Abstract
The Turpan-Hami Basin has been considered as the most typical coal-derived-oil basin in China for a long time. However, with the deepening exploration, this theory has caused increasing controversy and some scholars doubt that Permian or Jurassic dark mudstone may be the main source rocks. The origin uncertainty even restricts deciding the exploration direction. Taking the reservoirs of the northern piedmont belt as an example, this paper analyzed oil sources by the geochemical characteristic comparison of inclusions, crude oil, and source rocks. Combined with the previous studies, the hydrocarbon accumulation model is established. The results show that the geochemical characteristics of the inclusions and oil in most areas are obviously different. Most reservoirs are mixed-source reservoirs. The oil sources varied in different regions. In the area near Bogeda, C19+20TT and C28 sterane content in oil are high, indicating that coal and Permian lacustrine mudstone are main contributors. Far away from Bogeda, bounded by the thick coal seam of Xishanyao Formation, oil sources are quite different. Above it, C19+20TT is high and gammacerane and pregnane are low, C29>>C28>C27sterane, indicating that coal and carbonaceous mudstone are main sources. Under that, C21TT and C23TT content in the inclusions are high, C29≥C27>C28sterane, while C19+20TT and pregnane content in the oil are also high, indicating that it is a mixed oil system mainly derived from Jurassic lacustrine mudstone and coal. Lacustrine mudstone has higher contribution. This phenomenon is mainly related to different fault styles in different zones. Near Bogeda, strong stress caused vertical large faults developed, which connected Jurassic reservoirs and Permian source rocks. Far from Bogeda, the faults sliped along the thick coal seam, It is difficult for deep hydrocarbon to enter the shallow layer. In the future, it should be considered to look for the traps with relatively high-quality reservoir-cap combinations for exploration in the hydrocarbon supply window of effected hydrocarbon kitchens.
1. Introduction
The Turpan-Hami Basin, as one of the major petroliferous basins in West China, has been considered as the most typical coal-derived-oil basin in China for a long time [1], and hence, oil and gas exploration practice there has always been carried out under the guidance of the coal-derived hydrocarbon theory. However, with the deepening exploration and the progress in the experimental technology, the theory of coal-derived hydrocarbons has caused increasing controversy. At present, there are three main opinions. Among them, two still claim that most Jurassic crude oil comes from coal-bearing formations, and yet both emphasize that the wording “source rock of coal-bearing systems” with no deep-going description may provide no practical guidance on exploration. These two opinions state that the contributions of coal seams and dark mudstone are varied. One claims that dark mudstone is the most important source rock [2, 3], and the contributions of coal and carbonaceous mudstone to oil reservoirs in the coal-bearing system are limited. For example, in Northwest China, the macerals of some coal-bearing basins are similar to the Turpan-Hami Basin, but these basins have no discovery of coal-derived oil [4]. The other believes that coal should be the main source rock—some geochemical indicators of the Jurassic crude oil are closer to those of the coal seam, rather than those of the mudstone in the coal-bearing system [5, 6]. The third opinion highlights the importance of the Permian lacustrine source rock [7–9]. It is considered that the reserves currently found in the basin (more oil and less gas) obviously deviate from the hydrocarbon generation characteristics of vitrinite-rich source rock of a coal-bearing system (more gas and less oil) [9]—in other words, in the oil and gas reservoirs identified as being derived from the Jurassic coal-bearing source rock, a considerable part of hydrocarbons actually comes from the Permian lacustrine source rock. The similarity of geochemical indicators between the crude oil and the coal-bearing formations is just because of the concealing of the biomarkers of the Permian lacustrine crude oil, due to their absolute content greatly reduced by the higher thermal maturation.
At present, from an exploration point of view, the growth of oil and gas reserves in the Turpan-Hami Basin mainly depends on the rolling boundary expansion and peripheral extension of discovered oil and gas fields. It is an urgent issue to improve the currently low success rate of exploration and determine the strategic new fields and layers for future replacement. The unclear oil sources are one of the key factors restricting deciding the exploration direction. The northern piedmont belt is a typical embodiment of this issue. As one of the most important hydrocarbon-bearing structural belts in the Turpan-Hami Basin, it has great resource potential, with low exploration degrees and a resource proven rate less than 30%, especially for the lower petroleum system with the Permian Taodonggou Group as the source rock, which holds more than 60% of the remaining resources [10]. The discovery of the 100-million-ton-order Lukeqin heavy oil reservoir on the south slope of the Turpan-Hami Basin confirms that the Permian source rock in the Taibei Sag has great resource potential (Figure 1(a)). However, none of the oil and gas fields discovered by far in the northern piedmont belt, where the Permian source rock may be thickest, are identified as deriving from the Permian. Hence, where the hydrocarbons generated by this set of source rock accumulate and whether a considerable part of hydrocarbons from Permian charged into the present Jurassic reservoirs are two crucial geological puzzles for the subsequent exploration.
Previous studies more focus on the comparison of geochemical characteristics between crude oil and different types of source rock. Because crude oil represents the present oil and gas composition, if hydrocarbon source is single, the method and result are expected to be good. When present reservoirs are mixed-source system, the results may be affected, because the different maturity oil generated by different source rock has varied content of biomarkers and some information may be hidden. If reservoirs are considered to be mixed-oil system, there are obvious differences in the geochemical characteristics of oil and gas components in different occurrence states in the reservoir because of the different hydrocarbon generation and expulsion time of different source rocks. As a closed system, the fluid inclusion represents the paleo-hydrocarbon composition. The contained fluids are not prone to be affected by various secondary processes. By comparing the geochemical characteristics of inclusions and oil in the reservoir, the evolution process of oil and gas components can be better displayed [11]. Meanwhile, through the study of inclusion petrography, we can also observe the abundance and phase state of inclusion assemblages in different stages. After that, the filling intensity of oil and gas in each stage can be determined. At last, by comparing phase state of different inclusion assemblages and the current reservoir, the main contributors can be determined.
At present, the biomarker analysis technology for the mass fluid inclusion oil is highly mature [12]. Although the obtained information is the combination of multiple inclusions biomarker, the source information of hydrocarbons in different stage can be obtained by selecting the samples with inclusions in the same stage as far as possible. Therefore, this research determines the source of oil inclusions, mainly based on their carbon isotope ratios and gas chromatography-mass spectrometry (GC-MS) test results. Then, the identified sources of hydrocarbons are combined with the biomarker analysis of crude oil and previous research results on natural gas in the study area, to discuss the oil and gas source of each section of the northern piedmont belt in the Turpan-Hami Basin. The findings of this research provide theoretical support to determining the next exploration direction.
2. Regional Geological Background
The northern piedmont belt of the Turpan-Hami Basin, located in the north of the Taibei Sag, has a length of about 400 km from east to west, and the width varies from 5 to 20 km [13]. It is a thrust fold system formed by the Bogeda Mountain uplifting, characterized by the structural development characteristics of north-south belt-shaped zoning and east-west block-shaped zoning (Figure 1(a)). From north to south, it can be divided into the thrust nappe belt (the buried structure belt), central anticline belt, and thrust front belt (the southern fault-block slope belt) [13, 14]. The structural belts, such as Hongqicanbei, Guobeibei, Qiabei, and Kebei, belong to the thrust nappe belt; Hetaogou, Shanle, Zhaobishan, Hongqican, and Qialekan belong to the central anticline belt; Kekeya, Qiuling, and Yuguo belong to the thrust front belt. The structural style of the thrust nappe belt is mainly characterized by the overthrust of the old stratum to the new stratum (Figure 1(b)). The footwall of the overthrust belt is anticlines and fault-anticlines controlled by multiple basement-involved faults formed in the early stage. Affected by the nappe, the youngest stratum in most areas is Sanjianfang Formation or Xishanyao Formation of Middle Jurassic. The structural styles of the central anticline belt are mainly imbricate fan structure, thrust-opposite structure, and pop-up structure [14]. And many faults in this belt extend from basement to Paleogene, even Quaternary. As the distance from the orogenic belt becomes farther and the tectonic stress becomes weaker, the slippage layer of Xishanyao Formation (thick coal seam) has an important impact on the structural deformation style. Many shallow faults slip along the coal seam. In most areas of this belt, deep faults cannot extend to Middle Jurassic.
In terms of the regional position, the whole thrust-fold system is close to the hydrocarbon generation centers of two sets of source rocks, namely, the Jurassic Shuixigou Group and Permian Taodonggou Group [15] (Figures 1(c) and 2) and is thus considered a favorable directional area for oil and gas migration. The Jurassic Shuixigou Group includes two sets of coal measure source rocks, Badaowan Formation of Lower Jurassic and Xishanyao Formation of Middle Jurassic. During the sedimentary period of Badaowan Formation, Taipei Sag is in the sedimentary environment of shore shallow lake, and the source rock type is relatively good. Most of the organic matter types of coal measure dark mudstone belong to type II2, and the coal types are also relatively good [15]. The thickness of dark mudstone is more than 150 m, and the thickness of coal seam is about 10-40 m. The minerals of Jurassic dark mudstone in Turpan-Hami Basin are mainly composed of clay minerals and quartz, with a small amount of plagioclase (Figure 3). The of Badaowan Formation is 0.7%~1.3%. Shengbei depression is the highest, about 1.3%, followed by Qiudong and Xiaocaohu depression (about 1.0%) (Figures 2(b) and 2(c)). In the early sedimentary period of Xishanyao Formation, River marsh is developed. On the basis of stable tectonic subsidence, the swamp continues to spread and develop, forming very thick coal seams and carbonaceous mudstone, which are mainly distributed in Hetaogou-Kekeya-Shanle area. The maximum total thickness of coal seam is 216 m, and the maximum thickness of single layer is 43.2 m. Generally, there are 30~60 layers in these area. Vertically, they are mainly distributed in the second member of Xishanyao Formation (Xi-II Member) and also a set of good regional caprocks. The of Xishanyao Formation is 0.5%~1.00%, with an average of 0.72%. The source rocks in most areas of the piedmont zone are between 0.7 and 0.9%, and the Zhaobishan and the buried structure belt are basically less than 0.7 (Figure 2(a)). The coal rock macerals of Turpan-Hami Basin are mainly vitrinite, up to 50~90%, with an average of 70%. The content of inertinite is 2~67%, with an average of 20%. The content of crystite (including sapropelic group) is less than 10%, with an average of 7%. It mainly generates gas and has a certain oil generation capacity. The Permian lacustrine mudstone is too deep near the piedmont and has not been drilled. Based on outcrop, seismic, and other data, it is speculated that the thickness of Permian lacustrine mudstone in Taipei sag is between 100 and 300 m (Figure 2(d)), which has entered the high-mature evolution stage. For example, the dark mudstone of Talang section is 300 m thick, and the thickness of Zhaobishan section is nearly 300 m (Figure 3). The Permian dark mudstone is grayish black and black, with horizontal bedding and developed foliation. The minerals of Permian dark mudstone in Turpan-Hami Basin are mainly composed of clay minerals and quartz, with a small amount of feldspar and calcite, pyrite, and siderite [16]. The whole-rock maceral quantitative experiments show that the organic matter of Taodonggou Group source rocks is mainly vitrinite, and the vitrinite content can reach 40–90%, with an average of 74.5%. The content of exinite ranges from 5 to 24%, with an average of 13.25%. The content of inertinite ranges from 2 to 37% (%). Taodonggou Group source rocks are mainly type II [17], and TOC is between 0.90% and 3.42%.
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At present, the discovered hydrocarbons are mainly concentrated in the structural belt adjacent to the Jurassic hydrocarbon-generating sag (Shengbei Sag and Qiudong Sag), and no breakthrough has been made in the deeper layer or the piedmont buried structure belt. The representative examples include the Baka condensate gas field, Shanle oil field, and Zhaonan hydrocarbon-bearing structure. They are all structural reservoir. The main oil and gas bearing intervals of Baka condensate gas field are the first member of the Xishanyao Formation (Xi-I Member) and Sangonghe Formation, and Shanle oilfield is the fourth member of the Xishanyao Formation (Xi-IV Member), and Zhaobishan area is Sangonghe Formation. Because of the unclear understanding of the oil and gas distribution and the poor quality of seismic data, only a small number of wells have been deployed in the piedmont buried belt and deep layers of piedmont belt, and no breakthrough has been made. However, regional geological data show that there are still many sets of effective reservoir-cap assemblages in the deep layers of the buried belt and piedmont belt, which can be favorable strata for exploration. The main reservoir-cap assemblages from bottom to top include the following: ① Triassic Karamay sand and conglomerate as the reservoir and Triassic Haojiagou Formation thick mudstone as the caprock; ② the sandstone in the lower part of Badaowan Formation is the reservoir, and the mudstone and siltstone in the upper part are the caprock; ③ the sandstone of Sangonghe Formation is the reservoir, and the thick mudstone at the top of Sangonghe Formation is the caprock; ④ the sand and conglomerate of the Xi-I Member are reservoirs, and the thick coal seam of the Xi-II Member is caprock.
3. Experimental Samples and Methods
3.1. Samples
Some scholars believe that Kekeya crude oil is high maturity lacustrine oil based on crude oil adamantane compound analysis and lacustrine oil filled into Shanle reservoir by light hydrocarbon study. However, some biomarkers of the oil in these areas are more close to coal and carbonaceous mudstone biomarkers. Therefore, the inclusion samples collected in this study are mainly from Kekeya, Shanle, and Zhaobishan production intervals, and intervals with intensive oil and gas shows are used to analyze the evolution process of oil and gas components of these reservoirs. Eight wells in total are involved (Ke13, Ke19, Ke21, Ke24, Le1, Le2, Le3, and Zhao4) and contribute 25 core samples, which are specifically from Xi-IV Member, Xi-II Member, Xi-I Member, and the Sangonghe Formation. The lithology of the core samples is medium-coarse sandstone and fine sandstone. Among them, the samples of well Ke13 and well Le1 are from Xi-IV Member, the samples of well Ke19 are from Xi-II Member and Sangonghe Formation, the samples of well Ke21, well Le2, and well Le3 are from Sangonghe Formation, and the samples of well Ke24 are from Xi-I Member. In order to obtain better analysis results, more samples were collected in this study as much as possible, including the biomarkers of 13 crude oils and 5 sandstone extract samples. These samples mainly come from the main production intervals in different wells of different structural belts, which are basically consistent with the location of inclusion sampling.
3.2. Experimental Methods
First, the petrographic analysis is performed via the polarized fluorescence microscope using the fluid inclusion thin section, to identify the oil and gas inclusion assemblages. And the characteristics of fluid composition are investigated using the LABHR-VIS LabRAM HR800 research-grade microlaser Raman spectroscopy. Then, the samples with only one group of oil and gas inclusions or a group of samples with absolute advantages of inclusions are selected for inclusions GC-MS and carbon isotope ratio analysis. Nine samples are put through the GC-MS and carbon isotope ratio analysis using the Agilent 6890GC/5975iMs and FLASH HT EA-MAT 253 IRMS, and the petroleum geochemical characteristics of different inclusion assemblages are clarified. The GC-MS and carbon isotope analyses of inclusions are completed in the State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing), and the rest experiments are accomplished in the Beijing Research Institute of Uranium Geology.
The pretreatment of the GC-MS analysis of inclusions is key to experimentally investigating the geochemical characteristics of fluid inclusions. The treatment procedure includes six steps: ① Crush the core sample to 40–60 mesh particles, which are extracted for 24–48 hours to remove surface organic matter. ② Remove the cement in the sample with the diluted hydrochloric acid. ③ Put the sample into the mixed washing solution of the potassium dichromate solution and concentrated sulfuric acid (the mixed solution originally appears to be brown and turns green after reacting with organic matter); change the washing solution many times until the color of the solution does not change, to ensure sufficient reaction. ④ Flush the sample using the distilled water to remove the washing solution for later use. ⑤ Soak the sample into the dichloride stirred by ultrasonic oscillation, and collect and concentrate the supernatant, which is injected into the GC-MS through the chromatographic column to ensure no remaining organic matter. ⑥ Grind the sample using the treated mortar, after which the fluid inclusion is fully opened, and wrap the ground sample with silver paper, for later extraction of soluble organic components.
4. Fluid Inclusion Assemblage
A fluid inclusion assemblage (FIA) refers to a petrographically-associated group of fluid inclusions, with the same occurrence and similar composition and gas/liquid ratio, representing a fluid inclusion entrapment event during one stage of fluid movement [18, 19]. Accuracy of discriminating the fluid inclusion assemblage directly affects the results of the later oil source analysis.
A large number of fluid inclusions can be observed under the microscope in the Mid-Jurassic reservoir samples of the northern piedmont belt of the Turpan-Hami Basin, including liquid hydrocarbon inclusions, gaseous hydrocarbon inclusions, gaseous-liquid hydrocarbon inclusions, hydrocarbon-bearing brine inclusions, and brine inclusions (Figure 4). The fluid inclusions are mainly ellipsoidal, spherical, strip-shaped, and irregular in shape, and their dimensions are mostly between 5 μm and 25 μm, also with the presence of a few giant inclusions. Hydrocarbon inclusions are found with various fluorescent colors, mainly blue, blue-green, green, yellow-green, and yellow (liquid hydrocarbon and gas-liquid hydrocarbon inclusions). The pure gas inclusion is seen with no fluorescence. The inclusion abundance analysis shows that inclusions with blue fluorescence are the most, which are detected in almost every sample, followed by blue-green and green inclusions, and the least is yellow and yellow-green inclusions, which are only found in some samples. Such inclusions are mainly distributed along the micro crack and micro crack group cutting through quartz particles or quartz particles and their overgrowth edges in the linear, strip-like, and cluster forms (Figure 4(a)). They are formed in the late stage of the diagenesis of sandstone.
(a) Blue fluorescent inclusions distributed along the micro fractures cutting through some quartz particles, 3613.3 m, Sangonghe Formation, well Ke21; the left is under the plane-polarized light, and the right is under the UV-light
(b) Blue fluorescent gas-liquid hydrocarbon inclusion (condensate) along the micro fracture group cutting through the quartz particle, 3395.9 m, Sangonghe Formation, well Ke19; the left is under the plane-polarized light, and the right is under the UV-light
(c) Transparent colorless-gray gas-liquid hydrocarbon inclusion (condensate) with blue-green fluorescence, 3397.37 m, Sangonghe Formation, well Ke19; the left is under the plane-polarized light, and the right is under the UV-light
(d) Transparent colorless-gray gas-liquid hydrocarbon inclusion (condensate) with blue-green fluorescence, 3116.5 m, Xi-I Member (Xishanyao Formation), well Ke24; the left is under the plane-polarized light, and the right is under the UV-light
(e) Transparent colorless-gray gas-liquid hydrocarbon inclusion (condensate) with blue-green fluorescence, well Zhao4; the left is under the plane-polarized light, and the right is under the UV-light
(f) Dark gray natural gas inclusion, 3925.56 m, Badaowan Formation, well Zhao4
(g) Dark gray natural gas inclusion and hydrocarbon-bearing brine inclusion, 3117.2 m, Xi-I Member, well Ke-24
(h) Blue-green liquid gas-liquid hydrocarbon inclusions 3305.43 m, Sangonghe Formation, well Le3
(i) Green-yellow liquid gas-liquid hydrocarbon inclusions, 3275 m, Xi-II Member, well Ke19
(j) Yellow liquid gas-liquid hydrocarbon inclusions, 3275 m, Xi-II Member, well Ke19
(k) Blue liquid gas-liquid hydrocarbon inclusions, 3275 m, Xi-II Member, well Ke19
Since the occurrences of hydrocarbon inclusions are almost the same, the fluid inclusion assemblages (FIAs) are classified according to their fluorescence colors, phase states, fluid composition, and the proportions of various types of inclusions. Five assemblages are identified in the Mid-Lower Jurassic reservoir in the northern piedmont belt of the Turpan-Hami Basin.
The first FIA is that of the near yellow fluorescent inclusions and has the lowest abundance. It consists of yellow, green-yellow liquid hydrocarbon and gas-liquid hydrocarbon inclusions and mostly liquid hydrocarbon inclusions (Figures 4(i) and 4(j)).
The second and third FIAs are both near blue liquid hydrocarbon inclusions plus gas-liquid hydrocarbon inclusions. They appear to be blue, blue-green, and green under fluorescence. The main difference between these two FIAs lies in the proportions of liquid and gas-liquid hydrocarbon inclusions—in the second FIA, the liquid hydrocarbon inclusions account for about 60% and the gas-liquid inclusions, featuring low gas-liquid ratios (generally less than 15%), account for about 40% (Figure 4(k)). This FIA is dominant in the Xi-IV Member of the Shanle area and Xi-II and Xi-IV Member of Kekeya area. For the third FIA, the liquid hydrocarbon inclusions amount to 40%, and the gas-liquid inclusions, featuring relatively low gas-liquid ratios (generally less than 25%), account for about 60%. It is the main FIA in Sangonghe Formation of the Shanle area (Figure 4(h)).
The fourth FIA is a combination of liquid hydrocarbon+gas-liquid hydrocarbon both with blue fluorescence+gas inclusions. The liquid and gas-liquid hydrocarbon inclusions are colorless-gray under transmitted light and present bright blue and blue-green fluorescence. Gas hydrocarbons are gray and have no fluorescence. Among them, many gas-liquid hydrocarbon inclusions have high gas-liquid ratio (more than 50%). In this FIA, the gas-liquid inclusion has the highest relative abundance, accounting for about 65%, followed by the gas hydrocarbon inclusions (about 35%). This FIA is typical condensate inclusion according to maturity classification. The gas composition in the gas-liquid and gas inclusions is mainly CH4, and some inclusions also contain CO2, besides CH4. This FIA mainly develops Xi-I Member and Sangonghe Formation in the Kekeya area and the Sangonghe Formation in the Zhaonan area (Figures 4(b)–4(e)).
The fifth FIA is gas hydrocarbon inclusions. The gas composition is mainly CH4, and some inclusions are also found with the presence of CO2. This FIA is seen also more in the Xi-I Member and Sangonghe Formation in the Kekeya area and the Sangonghe Formation in the Zhaonan area (Figures 4(f) and 4(g)), and only a few gas hydrocarbon inclusions are observed in the Shanle area.
5. Oil Source Analysis of the Northern Piedmont Belt
Organic inclusions are fossil-scale micro oil reservoirs. It can show the evolution process of components, oil and gas injection process, and the main oil sources of today’s reservoirs by comparing inclusions with the oil and gas reservoir (regarding the phase state, composition, etc.) and various source rocks [20].
5.1. Comparison of Fluid Phases between Inclusions and the Present Oil and Gas Reservoirs
The comparison shows that the FIA captured in the reservoir is well comparable with the hydrocarbons in the present oil and gas reservoirs, in terms of phase states. For example, the Lower Jurassic condensate gas reservoir in Kekeya has high condensate oil content (the PVT analysis of well Ke19 shows that the condensate oil content is about 278.3 g/m3). The condensate oil in natural gas features a low density of 0.7682–0.08089 g/cm3, low viscosity, and low initial distillation point, and meanwhile, the FIA in the reservoir is mainly of the fourth type (condensate inclusions), followed by the fifth type—a large number of gas-liquid hydrocarbon inclusions, and natural gas inclusions are observed, with the relative abundance of pure liquid hydrocarbon inclusions less than 10%. It is basically consistent with the current phase state of Kekeya condensate gas reservoir, indicating that the source of oil in the fourth inclusion combination is one of the main oil sources of today’s reservoir. Another example is Xishanyao oil reservoir in the Shanle (more oil and less gas), and the natural gas is dissolved gas, and crude oil has low density (0.808 g/cm3) and low viscosity; the FIA in the reservoir rock is mainly of the second type, with very few pure gas inclusions; the near blue fluorescence and the proportion of various inclusions show that the inclusions are light oil inclusions (according to maturity classification) with low relative molecular weight [19], but slightly lower than the fourth group of inclusion assemblages. The crude oil in Shanle area is also slightly heavier than the lower Jurassic oil in Kekeya area. It indicates that the source of the second inclusion assemblage should be one of the main contributors of the present Xishanyao reservoir in Shanle area. According to the oil test of well Zhao4 in Sangonghe Formation, the daily output of oil is 25 m3 and gas is 14400 m3. The oil quality is light, and the gas-liquid ratio is high. In the inclusion assemblage of Zhaonan area, blue gas-liquid hydrocarbon inclusions account for about 65% ±, natural gas inclusions account for 25% ±, liquid hydrocarbon inclusions account for only 10% ±, and the gas-liquid ratio of gas-liquid hydrocarbon inclusions is 25%-50%, which also shows that the both fluid phase is similar.
5.2. Comprehensive Analysis of Oil Source
There are great differences among the typical source rock biomarkers in the Turpan-Hami Basin [2, 5, 21, 22]. By comparing the geochemical characteristics of inclusion oil, crude oil, and source rock, it is found that crude oil of some areas of the piedmont belt have obvious mixed-source characteristics. (1)For most crude oil, the main peak of tricyclic terpanes (TT) occurs at C19, with only those of a few samples at C20. Almost no samples are found with the main peaks at C21 or C23 (Table 1) (Figure 5). Moreover, the terpanes at and above C21 are less, and C19TT/C21TT is between 1.26 and 10.11. The percentage of C19+20TT in C19+20TT, C21TT, and C23TT is highest (between 60.4 and 87.19%) (Figure 6). Low carbon tricyclic terpanes (C19TT and C20TT) may be derived from diterpenoid, reflecting the biogenic characteristics of higher plants, and the shallow water environment may be conducive to the formation of low carbon tricyclic terpanes [23]. For the typical coal and carbonaceous mudstone, the tricyclic terpane is dominated by C19TT and C20TT—the main peak of coal occurs at C19 and that of carbonaceous mudstone, at C20 [21]. The percentage of C19+20TT is absolutely dominant, usually greater than 60% [24]. The terpanes’ content at and above C21 is very low. The content of C24 tetracyclic terpane in most crude oils is relatively high, and C26TT/C24 tetracyclic terpane is less than 0.5, which also reflects the biogenic characteristics of higher plants [25]. These characteristics show that coal-derived oil filled into most reservoirs. However, the experiment results showed that there were some differences in tricyclic terpane of various inclusion assemblages. The content of tricyclic terpanes of the second FIA is relatively low—the main peak occurs at C20 (Figure 5); the percentage of C19+20TT is between 55.5 and 69.4% (Figure 6); the content of C25 and C26 is low; C26 tricyclic terpanes/C24 tetracyclic terpanes are 0.21–0.38. It shows that oil source of the second FIA is more close to carbonaceous mudstone. In comparison, the tricyclic terpane content of the third and fourth FIAs is relatively high. Most third and fourth FIAs’ samples have the main peaks occurring at C20, C21, or C23 (Figure 5 and Table 1). Except for the samples from well Zhao4, the percentages of C19+20TT, C21TT, and C23TT are 38.65~52.09%, 26.36~32.8%, and 14.43~33.25%, respectively (Figure 6), and C26 TT/C24 tetracyclic terpane is at 0.62–1.05. It shows that most third and fourth FIAs’ oil does not come from coal and carbonaceous mudstone, but mainly from lacustrine source rocks (the main peaks occur at C21 or C23). The percentage of C19+20TT in inclusion oil of well Zhao4 is 61.09%, and C26TT/C24 tetracyclic terpane is 0.39, which is more closely related to carbonaceous mudstone(2)Gammacerane is one of the important parameters in environmental discrimination. Gammacerane can evolve from some chemical components of lower organisms and is unlikely to derive from higher plants [26]. Hence, there is almost no gammacerane in coal [2], while the coal-bearing system mudstone contains a certain amount of gammacerane and the content of gammacerane may be even higher in mudstone more of the lacustrine facies. Wang et al. [27] summarize the gammacerane/C30 (H+M) values of the limnetic, coal-swamp, and lacustrine facies source rock of the Lower Jurassic (Figure 7), which shows the feature of the increase in gammacerane/C30 (H+M) values as the sedimentary facies is more of the lacustrine facies. Furthermore, the gammacerane content can reflect the salinity variation of water in the sedimentary environment [28]. The higher the salinity is, the higher the gammacerane content becomes. The Permian source rock is of the brackish lacustrine deposition [5], thus associated with the highest gammacerane content and gammacerane/C30 (H+M) mostly greater than 0.25. At the same time, the significance of Pr/Ph cannot be ignored. The content of phytane and pristane is controlled by the sedimentary environment and parent material input. When the oxidation of the sedimentary environment strengthens, the Pr/Ph increases. Therefore, the Pr/Ph increases gradually from lacustrine facies to limnetic to coal-swamp. The Pr/Ph of most coal-swamp source rocks is greater than 3. The coal-swamp source rocks are mainly coal, carbonaceous mudstone, and few dark mudstone. Compared with typical source rocks, the second FIA oil is more closely related to coal-swamp source rocks, gammacerane/C30(H+M) is between 0.02 and 0.05, and Pr/Ph of the two samples is greater than 3. The third and fourth FIA represent that the most inclusion oil may mainly come from lacustrine source rocks or a small amount of oil comes from limnetic source rocks, gammacerane/C30(H+M) is between 0.12 and 0.19. Pr/Ph is less than 3. The lithology of lacustrine source rock is dark mudstone. The source rock of limnetic is an transitional facies zone between lake and coal-swamp. The lithology of the source rock of limnetic is dark mudstone, carbonaceous mudstone, and coal [27]. Most of the crude oil falls into the range of limnetic facies, and a small part falls into the range of coal-swamp facies and Permian lacustrine facies, indicating that the source rocks of the current reservoirs are not only coal and carbonaceous mudstone, but also Jurassic lacustrine oil and Permian lacustrine oil(3)There were obvious differences in sterane of various inclusion assemblages, crude oil, and the typical source rocks (Figures 8 and 9). The pregnane and homopregnane content in of the second FIA oil steranes is relatively low; the C27-C29 regular steranes are associated with the horizontally inverted L-shaped distribution, with the absolute predominance of C29 (68%–71%), followed by C28 at 12%–19% and the least C27 at 12%–16%. In comparison, the sterane compounds in the third and fourth FIA have higher proportions of pregnane and homopregnane. The C27-C29 regular steranes are mostly found with asymmetric or symmetric V-shaped distribution, with a few cases of the horizontally inverted L-shaped distribution; C29 is mostly between 39% and 57%; the least C28 is about 19%–25%; C27 is 23%–38%. For most crude oil, the C27-C29 regular steranes are associated with the horizontally inverted L-shaped distribution or vertically inverted L-shaped distribution (C29 steranes having a slight predominance (40%–50%) and followed by C28 (about 30%–40%) and the least C27 (about 10%–30%) [5]). For a small number of crude oil, the C27-C29 regular steranes are distributed in asymmetric “V” shape or symmetrical “V” shape. Generally, the pregnane content in coal and carbonaceous mudstone is extremely low and even cannot be detected in some samples [21], which may be related to the low salinity, while there is a certain amount of pregnane and homopregnane in the coal-bearing system mudstone. And, in most cases, the distribution of sterane compounds in coal and carbonaceous mudstone is generally horizontally inverted L-shaped, with C29>>C28>C27, and the C29 sterane holds the absolute predominance (about 60%–70%). Depending on the varied sedimentary environments, the steranes in the coal-bearing system mudstone may be associated with the horizontally inverted L-shaped [5], asymmetric V-shaped [22], or symmetric V-shaped [29] distribution; the closer the sedimentary environment is to the lake, the more symmetrical the regular steranes are. The source rock of the Permian Taodonggou Group is characterized by enrichment of C28 ergostane, and the sterane distribution is mainly vertically inverted L-shaped. Therefore, based on the characteristics of sterane, it shows that oil source of the second FIA is more close to coal and carbonaceous mudstone and the third and fourth FIA’s oil mainly comes from dark mudstone; most oil is mainly contributed by coal and carbonaceous mudstone or Permian lacustrine mudstone, and a small amount is from Jurassic lacustrine mudstone, with obvious mixed source characteristics(4)The oil-source correlation based on the carbon isotope similarity of the chloroform bitumen “A” and its components is an important supplement to that based on biomarkers. The δ13C of the chloroform bitumen “A” from the coal-bearing system source rock of the Turpan-Hami Basin ranges from -25.3‰ to -27.7‰ (Table 2); that of the saturated hydrocarbons ranges from -26.9‰ to -28.8‰; that of the aromatics ranges from-23.01‰ to -28.0‰; that of the nonhydrocarbons ranges from -24.4‰ to -27.1‰; that of the asphaltene ranges from -23.9‰ to -26.8‰. The carbon isotope ratios of the group components of the Taodonggou Group source rock are lower, mostly below -29‰ [30]. For the inclusions, the carbon isotope ratio of the chloroform bitumen “A” ranges from -25.9‰ to -27.5‰; δ13Csaturated ranges from -26.0‰ to -27.2‰; δ13Caromatic ranges from -25.1‰ to -27.5‰; δ13Cnonhydrocarbon ranges from -25.3‰ to -27.1‰; δ13Casphalteneranges from -25.2‰ to -27.2‰. The comparison of the carbon isotope ratio distribution ranges between the inclusion oil and coal-bearing system source rock shows an extremely close genetic relationship between them (Figure 10). It shows that the inclusion oil mainly comes from Jurassic coal measures
(a)
(b)
(a) The regular sterane distribution of inclusions of Kekeya area
(b) The regular sterane distribution of crude oil and sandstones of Kekeya area
(c) The regular sterane distribution of inclusions of Shanle area
(d) The regular sterane distribution of crude oil of Shanle area
(e) The regular sterane distribution of inclusions, crude oil, and sandstone of Zhaobishan area
(f) The regular sterane distribution of crude oil and sandstone of Aketashi and Qialekan areas
To sum up, the piedmont zone is a multisource hydrocarbon accumulation area, including Jurassic coal-measure mudstone, coal, carbonaceous mudstone, and Permian lacustrine mudstone. Jurassic reservoirs are mixed-source reservoirs. There are some differences in main oil sources of different strata in different structural belt. In Aketashi, Shanle, Zhaobishan, Ke21 and Ke24 well blocks, and other areas belonging to the central anticline belt, Permian lacustrine oil has a certain contribution (Figure 9), and the steranes of most crude oils are distributed in vertically inverted L-shaped. And gammacerane/C30(H+M) of most crude oils in these area is relatively high (the value is similar to that of Permian source rocks and oil derived from Permian). However, the percentage of C19+20TT (60.4-80.55%) also indicates that coal-derived oil has a certain contribution. The inclusion oil biomarkers also shows that coal measure mudstone had important contribution. Therefore, in central anticline belt, the three types of source rocks had important contributions to the reservoirs. In thrust front belt, such as well blocks Ke19, Ke20, and Ke13, separated by the thick coal seam of the Xi-II Member, there are some differences between the upper and lower main oil sources. Previous research shows that there are obvious differences in the contents of pregnane, homopregnane, tricyclic terpene, and pentacyclic triterpene of crude oil [15]. The pregnane, homopregnane, tricyclic terpene, and pentacyclic triterpene of crude oil in the lower reservoirs are significantly higher than those in the upper reservoirs [15]. As mentioned above, the second FIA mainly exists above the thick coal seam of the Xi-II Member, while the third and fourth FIA mainly occur in the Xi-I Member, Sangonghe Formation and Badaowan Formation. The fluid inclusion biomarker compositions of the upper and lower reservoirs are also greatly varied in the characteristics of pregnane, homopregnane, tricyclic terpene, and pentacyclic triterpene. The lower fluid inclusions have also significantly higher content. It indicates that the oil source represented by the second FIA is one of the main oil sources of the upper reservoirs, while the oil source represented by the fourth and third FIAs is the main oil source in the lower reservoirs.
In addition, previous studies on the light hydrocarbon composition of crude oil found that the crude oil in the Xi-IV Member of well Ke13 in the piedmont belt is coal derived oil [31]. The crude oil of the Xi-I Member of well Ke19 and well Ke21 is lacustrine oil [7]. Therefore, coal and carbonaceous mudstone contribute more to the reservoirs above the thick coal seam in the thrust front, while the oil under the thick coal seam mainly comes from limnetic and lacustrine facies dark mudstone.
The characteristics of natural gas associated with crude oil can also provide some evidence for oil source analysis. The carbon isotopic distribution of methane and ethane in well block Ke19 is -44.0~-38.7‰ and -29.0~-27.5‰. The gas is humic type deviated sapropel, and the gas maturity is 0.8~1.0%. The Badaowan Formation source rocks in Kekeya area are mainly dark mudstone, and is about 0.9%. There are relatively few coal and carbonaceous mudstone. The sedimentary environment is closer to lake, and the kerogen mostly belongs to type II2 [15], indicating that the gas associated with crude oil mainly comes from the source rocks of Jurassic Badaowan Formation. It can also prove that oil from Jurassic Badaowan dark mudstone filled into these reservoirs. The gas of some wells in Zhao4 well block, Aketashi, and Shanle areas is oil-type gas. Carbon isotope of methane in well Zhao4 is -40.7‰, that of ethane is -29.3‰, and that of propane is -26.8‰. In Shanle area, the carbon isotope of Le4 methane is -45.5‰, that of ethane is -30.8‰, and that of propane is -28.6‰, and the carbon isotope of Le2 methane is -45.2‰, and that of ethane is -30.2‰. Carbon isotope of Le10 methane is -41.4‰, and that of ethane is -29.7‰. The carbon isotopes of methane in Le 101 are -41.6‰, those of ethane are -29.8‰, and those of propane are -27.5‰ [32], and the carbon isotopes of methane in well Ke28 are -41.6‰, and those of ethane are -30.6‰. The maturity of natural gas is calculated by using the calculation formula of oil-type gas maturity in Junggar and Turpan-Hami basins [33] (), and the maturity of natural gas in Aketashi, Shanle, and Zhaobishan areas is between 0.8 and 1.2, mostly between 1.08 and 1.2. The bottom boundary of Badaowan Formation is less than 0.9 in this area, indicating that there is hydrocarbon supply from lacustrine mudstone with higher maturity in depth. It is speculated that the oil-type gas near the piedmont area mainly comes from Permian lacustrine mudstone. Therefore, it can also indicate that the central anticline has a certain degree of injection of Permian oil.
In addition, there are some differences in the maturity of inclusion oil, crude oil, and core extract oil, which reflects the injection process of oil from different sources. The maturity of crude oil is slightly higher than that of inclusion oil (Figure 11), and the maturity of core extract varies from low to high (the biomarkers of extracted oil in these cores are close to that of typical Permian source rocks). Previous studies on adamantane show that the maturity of crude oil in Turpan-Hami Basin is between 1.3 and 1.6%, which is higher than that of source rocks in Badaowan Formation, indicating that Permian oil and gas also filled into the piedmont belt in later period. Therefore, it is speculated that the Permian source rock was mature at the end of Xishanyao Formation sedimentation [34] and generated some crude oil with relatively low maturity into the reservoirs. Due to the low maturity of Permian oil, the biomarker content in the oil is relatively high. Therefore, the information of the oil filled in this period has been preserved, and the C27-C29 regular steranes of much crude oil are distributed in the vertically inverted L-shaped. Subsequently, the Jurassic source rock gradually matured and began to supply a large amount of hydrocarbon. Because the source rock is close to the reservoir, its filling is strong. Moreover, the diagenetic environment may be conducive to the formation of inclusions. At this time, a large amount of crude oil formed by Jurassic dark mudstone was captured. Due to the limited number of inclusion samples, the filling strength of Permian oil is not easy to judge at this time. In the late period, a small amount of oil and gas with high maturity filled into the reservoirs, which came from two sources: One is coal-generated. During the process of increasing coal maturity, the porosity of coal will be greatly reduced due to dehydration, and the generated hydrocarbons will be adsorbed by more and more developed micropores, which greatly reduces the hydrocarbon expulsion efficiency of coal. And the efficiency of coal hydrocarbon generation is relatively low. It can be released only after smaller molecules are formed in a higher evolution stage, and its hydrocarbon expulsion and filling are relatively later than that of mudstone [8]. The characteristics of some biomarkers in crude oil are similar to that of coal. The other is generated by the Permian source rock, with thermal maturity higher than that of Jurassic source rock. The later mixing with such hydrocarbons improves the maturity of crude oil. However, because the higher maturity may lead to the lower content of most biomarkers, these biomarkers were covered up and a small part of the geochemical information of Permian oil with higher maturity in the core extract is retained.
6. Exploration Implication
According to the oil source characteristics and structural characteristics in different well areas, it is found that the fault style has obvious control over the distribution of oil and gas (Figure 12). As mentioned above, the development of coal measure strata in Turpan-Hami Basin is one of the most important detachment layers affecting the structural style. After experiencing multistage and multidirectional structural activities, each secondary structural belt in Turpan-Hami Basin show obvious differences in structural styles, especially the obvious differences in fault styles, resulting in different vertical hydrocarbon supply windows of source rocks in each section. For example, in Kekeya area, the coal seams in Shuixigou Group are developed. During Yanshanian period, with the strong nappe of Bogeda Mountain, strong slippage occurred along the coal seams. The strata are divided into different structural layers by slippage faults. Slippage folds are formed in above the faults, and the structural activities are weak in the below the faults. The faults are not developed, resulting in the small hydrocarbon supply window of Permian source rocks, and a large amount of oil and gas from Permian source rocks cannot migrate upward to Jurassic. Therefore, at present, only a small amount of Permian oil information is found in the middle and lower Jurassic in Kekeya area, and most of the oil and gas generated in Badaowan Formation are also mainly accumulated under thick coal seams and rarely migrated to shallow parts. Further south into the depression area, most faults basically slipped in the middle and lower Jurassic coal seam and formed two sets of upper and lower fault systems with the Jurassic bottom as the boundary. It is difficult for the oil and gas from Permian source rocks to enter the shallow layer. Therefore, there is few Permian geochemical information about the oil and gas in the shallow. In Aketashi and Shanle areas closer to the piedmont, although coal seams are also developed, they are close to the orogenic belt. The structural style is thrust imbricate structure. Many faults can communicate with the Permian source rocks. The hydrocarbon supply window of the Permian source rocks becomes larger, and the oil and gas from Permian source rocks are filled into the shallow Jurassic layer along the faults, with more obvious mixed source characteristics.
Therefore, for the future exploration of Turpan-Hami Basin, due to the large residual resource potential and low exploration degree of the lower petroleum system, the research and exploration of the lower petroleum system is extremely important, especially the exploration under the thick coal seam of Xi- II Member. First of all, we should consider looking for exploration targets based on Permian source. The lower Jurassic structural oil and gas reservoir in the piedmont buried belt and the Triassic structural reservoir in Taipei Sag are the most important fields. The piedmont overtopping zone is the first row of anticline belt in the northern piedmont zone. There are many remaining anticline traps in the buried belt, where the thickness of Permian source rock is large and the anticline traps are developed. The faults connecting with Permian source rock developed, and the traps have the sealing of thick coal seams. The preservation conditions of Triassic structural traps in Taipei Sag are relatively good. The oil and gas generated in Permian enter the Permian and Triassic reservoirs through the lower fault system. Among them, Triassic is buried shallowly and the reservoir quality is relatively good. For the exploration considering Badaowan Formation as the source, tight oil and gas reservoirs are very important targets. It is necessary to depict the distribution of high-quality coal-measure dark mudstone. On this basis, search for traps with large thickness of coal seam and good reservoir quality of Lower Jurassic for exploration.
7. Conclusions
Most reservoirs are mixed-source reservoirs. There are not only coal-derived oil, but also crude oil generated by Jurassic lacustrine, limnetic, coal-swamp, and Permian lacustrine source rocks. There are some differences in main oil sources of different strata in different structural belt. It is obviously controlled by the fault, which controls the vertical hydrocarbon supply window of the source rock. In Aketashi, Shanle, Zhaobishan, and other areas belonging to the central anticline belt, basement involvement faults developed and connected Permian lacustrine source rocks and Jurassic Reservoirs. The reservoir is a mixed-source reservoir of Permian lacustrine and Jurassic coal measure source rocks. In thrust front belt, separated by the thick coal seam of the Xi-II Member, there are some differences between the upper and lower main oil sources. Strong slippage occurred along the coal seams, and it is difficult for deep oil to enter the shallow reservoirs. The oil above the coal seam mainly comes from coal-swamp coal and carbonaceous mudstone. The oil below the thick coal seam mainly comes from limnetic and lacustrine face dark mudstone, and the contribution of Permian lacustrine oil is also relatively small. In future exploration, we should consider looking for the high-quality reservoir-caprock assemblage near the effective hydrocarbon kitchen within the hydrocarbon supply window, especially for the exploration of lower petroleum system with Permian as source. The structural reservoirs in piedmont buried zone and the Triassic structural reservoirs in Taipei Sag are favorable exploration fields in the future.
Data Availability
The data used to support the findings of this study are included within the article.
Conflicts of Interest
The authors declare that they have no conflicts of interest.
Acknowledgments
This work was funded by the Science and Technology Projects of PetroChina Company of Exploration and Production (Grant No. kt2021-06-06).