In recent years, major breakthroughs have been made consecutively in petroleum exploration of the Junggar Basin, and two large oil fields, Mahu and Jimusaer, each with oil reserves of 10×10⁸ t have been discovered. However, except the Kelameili large gas field discovered in 2008, the natural gas exploration has seen no breakthrough in over a decade. The oil and gas exploration results show that the basin has "more oil and less gas", with a ratio of proved natural gas reserves to oil reserves being only 0.06:1, which is apparently different from other large petroliferous superimposed basins in central and western China. The “more oil and less gas" phenomenon does not match with the geological conditions of natural gas in the basin: (1) It does not match with the main types of source rocks. The Junggar Basin mainly develops three sets of source rocks, Carboniferous, Permian and Jurassic, among which the Carboniferous-Lower Permian Jiamuhe Formation and Jurassic are coal measure source rocks with large thickness and wide distribution that generate gas primarily and have huge gas generation potential. (2) It does not match with the ultra-deep buried depth of the source rocks. The Carboniferous-Permian source rocks in the Junggar Basin are old and deeply buried, at 10 000 m to 12 000 m and up to over 15 000 m depth in the Central Depression belt, so they have reached high thermal maturity with the capacity of massive gas generation. (3) It does not match with the exploration fields of the southern and northern foreland thrust belts of the Tianshan mountains. The southern and northern foreland thrust belts of the Tianshan mountains have similar structural and sedimentary geological backgrounds, and macroscopic conditions for hydrocarbon accumulation. The foreland thrust belt of Kuche in the south has formed a large gas area of over a trillion cubic meters of reserves, while only five medium-small fields with proven gas geological reserves of 346×10⁸ m³ have been discovered in the foreland belt in southern Junggar Basin in the north of the Tianshan mountains. The exploration results of natural gas in these two foreland belts differ greatly.

From the perspective of exploration degree, the Junggar Basin has a low proven rate of natural gas of only 9.0%, which is still in an early exploration stage. Although the discovered natural gas fields (reservoirs) are mainly small and medium-sized secondary gas reservoirs, there is also a large Carboniferous gas field, Kelameili, with a reserve scale of 100 billion cubic meters. Based on the recognition of geological conditions and distribution pattern of natural gas, the authors believe that the Junggar Basin still has the basic geological conditions for forming large to medium-sized gas fields (reservoirs), and there are three key natural gas exploration fields and directions with considerable exploration potential of natural gas.

Hydrocarbon exploration in the Junggar Basin started relatively late, with proven reserves of natural gas firstly submitted in 1983. The exploration history of natural gas in this basin can be roughly divided into the following three stages: (1) The accompanying development stage (1983-1998): natural gas exploration mainly developed along with the oil exploration. In this stage, nine small gas fields (reservoirs) were discovered successively, including Xiazijie, Santai and Wucaiwan, with proven cumulative reserves of 353×10⁸ m³. (2) The major discovery stage (1999-2008): with the discovery of Hutubi gas field in 1999 as a turning point, eight large to medium- sized gas fields were discovered later on, including Hutubi, Mosuo Bay, Mahe and Kelameili, with proven cumulative reserves of 1619×10⁸ m³, making this stage the most fruitful. (3) The stage poised to breakthrough (2009-2018): Although only the Jinlong gas field was discovered with proven gas reserves of 120×10⁸ m³, several new discoveries have been made recently in the southern thrust belt and the eastern uplift zones of the Dinan Uplift, with probable and possible gas reserves of 1074 × 10⁸ m³ submitted, showing a promising exploration outlook.

After more than 30 years of development, 18 gas fields (reservoirs) have been discovered in the Junggar Basin, with proven gas reserves of 2092×10⁸ m³ and annual gas production of 28.4×10⁸ m³ in total. These discovered natural gas fields (reservoirs) contain 5 pure gas reservoirs (75% of the reserves) and 11 associated gas reservoirs (25% of the reserves). The natural gases include coal-type gas, oil-type gas, mixed gas and biodegraded gas, but mainly coal-type gas, accounting for 70% of the reserves (Table 1)^{[1,2,3,4,5,6,7,8,9]}. Although the number of pure coal-type gas fields (reservoirs) discovered is small, the size of single gas reservoirs is large and they are the main part of the discovered natural gas reserves. Therefore, coal-type gas is the main target for large and medium-sized gas fields (reservoirs) in the Junggar Basin.

Affected by tectonic sedimentary cycles of Hercynian, Indosinian, Yanshanian, Himalayanian, etc.^[10,11], the Junggar Basin has developed three sets of large-scale source rocks of good quality from bottom to top.

The first set is the coal measure source rock formed in Carboniferous-Lower Permian Jiamuhe Formation deposited at the ocean-land transition stage of the Late Hercynian. Mainly distributed in the three active continental margin belts in the northeast, northwest and southeast of the basin, it is 100-300 m thick, 3×10⁴ km² in area, contains mainly type Ⅲ organic matter with a TOC value ranging from 0.5% to 43.7% (on average 4.40%). The samples of Lower Carboniferous source rock have vitrinite reflectance values (R_o) of 0.55%-4.21% (on average 1.42%), and most of the samples are highly-matured to over-matured. The samples of Upper Carboniferous source rock have R_o values of 0.54%-1.83% (on average 0.97%), and most of the samples are in matured to highly- matured stage. The dynamic simulation of hydrocarbon generation shows that the Carboniferous source rock is fairly late in hydrocarbon generation and begins to generate gas massively when reaching the R_o of over 1.2%, and has gas kitchen area of 1.97×10⁴ km². The Carboniferous rock is the most important gas source rock in the Junggar Basin at present, which supplies gas for the Zhongguai and Wuba District in the western basin and Kelameili gas field in the eastern basin.

The second set is the lacustrine source rock deposited in the faulting to depression transition stage of Permian, including the Fengcheng Formation and Lower Wuerhe Formation. It is the most important set of oil source rock in the Junggar Basin, which provides oil for most oil reservoirs discovered in this basin. Mainly distributed in the northwestern margin of the basin, the source rock of the Fengcheng Formation has a thickness of 0-225 m, Type Ⅰ-Ⅱ₁ organic matters, a TOC value ranging from 0.61% to 4.01% (on average 1.38%), and R_o ranging from 0.85% to 1.22%, which is at peak of oil generation stage. It is inferred that it has reached the stage of cracked-gas generation deep in the sag, with an area of gas source rock of 1.71×10⁴ km². The source rock of the Lower Wuerhe Formation is distributed mainly in secondary sags like Mahu, west Well Pen1, Shawan and Fukang in the Central Depression of the basin. It has a thickness of 0-200 m, Type Ⅱ-Ⅲ organic matter, a TOC value ranging from 0.50% to 9.16% (on average 1.73%), and R_o ranging from 0.7% to 1.0%, and just reaches the peak of oil generation. It is inferred that it has entered gas generation stage in the deep parts of the sags, and has an area of gas source rock with R_o larger than 1.6% of 1.55×10⁴ km². The Permian source rocks in the Central Depression belt are buried at a depth of around 10 km, with the maximum buried depth of more than 15 km, which have the conditions and potential for generating large-scale gas^[12,13]. The oil-type gas coming from the Permian source rocks has been found in the western, central and eastern Junggar Basin.

The third set, a set of major gas source rocks in the basin, is the coal measure source rock of the Middle and Lower Jurassic deposited in the Mesozoic coal-accumulating basin period. Being largely shallow water lacustrine sediments, this set of source rock has a thickness of 100-800 m, an area of 9.4×10⁴ km², Type Ⅱ₂-Ⅲorganic matter, and mainly consists of carbonaceous mudstone with a TOC value ranging from 6.03% to 39.96% (on average 18.22%) and coal with a TOC value ranging from 41.79% to 91.94% (on average 64.73%). As the Junggar Basin of the Himalayan Period tilted southward, the mature source kitchens of the Jurassic are mainly in the southern Junggar Basin. The samples of this set source rock from the outcrop profile and a small number of exploratory wells have measured R_o values from 0.61% to 0.72%, which is in the low-matured to matured stage. Because these samples were generally located at the structural high parts, they cannot fully reflect the real situation deep in the sag. According to the basin simulation and natural gas geochemical characteristics, it is inferred that the source rocks of the Middle and Lower Jurassic in the main structures of the southern Junggar Basin have all entered high-over mature stage, with an equivalent R_o ranging from 1.3% to 2.6%. When the R_o exceeds 1.2%, the source rock begins to generate gas massively, and the gas kitchen reaches an area of 1.41×10⁴ km² (Fig. 1). The natural gas of Hutubi gas field and Mahe gas field in the southern Junggar Basin all comes from this set of source rock.

The main gas kitchens of the three sets of source rocks shows zoning distribution on the plane, and not completely superimpose vertically. The superposed area of the gas kitchens reaches 6.64×10⁴ km², laying a solid foundation for forming large and medium-sized gas fields (reservoirs). In addition, the geothermal field of the Junggar Basin has the characteristics of "early hot and late cold". The geothermal gradient has been decreasing continuously since the late Paleozoic^{[13,14,15,16,17]}, and was 5.5 °C/100 m at the end of the Carboniferous (300 Ma from now), 4.5 °C/100 m in the Early Jurassic, and is 2.3 °C/100 m now^{[14,15,16,17,18]}. Compared with the other continental basins in China, the Junggar Basin is lowest in geothermal gradient now. The characteristics of low geothermal field have determined that the thermal evolution of hydrocarbon source rocks is relatively slow, and greater buried depth is needed for the source rocks to reach the same maturity and gas generation threshold, so the main gas generation window would go deeper, and the main gas source kitchens would appear at much larger buried depth. The exploration of natural gas in the Junggar Basin has mainly concentrated on the moderately to shallowly buried formations at present, and the discoveries are mainly the small to middle-sized secondary gas reservoirs. Large primary gas reservoirs should be developed in the vicinity of the main gas source kitchens in the moderately to deeply buried formations. The limited exploration depth and understanding result in "more oil but less gas" discovered, the potential of natural gas resources may be underestimated.

There are two types of natural gas reservoirs in the Junggar Basin, volcanic reservoirs and clastic reservoirs. The volcanic reservoirs developed in the Carboniferous-Early Permian are mainly mid-basic lava and pyroclastic rocks in the environment of island arcs and rifts. The reservoirs consist of a variety of rocks of different lithologies, including andesite, basalt, tuff, volcanic breccia, rhyolite, etc. Among them, mid-basic lava is distributed in the Permian of northwestern margin and Carboniferous of the hinterland and east of the basin; while the pyroclastic rocks are widely distributed across the basin. The reservoirs are highly heterogeneous, with primary pores, secondary dissolution pores and fractures^[19]. The physical properties of volcanic reservoirs are hardly affected by buried depth, but mainly controlled by the lithology and weathering and leaching time, and volcanic rocks with various kinds of lithologies can all form favorable reservoirs after long-term weathering and leaching. Weathering and leaching is the main controlling factor for the formation of favorable reservoirs in the weathered crust of volcanic rocks. Simulation shows that the process of weathering would reach an equilibrium after 20 Ma, the equilibrium thickness of weathered crust reservoir is approximately 550 m, and the cores collected prove that the maximum porosity is up to 24%^[20]. The high-quality volcanic reservoirs revealed by drilling are mainly concentrated within 550 m down from the top of the weathered crust, but the reservoir depth of the weathered crust can further extend down to a depth of 1100 m from the top of the weathered crust when faults exist, and the coring proves that the reservoirs have a maximum porosity of 32%^[20]. The reservoirs of volcanic weathered crust are mainly distributed in the Western Uplift, Eastern Uplift and Luliang Uplift of the basin.

The clastic reservoirs are composed of sandy conglomerates and sandstones. The sandy conglomerate reservoirs are mainly developed in the Permian, Triassic and Tertiary, and distributed in the frontal facies belt of each major sedimentary system, with high heterogeneity. They have both primary inter-granular pores and secondary dissolution pores, and become worse in physical properties with increase of buried depth in general. For example, for the Permian in the northwest margin of the basin, the average porosity of the sandy conglomerates in the Jiamuhe Formation, Fengcheng Formation and Xiazijie Formation ranges from 2.28% to 11.19%. On the plane, the reservoirs in the Kebai Fault zone in the northwestern margin are slightly better in physical properties, with a porosity of more than 10% generally, and the reservoirs gradually worsen in physical properties from the northwestern margin to the central part of the basin. In the eastern part of the basin, the Lower Wuerhe Formation of the Permian has a porosity ranging from 5.24% to 10.79% except in the Huoshao Mountain area where it has an average porosity of 10.7%. In contrast, the reservoirs of the Lower Wuerhe Formation in the northwestern margin are better in physical properties in general, with porosity ranging from 9.68% to 12.11%. Toward the central part, the reservoirs turn poorer in quality, with porosity ranging from 6.28% to 10.94% in Mabei-Luxi-Shixi areas. But the development of the secondary dissolution porous belt in the deep formations can significantly improve reservoir quality. For example, the sandy conglomerate reservoir of the Triassic Baikouquan Formation in the Mahu sag is under the control of secondary dissolution, where the effective reservoirs still developed at the depths of more than 4500 m, with porosity ranging from 10% to 15%. Actual drilling reveals that effective reservoirs developed with a porosity of about 10% at a depth of 6000 m in the Central Depression belt owing to secondary dissolution. The sandstone reservoirs mainly developed in the Jurassic-Paleogene, and the sandstone reservoirs in non-coal-bearing formations (Paleogene, Cretaceous, Jurassic Qigu Formation, Toutunhe Formation, Sangonghe Formation) are better in physical properties than those in coal-bearing formations (Xishanyao Formation and Badaowan Formation). On the plane, the Cretaceous sandstone reservoir has a porosity ranging between 12% and 28%, among which the Cretaceous Qingshuihe Formation sandstone at the buried depth of 6000 m in the Sikeshu sag has a porosity of 16.8%. The Jurassic Qigu Formation is distributed limitedly at the margins of the basin, while it has been basically denuded in the heartland of the basin. Except for the southern margin of the Kayindike area where the Jurassic sandstone is poor in physical properties with an average porosity of 8%-11.2% due to the deeply buried depth, the Jurassic sandstone in the other areas are better in physical properties due to shallow depths. For example, in the northwestern margin, the Jurassic sandstone is at the buried depth of greater than 1000 m and has a porosity ranging from 18% to 28%. The sandstone of the Toutunhe Formation is mainly distributed in the west part, the Luxi area of the central part and the eastern part, and in the southern margin of the basin. The sandstone of Toutunhe Formation is fairly good in physical properties, with a porosity ranging from 12% to 24%. In Sikeshu sag at the southern margin, the sandstone at the depth of 6000 m has a porosity ranging from 9% to 12%. The reservoir of the second member of Sangonghe Formation is the best in quality in the Jurassic. Except for the Santai-Beisantai in the east, Cai35 well area and Shidong area where this member of sandstone has a porosity of less than 12% due to finer grain size, it has a porosity between 12% and 30% in the other areas. This member of sandstone contains mainly primary intergranular pores and is low in heterogeneity.

The weathering and leaching of volcanic rocks and secondary dissolution of sandy conglomerates lead to the development of two types of effective reservoirs in the moderately to deeply buried formations, which provide good reservoir conditions for near-source accumulation of natural gas in the basin.

The natural gas caprocks in the Junggar Basin are relatively monotonous in lithology and mainly argillaceous rock. From bottom to top, there are six sets of mudstone caprocks, of which three are regional caprocks, including the Upper Permian Wuerhe Formation (P₃w), Triassic Baijiantan Formation (T₃b) and Cretaceous Tugulu Group (K₁tg) (Fig. 2), and the other three are local caprocks, including the second member of Lower Jurassic Badaowan Formation (J₁b₂), third member of Lower Jurassic Sangonghe Formation (J₁s₃), and Tertiary Anjihaihe Formation (E_2—3a). The first set of regional caprock, the Upper Wuerhe Formation (P₃w) is brown and grey-brown mudstone, 50-350 m thick, which is mainly distributed in the Central Depression belt of the basin, onlapping and thinning towards the uplift areas until pinching out. The second set of regional caprock is the Baijiantan Formation (T₃b) dark-grey mudstone 100-800 m thick, which is thicker in the western sags and southern margin, but thinner in the central area and east because of the paleouplift, and thins and pinches out towards the paleo-uplift and slope on the whole. The third set of regional caprock is the Cretaceous Tugulu Group (K₁tg) dark-grey and greyish-green mudstone 200-2000 m thick. Widely distributed across the basin, it is thickest in the Central Depression belt and southern margin^[21], and thins towards the eastern and western flanks until pinches out. The first set of local caprock is the Badaowan Formation (J₁b₂) dark-grey mudstone (160-260 m thick), which is thicker in the central sags and southern margin of the basin and thins towards the western and eastern slopes. The second set of local caprock is the third Member of the Sangonghe Formation (J₁s₃) dark-grey and greyish-green mudstone (150-250 m thick), which is mainly distributed in the Central Depression belt and thins towards the west, east and southern margins. The third set of local caprock is the Anjihaihe Formation (E_2—3a) greyish-green mudstone (140-180 m thick), which is mainly concentrated in the south of the Central Depression belt and the southern margin. The six sets of mudstone caprocks combine with the underlying reservoirs into favorable reservoir-cap assemblages, and can form effective seals to the natural gas reservoirs under certain geological conditions. Deformation simulation experiments show that a certain buried depth is needed for mudstone caprocks to effectively seal natural gas under pressure, and the critical depths for salt, gypsum and mudstone caprocks of the same thickness changing from brittleness to semi-plasticity and plasticity^{[22,23,24,25,26]} increase in turn. The critical depths for salt caprock, gypsum and mudstone to change from brittleness to semi-plasticity are 600 m, 2000 m and 3200 m respectively^[25,26]. The stronger the plasticity, the better the sealing performance of the caprock will be. Mudstone caprocks need a greater buried depth than salt or gypsum caprocks to form effective sealing of the same height of gas column. The characteristics of mudstone caprock alone determine that the gas sealing conditions in the moderately to deeply buried formation are better than those in the moderately to shallowly buried formation in the basin, so large and medium-sized gas reservoirs are more likely to occur in the moderately to deeply buried formations.

The Junggar Basin has three sets of major source rocks vertically, Carboniferous, Permian and Jurassic source rocks, which form three main gas source kitchens and gas-bearing systems on the plane correspondingly. The gas reservoirs formed by the gas-bearing systems all accumulate around the gas source kitchens around the sags (Fig. 3). Controlled by the distribution of source rocks, the planar distribution of the three main gas source kitchens is obviously zonal. The main gas source kitchens of the Carboniferous, controlled by residual hydrocarbon-generating sags, are mainly distributed in the three active continental margin belts in the northeast, southeast and northwest of the basin. The main gas source kitchens of the Permian, controlled by highly-matured hydrocarbon-generating sags, are distributed in the Shawan, Fukang and West Well Pen1 sags. The main gas source kitchens of the Jurassic controlled both by the distribution of Jurassic source rock and later buried depth, are mainly distributed in the southern margin and Fukang sag. The discovered natural gas reservoirs so far are all controlled by the main gas source kitchens. For example, the Carboniferous gas fields of Kelameili and Wucaiwan are controlled by the main gas source kitchens in Dishuiquan and Wucaiwan, and distributed in the adjacent Dinan Uplift belt. The moderately to shallowly buried gas reservoirs of Mosuowan and Mobei sourcing from Permian are mainly distributed in the vicinity of gas source faults in good configuration with the highly-mature gas source kitchens of the Permian. The Hutubi and Mahe gas fields (reservoirs) sourced by Jurassic are mainly distributed above the main gas source kitchens of the Jurassic in the southern margin (Fig. 3).

The Junggar Basin has experienced multiple stages of tectonic movements^[27], including the Hercynian, IndoChina, Yanshanian and Himalayan movements, which are unfavorable for the formation and preservation of large and medium-sized natural gas reservoirs. Under the same geological conditions, natural gas has stronger diffusion ability than oil, so the accumulation of gas demands better caprock sealing capability. The mudstone caprock is likely to break due to its brittleness during the later structural extrusion deformation^[25,26], while the stable tectonic setting can eliminate brittle fracturing of mudstone caprock due to tectonic reformation, and thus enable the formation and preservation of large and medium-sized natural gas reservoirs. The stability of tectonic setting is mainly reflected in the three aspects below: (1) the structural inheritance or continuity, that is, the paleo-structure was maintained as a positive structural unit during the accumulation period; (2) there was weak structural reformation in later periods, namely, the formations underwent little uplift and denudation after the accumulation period; (3) the faults in later period brought less damage to the reservoir, that is, after the accumulation period, the faults brought no or less damage to the structure in the early accumulation period. For example, the fault terrace belt and piedmont thrust belt in the northwestern margin underwent the adjustments and reconstructions of multi-stage tectonic movements, where the gas reservoirs formed in the early stage were often difficult to accumulate and preserve in large scale, hence only medium-sized or small gas fields were found in the fault terrace belt in the northwestern margin and Kelameili piedmont. In contrast, the uplift belt located in the central area of the basin basically subsided continuously after the structural uplift in the Hercynian Period, and the gas reservoirs formed in the early stage were not easily damaged in later period, which was conducive to forming large and medium-sized gas fields. For example, the Kelameili gas field is located in the Dinan Uplift belt in the eastern segment of the Luliang Uplift, which is in the central area of the basin (Fig. 3).

Under the control of four sets of the regional mudstone caprocks, there are three sets of reservoir-caprock assemblages (the lower, middle and upper) developed in the Junggar Basin. In the lower part, the reservoir-caprock assemblages of the mudstones at the top of the Upper Permian Upper Wuerhe Formation and the volcanic rocks in the Carboniferous are developed; in the middle part, the reservoir-caprock assemblages of the mudstones in the Upper Triassic Baijiantan Formation and the conglomerates in the Middle-Lower Triassic, as well as the reservoir-caprock assemblages of the mudstones in the Cretaceous Tugulu Group and the sandstones in the Jurassic and Cretaceous are developed; in the upper part, the reservoir-caprock assemblages of the mudstones in the Paleogene Anjihaihe Formation and conglomerates in the Ziniquanzi Formation are developed (Fig. 4).

The vertical distribution of natural gas reservoirs is controlled by the above three sets of reservoir-caprock assemblages. The discovered large and medium-sized gas fields so far are mainly controlled by the upper and lower reservoir- caprock assemblages. The mudstone of the Upper Wuerhe Formation onlapping the paleo-uplift controls the distribution of Carboniferous-Permian natural gas reservoirs, and gas fields like Kelameili, Wucaiwan and Jinlong are all controlled by this reservoir-caprock assemblage. The Anjihaihe Formation overpressured mudstone and the Ziniquanzi Formation sandstone constitute a high-quality reservoir-caprock assemblage in the southern margin of the Junggar Basin, which has the most gas found in this area, and Hutubi and Mahe gas fields are found in this reservoir-caprock assemblage ^[27]. There are several sets of high-quality reservoir-caprock assemblages of lacustrine mudstone and sandstone in the Triassic-Cretaceous of the Central Depression, which control the distribution of moderately to shallowly buried secondary gas reservoirs. The discovered Mosuowan and Mobei gas reservoirs are controlled by this set of reservoir-caprock assemblage. Although the gas reservoirs found in this set are small in scale, they still deserve great attention (Fig. 4).

Based on the analysis of macro-geological characteristics of the gas source rocks, reservoirs and caprocks and basic reservoir-controlling rules, through in-depth examination of the gas kitchens, large-scale reservoirs and key reservoir-controlling factors, we have sorted out the Carboniferous volcanic rocks, the lower assemblage in the southern margin and the Central Depression belt as the key directions for natural gas exploration in the future.

The Carboniferous volcanic rocks are the formation with the most gas reserves discovered in the basin. The three major hydrocarbon-generating sags, Dishuiquan, Wucaiwan and Dongdaohaizi were assessed in four times of resource evaluations. The natural gas resources of the Carboniferous were estimated at around 7626×10⁸ m³. Gas fields like Wucaiwan and Kelameili were discovered around these hydrocarbon-generating sags, which have proven gas geological reserves of 1137×10⁸ m³, accounting for 54.3% of the total proven gas geological reserves in the basin.

4.1.1. Hydrocarbon-generating sags are developed in all of the three main active continental margins in the Carboniferous and have gas generation potential

The Carboniferous-Early Permian was in the ocean-continent transition stage. With the closure of the eastern Junggar Ocean, the western Junggar Ocean and the north Tianshan Mountain-Bogeda Mountain ocean basins, three main active continental margin belts were formed in the northeast, northwest and southeast. All the three active continental margins have gone through three evolutionary stages: the early stage of trench-arc basin, the middle stage of foreland basin and the late stage of faulted basin^[29,30,31]. The Ludong and Wucaiwan areas in the northeastern continental margin, Fukang and Jimusaer areas in the southeastern continental margin, and the Zhongguai uplift area in the northwestern continental margin were all in shallow-water swamp environment in the evolutionary stage of foreland basin and faulted basin, when coal measure source rocks widely developed^[32].

The wells drilled in the three active continental margins show that the Carboniferous source rock is composed of dark-grey mudstone, carbonaceous mudstone and tuffaceous mudstone with a thickness of 50-300 m. This set of source rock has an average organic carbon content (TOC) of more than 2%, average total hydrocarbon content (S₁ + S₂) of more than 2 mg/g, typeⅡ₂-Ⅲ organic matters, and average measured Ro of 0.74%-1.67%, indicating it is in the evolution stage of maturity to high maturity and high in quality. Coal- type gas reservoirs sourced by the Carboniferous source rock have been found in all of the three active continental margin belts. The Wucaiwan and Kelameili gas fields in the northeastern continental margin are sourced mainly by the source rock of the Lower Carboniferous Dishuiquan Formation. The Xiquan2, Xiquan10 and Fu26 gas reservoirs discovered in the southeastern continental margin are sourced by the coal measure source rock of the Lower Carboniferous Songkaersu Formation. The Zhongjia2H, Chefeng6 and Jinlong43 gas reservoirs discovered in the northwestern continental margin are sourced by the humic-type source rock of the Upper Carboniferous Chepaizi Formation and the Lower Permian Jiamuhe Formation (Table 2).

The Carboniferous source rocks of the three active continental margin belts were calibrated, tracked and interpreted with the outcrop, drilling, well-logging and seismic data. On the basis of the confirmation of Dishuiquan, Wucaiwan and Dongdaohaizi sags during the four times of resource assessments, five residual hydrocarbon-generating sags in the Carboniferous-Lower Permian Jiamuhe Formation, Dajing, Fukang, Jimusaer, Mahu and Shawan, have been newly sorted out. Consequently, the hydrocarbon-generating sag area in the Carboniferous-Lower Permian Jiamuhe Formation of the basin has increased from 7015 km² to 14 765 km². The natural gas geological resources of the Carboniferous-Lower Permian Jiamuhe Formation were re-estimated at 1.1×10¹² m³.

4.1.2. Carboniferous gas accumulation is controlled by the favorable reservoir-caprock assemblages

Based on the analysis of residual magnetic anomaly data of the northern Xinjiang, it is found that large-scale volcanic rocks develop in all the three active continental margin belts of the Junggar Basin. In the three uplift zones, subjected to long-term weathering and denudation (generally greater than 20 Ma), weathered crust reservoirs are widespread 400 m down from the top of the weathered crust^[24], with dissolved pores and fractures as main storage space. Under the weathered crust, there are also inside volcanic rock reservoirs, which are also pore-type and fracture-type reservoirs with a porosity range of 6.07%-19.10% and permeability range of (0.03-0.28)×10^-3 m². Tuff, lithic tuff, and sedimentary tuff in the Carboniferous below 7000 m of Well Moshen1, have a porosity range of 6.2%-11.0% from well logging interpretation. The oil test results proved that 7134-7160 m and 7350- 7374 m of the well were natural flow highly-yield water layers, which confirms that there are still effective reservoirs in the Carboniferous more than 7000 m depth in the Junggar Basin.

The large-scale volcanic rock reservoirs of the Carboniferous and the lake-flooding mudstone of the Upper Wuerhe Formation constitute a high-quality reservoir-caprock assemblage^[33], which is mainly distributed in four favorable areas on the plane (Fig. 5): (1) Dinan Uplift belt, with an area of 3495.8 km²; (2) Eastern Uplift belt, with an area of 7064.4 km²; (3) Mosuowan Uplift belt, with an area of 593.6 km²; and (4) Zhongguai Uplift belt, with an area of 1831.7 km². The total area of the favorable zones is 12 986 km².

Based on a comprehensive analysis of source rocks, reservoir-caprock configuration, paleouplift background and late fault damages, in combination with the current exploration results, four favorable zones, the Dinan Uplift belt, Eastern Uplift belt, Zhongguai Uplift belt and Mosuowan Uplift belt have been made out as the key target areas for searching large and medium-sized Carboniferous gas fields (reservoirs) (Fig. 5).

The foreland thrust belt in the southern margin of the Junggar Basin covers an area of about 2.3×10⁴ km². The natural gas geological resources and remaining gas resources of the area were estimated at 9800×10⁸ m³ and 9454×10⁸ m³ in the fourth time of resource evaluation. This area has 3 reservoir-cap assemblages, but the exploration work and hydro-carbon discoveries before were mainly concentrated in the middle and upper assemblages, while the lower assemblage is low in exploration degree, with no major breakthrough so far. Based on a comprehensive analysis, there are three favorable conditions for gas accumulation in the lower assemblage in the southern margin of the Junggar Basin.

Firstly the structural formation of the lower assemblage in this area is relatively well preserved, which is conductive to the formation of large and medium-sized gas fields. Under the control of two sets of regional mudstone caprocks of the Anjihaihe Formation and Tugulu Group, three sets of (the upper, middle and lower) structural layers and reservoir assemblages develop in the southern margin of the Junggar Basin. The upper structural layer includes the strata above the Anjihaihe Formation, which has source rocks of the Jurassic, Cretaceous and Tertiary, and the Taxihe Formation mudstone and Shawan Formation sandstone constituting good reservoir-caprock assemblage, forming the upper source-reservoir-caprock assemblage. The upper reservoir assemblage has shallow buried depth, poor sealing capacity of the mudstone caprock, and serious damage caused structural deformation, so the natural gas in it is difficult to preserve. The middle structural layer includes the strata between the Anjihaihe Formation and Tugulu Group, which has the Jurassic and Cretaceous source rocks, the mudstone of the Anjihaihe Formation as caprock, and the sandstone of Donggou Formation as reservoir, forming the middle source-reservoir-caprock assemblage. Deeper in buried depth, the middle reservoir assemblage has better sealing capacity of mudstone caprock and better integrity of the lower structure, so medium sized gas fields are likely to occur in this assemblage. The lower structural layer includes the strata below the Cretaceous Tugulu Group, which has the Jurassic source rock, the Tugulu Group mudstone as caprock and the Toutunhe Formation sandstone as reservoir, forming the lower reservoir assemblage. The lower reservoir assemblage has deep buried depth, so its mudstone caprock has high sealing capacity, and its structures are complete, making it possible for large and medium-sized gas fields (reservoirs) to form.

Secondly, there are several sets of effective clastic reservoirs developed in the lower assemblage at the southern margin of the Junggar Basin, which provide the reservoir conditions for forming large and medium-sized gas fields (reservoirs). There are three sets of large-scale clastic reservoirs, the Qingshuihe Formation (K₁q), Kalazha Formation (J₃k) and Toutunhe Formation (J₂t) below the mudstone of the Cretaceous Tugulu Group^[34], of which the buried depth of the main structure is shallower. The Cretaceous Qingshuhe Formation is a set of thick massive conglomerate and sandstone (40-80 m thick), in the main structure, the reservoir of the Qingshuihe Formation is at the buried depth of 6000-6500 m. The Jurassic Kalazha Formation is a set of thick massive sandstone and conglomerate (200-600 m thick). In the main structural belt, the reservoir of the Kalazha Formation is at the buried depth of 6500-7000 m. The Jurassic Toutunhe Formation is a set of interbedded sandstone (50-280 m thick). In the main structural belt, the reservoir of the Toutunhe Formation is at the buried depth of over 7000 m. According to the relationship between porosity and depth of the reservoirs in the southern margin and adjacent regions of the Junggar Basin, it is inferred that the reservoirs at 6000-7000 m depth in the Wugui structural belt of the main part of the southern margin have a porosity range from 5% to 10% (Fig. 6)^[35], which has reached the standard of effective reservoir for deep natural gas accumulation. In addition, the Well Xihu1 drilled there encountered 201m-thick medium-fine sandstone in the interval of 5970-6171 m of the Toutunhe Formation, which has a measured porosity range of 7%-10% and an average porosity of 8%, verifying the reliability of the porosity-permeability prediction model mentioned above. In the formation test after fracturing, the intervals of 5996-6018 m and 6139-6160 m in this well produced 50.29 m³/d and 55.3 m³/d of water respectively and a small amount of oil, proving that large-scale effective reservoirs still exist in the main structure of the lower assemblage at the southern margin at the buried depth of 6000-7000 m, which provide storage conditions for large-scale natural gas accumulation.

Thirdly, the central-eastern segment of the second row of structure in the lower assemblage at the southern margin of Junggar Basin has the best trap-source configuration both in time and space, which is a key target for breakthrough. In this area, three rows of structural belts turn up successively from the piedmont to the basin (Fig. 7). The first row is the Qigu piedmont fault-fold belt, where the structural traps were formed approximately 150 Ma ago. The second row is the Huoma structural belt, where the structural traps were formed 8-10 Ma ago. The third row is the Dushanzi-Anjihai-Hutubi structural belt, where the structural traps were formed approximately 2.58 Ma ago^[36]. The coal measure source rocks of the Middle-Lower Jurassic generate gas primarily, of which, the source rock of the Badaowan Formation (J₁b) reached gas generation peak at 140 Ma-65 Ma, and the source rock of the Xishanyao Formation (J₂x) reached gas generation peak at 22 Ma-6 Ma^[37]. From the perspective of the matching relationship between the structure forming time and the hydrocarbon generation peak, the traps in the first and second rows of structural belts formed earlier match with the hydrocarbon generation peak better, while the traps in the third row of structural belt formed after the hydrocarbon generation peaks of the two sets of the main source rocks, so they don’t match well with the hydrocarbon generation peaks. Due to strong structural compression of the piedmont belt, the first row of structural belt is badly fragmented and thus has poor preservation condition unfavorable for gas accumulation. Therefore, the second row of structural belt has the best trap-source configuration in time and space and best preservation conditions, so it is the most favorable structural belt. Meanwhile, since the Mesozoic, the depocenter of the southern margin of Junggar Basin has been located in the central-eastern segment, the source rocks deposited before were buried deep in foreland thrust belt of the Late Himalayan period, and the source rocks of the Middle-Lower Jurassic are buried at the depths of 6000-8000 m and have reached mature-overmature stage. The main gas-generating center is located in the central-eastern segment of the southern margin of Junggar Basin. The results of the fourth resource assessment show that this segment has natural gas geological resources of 9738×10⁸ m³, accounting for 99% of the total resources of the entire southern margin of Junggar Basin, of which the natural gas geological resources of the lower assemblage are 7608×10⁸ m³, accounting for 78% of the total resources. Therefore, from resource potential and matching conditions of accumulation, the lower assemblage of the central-eastern segment in the second row of structural belt has the best gas accumulation conditions, and thus is the key direction of natural gas exploration in the southern margin^[38].

In the lower assemblage of the central-eastern segment in the southern Junggar are seven large structural traps, including Tugulu, Manasi and Huoerguosi etc, with a trap area of 19.2- 211.5 km² each, and a total area of 788.2 km². They have high point buried depths of 3200-7200 m and potential trap resources of 4250×10⁸ m³, and can form large natural gas fields (reservoirs), so they are the key targets for future gas exploration.

The Central Depression belt is located in the center of the basin, with an area of 3.81×10⁴ km². It is composed of five secondary sags, Mahu, Pen1 West, Shawan, Fukang and Dongdaohaizi, where there are multiple sets of source rocks, including the Carboniferous, Permian and Jurassic. The source rocks are buried deep at 5000-10 000 m generally, and up to 15 000 m. The Permian Fengcheng Formation and the Lower Wuerhe Formation are two major sets of source rocks, which are widely distributed in the Central Depression belt. The source rocks of the Permian have been encountered in the Mahu sag and its peripheral areas. The source rock of the Fengcheng Formation has an average TOC of 1.38%, average S₁ + S₂ of 4.96mg/g, TypeⅠ-Ⅱkerogens and a measured R_o range of 0.56%-3.95%. The source rock of the Lower Wuerhe Formation has an average TOC of 1.99%, average S₁+S₂ of 2.68 mg/g, TypeⅡ-Ⅲ kerogens and a measured R_o range of 0.54%-2.28%. The simulation of hydrocarbon generation shows that the source rock of the Fengcheng Formation generates largely oil, and a small amount of natural gas when reaching R_o of greater than 2%^[39]. The source rock of the Lower Wuerhe Formation generates oil in the early stage and gas in the late stage, reaches the oil-generating peak at R_o of greater than 1%, and begins to generate large amount of gas when reaching R_o of greater than 2%. The source rock of the Lower Wuerhe Formation has a gas-generation intensity of (5-160)×10⁸ m³/km², and the area with the gas-generation intensity greater than 20×10⁸ m³/km² of 1.5×10⁴ km². The natural gas geological resources of the Central Depression were estimated at 8351×10⁸ m³ in the third resource assessment, which indicates that the Central Depression belt possesses the resource base for natural gas accumulation ^[40].

There are two types of exploration targets developed in the Central Depression belt, the deep large structural targets and the large stratigraphic-lithological targets. The deep large structural targets mainly include seven large anticlinal traps of Mahu, Manan, Mabei, Well area Da1, etc., where the target strata are in the Carboniferous-Permian, with the trap area of 1784 km², and the two accumulation modes are late-generation ancient-reservoir and self-generation self-reservoir. With resources of 6000×10⁸ m³, Mabei and Manan anticlinal traps are the key exploration targets in the deep formations of the Central Depression belt. Stratigraphic-lithological traps are mainly distributed in the Triassic-Cretaceous, including Zhongguai Uplift faulted-lithological trap group and Shixi nose uplift faulted-lithological trap group, with a total area of 5369 km². Through migration along faults, the oil and gas generated by the source rock of the Lower Wuerhe Formation would accumulate in large stratigraphic-lithological traps. With potential resources of 5000×10⁸ m³, these are the key exploration fields of both oil and gas^[41,42].

The “more oil and less gas” phenomenon in the Junggar Basin does not match with the actual geological conditions of the natural gas. From the perspectives of gas source rocks, reservoirs and caprocks, the basin has geological conditions for forming large and medium-sized gas fields (reservoirs). The basin has three favorable exploration directions of large and medium-sized gas fields (reservoirs), the Carboniferous volcanic rock, the lower assemblages of the southern margin and the Central Depression belt.

The gas accumulation in the Carboniferous volcanic rocks is mainly controlled by the palaeo-uplift background, gas source kitchens and high-quality reservoir-caprock assemblages. The comprehensive evaluation shows that the Diannan Uplift belt, Eastern Uplift belt, Zhongguai Uplift belt and Mosuowan Uplift belt are favorable exploration areas.

The gas accumulation in the lower assemblage at the southern margin is mainly controlled by the Jurassic highly- mature gas source kitchens, overpressured mudstone caprocks and trap-source matching conditions. The seven large structural traps, Tugulu, Manasi and Huoerguosi etc. in the lower assemblage of the central-eastern segment of the southern margin are the most favorable exploration targets.

The gas accumulation in the central depression belt is mainly controlled by deep traps and reservoir conditions, and the deep large structures in Mabei and Manan and the Zhongguai and Shixi nose structural-lithological targets are favorable exploration targets.