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DAI Jinxing, NI Yunyan, QIN Shengfei, HUANG Shipeng, PENG Weilong, HAN Wenxue. Geochemical characteristics of ultra-deep natural gas in the Sichuan Basin, SW China. PETROLEUM EXPLORATION AND DEVELOPMENT, 2018, 45(4): 588-597.  
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Editorial Office of Petroleum Exploration and Development
Geochemical characteristics of ultra-deep natural gas in the Sichuan Basin, SW China
DAI Jinxing*, NI Yunyan, QIN Shengfei, HUANG Shipeng, PENG Weilong, HAN Wenxue
Research Institute of Petroleum Exploration & Development, PetroChina, Beijing 100083
* Corresponding author. E-mail: djx@petrochina.com.cn
Fund:Supported by the China National Science and Technology Major Project (2016ZX05007-001).
Abstract

The natural gas components and geochemistry of 38 ultra-deep gas wells (burial depth greater than 6 000 m) in the Sichuan Basin were analyzed to determine the genesis of ultra-deep natural gas in the basin. The ultra-deep natural gas components of the basin have the following characteristics: Methane has an absolute advantage, which can be up to 99.56% with an average of 86.6%; ethane is low, with an average of 0.13%; there is nearly no propane and butane. So it is dry gas at over-mature thermal stage. The content of H2S can be up to 25.21%, with an average of 5.45%. The alkane gas isotopes are: the carbon isotope varies from -32.3‰ to -26.7‰ for methane and from -32.9‰ to -22.1‰ for ethane. There is nearly no carbon isotopic reversal among methane and its homologues. Hydrogen isotope varies from -156‰ to -114‰ for methane, and from -103‰ to -89‰ for some ethane. The carbon isotope of CO2 varies from -17.2‰ to 1.9‰ and most of them fall within the range of 0±3‰. According to the δ13C1- δ13C2- δ13C3 plot, except some wells, all other ultra-deep gas wells are dominated by coal-derived gas. Based on the CO2 origin distinguishing plot and δ13CCO2, except some individual wells, most of the ultra-deep CO2 are of carbonate metamorphic origin. H2S in the ultra-deep layer of Longgang and Yuanba gas fields belongs to thermochemical sulfate reduction (TSR), while H2S from Well Shuangtan belongs to thermal decomposition of sulfides (TDS).

Key words: Sichuan Basin; ultra-deep gas; coal-derived gas; H2S; origin; geochemistry
Introduction

While petroleum exploration and production mainly focused on the middle-shallow layers in the past, it is now conducted at a fairly high level, and consequently with a reduced petroleum potential. Therefore, the deep and ultra-deep layers, with great petroleum potential, have become an important target for petroleum exploration, in particular for natural gas exploration. Scholars from different countries and institutions define “ deep” and “ ultra-deep” differently. In the Calculation Specifications for Petroleum Reservesissued by the National Mineral Reserves Committee (China) in 2005, a burial depth of 3 500-4 500 m is defined as deep layer and burial depth > 4500 m as ultra-deep layer. In Chin’ s drilling engineering, 4500-6 000 m is adopted as a deep layer, and more than 6 000 m as an ultra-deep layer. By contrast, for most European and American scholars, a deep layer corresponds to a burial depth over 4 500 m, because when the average geothermal gradient reaches 2.5-3.0 ° C/100 m, and the depth reaches 4 000-5 000 m, the large-scale liquid hydrocarbon generation ends and it transforms into the gaseous hydrocarbon generation[1]. Li Xiaodi shares the same point[2]. Tuo Jincai et al. define a burial depth > 4 500 m[3]as a deep layer. For Liu Wenhui et al., “ deep natural gas refers to natural gas that exists > 4 500 m underground” [4]; for Samvelov, a deep layer is > 4 000-5 000 m in depth[5]. As many scholars have pointed out, in order to establish a depth criterion for deep layer, the basin geothermal gradient should be taken into consideration[6, 7, 8]. For layers with relatively high geothermal gradient, the deep layer is relatively shallow; while for layers with relatively low geothermal gradient, the deep layer is relatively deep. In the Songliao Basin, the geothermal gradient is 3.7 ° C/100 m on average, 6.1 ° C/100 m the highest[9]. In the North China Basin, the geothermal gradient is 3.58 ° C/100 m on average[10]. Therefore, in eastern China, a deep layer is 3500-4 500 m in depth, and the ultra-deep corresponds to > 4500 m[8]. In the Tarim Basin in western China, the geothermal gradient is 2.26± 0.3 ° C/100 m on average[11], hence a deep layer is 4500-6 000 m in depth, and an ultra-deep layer > 6500 m[8]. In the Sichuan Basin, the average geothermal gradient is 2.28 ° C/100 m[12], basically equivalent to that in the Tarim Basin. Therefore, the depth of deep and ultra-deep layers should be the same as that of the Tarim Basin.

Since the geothermal gradient is high in eastern China and low in the Mid-western China, there should be different criteria for distinguishing between deep and ultra-deep layers. Zhao Wenzhi et al. suggest that in the eastern part of China, a deep layer corresponds to 3 500-4 500 m in burial depth, and an ultra-deep layer > 4 500 m[13], while in the western region, a deep layer is 4 500-5 500 m in burial depth, and an ultra-deep layer > 5 500 m. Wang Zhaoming et al., after an exploration in the Kuqa Depression, suggest that an ultra-deep layer is > 6500 m[14]. Feng Jiarui et al. define a burial depth of > 7000 m as an ultra-deep layer[15]. Xiao Deming et al. think that the deep layers in the northern Songliao Basin are those layers below the 2nd Member of the Lower Cretaceous Quantou Formation[16]. Mielieniexsk believes that the natural gas below the oil window is generally called as deep-layer gas[17]. He Zhiliang et al., and Li Zhonghe, Sun Wei et al. believe that in China’ s mid-west oil and gas basins, a deep layer generally corresponds to 4500-6000 m in depth, and an ultra-deep layer > 6 000 m[18, 19, 20]. The authors of this paper agree with He Zhiliang, Li Zhong and the Chinese Petroleum Institute’ s criteria of deep and ultra-deep layers[8].

The Yangxin Series (7 153.5-7 175 m) of the Laoguanmiao in the Sichuan Basin is the earliest discovered ultra-deep gas reservoir in China[21]. The Mills Ranch gas field in the Anadarko Basin in the United States was once the deepest gas field in the world, with a proven reserve of 365× 108m3 in the Lower Ordovician carbonate rocks (7 663-8 083 m)[22]. By the end of 2016, 52 industrial oil-gas fields with a depth > 6000 m have been discovered all over the world. The Merganser deepwater gas field, located in the Gulf of Mexico Basin in the U.S., has a depth of 8547 m and a reserve of only 21.89× 108m3, making it the world’ s deepest gas field[23]. The deepest gas field in China is the Keshen gas field in the Tarim Basin. The wells in the Keshen 9 gas reservoir are drilled with average depth of 7 785 m; the depth of the Keshen 902 well is 8038 m, and the gas production rate is 30× 104 m3/d using a 5 mm oil nozzle in the reservoir without reservoir stimulation[24].

1. Overview of natural gas geology in Sichuan Basin

The Sichuan Basin is a large superimposed gas-bearing basin developed on the basis of the Craton, with an area of approximately 18× 104km2. It is one of the most stable basins in China, and is conducive to the development and preservation of gas fields. The Sichuan Basin is also one of the first basins in the world to explore and exploit natural gas. As far back as the Qin and Han dynasties, artificially drilled salt wells appeared, and natural gas was produced too[25]. The Weiyuan gas field is the oldest Sinian gas field in terms of reservoirs in China. In 2016, the annual output of natural gas amounted to 300.19× 108m3 (among which, shale gas reserves are 78.82× 108m3). By the end of 2016, a total of 130 gas fields (including 3 shale gas fields) had been discovered in the basin, and 21 of them are large gas fields (Fig. 1). The proven natural gas geological reserves were 37 544× 108m3(among which, shale gas reserves were 5441× 108m3), which accounted for only 9.85% out of the 38.11× 1012m3of the total natural gas resources of the basin, indicating great potential for natural gas exploration. Industrial oil and gas bed series are numerous: there are 25 regular tight gas and oil pays (18 marine facies) and 2 shale gas pays. Hence, the Sichuan Basin is the oil and gas- containing basin with the largest number of industrial petroleum bed series found in China. The Yuanba and Longgang gas fields are two large ultra-deep gas fields with reservoir depth > 6 000 m. Previously, researchers believed that there were 8 large ultra-deep gas fields in the Sichuan Basin. This view is debatable, for a depth of 4 500 m as the yardstick of ultra-deep layer is apparently too shallow when applied for the Sichuan Basin[26]. Recently, Shuangtan 3 well in Western Sichuan has obtained industrial gas flow in the ultra-deep Devonian Guanwushan Formation (7 569-7 601.5 m), which fills the gaps in China’ s industrial gas reservoirs in the Devonian System.

Fig. 1. Distribution of gas fields in the Sichuan Basin, SW China.

The Sichuan Basin consists of a binary structure of basement and sedimentary caprock. The total thickness of the sedimentary caprock on the Presinian substrate is 6 000- 10000 m. The caprock is formed by the superposition of the marine strata and the terrestrial strata. The thickness of marine strata, the mainly developed strata from Sinian to Middle Triassic, is as much as 2 000-5 000 m. Most of the gas source rocks in the basin (mainly the Doushantuo FM. (Z1do), Qiongzhusi FM. (— C1q), Longmaxi FM. (S1l), Longtan FM. (P3l), and Dalong FM. (P3d)) and gas fields are distributed in this set of strata. Above the Middle Triassic are strata of terrestrial clastic rock, with a thickness of 2 000-5 000 m, among them, the Upper Triassic Xujiahe FM. (T3x) is coal series, the Lower Jurassic Lianggaoshan FM. (J11) and the Ziliujing FM. (J1z) are mainly lacustrine dark mudstones. A small amount of petroleum in the Sichuan Basin has a bearing on the Lower Jurassic. The crude oil and gas combination in the Sichuan Basin is shown in Fig. 2.

Fig. 2. Histogram of the source, reservoir and caprocks in the Sichuan Basin. T2l— Middle Triassic Leikoupo Formation; T1j— Lower Triassic Jialingjiang Formation; T1f— Lower Triassic Feixianguan Formation; P3ch— Upper Permian Changxing Formation; P2m— Middle Permian Maokou Formation; P2q— Middle Permian Qixia Formation; P1l— Lower Permian Liangshan Formation; C2h— Middle Carboniferous Huanglong Formation.

2. Component characteristics of natural gas

The ultra-deep (≥ 6 000 m) natural gas in the Sichuan Basin is mainly found in the Longgang and Yuanba gas fields (Fig. 1). Although individual wells (Puguang 9 and 10) in the Puguang gas field have been drilled into ultra-deep layers, the mainstream well depth is around 5 259 m[26], in the range of deep gas fields. In addition, all of the ultra-deep gas wells are regional wells (Table 1). As demonstrated in Table 1, the latest layer of ultra-deep gas is the Middle Triassic Leikoupo FM. (T2l4) (Pengzhou 1, Xintan 1 and Yangtan 1), and the oldest layer is the Lower Cambrian Longwangmiao FM. (— C1l, Longtan 1). In the Longgang and the Yuanba gas fields, natural gas reservoir is located in the Changxing FM. (P3ch) and the Feixianguan FM. (T1f). All ultra-deep gas reservoirs are carbonate rocks.

Table 1 Geochemical features of natural gas from ultra-deep (> 6 000 m) wells in the Sichuan Basin.

As shown in Table 1 and Fig. 3, alkane gas is mainly composed of CH4. According to the analysis of 38 wells, the average content of CH4is 86.67%, ranging from 53.25% (YB1) to 99.56% (Shuangtan 7). The C2H6 content is very low, precisely 0.01% (Laojun 1)-1.05% (YB 12), with the mean of 0.13%. The C3H8 content is 0 in 35 wells, and 0.29% in very few wells (Puguang 9). In 46 wells, the C4H10content is 0. In summary, the content of C2H6is very low, and the content of C3H8and C4H10 is close to zero. Obviously, this is associated with the high maturity and cleavage in the ultra-deep layer. It can be seen that the ultra-deep gas in the Sichuan Basin is dry gas. The nitrogen content is generally low, ranging from 0.01% (LG9) to 15.06% (YB221), averaging at 1.84%. The CO2 content was 7.72% on average, the maximum and minimum content is 40.05% (Longgang 39) and 0.07% (YB222) respectively. The H2S content averages at 5.45%, with a maximum of 25.21% (Laojun 1) and a minimum of 0.02% (Shuangtan 1).

Fig. 3. Components of ultra-deep natural gas in the Sichuan Basin. The sample numbers are in the brackets.

3. Composition of carbon and hydrogen isotopes

As can be seen from Table 1, among all the wells, the most common gases in alkane gases are CH4and C2H6. Therefore, only δ 13C1, δ 13C2, and δ D1 are available, providing very limited information of carbon and hydrogen isotope, and consequently making it more difficult to identify genetic types of natural gas.

3.1. Carbon isotopic values of alkane gas

As shown in Table 1, the δ 13C1value ranges from -33.6‰ (Xinshen 1) to -26.7‰ (Shuangtan 8), and the δ 13C2 value ranges from -32.9‰ (Xinshen 1) to -22.1‰ (Longgang 8). It is clear from Fig. 4 that most of the natural gas can be classified as primitive type natural gas[27, 28, 29, 30, 31, 32], and gas source correlation can be carried out using the δ 13C1value.

Fig. 4. Series types of carbon isotopes.

3.2. Hydrogen isotopic values of alkane gas

It is clear from Table 1 that the δ D1value ranges from -156‰ (YB221) to -113‰ (YB12), and in only 4 samples, the δ D2 value ranges from -103‰ (YB222) to -89‰ (Puguang 9).

3.3. Carbon isotopic values of CO2

As can be seen from Table 1, the δ 13CCO2 value ranges from -17.2‰ (Longgang 1) to 1.9‰ (Longgang 61), which is far lower than the high δ 13CCO2values in China and other places in the world. In China, the δ 13CCO2 value ranges from -39‰ to 7‰ [33]; in the world, it was once considered to be from -42‰ to 27‰ [34]. The authors find that the range is becoming even larger recently, varying from -55.2‰ to 45.0‰ [35].

4. Origin of natural gas
4.1. Origin of alkane gas

The values of δ 13C1, δ 13C2, and δ 13C3 are listed in Table 1 and demonstrated in Fig. 5, and the origin of alkane gas from Longgang, Yuanba and Puguang gas fields and regional exploration wells are discussed respectively in Table 1.

Fig. 5 Chart for ultra-deep natural gas δ 13C1-δ 13C2-δ 13C3 identification in the Sichuan Basin[36].

It is clear from Fig. 5 that the alkane gas in the Longgang gas field is coal-derived (except carbon isotopic reversal in Longgang 62 and Longgang 001-3). This is consistent with previous researches by Hu Guoyi et al.[27] and Qin Shengfei et al.[30]. Zhao Wenzhi et al.[37]pointed out that the reef beach in Longgang is a single coal-derived gas accumulation domain, with intrusive asphalt developed in the reservoir. Possible causes of isotope reversal in alkane gases are as follows[32, 38]: 1) isotope fractionation effect during gas migration; 2) oxidation of a certain alkane gas component by bacteria; 3) mixture of organic and inorganic gases; 4) mixture of coal-derived gas and oil-type gas; 5) mixture of gases generated by the same type of source rocks but from two different intervals with different maturity; 6) mixture of gas generated by source rocks of the same interval but at different maturity level. However, the component characteristics of gases from the two wells with carbon isotopic reversal does not match Cause 2; meanwhile, all the helium isotopes of gases from Sichuan Basin demonstrate its crust-derived origin[39], so Cause 3 can be eliminated; finally, the natural gas in this gas field is mainly coal-derived gas, so Causes 4-6 can be eliminated. Therefore, the carbon isotopic reversal of the two wells may be related to the carbon isotope fractionation in coal-derived gas migration, namely, the fractionation effect leads to the carbon isotopic reversal of coal-derived gas from positive carbon isotope series.

As shown in Table 1, among the alkane gases from the Yuanba gas field, those contain δ 13C1, δ 13C2 or δ 13C3 are positive carbon isotope series, which are primary-type alkane gases without secondary alteration or mixture. As can be seen from Fig. 5, the alkane gas in the Yuanba gas field is mainly coal-derived gas, except for the two wells of YB221 and YB222, which display characteristics of oil-type gas. Scholars hold different views about the origin of the alkane gas in the Yuanba gas field and source rocks. Some believe that alkane gases are mainly coal-derived with a small percentage of oil-type gas[27, 40]. The authors of the present article hold the same view. There are many dark mudstones and marls in the lower part of the Longtan FM. in Yuanba 3, and intervals for which the TOC is > 0.5% is up to 70 m. In the Longtan FM., close to the southeast of the gas field, near Yilong, the coal seam has 3 layers[27], indicating a desirable condition for the formation of coal— derived gas source rocks. Others believe that alkane gas is mainly oil-type gas originated from the cracking of crude oil[29, 41, 42, 43], and source rocks are mainly in Dalong FM. and Longtan FM. [Wujiaping FM. (P3w)]. The TOC value is 0.27%-7.2%, and the kerogen δ 13C of the Longtan FM. in Yuanba 3 is -27.8‰ - -24.9‰ , -26.8‰ on average. The organic matter is mainly mix-typed[44, 45]. Based on the characteristics of argon isotopes, some researchers speculated that the gas in the Yuanba gas reservoir may be oil cracking gas formed in the Sinian or Lower Cambrian Qiongzhusi FM.[46] We supported the view that, the alkane gases in the Yuanba gas field are mainly coal-derived gases, with a small amount of oil-type gases. The source rocks should be Longtan FM. (Wujiaping FM.) and Dalong FM. The kerogen value of Longtan FM. in Yuanba 3 is basically equivalent to the Type III-kerogen δ 13C value, i.e. -25.4‰ - -26.6‰ according to the classification of Redding et al.[47] Therefore, the source rocks of Longtan FM. or Wujiaping FM. in Yuanba gas field are not mix-typed but humic-typed and is conducive to gas generation. Fig. 6 is based on the δ 13C1and δ 13C2 values in Table 1. It can be seen from Fig. 6 that the alkane gas in the Yuanba gas field is also mainly coal- formed.

Fig. 6. Diagram for δ 13C1-δ 13C2comparison of coal-derived gas and oil-type gas.

As indicated in Table 1, among the alkanes gas in regional exploratory wells, except for Yangxin 1, all that contain δ 13C1, δ 13C2 and δ 13C3 are positive carbon isotope series. According to the identification standard of the coal-derived gas being δ 13C > -28‰ and the oil type gas being δ 13C2< -28.5‰ [31, 32], alkane gas from Pengzhou 1 is coal-derived gas, and that from Xinshen 1 is oil-type gas. The identification diagram (Fig. 5) verifies this view. Again, the identification standard says the coal-derived gas has δ 13C > -28‰ , and when δ 13C2 ranges from -28.5‰ to -28‰ , the natural gas is mainly coal-derived gas[32]. Except for inorganic gas, methane with δ 13C2 value > -30‰ is coal-derived gas.[33] The alkane gas from all Shuangtan FM., Longtan 1 and Laojun 1 in Table 1 is coal-derived gas.

The δ D1— 2 data in Table 1 are not abundant, but judging from the limited data, the δ D1 value of coal-derived gas is heavier, ranging mainly from -129‰ to -113‰ , while the δ D1 value of oil-type gas is light, ranging mainly from -156‰ to -131‰ . The δ 13C1-δ D2 Chart (Fig. 7) reflects this feature. In particular, it is necessary to point out that the oil-type gas produced in the Qiongzhusi FM. and the Sinian sapropelic source rocks in the paleo-uplifts in the Middle Sichuan Basin also have light δ D1 values, from -150‰ to -131‰ [48](Fig. 7). As shown in Fig. 7, in the Longgang and Yuanba gas fields, all the alkane gases from regional exploration wells except for Xintan 1 are coal-derived gas. The δ 13C1-δ 13C2 comparison diagram also proves that the alkane gas in the regional exploratory wells is mainly coal-derived gas (Fig. 6).

Fig. 7. Comparison diagram of δ 13C1-δ D1 in natural gas between Cambrian-Sinian System and Changxing FM. -Feixianguan FM. in Sichuan Basin.

There are many Shuangtan wells in the northwestern Sichuan Basin (Table 1). Most of the wells have got commercial gas stream. The producing formations are Changxing FM. (P3ch), Maokou FM. (P2m), Qixia FM. (P1q), Guanwushan FM. (D2g), and Longwangmiao FM. (— C1l). Previous studies focused on the source rocks of Paleozoic oil and gas in the northwestern Sichuan Basin. Based on a variety of biomarker studies on solid bitumen, oil sandstone, and oil seepage found in outcrop regions, the source rock is considered as black shales of Sinian Doushantuo FM.[49], Cambrian or Lower Cambrian[50, 51], Lower Cambrian and Lower Silurian[52, 53]. Tenger et al. argue that the high-quality source rocks of marine reservoirs in the northern part of Longmenshan include Qiongzhusi FM., Dalong FM. argillite and Qixia FM., and Maokou FM. carbonate rocks[54]. As noted, the Upper Paleozoic source rocks are particularly noteworthy, because if there are source rocks of the Dalong FM. in northwestern Sichuan as in the Yuanba gas field, it can be explained that the alkane gas from Shuangtan wells is coal-derived gas, not oil type gas originated from Doushantuo FM. and Qiongzhusi FM. of Lower Cambrian (Fig. 6).

4.2. Origin of Carbon Dioxide

Carbon dioxide can be both inorganic and organic origin. δ 13CCO2 is an effective method to identify the two possible causes. There have been many studies on this at home and abroad. Shen Ping et al. believe that for inorganic genesis, δ 13CCO2> -7‰ , while for organic genesis, the δ 13CCO2 value is -20‰ to -10‰ [55]. Shangguan Zhiguan et al. state that for the metamorphic genesis, the δ 13CCO2 value is from -3‰ to 1‰ , while for the mantle origin, the average δ 13CCO2 value is -8.5‰ to -5‰ [56]. Moore et al. point out that the δ 13CCO2 value in the basalt inclusions of the middle Pacific ridge is -6‰ to -4.5‰ [57]. Could et al. think that though the δ 13CCO2 value of the magma source varies a lot, it is generally -7‰ ± 2‰ [58]. Dai Jinxing et al. conduct a comprehensive study on a large number of δ 13CCO2 values acquired by domestic and international researchers, summarizing that the total organic origin δ 13CCO2 value is < -10‰ , and the inorganic origin δ 13CCO2 value is > -8‰ . The inorganic δ 13CCO2 value of the carbonate rock metamorphoses is close to the δ 13C value of the carbonate rock, which is around 0± 3‰ ; the δ 13CCO2 value of the volcanic-magmatic and mantle-related inorganic genesis is mostly -6‰ ± 2‰ . A diagram to identify organic and inorganic CO2 is provided (Fig. 8)[59].

Fig. 8. Identification of organic and inorganic CO2.

The δ 13CCO2values and CO2content of relevant wells in Table 1 are put into Fig. 8. It is clear from Fig. 8, only 2 wells (Longgang 1 and YB27) have standard organic CO2(The CO2and hydrocarbon generation happen during the same period). Most of the CO2 are of inorganic origin, formed during the cracking and metamorphism of carbonate reservoirs during the over-mature stage. This is evidenced by the δ 13CCO2values of the wells, which are basically within a range of 0± 3‰ of the δ 13C value of carbonate rocks.

4.3. Origin of H2S

There are three genetic types of H2S:

4.3.1. Bacterial sulfate reduction (BSR)

Sulfate-reducing bacteria use a variety of organic substances (including oil and gas) as hydrogen donors to reduce sulfates to form H2S, which can be summarized by the following reaction formula[60]:

$\Sigma \text{CH(oil and gas)}+\text{CaS}{{\text{O}}_{4}}\xrightarrow{\text{Effects of sulfate reducing bacteria}}$

$\text{CaC}{{\text{O}}_{3}}+{{\text{H}}_{2}}\text{S}+{{\text{H}}_{2}}\text{O}$ (1)

For the BSR-related formations, the temperature is generally < 80 ° C, Ro is about 0.2%-0.3%[61, 62, 63], and the H2S content is generally < 5%[64]. Since the dry gas of H2S in Table 1 is at an over-matured stage, the Ro generation is much larger than 0.3% and therefore does not belong to the BSR genesis.

4.3.2. Thermochemical sulfate reduction (TSR)

TSR refers to H2S formed by high-temperature chemical reduction of sulfates with the participation of hydrocarbons or organic matter. Its formation can be summarized by the following formula:

$\text{2C}+\text{CaS}{{\text{O}}_{4}}+{{\text{H}}_{2}}\text{O}\to \text{CaC}{{\text{O}}_{3}}+{{\text{H}}_{2}}\text{S}+\text{C}{{\text{O}}_{2}}$ (2)

$\Sigma \text{CH(oil and gas)}+\text{CaS}{{\text{O}}_{4}}\to \text{CaC}{{\text{O}}_{3}}+{{\text{H}}_{2}}\text{S}+{{\text{H}}_{2}}\text{O}$ (3)

In formula (2), C is the carbon of the organic compound in the source rock; In formula (3), ∑ CH is oil-gas. The formation of TSR requires a temperature of 100 ° C-140 ° C[65]; the H2S formation temperature in Leikoupo FM. of Zhongba gas field is higher than 119 ° C [66], which in Cai Chunfang’ s calculation is > 120 ° C[67]. Its H2S content changes greatly. For natural gas, there are two identification marks of TSR. One is a high H2S concentration (> 5%); the other is that the starting temperature of the reaction is generally > 120 ° C[67]. The H2S content in Yuanba gas field ranges from 0.20% (YB1, T1f2) to 13.33% (YB1, P3ch2), mostly > 5% (Table 1). Meanwhile, the formation temperature of the Feixianguan FM. gas reservoir is 149.9 ° C, and that of the Changxing FM. gas reservoir is 139.2 ° C-150.3 ° C[68]. Both show that H2S from the Yuanba gas field belongs to the TSR type. The H2S content in the Longgang gas field is fairly high, namely > 5%, so its H2S also belongs to the TSR type. H2S in the Middle and Lower Triassic and Sinian Systems in the Sichuan Basin is the TSR type[69], H2S in the Sinian System in Weiyuan gas field is of TSR origin[70]. In addition, H2S in Puguang gas field is of TSR origin[66, 70, 71]. In Table 1, both Laojun 1 and Pengzhou 1 produce dry gas, for which the H2S content is from 3.72% to 25.21%. The H2S genesis is TSR.

4.3.3. Thermal decomposition of sulfides (TDS)

H2S is formed by the cleavage of petroleum or kerogen. There are two identification features: 1) it exists in the over- mature sulphate rock formation; 2) the H2S content is generally less than 2%[60] or generally within 2%-3%[72]. The gas composition formed by the overheat gasification of petroleum and condensate is 4CO2• 46CH4• N2• H2S + trace hydrogen[73]. According to this composition, in the superheated gas mixture, the H2S content accounts for about 1.9% of the total gas composition, which determines the H2S content of TDS genesis is less than 2%. Some scholars consider the aforementioned H2S genesis in the Sinian gas reservoir as of TSR genesis[69, 70]. However, others consider it as of TDS genesis. There are two explanations for this. 1) The gas reservoir produces dry gas; the Ro maximum is 3.136%-4.64%, the H2S content is mostly 0.9%-1.5%, with only two wells being more than 2%, and a small number of wells is merely 0.5%-0.9%[60]. 2) Based on the analysis of 447 gas samples, the H2S content was 3.44% at maximum, with an average of 1.09%[74]. It was considered that the H2S in the Sinian Dengying FM. gas reservoir in the Weiyuan gas field was not of TSR origin but of TDS genesis. In Table 1, the Shuangtan wells are dry gas with high CH4content, and very low H2S content (0.02%-0.41%). Therefore, preliminary analysis suggests that it may also be of the TDS genesis. However, due to the absence of H2S analysis in many wells, the actual genesis requires further study and confirmation.

5. Conclusions

In the Sichuan Basin, two large fields of coal-derived gas have been discovered in ultra-deep layers in Longgang and Yuanba. In most of the ultra-deep wells, there is coal-derived gas with a positive carbon isotope series; while only in the Xinshen 1 and YB222 wells, there is oil-type gas. As petroleum exploration goes on, some ultra-deep gas fields will be proved among this group of ultra-deep exploratory wells. At present, ultra-deep exploratory wells are drilled mainly in northeastern and western Sichuan. It is proposed that ultra-deep gas exploration be carried out in the southern, middle and eastern areas of Sichuan to make new discoveries and breakthroughs.

All of the ultra-deep gasses are dry gas with very low humidity (0.02%-1.25%) (Table 1), indicating that natural gas is the outcome of over-maturity. H2S in the ultra-deep layer belongs to TSR, while H2S from Well Shuangtan belongs to TDS.

Previous studies have generally discovered bitumen in gas reservoirs, and take the gas in the gas reservoir as oil-type gas derived from crude oil cracking. This view is debatable. For example, disseminated bitumen is developed in the reservoir of the Longgang gas field, but Longgang is a coal-genetic gas field. The reason is that in the period of coal generating both gas and oil, in addition to a large amount of coal-genetic gas, a small amount of condensate oil and light oil is also generated, with the latter producing bitumen during the over-mature stage. Therefore, the discovery of bitumen in the reservoir does not necessarily indicate an oil-type gas. A comprehensive study of the size, occurrence, and gas isotopic composition of the asphalt is needed to draw a final conclusion.

Acknowledgments

The authors thank Professor Liu Quanyou and Senior Engineer Xie Banghuathe for providing valuable geochemical data and related documents on Well Qutan.

The authors have declared that no competing interests exist.

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