu, Penyijingxi, and Shawan sags located in the Western region of the Junggar Basin. There are still no large-scale natural gas reservoirs that have been discovered. It is uncertain whether the Permian source rock has natural gas generation potential, although it is the primary oil source rock in the Western Junggar Basin [6,7]. The geochemical characteristics and distribution of the Permian oil-prone source rocks and the potential of natural gas exploration were discussed. Recently, the potential of natural gas exploration has been proved partly by the exploration wells.

2. Geological Setting

The Junggar Basin is one of the most essential hydrocarbon-bearing basins in northwestern China, with an area of 13.6 × 104 km2 [8]. The Junggar Basin is located in the west of the Junggar–Tuha Plate and connects with the Western Junggar Orogenic Belt, as shown in Figure 1 [9,10]. Many oil and a few gas fields have been discovered through some decades of hydrocarbon exploration (Figure 1). Much progress has been made and commercial shale oil flow has been recently obtained from the Permian rock units. Therefore, the Junggar Basin has become a hot topic of petroleum exploration in China [11].
The basement of the Junggar Basin is of the Carboniferous age. The sedimentary fill of this basin comprises sedimentary units ranging in age from the Permian to the Quaternary [12], as shown in Figure 2. The Carboniferous stratigraphy of the Junggar Basin mainly deposits volcanic rocks and shallow marine clastic rocks [13]. In the Early and Middle Permian, the Junggar Basin developed several depositional and subsidence centers, mainly fan-deltaic and lacustrine sediments [14], which are the most critical source rocks [15]. From Late Permian to Triassic, the Junggar Basin underwent a high subsidence phase. The Late Permian basins have a reduced distribution and a limited distribution of hydrocarbon source rocks. The Triassic basin is more extensive than the Upper Permian, and a basin-covering layer system developed. During Jurassic times, a set of continental coal-bearing deposited and associated shallow water sediments were deposited.

3. Source Rocks Geochemical Characteristics and Distribution

As mentioned above, the natural gas generation potential of the Permian source rocks is the key to achieving breakthrough in natural gas exploration. The Permian source rock mainly consists of the Jiamuhe Formation, the Fengcheng Formation, and the Lower Wuerhe Formation [10]. Since the distribution of hydrocarbon source rocks of the Jiamuhe Formation are relatively limited and the quality of source rocks of the Lower Wuerhe Formation are poor, only the geochemical characteristics of source rocks in the Fengcheng Formation are discussed. The geochemical features of source rocks include organic matter abundance, type, and maturity.

3.1. Organic Matter Abundance

Organic matter abundance is one of the main indexes to determine the hydrocarbon generation potential. At present, the commonly used organic matter abundance indexes mainly include total organic carbon content (TOC), chloroform asphalt “A”, and total hydrocarbon content (HC), as well as rock pyrolysis hydrocarbon generation parameters S1 (free hydrocarbon) and S2 (pyrolysis hydrocarbon), among which organic carbon content (TOC) and rock pyrolysis hydrocarbon generation parameters are commonly used [16].
The source rocks of the Permian Fengcheng Formation were widely drilled in the Mahu Sag. The TOC ranges from 0.1% to 4.0%. The main distribution of S1 + S2 ranges from 0.02 mg/g to 30 mg/g (Figure 3), suggesting that the source rocks are relatively fair, and good to excellent, according to the guidelines of reference [17].

3.2. Organic Matter Types

The types of kerogen have an obvious influence on the hydrocarbon generating ability. Type I kerogen has high original hydrogen content, low oxygen content, and the most substantial oil generating ability. The hydrogen content of type II kerogen is higher but slightly lower than that of type I kerogen. Type III kerogen has low original hydrogen content and high oxygen content. Its oil generating ability is poor, and it primarily generates natural gas.
The kerogen elemental diagram is the standard method to determine the type of organic matter. The H/C of kerogen in the Fengcheng Formation source rock is as high as 1.8, as shown in Figure 4. The main types of kerogen are type I and type II1, and the proportion of type II1 organic matter is relatively high, mainly humic organic matter. At the present phase of the hydrocarbon exploration no exploratory well has been drilled to the center of hydrocarbon producing sag. The source rock samples are mainly distributed in the slope area with shallow water bodies.

3.3. Organic Matter Maturity

Vitrinite reflectance (Ro) is the most commonly used index to determine the maturity of organic matter. Ro of hydrocarbon source rocks varies widely in the central depression of the Junggar Basin, up to 2.0% or more [18]. The maturity of the source rocks from the Fengcheng Formation varies greatly and low to high maturity stage have been measured [18]. It is generally believed that source rocks in the Fengcheng Formation had entered the phase of oil generation in the Mahu, Penyijingxi, and Shawan sags.

3.4. Distribution of Source Rocks

The source rocks revealed by drilling are mainly distributed around sag, and distribution of source rocks in sag is mainly predicted based on seismic due to lack of drilling data. The quality of seismic data has been poor for a long time and it isn’t easy to characterize the distribution of source rocks in the Junggar Basin. Several basin-level 2D seismic grid lines were acquired in the Junggar Basin from 2018 to 2020. The imaging quality of deep seismic data was significantly improved through the combined processing of 2D survey lines and 3D seismic. The distribution characteristics of mudstone can be defined through the description of formation thickness. We consider the mudstone thickness to characterize the hydrocarbon source rock distribution because most of the mudstone samples of the Fengcheng Formation have TOC’s greater than 0.5%.
The distribution of the Permian source rocks in the western part of the basin is described, as shown in Figure 5. The source rocks of the Permian Fengcheng Formation are widely distributed in the three sags of the basin’s western region, with a thickness more than 100 m.
In summary, the Permian source rocks in the Junggar Basin have high organic matter abundance and are mainly medium-good hydrocarbon source rocks, with organic matter type II, and are developed from low to high maturity. They are primarily distributed in the Mahu, Penyijingxi, and Shawan sags in the western part of the basin.

4. Gas Generation Potential

Several decades’ petroleum exploration had proved the Fengcheng Formation hydrocarbon source rock potential, being the principal source of the billion-ton big oil play in the central area of the Mahu Sag. Although early explorations have confirmed that associated gas is common in the oil from the Fengcheng source rocks [19], there is still a lack of relevant research on whether the source rocks of the Fengcheng Formation can generate gas on a large scale.

4.1. Hydrocarbon Generation Simulation

To reveal the gas generation potential of the Fengcheng Formation source rocks, hydrocarbon generation simulation experiments were carried out to evaluate their gas generation potential. The hydrocarbon generation simulation experiment is the most intuitive method to evaluate the gas potential of source rocks.
Currently, the commonly used hydrocarbon generation simulation methods mainly include Rock-Eval pyrolysis hydrocarbon generation, autoclave confined space hydrocarbon generation and gold tube hydrocarbon generation simulation [20,21]. Rock-Eval pyrolysis hydrocarbon generation is carried out in an open system under atmospheric pressure. It is easy to operate and can analyze various hydrocarbon components online with a single injection. However, this experimental system does not consider the influence of formation water and pressure on hydrocarbon generation process, so it differs significantly from the natural geological background. The autoclave confined space hydrocarbon generation simulation is carried out in an ample hydrocarbon generation space with low fluid pressure and no hydrostatic pressure, and the influence of formation water and pressure on hydrocarbon generation process is not considered enough [22]. The gold tube hydrocarbon generation simulation experiment is more suitable for hydrocarbon simulation of pure kerogen because the space of the gold tube is small, and the sample used is of milligram level. The error of quantitative analysis of hydrocarbon products is more significant, but the hydrocarbon simulation of kerogen ignores the influence of inorganic minerals on hydrocarbon formation. In addition, the pressure inside the gold tube can be changed by adjusting the water pressure of the autoclave outside the gold tube. Still, due to the deformation of the gold tube and the uncertainty of the number of products generated, it is doubtful whether the fluid pressure inside the gold tube is equal to the external pressure [23].
Considering different hydrocarbon generation simulation methods, the DK-II type of formation pore thermal pressure hydrocarbon generation and discharge simulation instrument developed by the Wuxi Institute of Petroleum Geology of Sinopec Petroleum Exploration and Development Research Institute was selected. We consider the limited space, overlying formation pressure, the internal fluid pressure of source rock and temperature of the hydrocarbon generation process thoroughly, to restore the hydrocarbon generation process of source rock under geological conditions to the greatest extent.
Since the Fengcheng Formation source rocks were only drilled in the Mahu Sag, were selected for hydrocarbon generation simulation experiments in this study. And the information on sample parameters is shown in Table 1.
The oil and gas production rate at different evolutionary stages of each sample was obtained by conducting a hydrocarbon generation simulation experiment. Dai Jinxing et al. ([24] made statistics on the gas generation intensity of the large and medium-sized gas fields discovered in China, and found that the gas generation intensity was all greater than 20 × 108 m3/km2. The latter authors concluded that the gas generation intensity greater than 20 × 108 m3/km2 was one of essential conditions for forming large and medium-sized gas fields [24]. The values of the gas generation intensity of the Fengcheng Formation source rocks reaches 20 × 108 m3/km2 at 425 °C (Figure 6), meaning that the gas generation intensity of the Fengcheng Formation source rocks could reach the essential condition of large and medium-sized gas fields at 425 °C. The gas generation intensity calculation was based on the rock density of 2.5 g/cm3 and the average source rock thickness of 150 m.
The vitrinite reflectance (Ro) of source rock samples at each simulated temperature point was measured during the hydrocarbon generation simulation experiment, and the Ro corresponding to 425 °C was about 1.45%. The relationship between the gas generation intensity and burial depth of source rock was deduced according to the relationship between Ro and burial depth.
In general, the relationship between Ro and burial depth is exponential. With the increase in depth, the growth rate of Ro gradually slows down [25]. It is indicated that the Ro at abnormally high pressure does not match its thermal history and is lower than that under the normal pressure condition (Figure 7). Previous studies have shown that overpressure may retard the evolution of organic matter and suppress the increase of Ro.
According to the statistics of the pressure coefficient variation with depth in the western part of the basin, it is evident that the pressure coefficient at 4000 m is more than 1.2, indicating abnormal high pressure (Figure 7a). There are apparent differences in the degree of abnormal development in different regions. The pressure coefficient of the Well MS 1 is higher, with a pressure coefficient of more than 2, which is close to the rock breakdown pressure, and may be the maximum pressure that could be developed. The degree of abnormal pressure development in the Well DT 1 is relatively lower, with a pressure coefficient distributed in the range of 1.2~1.35. Considering that most of the pressure coefficients deeper than 4000 m are above 1.2, it could be assumed that the pressure development of Well DT 1 is the lowest in the study area.
The overpressure retardation of organic matter maturation is evident, with its depth exceeding 4000 m (Figure 7b). The higher the overpressure, the stronger the effect on the retardation of organic matter maturation. Thus in Well MS1, with the highest overpressure, the pressure coefficient is 2.0; it could be deduced that for a depth of 7000 m, the predicted Ro is 1.45%. Taking Well DT1 with the weakest overpressure, the pressure coefficient is between 1 and 1.5, and the predicted Ro is 1.45% at the depth of 6000 m. Therefore, it could be concluded that when the average burial depth is than over 6500 m, the Ro of the Fengcheng Formation source rock is about 1.45%, and the gas generation intensity can reach 20 × 108 m3/km2.

4.2. Controlling Factors of Natural Gas Generation Retardation

The Fengcheng Formation source rocks in Junggar Basin entered the stage of large-scale gas generation at a depth of about 6500 m, which is more remarkable than the traditional understanding. Comprehensive analysis suggests that overpressure and low geothermal gradient were the main controlling factors for the larger-scale gas generation retardation.
(1)
Low geothermal gradient
The geothermal gradient of the Junggar Basin is relatively low. The current geothermal gradient is about 2.1 °C/100 m, which is significantly lower than that of Basin located in eastern China, such as Yinggehai Basin (about 3.1~4.3 °C/100 m, reference [26]) and Bohai Bay Basin (about 3.5 °C/100 m, reference [27]).
A low geothermal gradient has a noticeable influence in the hydrocarbon generation of source rocks. To reveal the influence of low geothermal gradient on the evolution of source rocks, PetroMod simulation software is used to simulate the hydrocarbon generation process of source rocks with TOC of 3% and HI of 600 mg/g under the background of geothermal gradients of 2.1 °C/100 m (representing Junggar Basin) and 3.5 °C/100 m (representing eastern China Basin). It is found that the beginning depth of abundant gas generation with a geothermal gradient of 2.1 °C/100 m is 2000 m more than with a geothermal gradient of 3.5 °C/100 m.
The hydrocarbon generation modeling results show that the geothermal gradient has influence on natural gas generation, and the low geothermal gradient causes gas generation retardation.
(2)
Overpressure
In addition to lower paleo-temperature affecting hydrocarbon generation, overpressure is an essential factor affecting natural gas generation. Overpressure is developed in the Junggar Basin. It has been mentioned above that there is overpressure development with a pressure coefficient of 1.2~2.0 in the depth of more than 4000 m. Ro of source rocks in depth of more than 4000 m is significantly lower (Figure 7), indicating that overpressure is another controlling factor in natural gas generation retardation.

5. Natural Gas Exploration Potential

5.1. Hydrocarbon Generation

The Permian Fengcheng Formation source rocks in the Junggar Basin have a high abundance of organic matter, suitable organic matter types, and moderate organic matter maturity evolution. Based on the study of geochemical characteristics, distribution, and gas generation potential, it could be concluded that the Fengcheng source rock can generate medium to large-scale natural gas reservoirs in the depths of more than 6500 m.
The burial depth of the Fengcheng source rocks in the Mahu Sag is generally less than 6500 m, and several decades’ hydrocarbon explorations show that the resources are mainly oil and less natural gas. Despite the number of exploration wells drilled in the sag for shale oil exploration, no large-scale natural gas reservoirs have been found.
In the Penyijingxi and Shawan Sags, the burial depth of the Fengcheng Formation source rocks is at depth between 8500 m and 10,000 m, respectively. As the burial depth is far greater than 6500 m, it could be concluded that the Fengcheng source rocks in the Penyijingxi and Shawan Sags have great potential of natural gas generation. Recently, natural gas reservoirs have been found around the Penyijingxi and Shawan sags, and several exploration wells have achieved the industrial gas flow standards in their production. In summary, the oil and natural gas exploration status is consistent with the research on the natural gas generation potential of Fengcheng Formation source rocks.
Furthermore, in addition to the Fengcheng Formation source rocks, the burial depth of Jurassic source rocks in the southern margin of the Junggar Basin is over 10,000 m. And the Jurrassic coal-bearing source rocks are widely distributed, with high organic matter abundance, mainly Type-II and Type-III organic matters, and high natural gas generation potential [28,29].
In summary, both the Permian source rocks in the Penyijingxi and Shawan sags and the Jurrassic source rocks in the southern margin of the Junggar Basin have a relatively higher potential of natural gas generation.

5.2. Quality of Reservoir

Both volcanic reservoirs and clastic reservoirs are natural gas reservoirs in the Junggar Basin. The volcanic reservoirs are mainly distributed in the Carboniferous and Early Permian. The volcanic reservoirs lithology is mainly andesite and dacite, followed by tuff and volcanic breccia. The lithofacies are mainly consists of intermediate-acid effusive faceies, followed by explosive facies. The volcanic reservoirs are highly heterogeneous, with primary pores, secondary dissolution pores and fractures [30,31]. Usually, the physical properties of volcanic reservoirs are controlled by lithology and weathering process, not by burial depth [32]. Previous research showed that the equilibrium thickness of weathered is about 550 m, and the maximum porosity is as high as 23% [33]. The weathered crust of volcanic reservoirs are distributed in the Western Uplift, Eastern Uplift, Luliang Uplift, and the Mosuowan Uplift, Mobei Uplift, Shixi Uplift in the Central Depression, nearly account for half of the Junggar Basin [34].
The clastic reservoirs lithology is sandstones and sandy conglomerates. The sandstone is mainly distributed in the Jurassic. Due to shallow depths, the Jurassic sandstone usually has much better physical properties with porosity greater than 12%. The sandy conglomerate is mainly distributed in the Permian. Due to the second dissolution, the sandy conglomerate still had a porosity greater than 10% at a depth of 6000 m.
In summary, both the wreathing volcanic rocks and secondary dissolution of sandy conglomerates are effective reservoirs for natural gas accumulation.

5.3. Caprock

The preservation condition is one of the key factors controlling natural gas accumulation. There are three separate sets of regional mudstone caprocks developed in the Permian, Triassic, and Cretaceous. The Permian regional caprocks, with average thickness of 200 m, are mainly developed in the central Depression. The Triassic regional caprocks have a much greater thickness (150 m~940 m) and mainly distributed in the southern margin of the Junggar Basin. The Cretaceous caprocks are developed nearly entire basin, with average thickness about 1000 m. Besides the huge thickness, the Permian region caprocks, which also are the essential caprocks for natural gas reservoirs, usually develop overpressure. For instance, the Permian caprocks pressure coefficient of the Well MS 1 could reach 2.2. Both huge thickness and high overpressure are essential for natural gas reservoir preservation.

5.4. Natural Gas Exploration Potential

Historically, Junggar Basin is rich in oil and poor in natural gas, and usually considering as a typical “oil basin”. The ratio of proved natural gas reservoirs to oil reservoirs being only 0.06:1, and the natural gas exploration has seen no breakthrough until 2019 [34]. Since 2020, several exploration wells production have achieved the industrial gas flow standards, the natural gas exploration potential should be paid attention.
Around the Penyijingxi and Shawan Sags, several exploration wells’ (SX 16, SX 18, etc.) production have achieved the industrial gas flow standards. In the southern margin of the Junggar Basin, a significant breakthrough in natural gas exploration has been achieved by the exploration wells GT 1 and HT 1, which confirms the sizeable natural gas exploration potential in the southern margin of the basin.
In summary, the oil and natural gas exploration status is consistent with the research on the natural gas generation potential of the Fengcheng Formation source rocks, and it is believed that the Junggar Basin may have huge natural gas exploration potential.

6. Conclusions

(1)
The Permian Fengcheng Formation source rocks in the Junggar Basin have abundant organic matter, good suitable organic matter types. Hydrocarbon generation simulation experiments show that oil-prone Fengcheng Formation source rocks have strong gas generation potential, reaching the gas generation standard (20 × 108 m3/km2) of medium to large gas fields.
(2)
Low geothermal gradient and overpressure are the main controlling factors on natural gas generation retardation, causing oil-prone source rock to have considerable natural gas generation potential for depth below 6500 m.
(3)
In addition to high natural gas generation potential, two set of effective reservoirs (wreathing volcanic rocks and secondary dissolution of sandy conglomerates) and thick caprocks with overpressure are developed in the most areas of Junggar Basin. Combined with natural gas exploration practice shows that the Junggar Basin have relatively large natural gas exploration potential.

Author Contributions

Conceptualization, A.Y. and X.D.; Formal analysis, L.Q.; Funding acquisition, H.L.; Investigation, M.H.; Methodology, Z.J. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by Major projects of PetroChina science and technology [2021DJ0206].

Institutional Review Board Statement

Not applicable.

Informed Consent Statement

Not applicable.

Acknowledgments

We thank the editor and three anonymous reviewers for their insightful reviews, which greatly improved the article. We also thank Xinjiang Oil Field Company, PetroChina, for providing access to the cored rock samples.

Conflicts of Interest

The authors declare that they have no known competing financial interest or personal relationships that could have appeared to influence the work reported in this paper.

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Figure 1. Location of Junggar Basin and study area in the Basin (Modified after reference [10]). (a) geotectonic setting of the Junggar Basin; (b) tectonic unit of the Junggar Basin; (c) study area tectonic unit and petroleum, exploration well distribution. Reprinted with permission from Ref. [10]. 2020, Elsevier.
Figure 1. Location of Junggar Basin and study area in the Basin (Modified after reference [10]). (a) geotectonic setting of the Junggar Basin; (b) tectonic unit of the Junggar Basin; (c) study area tectonic unit and petroleum, exploration well distribution. Reprinted with permission from Ref. [10]. 2020, Elsevier.
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Figure 2. Lithological stratigraphy in the Junggar Basin (After reference [10]). Reprinted with permission from Ref. [10]. 2020, Elsevier.
Figure 2. Lithological stratigraphy in the Junggar Basin (After reference [10]). Reprinted with permission from Ref. [10]. 2020, Elsevier.
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Figure 3. Crossplot of TOC and S1 + S2 of the Permian Fengcheng Formation source rocks.
Figure 3. Crossplot of TOC and S1 + S2 of the Permian Fengcheng Formation source rocks.
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Figure 4. Kerogen types of source rocks of the Permian Fengcheng Formation.
Figure 4. Kerogen types of source rocks of the Permian Fengcheng Formation.
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Figure 5. Source rock thickness isoline map of the Permian Fengcheng Formation in the Junggar Basin.
Figure 5. Source rock thickness isoline map of the Permian Fengcheng Formation in the Junggar Basin.
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Figure 6. Hydrocarbon producing rate and gas generation intensity of the Fengcheng Formation.
Figure 6. Hydrocarbon producing rate and gas generation intensity of the Fengcheng Formation.
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Figure 7. Diagram of the relationship between pressure coefficient, Ro and depth of the Junggar Basin. (a) relationship between pressure coefficient and depth; (b) relationship between Ro and depth.
Figure 7. Diagram of the relationship between pressure coefficient, Ro and depth of the Junggar Basin. (a) relationship between pressure coefficient and depth; (b) relationship between Ro and depth.
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Table
Table 1. Geochemical parameters of simulated hydrocarbon generation samples.
Table 1. Geochemical parameters of simulated hydrocarbon generation samples.
SamplesLithologyTOC (%)IH (mg/g TOC)Tmax (°C)
S1Dolomitic mudstone3.05608436
S2Dolomitic mudstone2.37604446
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Yiming, A.; Ding, X.; Qian, L.; Liu, H.; Hou, M.; Jiang, Z. Gas Generation Potential of Permian Oil-Prone Source Rocks and Natural Gas Exploration Potential in the Junggar Basin, NW China. Appl. Sci. 2022, 12, 11327. https://doi.org/10.3390/app122211327

AMA Style

Yiming A, Ding X, Qian L, Liu H, Hou M, Jiang Z. Gas Generation Potential of Permian Oil-Prone Source Rocks and Natural Gas Exploration Potential in the Junggar Basin, NW China. Applied Sciences. 2022; 12(22):11327. https://doi.org/10.3390/app122211327

Chicago/Turabian Style

Yiming, Abilimit, Xiujian Ding, Liangrong Qian, Hailei Liu, Maoguo Hou, and Zhongfa Jiang. 2022. "Gas Generation Potential of Permian Oil-Prone Source Rocks and Natural Gas Exploration Potential in the Junggar Basin, NW China" Applied Sciences 12, no. 22: 11327. https://doi.org/10.3390/app122211327

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