Large-scale sandstone gas provinces have been developed in many of petroliferous basins in central and western China, such as the Cretaceous large gas province in the piedmont thrust belt of the Kuqa Depression, the Tarim Basin^[1,2,3,4,5], the large tight sandstone gas province of the Upper Paleozoic in the Ordos Basin^[6,7,8,9,10], the large gas province of the Upper Triassic Xujiahe Formation in the Sichuan Basin^{[11,12,13,14,15]}, the large biogas accumulation province of the Quaternary sandstone in the eastern Qaidam Basin^{[16,17,18,19]}. These large gas provinces are all sandstone gas reservoirs, but have different pay zones, natural gas origins and gas accumulation mechanisms. Whether natural gas reservoir formation mechanisms in these large gas provinces share similar origins, what main differences are among them, and what geological effects have taken place after the accumulation of natural gas have been rarely discussed. Hence, we carried out this research on the regional geological and tectonic background, stratigraphic burial evolution, basic characteristics of gas reservoirs, fluid geology, and geochemical features of large sandstone gas provinces in central and western China, so as to explore the origin differences and geological effects of regional natural gas reservoir formation.

The pumping effect in the natural gas accumulation process, abbreviated as structural pumping, refers to the phenomenon where cavity occurs inside a geological body in a closed environment, due to the in-situ stress, and a pumping force is generated by the pressure difference between the cavity and the surrounding rock and greatly accelerates the directional flow of fluids inside the surrounding rock^[20]. The most typical case of such effects is the Kela-2 large Cretaceous gas field in the piedmont thrust belt of the Kuqa Depression, the Tarim Basin. In 2006, Zhao et al. discussed the development conditions and mechanisms of structural pumping and the basic characteristics of the Kela-2 gas field^[20]. In 2012, Li et al. further proposed the pumping effect produced by large-scale natural gas accumulation^[21].

Based on our research, we believe that pumping causes not only effects such as gas reservoir overpressure, increased reservoir porosity, “drying” of natural gas, and the significant increase in the methane carbon isotopic ratio^[21], but also the phenomenon of formation pressure coefficients and geothermal gradients increasing close to the regional gypsum-salt cap rock. The methane isotopic ratios of natural gas in different pay zones of gas reservoirs affected by pumping are basically similar. The pumping effect exists not only in the Cretaceous System below the gypsum-salt layer in the Kuqa Depression of the Tarim Basin, but also in the carbonate gas reservoir in the uplift structural belt strongly impacted by the Himalayan orogeny and the Jialingjiang Formation of the gypsum-salt- bearing area in the Sichuan Basin.

The pumping effect induced by natural gas accumulation in the Kuqa foreland thrust belt was mainly a process where the fold structure under the Neolithic ultra-thick salt cap rock was lifted due to the tectonic movement in the late Himalayan period. The fluid in the underlying sandstone was separated by newly-emerging cavity, generating a pressure difference from the surrounding rocks. The deeper natural gas was drawn along the deep fault so as to rebuild the pressure balance of the formation. Fig. 1 shows in the Kela-2 gas reservoir of the Kuqa Depression in the Tarim Basin with relatively strong uplifting effect in the Himalayan period, the pressure coefficient of the Paleogene reservoir under the gypsum-salt layer is 2.06-2.15, and the geothermal gradient is 2.72-3.08 °C/100 m. The formation pressure coefficient at the top of the Cretaceous sandstone gas reservoir reaches 2.01-2.06, and the geothermal gradient is 2.66-2.73 °C/100 m. The pressure coefficient in the main part of the gas reservoir is 1.92-1.98, and the geothermal gradient is 2.63-2.64 °C/100 m. The pressure coefficient in the lower part of the gas reservoir is 1.71-1.86, and the geothermal gradient is 2.61-2.63 °C/100 m. The pressure coefficient of the lower Keshen 1-Keshen 2 gas reservoir with the relatively weak lifting effect on the south is only 1.67-1.68, and the geothermal gradient is 2.37-2.44 °C/100 m, which are significantly lower than those of the Kela 2 gas reservoir. The methane carbon isotopic compositions of natural gas are also basically similar. For example, the methane carbon isotopic compositions of the Kela 2 gas reservoir are -28.2‰--26.8‰, and those of the Keshen 2 gas reservoir are -28.5‰--27.3‰. There is no fractionation effect manifesting itself as methane carbon isotopic compositions higher in lower strata and smaller in shallower strata, due to natural gas migration.

Another example is the Shuangyushi Permian carbonate gas field in the northwestern Sichuan Basin, which based on the low-amplitude structural prototype of the Indosinian period strengthened in the Yanshanian period and formed by strike- slip compression in the Himalayan period^[22,23]. The regional cap rock Jialingjiang Formation gypsum-salt layer develops above the gas field, where the upper Maokou Formation gas reservoir has a pressure coefficient of 1.8 and a geothermal gradient of 2.1 °C/100 m; the lower Qixia Formation gas reservoir has a pressure coefficient of 1.36 and a geothermal gradient of 1.9 °C/100 m. These are also the pressure and geothermal profile characteristics of gas reservoirs affected by structural pumping. The methane carbon isotopic compositions of natural gas are about -30‰, e.g., -30.1‰--29.7‰ in the deep Qixia Formation, and -30.5‰--29.2‰ in the relatively shallower Maokou Formation, also without fractionation effect due to natural gas migration.

Another case is the Wolonghe Dolomite gas field in the highly-steep structure in eastern Sichuan^[24], where the natural gas layer develops not only in the dolomite reservoir inside the gypsum-salt layer of the regional cap rock Jialingjiang Formation, but also in the Permian Changxing Formation, Maokou Formation and Qixia Formation, and Carboniferous Huanglong Formation below the gypsum-salt layer. The formation pressure coefficient of the Jialingjiang Formation gypsum-salt cap rock gas layer in the main part of the anticline structure of the Wolonghe gas reservoir is 2.0-2.1, and the geothermal gradient is 2.8-3.3 °C/100 m. The pressure coefficient of the gas reservoir in the upper Shangchangxing Formation is 1.8-1.9, and that in the Maokou-Qixia Formations is 1.4-1.6. The pressure coefficient of the main gas reservoir in the Lower Carboniferous Huanglong Formation is 1.1-1.2, and the geothermal gradient is 2.5-2.7 °C/100 m. Profile characteristics presenting smaller pressure coefficient and lower geothermal gradient in the lower strata, and larger pressure coefficient and higher geothermal gradient in the upper ones are also observed, which is the result of fault- based connection with the deep strata under the pumping effect, leading to upward transmission of pressures and temperatures.

Hence, the pumping effect during forming a gas reservoir not only leads to high-pressure/ultra-high-pressure gas reservoirs by structural lifting, but also results in the geological effects featuring larger pressure coefficients and higher geothermal gradients in the upper/shallow strata with stronger tectonic uplifting, smaller pressure coefficient and lower geothermal gradient in the lower/deep ones with weaker tectonic uplifting. Meanwhile, different gas layers in the same gas reservoir have similar methane carbon isotopic compositions. This phenomenon exists not only in the Kuqa foreland thrust belt, but also in the Carboniferous-Permian highly-steep structure in the eastern Sichuan Basin, and the Middle Permian Qixia- Makou Formations in Shuangyushi of northwestern Sichuan.

According to the basic geological conditions where pumping occurs, it is predicted, besides the Kuqa Kelasu structural belt, the Shuangyushi structure in northwestern Sichuan and the Wolonghe structure in eastern Sichuan, that the foreland thrust belts (such as the Paleogene subsalt area in the thrust belt of northern Kuqa, the Jialingjiang Formation subsalt area in multiple fold-uplift belts in eastern Sichuan, the foreland thrust belt in northwestern Sichuan Basin, the Jialingjiang Formation subsalt area in the northern frontal belt, the Ganchaigou Formation subsalt area in western Qaidam Basin) and strongly uplifted-eroded areas during the Himalayan period are favorable areas for occurring of pumping and the regional accumulation effect of natural gas.

Water absorption during natural gas accumulation refers to the effect that mudstone absorbs formation water from sandstone while leaving natural gas untouched in place, in order to maintain its internal fluid pressure balance under the effects of rock elastic restoration and fluid expansion during uplifting and denudation of strata. The geological effect of natural gas accumulation produced by this mechanism is known as the water absorption effect^[21]. The basic principle is that the expansion volume of clay minerals is positively correlated with the osmotic pressure between the mineral particles and the crystal layer^[25,26]. After the formation is lifted and depressurized, the clay minerals in the mudstone expand. The pore space in the mudstone is increasing, generating negative pressures driving formation water from the reservoir rock into the mudstone. The main geological effect of this mechanism is presence of regional water-free gas provinces or gas reservoirs in the formation with a high sandstone-to-formation thickness ratio.

Based on our research, we believe: (1) The mechanism of water absorption is not only due to the rock elastic re-expansion, but also the difference in the expansion and relative permeability between gas and water, for mudstone water absorption. (2) We not only learn that the primary mechanism of water absorption in the Upper Paleozoic water-free natural gas accumulation area of the Ordos Basin, but also realize that the water-bearing gas province is formed due to the effect of multiple factors such as relatively weak water absorption, high sand-to-formation thickness ratio, or insufficient gas sources. (3) The formation of the Jurassic Shaximiao Formation water-free natural gas accumulation area in the northern Sichuan Basin is also the result of this effect.

Firstly, the mechanism of water absorption is caused by a combination of multiple factors. It mainly includes rock elastic restoration, fluid expansion, and relative permeability difference effect during uplifting and denudation. We not only recognize the fact that the mudstone has a greater elastic re-expansion effect than sandstone (Fatt)^{[27,28,29,30]} and can absorb formation water from the bottom of sandstone gas reservoirs to maintain the internal fluid pressure balance^{[31,32,33,34]}, but also believe that the expansion coefficient of gaseous hydrocarbons is much higher than that of liquid water^[35], causing displacement of formation water. It is also believed that when there is a pressure difference between the inside and outside of a gas reservoir, the relative permeability of water is an order of magnitude higher than that of gas^[36,37]. Hence, the water is quickly absorbed by the mudstone.

Secondly, the Upper Paleozoic water-free gas accumulation area in the Ordos Basin is indeed the result of water absorption. The water-bearing natural gas fields of the Tianhuan syncline and Yimeng uplift area are caused by different geological conditions. Fig. 2 indicates that the accumulation of natural gas in the Upper Paleozoic of the Ordos Basin shows that the Tianhuan syncline and Yimeng uplift are water-bearing, while the main body of Sulige gas field and its east and south areas are basically water-free. It was thought that this characteristic was caused by the variation of source rocks. However, our research results were different: (1) We believe that the general water-bearing condition in the Tianhuan syncline-western Sulige area is caused by the little uplift and weak water absorption in the Himalayan period. The main evidence is that the uplift since the Himalayan period in the Tianhuan syncline is only 500-800 m, while that of the Sulige-Gushan area in the Himalayan period reached 1000-3000 m. The formation depressurization in the Sulige gas field is 10-35 MPa, which is conducive to the elastic restoration induced by lowered overburden pressures after mudstone uplifting, the gas expansion and water displacement, the increase of relative permeability difference between gas and water, and general occurring of water absorption. (2) The view that the variation of gas source rocks causes water-bearing condition is untenable, because the gas generation intensity in the Daniudi gas-bearing area is similar, but it is basically water-free. (3) The basis for the long-distance eastward lateral migration of natural gas is still insufficient. Although the carbon isotopic composition of natural gas methane is lower in the east than that in the west in some areas, it presents the characteristics of near-source accumulation in the whole region. That is, the southern region with the highest thermal evolution of source rocks has the highest carbon isotopic composition. For example, it is -31.3‰--29.8‰ in the southern Sulige gas field, with an average of -30.3‰; followed by that in the east by south, southwest, and central by south areas, such as -34.5‰- -0.2‰ in the Zizhou gas field, with an average of -32.5‰; -33.8‰--30.4 ‰ in the Dingbian area of the Sulige gas field, with an average of -31.9‰; -34.8‰--30.3‰ in the Yulin-Uxin Banner area, with an average of -32.7‰. The methane carbon isotopic composition is lighter in the northeast region. For example, it is -35.5‰--31.7‰ in the Mizhi gas field with an average of -33.6‰; -37.9‰--33.3‰ in the Daniudi gas field, with an average of -35.8‰; -38.1‰ - -35.7‰ in the Shenmu gas field, with an average of -36.9‰. In particular, the carbon isotopic composition of natural gas in the Shenmu gas field shows a typical normal carbon isotopic composition series, with highly consistent isotopic composition line shape, suggesting near-source accumulation of natural gas^[38]. (4) We agree with the view of previous scholars that the water content in the central and western parts of the Yimeng uplift is mainly related to the high sandstone- to-formation thickness ratio and insufficient gas sources^[39]. According to the mechanism analysis, the Huanxian County- Qingyang-Yichuan-Yanchang area is located in the front of the southern provenance system, with sufficient gas sources. The Weibei uplift was significantly raised up in the Himalayan period, with relatively large mudstone/formation ratio up to 70%-90%. This is the most favorable area for the mudstone water absorption and the formation of large areas of lithostratigraphic gas accumulation. In addition, the Sulige gas field and the area to the east also present the lower Upper Carboniferous Taiyuan Formation (C₃t)- Lower Permian Shanxi Formation (P₁s) coal-bearing strata with the gas reservoir pressure coefficient of 0.85-1.1. The gas reservoir pressure coefficient is 0.7-0.9 in the dark mudstone of the Lower Permian Lower Shihezi Formation (P₁x) and 0.4-0.6 in the Upper Shihezi Formation (P₁sh)-Upper Permian Shiqianfeng Formation (P₂s) red formation, presenting the characteristic of lower gas reservoir pressure coefficient in the red formation.

Furthermore, the gas-bearing area of the Jurassic Shaximiao Formation in the northern Sichuan Basin is water-free, which is also the result of water absorption. For example, the Bajiaochang Shaximiao gas reservoirs in the northern Sichuan Basin are mainly lithologic gas reservoirs based on sands of the fluvial channel facies and generally water-free. The sandstone-to- formation thickness ratio is extremely low, mostly 10%-15%. The mudstone is also a thin dark layer at the bottom, with relatively poor gas generation capacity; red from the lower to the upper part, with a formation pressure coefficient of 0.70- 0.85 at the bottom gas reservoir. Another example is the pressure coefficient of the Shaximiao Formation gas reservoir in the Qiulin area is 0.7-0.8, and that of individual formation is even as low as 0.4. So is the Wubaochang gas reservoir in northeastern Sichuan, which is also a lithologic gas reservoir based on fluvial-channel sands. It is generally water-free and has a low sandstone-to-formation thickness ratio (15%-20%). Gas reservoirs mainly develop in the dark mudstone-sandstone formation in the middle and upper parts of Shaximiao. The formation pressure coefficient is relatively low, mostly 1.15-1.25. The natural gas mainly comes from the deep Triassic Xujiahe Formation - Jurassic Ziliujing Formation (at the base). Hence, the pressure coefficient of the gas reservoir in the red mudstone-sandstone formation in the northern Sichuan Basin is lower than that in the dark formation, which is very similar to that in the Upper Paleozoic in the Ordos Basin.

Hence, besides the Upper Paleozoic in the central and eastern Ordos Basin and the Jurassic Shaximiao Formation in the northern Sichuan Basin affected by water absorption, there are regional uplift-denudation of the Himalayan period in the Jurassic development area in the central and eastern Sichuan Basin, the mudstone development area in the large section of the Xujiahe Formation in central and western Sichuan Basin, and the Silurian system in eastern Sichuan, and there is also a natural gas reservoir formation mechanism of mudstone water absorption. These should be considered natural gas accumulation areas favorable for large-area water absorption to produce low-pressure water-free gas accumulation.

The degasification in the natural gas accumulation process refers to the phenomenon where massive natural gas, originally dissolved, escaped from formation water and merged with the dispersed free gas in the reservoir layer to accumulate and form a reservoir in the process of uplifting, denudation, and depressurization of formation, lateral-migration depressurization of formation water, or the concentration increase of formation water in lateral migration. The large-scale natural gas accumulation will produce a fractionation effect of natural gas migration. For example, the farther the migration distance of water-soluble gas, the drier the accumulating natural gas is, and the higher the methane isotopic composition of natural gas is; the higher the formation water concentration is, the larger the methane carbon isotopic composition of natural gas in the high-concentration formation water area is, which is also known as the gas degasification effect^{[21, 40-41]}.

Our latest research results are mainly reflected in two aspects: Firstly, we have found that in the big picture of the fractionation effect that the methane carbon isotopic composition in water-soluble gas escape and accumulation of the Xujiahe Formation in central Sichuan is gradually increasing towards the southeast^[21], some isolated gas wells in local areas have presented lower methane carbon isotopic compositions. Secondly, the Quaternary biogas accumulation in the eastern Qaidam Basin is controlled not only by the lateral migration of water-soluble gas but also by the concentration and degasification of water- soluble gas, with apparent lateral migration and accumulation effect of natural gas.

Natural gas accumulation in the Upper Triassic Xujiahe Formation from the Lezhi to Nanchong area of central Sichuan Basin is mainly affected by the degasification of water-soluble gas due to the uplift, degasification, and depressurization in the Himalayan period, formation water lateral migration and depressurization^[40,41], and the local dispersed natural gas is affected by in-situ source rocks. The natural gas reservoir formation shows the geological effects of gas accumulation and reservoir formation such as the farther the migration distance, the higher the methane content, the heavier the methane carbon isotopic composition, the more the isoparaffins, and the larger the propane coefficient^[21], Moreover, the large-scale natural gas reservoirs of the Xujiahe Formation in the Anyue-Hechuan-Guang’an line are the result of massive water-soluble gas in the uplift, depressurization, and degasification, that in the lateral migration and depressurization, the accumulation and reservoir formation of in-situ dispersed natural gas. The Anyue-Suining-Nanchong line presents an evident pattern of methane carbon isotopic composition gradually becoming heavier to the southeast (Fig. 3). However, at the Well Guang’an 7 in the east of Guang’an gas field and Well Weidong 9 in the south of Anyue gas field, carbon methane isotopic compositions become lighter (-42.5‰ and -43.1‰, respectively). In these places, the gas generation intensity of source rocks in the Xujiahe Formation Section I is also (5-10) × 10⁸ m³/km², with R_o values of 1.2% and 1.3%, significantly lower than the thermal evolution in the same set of formations (R_o value of 1.4%-1.6%), and the carbon isotopic composition of natural gas methane produced is lighter. Hence, there is more accumulation of natural gas produced by in-situ source rocks in these local areas. Another example: Xujiahe Formation in central Sichuan has been uplifted by 2000-4000 m since the Late Cretaceous, and the depressurization of the formation has exceeded 30 MPa. It is calculated that the degasification gas per cubic meter of formation water is greater than 2.19 m³/m³. Given that the formation water in the Hechuan-Guang’an area is depressurized by about 20-40 MPa from west to east, it is calculated that the degasification gas per cubic meter of formation water is also greater than 2.19 m³/m³. There is also degasification gas generated after the formation water concentration is increased^[21]. It is estimated that the degasification gas per cubic meter of formation water in the Xujiahe Formation of the Hechuan- Guang’an area is greater than 5 m³/m³, which is a considerable degasification and accumulation amount of water-soluble gas. In addition, the gas generation intensity of the Xujiahe Formation source rocks in central Sichuan is (2-15) × 10⁸ m³/km², and a large amount of dispersed free gas should exist in the thick sandstone of the Xujiahe Formation. The gas saturation in this part of the reservoir layer is 15%-45%, mostly gas-bearing water layer and gas-water layer. It suggests that there is still massive dispersed free gas accumulated in the reservoir. As long as the formation pressure is further reduced, a large amount of water-soluble gas can escape from water and accumulate into a gas layer under reduced pressures. For example, Well Pengji in central and western Sichuan Basin is a geological reference well drilled in the 1950s on the west slope of the Xujiahe Formation instead of fold structure. It mainly produced brine in the 1950s, with a daily output of more than 3,000 m³. It initially produced a little gas. After over half a century of brine extraction and formation depressurization, a typical artificial gas reservoir was gradually formed. By 2007, at the beginning of the 21st century, it had produced 11 × 10⁴ m³ of natural gas per day^[41]. This shows that there is not only massive water-soluble gas in the Xujiahe Formation but also a large amount of dispersed free gas, which has laid a solid foundation for the degasification and accumulation of water-soluble gas into large-scale gas reservoirs.

The accumulation of Quaternary biogas in the eastern Qaidam Basin is related to the degasification and accumulation of massive water-soluble gas after the formation water concentration increases. Moreover, the reservoir-forming geological effect has occurred, i.e., the farther the lateral migration of water-soluble gas extends, the larger the methane carbon isotopic composition becomes, the higher the salinity of the formation water is, the more the natural gas accumulates. Previous studies have suggested that the accumulation of massive biogas in this area is not only a low-amplitude lithologic-tectonic dynamic balance in reservoir formation^{[16, 42]}. It is also believed that the large-scale accumulation is mainly related to the lateral migration and accumulation of water-soluble gas in the formation water^[43], as well as the control of methanogen distribution by salinity^[44,45]. However, after research, we think that previous scholars have recognized some of the large-scale natural gas reservoir formation mechanism, but it is not complete. No large-scale natural gas has developed in the Quaternary biogas hydrocarbon generation center of eastern Qaidam Basin, and the areas with relatively high salinity are where biogas reservoirs most develop (Fig. 4). This feature has yet to be fully explained by previous views. The development of gas source rocks is mainly in the central lake basin. The porosity of mudstone in this area is 15%-35%, and that of sandstone is 20%-30%, with an average porosity of 26%^[45]. Surface water can easily migrate from south to north after it intrudes into the ground from the south^[43] (Fig. 5). Due to the annual evaporation of 2570 mm in this area, in the absence of surface water supply or only a small amount of surface water supply in the northern part of the Sanhu area, the surface and shallow underground water can easily form high-concentration formation water and surface water by massive evaporation^[46]. According to experimental analysis, due to the different degasification gas contents in the formation water with different concentrations, the higher the salinity is, the less the degasification gas content is, the more the dispersed free gas is^{[47,48,49,50]}. After calculation, the amount of natural gas produced from the concentration and degasification of formation water is considerable. Table 1 shows that from the low-salinity areas such as Well Chadi 3 or Well Biedong 4 from the central lake basin to the main accumulation areas of high-salinity gas such as Tainan-Sebei, during the lateral migration of formation water, (0.27-0.63) m³/m³ water-soluble gas can be degasificated from the formation water. Based on the evaporation amount mentioned above, 2.57×10⁶ m³/km² of water can be evaporated every year, and (69.4-161.9)×10⁴ m³/km² of natural gas can be degasificated, i.e., about (70-160) × 10⁸ m³ of natural gas can be degasificated per square kilometer in just 10 000 years. Hence, large-scale natural gas accumulation has been formed in low-amplitude structural areas such as Sebei and Tainan, where formation water concentration is strong, and salinity is the highest. In Taijinar, Dongshan, Salt Lake, and other places with a high concentration of formation water, small-scale natural gas reservoirs have been accumulated; while most other areas only have scattered gas.

The lateral migration of water-soluble gas also produced a significant fractionation effect of methane carbon isotope composition. Table 1 and Fig. 4 show that the carbon isotope composition of natural gas is the lightest in the Sedong area near the center of lake basin gas generation, which is -72.3‰^[51]. Although the formation water salinity is high at 156.8 g/l in this area, the methane carbon isotopic composition is the lightest as it is the earliest dissolving and accumulating point during the migration of water-soluble gas from south to north. The highest salinity of formation water in Tainan, Sebei, Salt Lake, and other areas is 161.3 g/l, and the methane carbon isotopic composition in gas reservoirs is relatively heavy, ranging from -69.0‰ to -64.6‰^{[45, 52]}. Since there is massive natural gas extraction in the area, there is also a fractionation effect in the natural gas extraction process, which is lighter in the early stage and heavier in the later stage. Hence, the data are focused on the large-scale exploitation of natural gas, which leads to the heavier methane carbon isotopic composition of the sampling. Although the natural gas in this area has been affected by long-term exploitation, the methane carbon isotopic composition of Tainan natural gas collected in the early period is -69‰^[53], suggesting that the methane carbon isotopic composition in this area is still relatively light. The formation water is further migrated to Taijinar, the salinity is still relatively high (82.6 g/l), and the carbon isotopic composition of natural gas methane becomes heavier (-68.9‰). When the formation water was migrated to the Yanchi area, its salinity decreased to 25.3 g/l due to the effect of a small amount of rainwater from the north. However, due to the degasification of water-soluble gas and the fractionation of methane carbon isotopic composition induced by long-distance lateral migration, the methane carbon isotopic composition became the heaviest, reaching -64.6‰. Hence, the large-scale accumulation of biogas in the eastern Qaidam Basin is mainly due to the low- amplitude structural formation water concentration, water-soluble gas degasification, and accumulation in the intense evaporation area. The long-distance lateral migration and degasification of water-soluble gas have produced a fractionation effect that leads to the increased methane carbon isotopic composition with the extended distance of water-soluble gas.

According to the geological conditions resulting from degasification, the thick sandstone section of the Upper Triassic Xujiahe Formation in Sichuan Basin, the Lower Paleozoic in the Himalayan fold-uplift area of the Bachu Uplift in Tarim Basin, the western and northern Himalayan fold-uplift belts with sufficient gas sources in Qaidam Basin have similar geological conditions, which are favorable for occurring of natural gas degasification.

The sequestration effect during the natural gas reservoir formation and accumulation process refers to the phenomenon where both the deep-buried reservoir body and the surrounding rocks became highly tight due to strong diagenesis after they were uplifted in the Himalayan orogeny, the pressure on the fluid in the reservoir could hardly be relieved, and most of the fluid and pressure were maintained and preserved. Its natural gas reservoir-forming geological effect is mainly reflected as the ultra-high pressure (UHP)^[54] feature of tight gas development areas. This effect mainly occurs in areas with relatively good preservation conditions after the Himalayan uplifting, such as the tight gas of the Xujiahe Formation in the Laoguanmiao-Zhebachang-Jiange-Yuanba-Jiulong Mountain in northwestern Sichuan.

The geological characteristics of large-scale natural gas accumulation under sequestration are mainly explained with the tight gas of the Xujiahe Formation in northwestern Sichuan as an example. More than 4500×10⁸ m³ of tight sandstone gas third- grade geological reserves are found in the Xujiahe Formation of this area, which are mainly lithologic gas reservoirs, including Weicheng, Zitong, Laoguanmiao, Wenxingchang, Zhebachang, Bailongchang, Jiange, Yuanba^[55,56,57], Jiulong Mountain, and other Xujiahe Formation tight gas development areas. The main geological characteristics are as follows: (1) The reservoir layer is extremely tight, with extremely poor physical properties, porosity of 1%-8%, and permeability less than 0.1 × 10^-3 μm^2[58,59,60]. (2) Large-area tight gas mainly develops in the areas with extremely poor physical properties (porosity 2%-6%, permeability (0.001-0.050) × 10^-3 μm²), strong diagenesis, and a high degree of thermal evolution (R_o values of 1.6%-2.3%)^[61]; (3) tight gas reservoirs, gas source rocks, and tight dry layers, etc. develop alternately, mainly as medium-thin layers, with ultra-high pressure coefficients of 1.63-2.18^{[62,63,64,65,66,67]} (Fig. 6); (4) The reservoir layer is mainly detrital sandstone, generally high carbonate-containing debris (an average of 63.2% in the Jiange gas field) and high carbonate cement content (an average of 30.3% in the Jiange gas field). In addition, massive calcareous and siliceous cementation has developed in the tight reservoir body. Only medium-coarse sandstones with coarser grain size and sand-gravel with relatively uniform grain size have more dissolution pores and become favorable reservoir bodies^[68], which are conducive to the long-term sealing and preservation of fluids and the existence of high pressure.

The geological effect of natural gas reservoir formation under sequestration is also illustrated by the tight gas of the Xujiahe Formation in northwestern Sichuan. Fig. 7 shows that according to the current study, the tight gas development area of Member III of the Xujiahe Formation in northwestern Sichuan has a UPH feature in general, with a pressure coefficient of 1.8-2.2^{[62-67, 69]}. For example, the tight gas pressure coefficients in Laoguanmiao-Zhebachang-Jiange are up to 2.0-2.2. In the southwest slope of Jiulong Mountain structure and Laoguanmiao-Weicheng low-amplitude tectonic area, the reservoir porosity is mostly 1%-5%, and Jiange tight gas reservoir layer has the lowest porosity, ranging from 1% to 3%. The pressure coefficient of Jiulong Mountain-Yuanba tight gas is 1.6-2.1^[62,64], which is located in the Jiulong Mountain structure and its southeast peri-clinal area. The reservoir porosity in this area is mostly 2%-4%, and the tighter the reservoir, the higher the pressure coefficient. Fig. 6 shows that the pressure coefficient of the Jiulong Mountain main tectonic area with a high tectonic location is relatively low, mostly 1.5-1.6. The tectonic location of Wenxingchang is slightly higher than that of Laoguanmiao, and the pressure coefficient of Wenxingchang tight gas is slightly lower than that of Laoguanmiao tight gas. Hence, on the same structure, the pressure coefficient of the tectonic anticline area is slightly lower than that of the peri-clinal area, which may be related to the excessive local pressure relief of tensile fractures at the top of the structure. From the plane variation of the formation pressure coefficient, the formation pressure coefficient near the piedmont belt is mostly atmospheric pressure, which is related to the exposure of most formations. It has also led to the formation of atmospheric pressure lithologic-tectonic gas reservoir of Zhongba Xujiahe Formation.

In the tight gas area of the Xujiahe Formation, which is relatively far from the piedmont belt, as the reservoir is tight and has a large burial depth, with good sealing and lower depressurization during the Himalayan uplifting-erosion, ultra-high pressures are presented. In contrast, the piedmont belt is not only exposed on the surface, but also has the porosity of the reservoir layer of 4%-12%, which is relatively high. The depressurization of the formation is evident, where a natural gas accumulation area has been formed. Hence, the main geological effect of natural gas reservoir formation under sequestration is the regional development of high-pressure and UHP gas fields.

According to the geological conditions where the sequestration occurs, the Jurassic Ziliujing Formation, the Triassic Xujiahe Formation in central-western Sichuan Basin, the tight sandstone of the Silurian system in the East Sichuan fold belt, and the Paleozoic tight lithologic body in the medieval Sichuan uplift with similar geological conditions should be areas favorable for occurring of sequestration.

There are multiple accumulation mechanisms for the formation of large-scale sandstone gas fields in petroliferous basins in central and western China. The uplift and denudation since the Himalayan period have produced four main types of natural gas reservoir formation mechanisms, including structural pumping, mudstone water absorption, water-soluble gas degasification, and fluid sequestration. Different reservoir formation mechanisms of natural gas will produce their unique regional natural gas reservoir formation effects. Large-area structural pumping and fluid sequestration are conducive to development of regional UHP fluids and the formation of large-scale UHP gas fields. Mudstone water absorption in the formation with a low sandstone-to-formation thickness ratio is conducive to the development of large gas fields such as regional low-pressure and water-free gas reservoirs. The degasification of water-soluble gas in large-area thick sandstones can not only form large-scale natural gas accumulation, but the degasification of water-soluble gas will produce a regional regular gas isotopic fractionation effect.

Due to different geological backgrounds in large-scale sandstone gas fields of central and western areas, the mechanisms of natural gas reservoir formation and accumulation are different. In different basins or layers, where signs of similar natural gas reservoir formation effects are found, or there are formations with similar regional accumulation effects, there is possible large-scale accumulation of natural gas. Such areas should be considered a new area of interest in natural gas exploration.