The Anyue gas field is the largest mono-bloc marine carbonate gas field ever discovered in China. By the end of 2020, the cumulative proved gas reserves in the Sinian Dengying Formation and Cambrian Longwangmiao Formation were booked to be 1.03×10¹² m³, 56.3% of which were discovered in the Dengying Formation. With respect to gas origin, there are doubts about the common opinion of cracked gas^{[1,2,3,4,5,6]} in view of heavier methane carbon isotopic composition (δ¹³C₁) than δ¹³C in residual bitumen. Thus, some viewpoints, e.g. residual bitumen genesis, late kerogen genesis^[7], and aqueous fusion degassing^[8], were proposed to decipher gas origin. Due to the discrepancies in heavy hydrocarbon content, ethane carbon isotopic composition (δ¹³C₂), and methane hydrogen isotopic composition (δ²H_CH4) between Dengying gas and Longwangmiao gas, there are two viewpoints of Dengying gas origin, i.e. isogenetic Dengying and Longwangmiao gases originated from Cambrian Qiongzhusi source rocks^{[2, 4-5]} and hybrid gases from Qiongzhusi and Sinian source rocks^{[1, 3, 9-12]}. Both arguments have not been fully proved. In 2020, two wells, PT1 and JT1, drilled at the north slope in central Sichuan uplifted area yielded economic gas flow of 121.98×10⁴ m^3[13] and 51.62×10⁴ m^3[14] per day from the second member of the Dengying Formation (Deng2 for short) and the Cambrian Canglangpu Formation, respectively. PT1 Deng2 gases are geochemically similar to Anyue Dengying gases in heavy δ¹³C₂, light δ²H_CH4, and low ethane (C₂H₆) content. In contrast, JT1 gases feature light δ¹³C₂, heavy δ²H_CH4, and high C₂H₆ content. We thus began to concern Sinian (Dengying and Doushantuo) source rocks and protogenetic gas system. Our efforts focus on Sinian and Cambrian source-rock geochemistry, gas reservoir correlation, and reservoir forming conditions to investigate Sinian gas origin, contribution of Sinian source rocks to gas accumulation, and efficiency of the protogenetic gas system. Our findings may offer support to primary Sinian gas reservoir exploration in 3 craton basins with (potential) Middle Neoproterozoic source rocks^[15,16].

Different from gases of Cambrian origin, Sinian gases feature low hydrocarbon content and high non-hydrocarbon content, i.e. low CH₄ content, low C₂H₆ content, high CO₂ content, high N₂ content, high H₂S content, and high He content.

In Sinian hydrocarbon gases, CH₄ content ranges 70.36%-94.61% (average of 89.05%) and C₂H₆ content ranges 0.02%-0.07% (average of 0.04%). In Cambrian gases, CH₄ content ranges 90.92-99.10% (average of 95.77%) and C₂H₆ content ranges 0.05%-0.27% (average of 0.14%). In comparison, Sinian gases exhibit low CH₄ and C₂H₆ contents (Fig. 1a), which are related to high non-hydrocarbon content, e.g. CO₂. The drying coefficient of all samples is larger than 0.997, indicating typical dry gas.

Sinian non-hydrocarbon gases include CO₂, N₂, H₂S, and some He and H₂ and generally feature middle to high CO₂ content, middle H₂S content, trace to middle N₂ content, and trace He content. CO₂ content ranges 3.54- 28.17% (average of 8.52%); H₂S content ranges 0.08%-6.80% (average of 1.05%); N₂ content ranges 0.37%-4.45% (average of 1.22%); He content ranges 0.01%-0.10% (average of 0.03%); H₂ content ranges 0.01%-0.93% (average of 0.13%). Sinian gases mostly exhibit higher non-hydrocarbon content than Cambrian gases (Fig. 1b, 1c).

H₂S in gas reservoirs is the product of thermochemical sulfate reduction (TSR) and CO₂ is the by-product of TSR^[17,18,19]. As shown in Fig. 1b, H₂S content in Cambrian gases is mostly smaller than 1% and CO₂ content is mostly below 3%; H₂S content correlates well with CO₂ content. In Sinian gases, H₂S content is mainly below 1% and occasionally ranges 1%-3%; CO₂ content is mainly above 4%. High CO₂ content is related to the acidizing treatment in the tests in addition to TSR, which has been demonstrated using the samples from the interval at 5130-5196 m in the lower Deng4 Member, Well GS1. CO₂ content was measured to notably decrease with the time interval between sampling and acidizing treatment^[10]. The samples with CO₂ content above 8% were mostly acquired from those highly deviated wells after acidizing treatment. The value of δ¹³C_CO2 ranges from -1.3‰ to 1.1‰, indicating inorganic origin.

In Sinian gases, He content ranges 0.01%-0.06% with the average of 0.02%; N₂ content ranges 0.28%-0.9% with the average of 0.65%; He content correlates well with N₂ content (Fig. 1c). Wei et al. held the opinion that He in Gaoshiti-Moxi (GaoMo for short) gases may originate from radioelement decay, e.g. U and Th in the crust^[20]. N₂ in natural gases may come from atmosphere, organic matter diagenetic evolution, pyrometamorphism of N₂-bearing rocks in the earth crust, and mantle degassing. In view of N₂δ¹⁵N from -8‰ to -3‰ and good correlation between N₂ content and δ¹⁵N (Fig. 1d), we inferred that N₂ is the product of organic matter thermal ammoniation in source rocks and N₂ content may increase with thermal maturity. The enrichment of He and N₂, with their molecules smaller than methane molecules in diameter, in the Sinian and Cambrian Systems may indicate different origins of source rocks in addition to good preservation conditions; the content of He and N₂ was observed to increase with the maturity of source rocks.

Compared with Cambrian gases, Sinian gases feature heavy δ¹³C₂ and light δ²H_CH4.

Sinian gas samples with δ¹³C₁ from -35.1‰ to -31.0‰ and main peak from -34.0‰ to -32.0‰ were mainly acquired from GaoMo. This main peak is close to the range from -34.0‰ to -32.0‰ for Cambrian samples from GaoMo (Fig. 2a). The samples with δ¹³C₁ below -34.0‰ came from the Deng2 Member in Wells PT1 and ZJ2 drilled at the north slope, and these samples show heavier δ¹³C₁ values than Canglangpu analogues from Wells JT1 (-38.2‰) and CT1 (-36.2‰). The value of δ¹³C is somewhat related to H₂S content in gases. In eastern Sichuan Basin, for example, gas samples with high sulfur content (H₂S content of 8.77%-17.06%) occurring from the Upper Permian Changxing Formation to the Lower Triassic Feixian'guan Formation show δ¹³C₁ 2.3‰-4.8‰ heavier than the samples with low sulfur content (H₂S content of 0.02%-0.26%) and δ¹³C₂ 2.3‰-8.0‰ heavier than those samples^[17]. This means with respect to gas reservoirs with middle to low sulfur content, i.e. H₂S content mainly below 1% and occasionally between 1% and 2%, in the central Sichuan paleohigh, TSR is not the dominant factor controlling isotopic composition in spite of some influence. As per preceding studies, δ¹³C₂ variation is not necessarily correlated with H₂S content, but δ¹³C₁ tends to lighten with H₂S content^[10]. Thus, we attributed δ¹³C₂ variation in Sinian-Cambrian gases to source rocks with different maturities instead of TSR.

The δ¹³C₂ value of Sinian gases ranges from -33.6‰ to -26.0‰, and the main peak ranges between -29.6‰ and -27.1‰. Sinian δ¹³C₂ is much heavier than Cambrian δ¹³C₂ (with the main peak from -35.3‰ to -30.6‰) (Fig. 2a). Similar δ¹³C₁ and significantly different δ¹³C₂ between Sinian and Cambrian gases may be related to two factors. One is isotopic fractionation in the process of C₂H₆ pyrolysis at extremely high maturity. Due to the influence of activation energy, ¹²C cracked first and thus δ¹³C in residual C₂H₆ became heavy. As thermal evolution went on, there was less and less C₂H₆ and thus δ¹³C₂ got heavier and heavier^[21]. The other is greater δ¹³C₂ variation than δ¹³C₁ at the stage with high maturity in spite of the similar trend that δ¹³C₁ and δ¹³C₂ all get heavier at high maturity according to simulation experiments. Li et al.^[22] published thermal simulations of δ¹³C₁ and δ¹³C₂ variations in the gases originating from sapropelic source rocks. From the lowest maturity to the highest maturity, δ¹³C₁ became heavier by 5‰ and δ¹³C₂ became heavier by 11.7‰. Wang et al.^[23] stated that in the pyrolysis simulations for the oil samples from the Tarim Basin, δ¹³C₁ became heavier by 10‰ and δ¹³C₂ became heavier by 25‰; in bitumen pyrolysis simulations, δ¹³C₁ became heavier by 8‰ while δ¹³C₂ became heavier by 19‰. Hence, different δ¹³C₁ and δ¹³C₂ variations at extremely high maturity resulted in similar δ¹³C₁ and significantly different δ¹³C₂ between Sinian and Cambrian gases in the Sichuan Basin. As per the relation between δ¹³C₂ and C₂H₆ content (Fig. 2b), δ¹³C₂ becomes heavier with decreased C₂H₆ content. Canglangpu gases in the north slope of central Sichuan paleo-uplift and Longwangmiao gases in GaoMo originated from the same package of source rocks and consequently exhibit similar δ¹³C₂ and C₂H₆ content despite the large differences in buried depth. At Well JT1, for example, the differences in buried depth reach 1700-2200 m between the pay zone in the Canglangpu Formation at 7000 m and the Longwangmiao Formation in GaoMo; but there are no great discrepancies in δ¹³C₂ and C₂H₆ content. In contrast, the Dengying and Longwangmiao Formations show remarkably different δ¹³C₂ and C₂H₆ content despite the buried-depth differences of 500-1000 m; this indicates that the source rocks of Dengying gases and Cambrian gases are not exactly the same.

The δ²H_CH4 value of Sinian gases ranges from -157‰ to -135‰, and the main peak ranges between -150‰ and -137‰. The value of δ²H_CH4 somewhat correlates with δ¹³C₂; generally speaking, δ¹³C₂ becomes heavy as δ²H_CH4 becomes light (Fig. 3a). With respect to different intervals, Deng2 δ²H_CH4 ranges between -152‰ and -136‰ with the average of -145‰; Deng4 δ²H_CH4 ranges from -157‰ to -135‰ with the average of -142‰. As shown in Fig. 3a, Dengying gases generally show lighter δ²H_CH4 than Cambrian gases. The value of δ²H_CH4 is negatively correlated with drying coefficient; large drying coefficient corresponds to light δ²H_CH4, and small drying coefficient corresponds to heavy δ²H_CH4 (Fig. 3b). Despite the large differences in buried depth between the Canglangpu Formation in the north slope and the Longwangmiao Formation in GaoMo, Canglangpu δ²H_CH4 from -134‰ to -133‰ is quite similar to Longwangmiao δ²H_CH4 from -138‰ to -132‰ with the average of -134‰. This denotes small δ²H_CH4 variations in natural gases originated from the same package of source rocks. In contrast, Dengying gas δ²H_CH4 differs greatly from Longwangmiao gas δ²H_CH4 in GaoMo despite small discrepancies in buried depth. It is hard to decipher δ²H_CH4 differences from the perspective of maturity. This same issue can be observed to occur inside the Dengying Formation. For two wells drilled at the north slope, Deng2 δ²H_CH4 is -141‰ for ZJ2 (with mid-point buried depth of 6547 m) and -140‰ for PT1 (with mid-point buried depth of 5771 m). Mid-reservoir in Moxi is at 5390-5470 m, and δ²H_CH4 ranges between -150‰ and -139‰ with the average of -145‰. Mid-reservoir in Gaoshiti is at 5350-5580 m, and δ²H_CH4 ranges between -149‰ and -137‰ with the average of -144‰.

The value of δ²H is dependent on many factors. Generally, δ²H becomes heavy as the maturity and salinity of fossil water at the stage of source rocks deposition increase^[24,25,26]. As per simulation experiments, δ²H_CH4 produced would become light when water participated in the reaction of hydrocarbon generation at the stage with high thermal maturity^{[27,28,29,30]}. Such reaction may be extremely slow in situ, and there may be little change of δ²H_CH4 at the temperature above 200-240 °C in a period of time over a hundred million years; hence, δ²H composition exchange between gas and water may be neglected^[31,32].

He et al.^[27] attributed lighter Sinian gas δ²H_CH4 than Cambrian gas δ²H_CH4 in GaoMo to hydrocarbon generation with the participant of water at the stage with high thermal maturity. In view of the spatial distribution of δ²H_CH4 and specific geologic conditions of hydrocarbon accumulation, we tend to ascribe light δ²H_CH4 in Sinian gases to the salinity of water at the depositional stage of source rocks, instead of water participation. At Well JT1 drilled at the north slope, the Canglangpu Formation directly overlies Qiongzhusi source rocks; thus, Canglangpu gases mostly likely came from Qiongzhusi source rocks and highly unlikely from the Sinian System; Longwangmiao gases in GaoMo are also considered to originate from Qiongzhusi source rocks^{[1-4, 9-12]}. Therefore, Canglangpu and Longwangmiao gases could be taken as a reference to Cambrian source rocks, and the δ²H_CH4 value (from -138‰ to -132‰ with the average of -134‰) could be used as the characteristic value for Qiongzhusi source rocks. Oil and gas generated by Qiongzhusi source rocks in the Deyang-Anyue aulacogen may laterally migrate into Sinian Dengying reservoirs. This means that Sinian gases could be diagnosed to come from the Cambrian System if the δ²H_CH4 value is similar to that of Canglangpu and Longwangmiao gases; otherwise Sinian gases would be of hybrid sources. With respect to Deng2 gases, for example, δ²H_CH4 value is -141‰ for Well ZJ2 and -140‰ for Well PT1 drilled in the central source area in the Deyang-Anyue aulacogen^[33]. In Moxi, δ²H_CH4 value changes into -141‰, -147‰, -146‰, and -150‰ from Well MX9 to MX8, MX17, and MX11 in the direction toward the platform in the east. In Gaoshiti, δ²H_CH4 value changes into -137‰, -146‰, and -150‰ from Well GS1 to GS11 and GS135 (Fig. 4a). In the Deng4 Member, δ²H_CH4 also becomes light from the platform margin toward intra-platform (Fig. 4b). Such a trend indicates that gases in Sinian reservoirs (including Deng2 and Deng4) close to the aulacogen and source center mostly originated from Cambrian source rocks, which results in heavy δ²H_CH4. In the areas away from the Cambrian aulacogen and close to the platform, more gases came from the source rocks in the Dengying Formation; thus, δ²H_CH4 becomes light. Vertically, gas δ²H_CH4 is relatively light in the Deng2 Member because Deng2 pay reservoirs are laterally far away from Qiongzhusi source rocks, and δ²H_CH4 becomes lighter as the distance increases. For example, Deng2 δ²H_CH4 value is -137‰ for Well GS1 with the pay reservoirs at 5300- 5390 m and -146‰ at Well GS3 with the pay reservoirs at 5783-5810 m. The former is closer to the source window than the latter and thus shows heavier δ²H_CH4 than the latter. In summary, δ²H_CH4 is heavy in the areas with more gas from Qiongzhusi source rocks and light in the areas with more gas from Sinian source rocks.

At the depositional stage of Niutitang in the Early Cambrian, Yangtze region was in a brackish-saline marine basin, where the paleosalinity was relatively high from the Late Proterozoic Era to the Early Paleozoic Era^[34]. To investigate paleosalinity change at the depositional stage of source rocks from the Late Proterozoic Era to the Early Paleozoic Era inside and around the Sichuan Basin, we sampled Cambrian source rocks from the wells drilled in Gaoshiti, Moxi, Weiyuan, and Ziyang and outcrop sections in Guangyuan and Yangba, Deng3 source rocks from the Nanjiang-Yangba and Chengkou-Xiuqi sections in the Sichuan Basin, and Doushantuo source rocks from Qingping and Wangcang in western Sichuan and Zunyi in southeastern Sichuan. The method developed by Shi et al.^[35] was used to establish paleosalinity using the content of boron and potassium in clay minerals. The paleosalinity was estimated to be 5.7‰-44.2‰ (average of 18.5‰) for Qiongzhusi source rocks, 4.4‰-17.3‰ (average of 7.7‰) for Doushantuo source rocks, and 4.5‰-10.3‰ (average of 7.5‰) for Deng3 source rocks. These results are reconciled with the overall paleosalinity change from the Late Proterozoic era to the Early Paleozoic Era in Yangtze region. Thus, we concluded that the paleosalinity at the depositional stage of source rocks dominated δ²H_CH4 of natural gas.

Sinian gases may originate in Sinian source rocks^{[1, 3, 9-12]}. We used the abundance of ⁴⁰Ar in rare gases to estimate the age of gas source rocks and δ²H_CH4 method to assess the contribution of Sinian source rocks to Dengying gas reservoirs.

Helium and argon in the gases of crust origin mainly came from radioactive U, Th, and K in sedimentary rocks^[36]. The isotopic compositions of helium and argon are dependent on the age of source rocks and element abundance; thus, they may indicate cumulative age effect of source rocks. In other words, the ratio of ⁴⁰Ar to ³⁶Ar in gases increases with the age of source rocks and the ratio of ³He to ⁴He decreases with the age of source rocks. The element ⁴⁰Ar in the earth crust was mainly produced by ⁴⁰K decay, and ⁴⁰Ar in gases is positively correlated with K content in rocks and the age of source rocks. The content of ⁴⁰K in source rocks, together with ⁴⁰Ar of radioactivity origin from ⁴⁰K, increases with the age of source rocks. According to this principle, the abundance of ⁴⁰Ar was measured to be (18.2-64.9)×10^-6, (38.6-104.3)×10^-6, and (151.1-320.7)×10^-6, respectively for Longwangmiao, Deng4, and Deng2 gases in GaoMo, which correspond to estimated age of source rocks of 516-549, 530-576, and 584-774 Ma, respectively. This means that Longwangmiao gases mainly came from Cambrian source rocks, Deng2 gases came from Sinian source rocks, and Deng4 gases were generated by Sinian and Cambrian source rocks.

Gas δ²H_CH denotes paleosalinity at the depositional stage of source rocks; consequently, the contribution of source rocks may be assessed as per δ²H_CH4 changes in Sinian and Cambrian gases. The contribution ratio of Sinian source rocks to a specific sample was defined as the difference between the end-member value of Cambrian gas δ²H_CH4 and sample δ²H_CH4 divided by the difference in δ²H_CH4 end-member value between Cambrian and Sinian gases. It is important to select end-member value in the calculation of contribution ratio. Canglangpu gases are the typical example of gases originating in Qiongzhusi source rocks with the δ²H_CH4 value from -134‰ to -133‰. Longwangmiao gases also came from Qiongzhusi source rocks, and their δ²H_CH4 value ranges between -138‰ and -132‰ with the average of -134‰. Thus, the end-member value of -133‰ was set for Qiongzhusi source rocks; gases with δ²H_CH4 heavier than -133‰ were considered to completely come from Qiongzhusi source rocks. Dengying gas δ²H_CH4 ranges between -157‰ and -135‰, only one sample shows δ²H_CH4 value of -157‰. Thus, the end-member value of -153‰ was set for Sinian source rocks; gases with δ²H_CH4 lighter than -153‰ were considered to completely come from Sinian source rocks. The percentage of end-member value was not counted in. Sinian source rocks contributed 11%-68% (average of 39%) and 21%-89% (average of 54%) of gases to Deng4 and Deng2 reservoirs, respectively in the platform margin and 26%-89% (average of 55%) and 32%-89% (average of 68%) to intra-platform Deng4 and Deng2 reservoirs, respectively. Sinian source rocks contributed 40%-70% of gases to Dengying reservoirs on the average.

The above two methods arrived at similar conclusions. Gases from Cambrian source rocks feature heavy δ²H_CH4 and young age, and gases from Sinian source rocks feature light δ²H_CH4 and old age (Fig. 5).

Doushantuo organic-rich shales are an important package of source rocks in Yangtze region. By far, Exploratory Wells EYY1 (EYY2HF), EYiY1, EYiC1, EXD3, ZD1, and EYD1 drilled in western Hubei yielded shale gas flow of different volumes from the Doushantuo Formation. EYY1, a vertical well, yielded gas flow of 5460 m³ per day from the Doushantuo Formation in gas testing. EYY2HF drilled later with a horizontal section of 1410 m long at the original drilling site yielded economic gas flow of 5.53×10⁴ m³ after multi-stage fracturing in gas testing. The Doushantuo Formation was demonstrated to have efficient protogenetic gas system and promising exploration potential.

Owing to the discovery of the Anyue gas field, there has been interest in Proterozoic source rocks in the Tarim Craton and exploration potential. After years of research, Neoproterozoic rift was considered to occur in the deep Tarim Craton^[37,38,39], and high-graded Sinian source rocks were discovered in outcrop sections^[37]. The efficiency of the protogenetic gas system has been demonstrated in accordance with economic oil and gas flow from the Sinian System in recent exploration or the discoveries of fossil oil accumulations in Sinian dissolved porous-vuggy reservoirs. For example, Sinian dissolved pores in the outcrop sections in Kuruktag and Aksu have been observed to be filled with bitumen in many places. Tested oil output of 0.05 m³ at Well TD1 was suspected to partially come from the Sinian Shuiquan Formation^[38]. Well QG1 drilled at the North Tarim uplift yielded natural flow of (2-7)×10⁴ m³/d from a Precambrian buried hill, and cumulative oil output reached nearly 300 m^3[39]. Abundant bitumen, with the largest continuous thickness of 60 m, was drilled in the middle and lower Sinian Shuiquan Formation at Well DT1, eastern Tarim. As per a tentative diagnosis, the bitumen may come from Sinian-Nanhuan source rocks^[40]. Natural gas was released from the interval at 8737-8750 m in the Upper Sinian Qigbulak Formation at Well LT1 and could combust at the wellhead with the flame height of 0.5-1.0 m; the drying coefficient was tested to be 0.99. The interval at 8203-8260 m in the Lower Cambrian Wusonger Formation was tested to output daily oil of 134 m³ and daily gas of 45 917 m^3[41]; the drying coefficient of gas was tested to be 0.77. Sinian gases have much higher maturity than Cambrian gases migrating from Lower Cambrian Yurtusi source rocks. More efforts should focus on whether or not there are gases from deep Sinian source rocks.

In summary, oil and gas discovered in Yangtze and the Tarim intra-craton rift partially migrated from Proterozoic source rocks. Aulacogens in the Changchengian System were discovered to occur in the Ordos Basin^[42], where there may be source rocks of a specific scale. No hydrocarbon discoveries have been made by far, but we should pay great attention to this area^[16].

In view of carbon and hydrogen isotopic compositions and ethane content in Dengying gases, the Sichuan Basin, there is a package of efficient source rocks in the Sinian System in whole Yangtze, which made a great contribution to Sinian gas reservoirs in the Sichuan Basin. This package of source rocks consists of Doushantuo mudstones and Deng3 mudstones and argillaceous carbonate rocks. Doushantuo shales have been proved to be a package of high-graded source rocks around the Sichuan Basin. The thickness varies laterally inside the Sichuan Basin. The source rocks are smaller than 5 m thick in the paleohighs and 5-30 m thick^[43] or thicker apart from the paleohighs. As per the latest study, a tectonic-sedimentary framework with uplifts alternating with depressions also existed in and around the Sichuan Basin at the depositional stage of the Doushantuo Formation^[44]. Mianyang-Chengdu-Anyue-Sui'ning, Changning, Wanzhou, and Tongjiang were in the rifted region, where the thickness of the Doushantuo Formation was estimated to be 50-300 m. It was inferred that there are Doushantuo source rocks in the rifted region. Well GK1 was drilled with black shales of 35.5 m thick in the Sinian Deng3 Member, which are generally 5-30 m thick in the basin^[45]. In addition, argillaceous carbonate rocks in the Dengying Formation also have some potential of hydrocarbon generation^[45]. With respect to the evolution of hydrocarbon generation by Sinian source rocks, we take central Sichuan as an example. Hydrocarbon generation began in the Middle and Late Cambrian and suspended at the end of the Silurian Period because of tectonic uplift. Hydrocarbon generation went on to produce crude oil and wet gas from the Permian Period when deep burial occurred again to the Late Triassic. Gas generation by crude cracking took place from the Late Triassic. Cambrian source rocks began to generate hydrocarbons in the Silurian Period and generate crude oil on a large scale from the Permian Period to the Triassic Period. Wet gas generation started in the Early Jurassic, and gas generation by crude cracking began in the Middle Jurassic. The R_o value nowadays of Sinian source rocks in the basin is generally above 3.0%, and R_o value of Cambrian source rocks is generally larger than 2.5%, both of which indicate high to post maturity. Both conventional gases and shale gas accumulations are the product of secondary cracking of liquid hydrocarbons. The optimum window for gas generation is R_o 1.5%-3.5%^[46]. As for 10 samples of type I-II with different maturities (R_o of 0.65%-3.70%) from the US and Tarim, Sichuan, and north China, Zhang et al.^[47] used a gold-tube pyrolysis set for simulation experiments with heating step by step. As per the experiments, the R_o value for the first degradation of marine organic matter in the major period of gas generation was tested to range 0.7%-2.0%, the lower limit of which may extend to 3.5%. The quantity of gas generation at R_o above 2.0% was estimated to account for 15% of total gas generation by organic matter pyrolysis. In accordance with gas generation by either liquid hydrocarbon cracking or kerogen degradation at the highly to post mature stage, Sinian source rocks exhibit good potential of hydrocarbon generation, which should be highly valued in exploration.

The Sinian Dengying Formation in the Sichuan Basin was deposited with a package of microbial dolomites with good reservoir properties even at large buried depth. This package of reservoirs has been proved to be efficient by exploration activities.

The Deng4 Member drilled at Well MX108 is located in the platform margin around the aulacogen. The cored interval of 47 m thick could be divided into 2 short cycles with mound-beach complexes^[48] as per core observation, which lithologically consist of algal dolomicrite and dendrite, leiolite, thrombolite, algal stromatolite, and algal bound-frame dolomites of strong heterogeneity. Reservoir properties are good, and the porosity ranges 3%-8% for micropores and unequally sized pores and cavities.

The Deng4 Member drilled at Well MX51 is located inside the platform. The cored interval of 82 m thick could be divided into 2 short cycles with mound-beach complexes as per core observation, which lithologically consist of algal dolomicrite and thrombolite and microbial granular dolomites with micropores and dissolved pores. Reservoir heterogeneity is stronger than that in the platform margin. The porosity generally ranges 2%-5%.

Although, intra-platform microbial dolomite reservoirs are inferior to platform marginal reservoirs in thickness and petrophysical properties^[48]. However, high yield could be obtained from intra-platform beaches through detailed sweet spotting and horizontal well stimulation. For example, Well MX129H yielded daily gas of 141.19×10⁴ m³ from the Deng4 Member; Well GS123 yielded daily gas of 45.69×10⁴ m³ from the Deng2 Member in gas testing.

The original porosity and content of microorganisms and organic matter were high in Dengying microbial carbonate rocks at the depositional stage in the Sichuan Basin, and there are mainly primary algal growth framework pores and some pores related to microorganism and organic matter decay in diagenetic stromatolite and thrombolite dolomite reservoirs. Dissolved pores and cavities are mainly the product of early hypergenic corrosion^[49]. This is because (1) pores and cavities exhibit fabric selectivity and stratification and turn up at the top of the cycle shallowing upward; (2) concentrically rimmed phase-1 dolomites filled in dissolved pores and cavities are of U-Pb isotopic age 546±7.6 Ma, which is very close to the U-Pb isotopic age (584±32 Ma) of wall rocks (algal laminal dolomites)^[50]. In addition, microbial carbonate rocks had been in an acid environment in a long geologic period of time owing to organic acids produced by early degradation and late pyrolysis of microorganisms and organic matter. Such an acid environment was favorable for the generation and preservation of micropores. This is why there are cellular pores and initial deposition fabric well preserved in most age-old stromatolite and thrombolite dolomite reservoirs, just as in Paleogene stromatolite and thrombolite carbonate reservoirs; few sparry calcites or dolomite cements have been observed in pores.

In the sedimentary association of carbonate rocks and gypsum-salt rocks, microbial carbonate rocks tended to experience early dolomitization^[51]. That is why there are efficient reservoirs in Sinian stromatolite and thrombolite dolomites. Early dolomitization enhanced the anti-compaction and anti-pressolution of microbial dolomites; hence, initial pores may be well preserved in a deeply buried environment^[52].

Economic gas reservoirs discovered in the Upper Sinian Deng2 and Deng4 Members, the Sichuan Basin are directly overlain with Deng3 mudstones and Lower Cambrian (Qiongzhusi + Maidiping) mudstones. These direct capping formations and regional Upper Permian Longtan mudstones are the important protector of Sinian-Cambrian gas accumulations. There are two types of source-reservoir-seal assemblages in the Sinian System (Fig. 6); one consists of old reservoirs with hydrocarbons migrating laterally from young Qiongzhusi source rocks in the aulacogen, and the other consists of self-sourced reservoirs in the Sinian System, including the Doushantuo Formation and Deng3 Member, with vertical hydrocarbon migration and accumulation. Owing to low degree of exploration, proved gas reserves of 5908×10⁸ m³ in the Dengying Formation mainly concentrate in the Deng4 Member at present. Gas reserves in the platform margin mostly originated from Lower Cambrian Qiongzhusi source rocks. Sinian source rocks contributed 39% and 54% of gases on the average to the platform marginal Deng4 and Deng2 Members, respectively and 55% and 68% of gases on the average to the intra-platform Deng4 and Deng2 Members, respectively. Owing to the progress in exploration, Deng2 and Deng4 platform marginal zones have been expanded in the vertical and lateral directions in the slope zone outside GaoMo, where more Deng2 gases will be discovered. Deng2 and Deng4 platform marginal mounds and beaches in the north slope reach 10 144 km² and 4781 km², respectively^[53], where more Sinian primary gas reservoirs may be discovered because inter-beach tight barriers exist to form promising lithologic traps. In accordance with the reserves abundance ((2-4)×10⁸ m³/km² in the Dengying Formation) of discovered gas reservoirs, the Sinian System in the north slope may be another large gas province with resources of 10¹² m³ in the aftermath of the Anyue gas field.

The geochemical characteristics of Sinian and Cambrian gases in the Sichuan Basin differ in three aspects. Sinian gases feature low C₂H₆ content, heavy δ¹³C₂, and light δ²H_CH4, whereas Cambrian gases are the exact opposite of Sinian gases. In addition, the value of δ²H_CH4 becomes lighter when more gases originated from Sinian source rocks. Despite high thermal maturity (R_o), Sinian source rocks are efficient source rocks in view of gas generation by either liquid hydrocarbon cracking or kerogen pyrolysis at R_o<3.5%. There is no doubt about the efficiency of Sinian protogenetic gas system.

Sinian gas accumulations are mostly of hybrid sources in the Sinian and Cambrian Systems. Sinian source rocks contributed 39%-54% of gases on the average to platform marginal Deng4 and Deng2 reservoirs and 55%-68% of gases on the average to intra-platform Deng4 and Deng2 reservoirs. Several exploratory wells drilled in western Hubei yielded shale gas flow of different volumes from the Doushantuo Formation, which demonstrated the efficiency of Doushantuo source rocks and existence of the protogenetic gas system.

The Sichuan, Tarim, and Ordos Craton Basins were pervasively deposited with Mesoproterozoic and Neoproterozoic intra-craton rifts, where there may be protogenetic gas systems in view of promising high-graded source rocks. Sinian microbial carbonate rocks and granular dolomites could be constructively reworked to form large-scale efficient reservoirs, in which reserves of a specific scale have been discovered in the Sichuan Basin. There are also some discoveries in the Tarim Basin, and the Ordos Basin has the potential of exploration. More efforts should focus on risk-taking exploration based on detailed prediction of intra-craton rifts and promising facies belts for new breakthroughs in Sinian protogenetic gas systems.