The coal-derived gas in the broad sense refers to the gas produced by humic organic matter in coalification. The humic organic matter occurs in two forms, concentrated (coal seam) and dispersed (carbonaceous shale and mudstone), which are all gas-generating parent materials^[1]. According to the relationship between hydrocarbon source and reservoir, the coal-derived gas in the broad sense is divided into two types: The gas in the source-reservoir-in-one reservoirs, which dominates the unconventional gas, i.e. coalbed methane and shale (mudstone) gas; the gas in the reservoir away from the source rock, i.e. the coal-derived gas in the narrow sense that has migrated out of the gas-generating parent material, and is often called as the coal-derived gas. In fact, the coal-derived gas includes conventional and unconventional gas (tight gas). Yoloten and Urengoi gas fields, the second and third largest gas fields in the world, and Kela 2 gas field, the one with the highest abundance and output in China^[2] are all conventional sandstone coal-derived gas fields. Whereas the Sulige gas field with the largest reserves and the highest output in China is the unconventional tight sandstone coal-derived gas field^[2,3,4,5,6].

“Petroleum and natural gas generation during coalification”^[7], a symbol of the complete coal-derived gas theory, was advanced 40 years ago. The coal-derived gas theory has completed and developed the “plain coal-derived gas theory” and “coal-derived oil theory”, and ascertains that the coal measure produces largely gas with a small amount of oil^[8]. The paper “Petroleum and natural gas generation during coalification” was given high appraisals as the beginning of gas geology^[9]: the opening of geological research of coal- derived hydrocarbon^[2], a mature coal-derived gas/hydrocarbon theory^[10], a milestone in the research of coal-derived gas theory in China^[11], with great significance for global gas exploration^[2] by WANG Hongzhen, LI Desheng and SUN Shu, academicians of the Chinese Academy of Science, and ZHAO Wenzhi, academician of the Chinese Academy of Engineering and Galimov from the Russian Academy of Sciences.

In the major gas producing countries such as China, Russia, Turkmenistan, the Netherlands and Australia, etc., the coal- derived gas is the major source in the gas industry. Before the coal-derived gas theory was proposed in 1978, China had gas geological reserves of 2 284×10⁸ m³ (including 203×10⁸ m³ of coal-derived gas) and an annual gas yield of 137×10⁸ m³ (including 3.43×10⁸ m³ of coal-derived gas). By the end of 2016, China had gas geological reserves of 118 951.2×10⁸ m³ (including 82 889.32×10⁸ m³ of coal-derived gas, accounting for 69.7%) and an annual gas yield of 1 384×10⁸ m³ (including 742.91×10⁸ m³ of coal-derived gas, accounting for 53.7%). The gas geological reserves, coal-derived gas reserves, gas production, and coal-derived gas production in 2016 were 52 times, 408 times, 10 times, and 216.6 times those in 1978 respectively, and China has grown from a low-yield gas producing country to the world's sixth major gas producing country^[8]. The West Siberian Basin in Russia has the largest coal-derived gas reserves, the highest coal-derived gas yield, and the largest number of super giant gas fields with reserves over 1×10¹² m³ in the world. The basin has 7 super giant gas fields with the proven recoverable reserves of over 1×10¹² m³. The Urengoy gas field is the largest among them and also the third largest gas field in the world with recoverable reserves of 107 526.6×10⁸ m³, and by 2015, it had a cumulative gas production of 63 043.9×10⁸ m³, which is the highest in the world and is almost equivalent to the world’s gas yield in the past two years. The Amu Darya Basin is in Turkmenistan and Uzbekistan, which are both major gas producing countries with an annual output of 500×10⁸ m³. The gas is derived from the Middle and Lower Jurassic coal-bearing strata. Three super giant gas fields with recoverable reserves of 1×10¹² m³ were discovered in Turkmenistan. Among them, the Yoloten gas field is the world's second largest gas field with recoverable reserves of 123 105×10⁸ m³. Apparently, the coal-derived gas has made Turkmenistan and Uzbekistan major gas producing countries able to export gas to China. Australia has “abundant gas and little oil”. As of September 2017, it had proved and probable reserves of about 800×10⁸ BOE (about 109.6×10⁸ t), of which the gas reserves were about 13.5904×10¹²m³, accounting for 80%^[12]. The Kanalen Basin, the Bonaparte Basin and the Browse Basin on the northwestern continental shelf are three largest gas-bearing basins in Australia and have proven recoverable reserves of 51 671×10⁸ m³ combined. Of them, the gas reserves of the Kanalen Basin make up 50.4% of Australia’s gas reserves^[13], and the gas is dominated by coal-derived gas. Clearly, it is the coal-derived gas that has turned Australia into a major gas producing country with an annual output of over 1 000×10⁸ m³.

1.1.1. The original material of humic coal is mainly woody plant conducive to gas generation

In woody plants, the cellulose and lignin with low H/C (atomic) value that produce gas account for 60%-80%, while protein and lipids with high H/C (atomic) values the produce oil primarily make up not more than 5%^[14]. These characteristics of original material components make it inevitable that the coal measure produces largely gas with a little oil. The gas/oil equivalent ratio from modeling hydrocarbon generation of vitrinite, inertinite and exinite H/C (atomic) in the coal organic matter indicates that the vitrinite and inertinite, which are dominated in the humic coal, have low H/C (atomic) value, so they mainly generate gas, and thus the gas/oil equivalent ratio is always over 1 and up to 6; the exinite with high H/C (atomic) value is more likely to produce oil, but the exinite content is usually very low in humic coal, and thus, little oil is generated (Fig. 1)^[15].

1.1.2. Simulation of humic coal

From the 1980s to the early 21st century, the coalification experiments of organic maceral from immature lignite (R_o: 0.240%-0.409%), mudstone, type III kerogen and coal were done by many researchers^{[16,17,18,19,20,21,22,23,24]}, at temperatures from 300 °C to 600 °C (R_o: 2.5%-5.1%). The results show that anthracite has a coal gas generation rate of 218-590 m³/t (435 m³/t on average), and generates a small amount of oil, largely condensate and light oil. The thermal hydrocarbon generation modeling curve of coal samples of different geological ages in China (Fig. 2) show that the hydrocarbon generated by coal is dominated by gas, with a small amount of oil.

1.1.3. Gas pores are the product and trace of coal-derived gas generation

The scanning electron microscopic observation was carried out on 85 coal samples, including lignite, long flame coal, gas coal, fat coal, coking coal, lean coal, meagre coal and anthracite from 33 coal mines and cores of 6 wells in Shanxi, Shaanxi, Inner Mongolia and Xinjiang, etc. Gas pores were found in all the samples, indicating that gas is generated by all types of coal during coalification. The gas pores are generally circular and some elliptical, with a diameter between 3.5 μm and 0.2 μm. Two groups of gas pores in different sizes occur in some samples, probably marking two stages of gas generation^[25].

1.1.4. Chemical structure of humic kerogen prone to gas generation

In terms of the chemical structure, the humic kerogen, which consists of a large number of methyl and condensed aromatic rings and a small amount of short side chains, is likely to generate alkane gas and some light hydrocarbons, while the sapropelic kerogen with several long side chains is more likely to generate oil^[26].

The humic coal produces largely gas with a small amount of oil. In the immature pre-dry gas period, i.e. the period of peatification and lignite generation, this is reflected by the fact that the hydrocarbon gas generated is almost all methane, e.g. a large amount of biogas in the Tainan gas field in the Sanhu depression of the Qaidam Basin, the Pokur Fm. in the north part of western Siberian Basin. In the post-dry gas period of over maturity, namely the lean coal to anthracite period, this is reflected by the fact that the hydrocarbon gas generated is also largely methane, with trace amount of ethane and propane, for example, Yan'an gas field in the southern Ordos Basin^[27], the Kela 2 gas field and the Keshen gas field in the Kuqa depression, and the Rehden gas field in the northwestern basin of Germany. Apparently, in both the pre-dry and the post-dry gas period, the hydrocarbon generated by humic coal is dominated by gas. In the wet gas period or the gas-oil period, i.e. the long-flame coal to coking coal period, including part of the lean coal period^[28], corresponding to the "oil generation window" of sapropelic organic matter, in addition to a large amount of methane, a large amount of heavy hydrocarbon gas and unequal amount of light oil and condensate are generated, but the general characteristic is that in terms of gas-oil equivalent ratio, gas content is greater than oil content, for example, Ya-1 gas field in the Qiongdongnan Basin, the Anvil Hill gas field in the Taixi Basin, Chunxiao gas field in the Donghai Basin, Guang'an gas field in the Sichuan Basin, the middle Vilyui gas field in Vilyui Basin in Russia^[29], and several coal-derived gas fields in the middle and lower Jurassic coal measure source rocks in the Amu Darya Basin^[17]. In a few cases, coal-derived oil fields occur in coal-bearing areas in the gas-oil generation period. In contrast, the sapropelic organic matter produces mainly oil and a little gas in the "oil generation window".

1.2.1. Internal cause - high content of exinite

The hydrocarbon generation materials in coal are dominated by vitrinite and exinite in the organic maceral. According to geochemical indexes such as H/C atomic ratio and hydrogen index, resin, cutinite, sporophyte and phycoplast in the exinite are classified as type I kerogen, and the vitrinite is type III kerogen^[30]. Thus, in the gas-oil generation period, the vitrinite produces largely gas and a small amount of oil, while exinite produces mainly oil and a small amount of gas. In general, the organic maceral of coal has a low exinite content of only 1%-3%^[31]. Thus, coal-derived gas fields are likely to be found in coal-bearing strata at the gas-oil generation period, while the coal-derived oil field would occur only when the coal measure has high exinite content. DAI Jinxing et al.^[32] pointed out two internal causes of coal-derived oilfields in coal measures: (1) high exinite content (>7%); (2) being in the initial-medium coalification period. The data of R_o and organic maceral of the Paleogene and the Neogene coal measures in the Tuha Basin, the Gippsland Basin, and the Barito Basin, Indonesia are listed in Table 1. It can be seen from the table the coal measures in the three basins all have an average R_o of 0.52%-1.00%, indicating gas-oil generation period, and an average exinite content of 5%-15%, 2 to 5 times that of 1% to 3% of humic coal generating gas mainly. Therefore, these 3 basins are dominated by coal-derived oilfield due to high exinite content. By the end of 2017, 18 gas fields, like Shanshan, Wenmi, Qiulin oil fields, and Qiudong and Hongtai gas fields, which are related to Jurassic coal measure source rock, had been found in the Tupan-Hami Basin, with gas-oil equivalent ratio of gas and oil reserves of 0.28. The number of discovered gas fields and oil fields and gas-oil equivalent ratio of gas oil reserves show coal-derived oil fields dominate in this basin. Gong et al.^{[33,34,35,36,37]} found that the maturity of light hydrocarbon compounds and adamantane compounds in coal-derived oil of the Tupan-Hami Basin were much higher than that of the Jurassic coal measure source rock, thus, the underlying Permian and Carboniferous sapropelic source rocks also contributed to the coal-derived oil. The gas-oil equivalent ratio of gas-oil reserves in the coal measures of the Gippsland Basin and the Barito Basin is 0.14^[17], which is also due to the high exinite content (5%-14%) in the coal measure source rocks (Table 1).

1.2.2. External cause - gas diffusion in the coal-derived gas field due to shallow burial depth

In the gas-oil generation period, some coal-derived oil fields with small reserves may scatter around the margin of the coal-bearing basin, while many coal-derived gas fields are distributed in the middle of the basin. This kind of coal-derived oil field comes about because light hydrocarbon and oil relative content took the majority in the original gas and a large amount of alkane gas lost due to gas diffusion as the reservoirs originally deep buried in the coal-derived gas field turned shallower. For example, the Yiqikelike oilfield at the northeastern margin of the Kuqa Depression in the Tarim Basin, the Shanzijiao coal-derived oil field at the northeastern margin of the Taixi Basin^[38], and some coal-derived oil fields in the northeastern margin of the Amu Darya Basin^[39].

The Kuqa Depression in the Tarim Basin is one of the four continental large-scale gas production regions in China, where 12 coal-derived gas fields and condensate gas fields and 2 coal-derived oil fields (Yiqikelike, Dawanqi) have been discovered (Fig. 3). The Middle-Lower Jurassic coal measure source rocks in the Yangxia sag in the eastern part of the Kuqa Depression have a R_o value of 0.6%-1.4% and are in the gas-oil generation period, and the average exinite content of coal is 1.92% (130 samples), providing conditions for forming coal-derived gas fields. Not surprisingly, Dina 2, Tuziluk, Tiergen and Dalaoba condensate gas fields have been discovered there. The Yiqikelike coal-derived oil field was discovered in the southern margin of the Tianshan Mountain in the north, in which the oil reservoir is the Kezilenur Fm. buried at 150-550 m depth now. The Yiqikelike oilfield, like the Dina 2 and the Tuziluk coal-derived condensate gas fields, were buried at several kilometers deep in the geological history, but with the uplifting of Tianshan mountain, its reservoir turned much shallower, making the originally deep buried coal-derived condensate gas field transform to the current coal-derived oil field. The diffusion capacity of hydrocarbons varies greatly due to different carbon number of molecules. The diffusion capacity of the hydrocarbon decreases exponentially with the increase of the molecular weight. In fact, only C₁-C₁₀ hydrocarbons can diffuse^[40], i.e. the gas molecules have strong diffusion capability and the oil has weak or negligible diffusion capacity. The gas in the gas reservoir increases in diffusion amount and decreases in diffusion time as the molecules and burial decrease, e.g. methane, ethane, propane and butane in the reservoir at 1737 m depth would take 14 Ma, 170 Ma, 230 Ma and 270 Ma respectively to move to the surface^[41]. Thus, the combination of reservoir shallowing and gas diffusion results in the Yiqikelike coal-derived oil field. The reservoirs of Neogene Kangcun Fm. and the Kuqa Fm. in the Dawanqi coal-derived oilfield in the western Kuqa depression are 200-650 m deep, so this oilfield is similar to Yiqikelike oilfield in forming mechanism. CHEN Yicai et al.^[42] proposed through study that in the Dawanqi oil field, after 4.5 Ma of diffusion, the methane loss rate in the dissolved gas was 54% and the methane concentration was 12.82 m³/m³ in the upper reservoir at a depth of 300-400 m, and the methane loss rate was 13% and the methane concentration was 17.94 m³/m³ in the lower oil reservoir at the depth of 450-650 m. This example demonstrates that the shallower reservoir would have high loss rate, while the deeper reservoir lower loss rate as they get shallower. The massive loss of methane in the upper reservoir is the main reason giving rise to Dawanqi oilfield. The coal-derived oil fields formed by external causes are all small oil fields. The Yiqikelike oilfield was discovered in 1958 with reserves of 346×10⁴t, and is the first oilfield discovered in the Tarim Basin. It produced 95.79×10⁴ t of oil and 0.48×10⁸ m³ of gas cumulatively before abandoned in 1987. It is also the first abandoned oil field in China. The Dawanqi oilfield has reserves of 605×10⁴ t.

In China and Russia, the gas field with proven geological reserves of above 300×10⁸ m³ is classified as large gas field. In this study, China's gas fields are classified according to this standard. In the 1960s and 1970s, a large number of gas fields with proven reserves of more than 300×10⁸ m³ were discovered in the Western Siberian Basin, and thus, the large gas fields are divided into giant, ultra giant and super giant gas fields. The lower reserve limit of super giant gas field and ultra giant gas field are 1.0×10¹² m³ and (0.1-1.0)×10¹² m³ respectively^[43]. The major gas producing country refers to the country with an annual gas yield of more than 500×10⁸ m^3[44].

To discover and develop giant gas fields is the main way to become a major gas producing country. In the early 1950s, Russia (former Soviet Union) had gas reserves of less than 2230×10⁸ m³ and an annual gas yield of only 57×10⁸ m³, and was a low gas production country. From the 1960 to 1990, Russia discovered and developed more than 40 giant, ultra giant and super giant gas fields, and the gas reserves increased from 18 548×10⁸ m³ to 453 069×10⁸ m³. These gas fields are mostly distributed in the Western Siberian Basin and contain largely Cenomanian coal-derived gas. In 1983, the annual output of gas in Russia (the former Soviet Union) exceeded that of the United States and became the world's largest gas producing country. Especially, the Urengoi and the Yamburg super giant gas fields (Table 2) produced 3 407×10⁸ m³ combined in 1991, ranking the top two in the world then, and accounting for 58.8% and 14.4% of the total gas yield in Russia and the world^[45]. To discover and develop giant gas field is the key to make a country major gas producing country.

Thirteen super giant coal-derived gas fields and their countries, basins, year of discovery and development, original recoverable reserves and cumulative gas production in 5 basins in Asia, Europe and Africa are listed in Table 2. Except the Mamba super giant gas field in the Rovuma Basin, all the other gas fields have been developed. Among them, the Groningen super giant gas field in the Netherlands has the highest recovery factor, of up to 78.2%. It is still developed and will have higher recovery, so coal-derived super-giant gas fields can have very high recovery. The coal-derived gas takes a large proportion in the world's gas production and reserves. As of the end of 2017, 13 super giant coal-derived gas fields had been discovered worldwide, with the original recoverable reserves of 49.995 28×10¹² m³ (Table 2), which accounted for 25.8% of the world’s total remaining gas recoverable reserves of 193.5×10¹² m³ that year. In 2017, there were 15 major gas producing countries in the world, with a total gas yield of 28567×10⁸ m³. Among them, 6 produced mainly coal-derived gas (Russia, China, Australia, Netherlands, Turkmenistan and Uzbekistan), with a total gas production of 11 369× 10⁸m³, accounting for 39.8% of the total output of the major gas producing countries.

In the northwest basin of Germany with an area of 5.6×10⁴ km², 70 gas fields related to the Upper Carboniferous Westphalian coal measure source rock have been found^[46,47]. The coal system is about 2 000-2 500 m thick and has a coal- bearing degree of 3%, and is a favorable gas source rock system. The Rotliegendian sandstone overlying the gas source rock is the dominant reservoir of coal-derived gas, which is underlain by the upper Permian Zechstein salt rock of about 610-1 463 m thick in the Groningen, constituting a good combination of source rock, reservoir, and cap. The Groningen gas field is on a short-axis anticline in the north wing of the North Netherlands uplift in the northwestern basin of Germany. The geochemical analysis of 119 gas samples from the upper Carboniferous, Rotliegendian, Zechstein and Buntsandstein in 36 gas fields or gas producing points from the Ems River to the west of the Weser Rive shows the samples have a δ¹³C₁ of -31.8‰ to -20.0‰, mainly -28‰ to -23‰, and heavier δ¹³C₂ and δ¹³C₃ values, which are characteristics of coal-derived gas^[48]. However, the gas of Groningen gas field has a lower δ¹³C₁ value of -36.6‰, which is because the gas comes from the Wilhelmshaven sag in the east of the gas field. As the migration distance increases, the δ¹³C₁ value decreases from -29.5‰ to -36.6‰^[49]. Before the discovery of Groningen super giant coal-derived gas field with recoverable reserves of nearly 3×10¹² m³ in 1959 (Table 2), the Netherlands only had gas recoverable reserves of 740×10⁸ m³ and a gas production of 2.0×10⁸ m³, and needed to import gas in 1958. The Groningen gas field was put into production in 1963 and was fully developed in 1970. In 1975, its annual gas yield raised to 828.8×10⁸ m³, accounting for 92.3% of the gas yield in the Netherlands. As a result, the Netherlands jumped to export gas to Germany, France and Belgium.

The West Siberian Basin is a platform-type basin with an area of ​​about 230×10⁴ km², including the sea area of 35×10⁴ km², and is the largest petroliferous basin in the world. With the 64° north latitude as the dividing line, the basin part south of the line is the world famous oil producing area, and the part north of the dividing line is the world's largest gas producing area (Fig. 4)^[50]. The oil reservoirs are mostly distributed in the Lower Cretaceous Valanginian, Gormihavian and Barremian in the south part, and the gas reservoirs are concentrated in Cretaceous Cenomanian in the north part. The lateral distribution of oil and gas reservoirs is related to the type and abundance of dispersed organic matter, the development degree and extent of coal-bearing strata, or the planar distribution and vertical layers of marine and continental strata^[29]. The most important oil source rock in the western Siberian Basin is the Upper Jurassic marine Bargenov Fm., where the organic matter consists of plankton, bacteria and colloidal algae and the calcareous and siliceous mudstone has an average organic carbon content of over 10%. But the Bazhenov Fm. varies in TOC and R_o laterally: in the south of the dividing line, it has a higher TOC of 7%-11% and the R_o of 0.5%-1.1%, indicating it is in the oil generation window, so largely oil reservoirs occur there, contributing 51% of cumulative oil production in Russia; in the north of the dividing line, the formation has a lower TOC of 3%-7% and higher R_o between the bottom of the dominant oil generation window to the top of the dominant gas generation window^[51,52], so it is the secondary gas source rock there. Except in the Khanty-Mansiyskiy depression south of the dividing line in the southwestern part of West Siberian Basin, the Middle-Upper Cretaceous Aptian, Albian and Cenomanian (basically equivalent to Pokur Fm.) in the rest of West Siberian Basin are all coal-bearing and sub coal-bearing strata with mainly humic organic matter. The formations of the 3 stages contain 48.4×10¹² t of humus-dominated organic matter, more than any other formation in the basin. The mudstone in this formation has a TOC of 1.31% on average and 6% at maximum. The mudstone is uneven in organic matter abundance in the basin, and it is 0.3%-1.0% in the marginal and 1.5%-2.0% in the central and northern parts, with an increase trend from south to north. The coal-bearing degree also increases from south to north. Thus, the concentration of generated methane also increases from south to north and from the margin to the center. This is consistent with variation of coal-bearing degree and humus-dominated organic matter in the Pokur Fm., which makes it inevitable that there are more gas fields in the north part and few in the south part. The coal-derived gas reservoirs with large reserves in the western Siberian Basin are the products of coalification of the Pokur Fm. coal-bearing strata^{[29, 53-55]}. The coal-derived gas generated in the Pokur Fm. largely accumulates in the Cenomanian sandstone, which is overlain by 40-600 m thick large scale Turonian mudstone of good sealing capacity, providing good conditions for gas accumulation in the western Siberian Basin.

Up to now, Russia has proven oil reserves of 392.8×10⁸ m³, condensate oil reserves of 30.3×10⁸ m³ of and gas reserves of 640 000×10⁸ m³ cumulatively. The West Siberian Basin is richest in oil and gas and contributes 67.7% of the proven reserves in Russia^[52]. The western Siberian Basin has 58 gas fields, which are concentrated in the hydrocarbon traps such as Kala-Yamar and Nadim-Taz in the northern part of the basin and account for 93% and 92.9% of gas reserves and production in the basin respectively^[56]. Around 80% of gas reserves discovered are in the Pokur Fm. and formations equivalent to Pokur, and all gas reserves are in structural traps.

Gas reserves and production of the western Siberian Basin are concentrated in the Nadim-Taz hydrocarbon trap, and super giant gas fields contribute the majority (Table 2). Table 2 shows that in 2017 the total recoverable reserves of seven super giant gas fields (Urengoi, Yamburg, Povannikov, Zaporiyan, Medve, Jarazavi, Kruzinzhnov) in the basin were 28.383 8×10¹² m³, accounting for 15.2% of the remaining recoverable reserves in the world and 81.1% of Russia's original recoverable reserves that year. By the end of 2015, Urengoi, Yamburg, Powannikov, Zaporiyan and Medvei super giant gas fields cumulatively produced 14.597 8×10¹² m³ of gas, which was 4.1 times and 25.5 times of the total output of the world and Russia in 2015. The Pokur Fm. is the dominant pay (ПК1-6) and has 75% of reserves in the Urengoi gas field, which is the third largest gas field and has the highest cumulative gas production of 63 043.96×10⁸ m³ by the end of 2015 in the world (Table 2). It also has the highest annual gas yield in the world. In 1989, the Urengoi gas field produced 3 300×10⁸ m³ of gas^[52], accounting for 41.4% and 15.7% of the gas production of the former Soviet Union (Russia) and the world respectively that year. Clearly, to discover and develop super giant gas fields plays a key role in the rapid development of the world gas industry and the emergence of a major gas producing country.

The Amu Darya (Karakum) Basin with an area of 437 319 km² is in the Central Asia and mainly in Turkmenistan and Uzbekistan and partly in northern Afghanistan and northeastern Iran. The Amu Darya Basin is the largest gas-bearing basin in the Central Asia and the world’s third largest gas-rich basin after the western Siberian Basin and the Persian Gulf Basin^[57] (Fig. 5).

The Amu Darya Basin is a Mesozoic basin developing on the setting of the Hercynian geosyncline. The basin basement consists of Permian-Triassic granitoids, intermediate-basic volcanic rocks, marble, schists, and quartzite, etc. The sedimentary formations in the platform consist of Jurassic, Cretaceous-Paleogene and Neogene-Quaternary strata. The Amu Darya Basin has three sets of source rocks: the Middle-Lower Jurassic humic coal measure, the dominant source rock; the Upper Jurassic Oxfordian-Kimmeridgian marine carbonate rock and argillaceous limestone, the secondary source rock; and the Lower Cretaceous Aptian-Albian shale^{[56, 58]}.

3.3.1. Middle-Lower Jurassic source rock

The Middle-Lower Jurassic continental and marine-continental coal-bearing strata are composed of interbedded sandstone and mudstone with thin coal seams, coal lens bodies, and rich dispersed rock fragments. The mudstone accounts for 50% of the total source rock thickness, and the middle Jurassic coal-bearing clastic rock is 1 000-1 600 m thick and has some algal organic matter^[59]. The source rock has an organic carbon content of 0.04%-4.35%, 1.5% on average; a chloroform bitumen "A" content of 0.042%-0.065%, Type III-II kerogen, humic organic matter, R_o of 1.3%-2.3% and up to 3.6% at the bottom^[60], representing good quality gas source rock. At the geo-temperature of 130-190 °C, the source rock is in condensate oil, wet gas and dry gas stage and has an original gas generation amount up to 1 600×10¹² m³. Although the Middle-Lower Jurassic has good gas generation conditions, the reservoir-cap conditions are poor, with no good regional and local caps and poor gas preservation conditions, so only small gas fields have been found in the Middle-Lower Jurrasic. A large amount of coal-derived gas accumulates in the Upper Jurassic Callovian-Oxfordian carbonate reservoirs after migrating along faults and unconformity planes.

3.3.2. Upper Jurassic source rock

Upper Jurassic Oxfordian-Kimmeridgian marine carbonate rock and argillaceous limestone is 20-400 m thick and has an organic carbon content of 2.5%-5.0% and Type II kerogen. The Oxfordian hydrocarbon source rock, with a lower R_o of 0.50%-1.55%, is in the oil-generation stage, and produces oil largely. This set of carbonate rock is distributed throughout the basin and is also one of the most important reservoirs in the basin^[61]; above it is the Kimmeridgian-Tithonian salt-gypsum cap, which is 400-1 200 m thick and is a major regional cap, constituting the Upper Jurassic combination of source rock, reservoir and cap. In the Amu Darya region of western Uzbekistan and eastern Turkmenistan, the major oil and gas reservoirs are distributed in the Callovian-Oxfordian bioherm traps. The petroleum geologists of the former Soviet Union considered that the upper Jurassic was the main source rock within the basin. However, correlation of oil/source rocks indicates that the source rock of the discovered gas fields and condensate fields in the basin is possibly Middle-Lower Jurassic coal-bearing formation. It is hard for the upper Jurassic source rock with low maturity to give rise to a large number of pure gas reservoirs and high mature condensate reservoirs^[62].

3.3.3. Lower Cretaceous source rock

The Lower Cretaceous Aptian-Albian marine shale is a set of potential source rock 5-120 m thick, with an organic carbon content of 0.3%-1.5%, type II kerogen, and a chloroform bitumen "A" content of 0.023%, distributed in the Kopet piedmont depression in the southwestern basin.

Calculated with the conversion of 1 240 m³ gas to 1t of oil equivalent, with the Upper Jurassic Kimmeridgian-Tithonian gypsum as bound, the strata above the gypsum have proven oil, condensate and gas reserves of 29.04×10⁶ t, 30.88×10⁶ t and 38 377×10⁶ t^[58] respectively, with a gas-oil ratio of 640:1. In the strata above the gypsum, only the lower Cretaceous Aptian-Albian marine shale is possible source rock, but restricted in the Kopet piedmont depression and low in maturity, it can’t produce oil and gas. Thus, the oil and gas there is not produced by this source rock, but from the underlying source rocks. The strata below the gypsum have proven oil, condensate and gas reserves of 98.44×10⁶ t, 204.48×10⁶ t and 33390× 10⁶ t^[58] respectively, with a gas-oil ratio of 110:1. There are two sets of source rocks in these strata: (1) Jurassic Oxfordian- Kimmeridgian marine carbonate rock and argillaceous limestone with Type II kerogen in the oil-generation stage, which must generate oil largely with a little gas, but the product from the strata below the gypsum is mainly gas with a little of oil, so it isn’t generated by this set of source rock. (2) The other set of source rock is the Middle-Lower Jurassic continental facies and marine-continental coal-bearing formation that produces mainly gas with a little oil. Apparently, both gas and oil in the strata above and below the gypsum layer in the Amu Darya Basin are from this coal measure source rock^{[56, 58, 62-65]}. Analysis of 5 condensate oil samples from upper Jurassic and Cretaceous shows the condensate oil is rich in bicyclic sesquiterpenes, indicating its source rock is sedimentary rock with high content of higher plant; the R_o value of the condensate oil samples have entered high mature-over mature period, indicating the oil isn’t derived from the upper Jurassic source rock, but from the middle and lower Jurassic with larger burial depth; the condensate oil samples have a δ¹³C value of -24.57‰ - -21.22‰, indicating its source rock should be coal-bearing strata^[62], and the natural gas samples in both deep and shallow reservoirs have δ¹³C₁ of -38.1‰ - -24.6‰. Both oil-gas ratio and geochemical characteristics of hydrocarbon indicate that the oil and gas in the Amu Darya Basin are coal-derived and coal-derived gas takes dominance.

The IHS database shows 357 oil-gas fields, including 296 gas fields (gas field, condensate gas field and gas field with oil) and 61 oil fields (oil field, oil field with gas, and oil field with condensate gas), had been discovered in the Amu Darya Basin as of the end of 2017^[46]. Most of the gas fields are located in Turkmenistan and Uzbekistan. There are 149 gas fields and 9 oil fields in Turkmenistan, 128 gas fields and 43 oil fields in Uzbekistan, 17 gas fields and 9 oil fields in Afghanistan, and 2 gas fields in Iran. The two major gas producing countries, Turkmenistan produced 620×10⁸ m³ and Uzbekistan produced 534×10⁸ m³ of gas in 2017. All 3 super giant gas fields discovered in the Amu Darya Basin (Table 2) are all in Turkmenistan, and the Yoloten gas field is the third largest gas field in the world, with original recoverable reserves of 12.310 6×10¹² m³.

The Ordos Basin covers an area of 37×10⁴ km², in which Paleozoic has an area of 25×10⁴ km^2[66]. The basin is flat and stable in structure, and steady in sedimentation, with few faults^[67]. The pattern of oil and gas distribution in the basin is that gas fields accumulate largely in Paleozoic in the north, and oil fields gather in Mesozoic in the south^[68]. The Ordos Basin has the highest annual gas yield in China. The basin produced 424.45×10⁸ m³ of gas in 2017, accounting for 28.9% of China’s gas yield that year. The basin has 2 sets of gas source rocks.

3.4.1. Carboniferous-Permian coal measure source rock

The Carboniferous-Permian period is an important coalification period in China and the world. The Carboniferous- Permian source rock in the Ordos Basin occurs in the Benxi Fm., Taiyuan Fm. and Shanxi Fm. and consists of coal seam, dark mudstone and mud-bearing biolimestone. The source rock is thick in the east and west parts and thin and stable in the middle part. Coal seams occur largely in the Taiyuan Fm. and Shanxi Fm. and are 2-20 m. The coal seams are more than 25 m thick in the Wuda coal gathering center in the northwestern part of the basin, 6-12 m thick in the Sulige gas field, and around 5 m thick in Wushenqi. The dark mudstone is 140-150 m thick in the western part of the basin, 70-148 m thick in the east, and 20-50 m thick in the south and north^[2]. The geochemical parameters of the upper Paleozoic source rock in Table 3 show that the coal and dark mudstone in the Shanxi Fm., Taiyuan Fm. and Benxi Fm. are rich in vitrinite and inertinite but lean in exinite, representing humic gas source rock. The Carboniferous-Permian source rock has an area of 24×10⁴ km², of which, more than 18×10⁴ km² has entered massive gas generation stage^[69]. The gas generation strength of coal measure gas source rock of the Shanxi Fm. and Taiyuan Fm. exceed 15×10⁸ m³/km² and 5×10⁸ m³/km², respectively^[70]. The Carboniferous-Permian source rock in the Ordos Basin is characterized by “widespread” hydrocarbon generation. The source rock with gas generation intensity of more than 12×10⁸ m³/km² covers 71.6% of the total area of ​​the basin, making most of the basin in effective gas supply zone. The source rock in the Sulige gas field and its vicinity has a gas generation intensity of (12-30)×10⁸ m³/km^{2[69, 71]} and is continuous in distribution^[72]. The carbon isotope composition of alkane gas samples from the Carboniferous-Permian Shanxi Fm. and Shihezi Fm. of Sulige gas field, Yulin gas field, Shenmu gas field, Wushenqi gas field, Zizhou gas field, Mizhi gas field, Daniudi gas field, Yan'an gas field and Dongsheng gas field were analyzed extensively^{[27, 73-81]}. Projecting δ¹³C₁, δ¹³C₂ and δ¹³C₃ on the coal-derived gas and oil gas identification chart by δ¹³C₁-δ¹³C₂-δ¹³C₃ value (Fig. 6), it is found that all the Carboniferous-Permian gas samples fall in the coal-derived gas range. The δ¹³C in the Yan'an gas field reverses due to R_o>2.2%.

In addition to the coal measure major source rock, the limestone is the secondary source rock in Carboniferous-Permian. The limestone in Benxi Fm. has a thickness of 2-5 m and limited distribution. There are 3-5 layers of limestone in the upper and middle sections of the Taiyuan Fm., with the maximum thickness of 50 m in the central and eastern parts of the basin. The Taiyuan Fm. limestone is dark gray bioclastic micrite limestone rich in biological fossils with the sapropel-humic kerogen^[2]. Their hydrocarbon generation indexes are shown in Table 3.

The R_o value of the Carboniferous-Permian source rock is up to 2.8% in the Yan'an-Wuqi belt in the southern Ordos Basin and decreases toward the north and south sides and the edge of the basin. The source rock has R_o>1.5% in most part of the basin, indicating the source rock has entered high mature-over-mature gas generation stage. A set of typical tight sandstone reservoir occur in the Shanxi Fm. and the lower Shihezi Fm., and the major gas pays are distributed in the progradational sand bodies in the lower Shanxi Fm. and the lower part of the lower Shihezi Fm. The local caprock is the stably distributed lacustrine mudstone in the lower Shihezi Fm. and the Shiqianfeng Fm. The above combination of source rock-reservoir-cap makes it inevitable that the Carboniferous-Permian gas reservoirs appear mostly in the lower Shihezi Fm., followed by the Shanxi Fm. and the Taiyuan Fm.^[2].

3.4.2. Lower Paleozoic gas source rock

Only the Cambrian and Ordovician exist in the Lower Paleozoic of the Ordos Basin, of which the Middle and Lower Cambrian and the lower Ordovician Majiagou Fm. are widely distributed. The Cambrian carbonate rock is turbulent shallow water surface sea sediment with low organic matter content. In the Middle Ordovician Pingliang Fm. at the western margin of the basin, the carbonate rock has I-II₁ organic matter and an organic carbon content of 0.4%-1.2%, and the marl has an organic carbon content of 0.31%^[2]. Whether the Majiagou Fm. carbonate rock is source rock or not is controversial: One viewpoint is that it isn’t industrial gas source rock with an average organic carbon content of only 0.24%^{[66, 68, 83-84]}; another viewpoint is that it is gas source rock. The investigation of the Majiagou Fm. carbonate rock since 2016 shows the effective source rock with a TOC of 0.30%-8.40% is distributed around the Mizhi salt subsag, and the gas of the Majiagou Fm. is mostly from its in-situ oil source rock; the source rock above reservoir type gas pool only occurs in local parts^[85,86]. When the source rock with TOC>0.4% is regarded as effective source rock in the Majiagou Fm., the effective source rock is well developed below the Ordovician salt rock and has the potential to form self source rock-reservoir gas pool. But the Lower Paleozoic gas in the Ordos Basin is mainly derived from the upper Paleozoic coal-derived gas^[87].

In the carbonate rock paleo-weathering crust on the top of the Majiagou Fm., a giant gas field with dolomite as major gas reservoir has been discovered in the fifth Member of the Majiagou Fm., sealed by Carboniferous bauxite mudstone and argillaceous regional cap. The gas has a methane content of 91.51%-97.50% and a heavy hydrocarbon gas content of 0.1%-1.5%, representing dry gas. Fig. 6 shows there are both coal-derived gas and oil-type gas in the gas field. Researchers considered that the coal-derived gas was derived from the overlying Carboniferous-Permian coal measure gas source rock, and the oil-type gas was derived from the overlying limestone source rock in the Taiyuan Fm. But HUANG Difan held that 70% of the gas in the Jingbian gas field was derived from the lower Ordovician oil-type gas, and only 13% was coal-derived gas^[88]. CHEN Anding argured that 82% of the oil-type gas in the Jingbian gas field was derived from the Ordovician carbonate rock, while only 18% was the coal-derived gas^[89].

By the end of 2017, 11 gas fields with reserves of more than 300×10⁸ m³ including Sulige, Jingbian, Daniudi, Shenmu, Yan'an, Yulin, Zizhou, Wushenqi, Dongsheng, Liuyangbao and Mizhi gas, as well as 5 small gas fields, Yichuan, Huanglong, Shenglijing, Zhiluo and Liujiazhuang had been discovered in the Ordos Basin (Fig. 7). These gas fields cumulatively produced 3 783×10⁸ m³ of gas, of which over 90% is coal-derived gas. The Sulige gas field is a super giant gas field with proven geological reserves of 16 448×10⁸ m³ (Table 2), and in 2017, it produced 212.58×10⁸ m³ of gas, accounting for 14.2% of the gas yield in China that year, and cumulatively produced 1 564.23×10⁸ m³ of gas by 2017, accounting for 41.3% of the cumulative gas yield of the Ordos Basin. Therefore, exploring and developing the Sulige super giant gas field is of great significance for China to become the world’s sixth largest gas producing country and the Ordos Basin China's largest gas producing area. Major results have been achieved in exploring and developing the coal-derived gas in the Ordos Basin, but there is still considerable potential left. For example, coal-derived gas in the southwestern part of the Yi-Shan Slope should be explored. In the past, the exploration and development focused on Mesozoic oil field, and the deep coal-derived gas hasn’t been paid much attention. But there are favorable conditions for coal-derived gas accumulation there: (1) The Carboniferous-Permian coal seam is 4-8 m thick, and the dark mudstone is 50-60 m thick and has a TOC of 0.99%-7.33%, R_o of 1.8%-2.2%, providing good gas source conditions, and the main area has a gas generation intensity of more than 20×10⁸ m³/km². There conditions are favorable for formation of giant gas fields. (2) The upper and lower Shihezi Fm. and the Shanxi Fm. have abundant sandstone, with large single layer and gross thicknesses (the gross sandstone thickness of Well Zhentan 1 is 103.5 m), which is favorable for forming large-scale sandstone lithologic gas reservoir. (3) Well logging interpretation shows there are several gas-bearing and trace gas-bearing layers in the upper and lower Shihezi Fm. and the Shanxi Fm. in several exploration wells (Wells Zhentan 1, Zhentan 2, Qingtan 1 and Lian 1). The oil-bearing area has favorable coal-derived area of ​​32 400 km² (Fig. 7) and is expected to have proven coal-derived gas reserves of 1.0×10¹² m³, which will openup a new coal-derived development area with the production capacity of 100×10⁸ m³/a.

The Rovuma Basin is in the juncture of the Mozambique and Tanzania in East Asia on land and the west of the Indian Ocean, and covers 7.4×10⁴ km², including the land area of 3.2×10⁴ km², the sea area of 4.2×10⁴ km², and 3×10⁴ km² within Mozambique. The basin is on the Carboniferous crystalline rock basement and has the maximum sedimentary formation thickness of over 16 km^[90]. The basin is a new coal- derived gas play discovered after 2000. At present, the source rocks within the basin are not certain. Whether there are 3 sets or^[91] or 4 sets of^[92,93] source rocks and which set is the dominant source rock are still controversial.

3.5.1. Permian-Lower Triassic source rock

The Permian-Lower Triassic Karoo Fm. coal measure and shale source rocks are resulted from the Karoo rift in East Africa. The fluvial sandstone and coal measure were discovered on the continent within the basin^[94]. The shale is dominated by type III kerogen. In Well Lukuledi 1 in the northwestern part of the basin (Fig. 8), the shale has a TOC up to 7% and hydrogen index of 386 mg/g^[56]. The Karoo Fm. shale and coal measure in Ethiopia are more likely to produce gas, and are the dominant source rocks of the Calub gas field^[95].

3.5.2. Jurassic source rock

Although geochemical data of the Jurassic source rock in the Rovuma basin is not available, in the Mandawa sub-basin adjacent to the Tanzania Basin in the northern part of the basin (Fig. 8), 7 wells encountered about 400 m thick black shale, with a TOC of 0.6%-10.9%, 4.7% on average, mainly Type II/III kerogen and small amount of Type I and III kerogen. The Jurassic in the Rovuma basin has similar seismic reflection characteristics as that in the Mandawa sub-basin, and thus it is inferred that the Jurassic source rock also occurs in the Rovuma basin. Some studies concluded that the Jurassic source rock is the dominant source rock within the basin^[91,93].

3.5.3. Cretaceous source rock

The Cretaceous source rocks were revealed in Wells Lindi 2 (Tanzania) and Mocimboa 1 (Mozambique) (Fig. 8) in the Rovuma Basin. The Lower Cretaceous dark gray silty shale of Well Lindi 2 has a TOC of 1.34%. The Albian-Cenomanian shale in Well Mocimboa 1 has a TOC of more than 1% and the type III kerogen.

All the three sets of source rocks have mainly type III kerogen and are gas source rocks.

In addition, a small amount of liquid hydrocarbon was produced from the Eocene, Paleocene and Cretaceous in Well Mnagibay-1, and 1.9-2.1 t of light oil was produced from Well Mnagibay-3. The geochemical characteristics of oil are correlated to the Paleogene source rock. Therefore, the Paleogene is a set of oil source rock^[94], which is not the source rock of gas fields in the Rovuma Basin.

The Paleocene, Eocene and Oligocene in Rovuma Basin have large-scale (200-360 km²) sandstone reservoirs with good physical properties (porosity of 11%-33%, permeability of (20-1 560)×10^-3 μm²), large thickness (cumulatively 107-217 m in individual wells), and a set of 60-450 m thick regional mudstone cap overlies the Oligocene. Thus, the discovered gas reservoirs are concentrated in Paleocene, Eocene and Oligocene, while the Miocene and above reservoirs have no hydrocarbon accumulation^[92]. The gas generated by the Permian-Lower Triassic Karoo Fm., Jurassic and Cretaceous gas source rocks all could migrate upward through faults and unconformity planes to accumulate in Paleogene or the Upper Cretaceous (Mzia gas field). The major gas reservoirs occur in Paleocene, Eocene and Oligocene turbidite sandstone. The large gas fields are distributed in the distal deep-water thrust fault belt and its front edge, while no large gas field has been found in the near-shore land and shallow water normal fault areas^[91] (Fig. 8).

Previously, the geochemical characteristics of gas in the Rovuma basin were not investigated in-depth. But it was speculated that the gas was coal-derived gas as the three sets of source rocks have largely Type III kerogen^[56]. Recently, CAO Quanbin reached the findings based on the methane content of over 95%, analysis of δ¹³C₁, δ¹³C₂ and δ¹³C₃ values (shown in the figure, and the specific data not listed) and the average R_o of over 2.5% that some gas samples were coal-derived gas, others are mixture of coal-derived gas and oil-type gas, and all three sets of mudstone and shale could be source rocks for pool accumulation^[92]. The δ¹³C₁, δ¹³C₂ and δ¹³C₃ value were obtained through analysis of the map with the professional software and projected on δ¹³C₁-δ¹³C₂-δ¹³C₃ genesis identification map (Fig. 6). Fig. 6 shows that all points of the Rovuma Basin fall in the range of typical coal-derived gas fields in the Ordos Basin, i.e. Zizhou, Mizhi, Daniudi, Wushenqi gas fields. Thus, the gas of the Rovuma Basin is typical coal-derived gas.

Since August 2010, several major gas discoveries have been made in deep water and ultra-deep water drilling in the Rovuma Basin. By August 2013, 6 ultra-giant gas fields with recoverable reserves of over 1 000×10⁸ m³ and one super giant gas field (Mamba super giant gas field) have been discovered (Table 4)^[91], with total recoverable reserves of 35 736× 10⁸ m³. But these gas fields have not been produced yet. Their total recoverable reserves are comparable to the reserves of the Povayankov and Zaporal super giant gas field in the West Siberian Basin, or reserves of the Mamba super giant gas field and Doretabat super giant gas field in the Amu Darya Basin (Table 2). Therefore, Mozambique will become a major gas producing country when the gas fields in the Rovuma Basin are put into development.

The core of coal-derived gas theory is that coal measure is the gas source and the hydrocarbon generated by coal measure is largely gas with a little oil, so discoveries in coal-bearing basins are dominated by gas fields. But in a few individual coal-bearing basins or areas in gas-oil generation stage, coal- derived oil fields appear. There are two reasons: (1) Exinite content in organic maceral increases to 2-5 times that of the ordinary humic coal; (2) when the coal-derived gas field turned shallower during geologic history, the gas molecules diffuse faster than heavier oil molecules, leaving the oil behind.

Discovering and developing giant gas fields, especially super giant gas fields with recoverable reserves of over 1×10¹² m³, is the main way and key for a country to become a major gas producing country with an annual output of more than 500×10⁸ m³ and rapid development of the gas industry. The abundant coal-derived gas resources have made great contribution to the development of the gas industry in the world and in some countries. At present, 13 super giant coal-derived gas fields have been discovered in 5 coal-bearing basins in the world (West Siberia, Amu Darya, Northwestern Germany, Rovuma and Ordos). The coal-derived gas takes a large proportion in the world's gas reserves and production. As of the end of 2017, 13 super giant coal-derived gas fields had been discovered, with the original recoverable reserves of 49.99528×10¹² m³, accounting for 25.8% of the world’s total remaining gas recoverable reserves of 193.5×10¹² m³ that year. In 2017, there were 15 major gas producing countries in the world, with a total gas yield of 28 567×10⁸ m³, and 6 countries producing largely coal-derived gas (Russia, China, Australia, Netherlands, Turkmenistan and Uzbekistan) yielded 11369×10⁸ m³ of gas combined, and coal-derived gas accounted for 39.8% of the total output of the major gas producing countries.

Studying coal-derived gas and its enrichment rules and exploring and developing giant coal-derived gas fields, especially super giant coal-derived gas fields, are of great significance for rapid development of gas industry in a country. Before the discovery of Groningen super giant coal-derived gas field in 1958, the Netherlands only produced 2.0×10⁸ m³ of gas a year and needed to import oil and gas. In 1975, the Groningen gas field produced 828.8×10⁸ m³ of gas, accounting for 92.3% of the gas yield of the Netherlands that year, making the country a gas exporter. Due to the discovery of 7 coal-derived gas fields including Urengoi in the western Siberian Basin, Russia (the Soviet Union) has ranked the first or second largest major gas producing countries for 30 years consecutively. The Urengoi gas field has the highest cumulative gas production and annual output in the world. The Sulige super giant gas field and a number of gas fields were discovered in the Ordos Basin, making it a basin with the highest annual gas output in China. With the discovery of the Mamba super giant gas field and a number of large gas fields in the Rovuma basin, Mozambique will become a major gas-producing country when these gas fields are put into development.