Carbon Dioxide and its Carbon Isotopic Composition of Natural Gas in the Sichuan Basin, SW China

The Sichuan Basin, covering an area of 180 × 10 3 km 2 , has the following advantages in natural gas geology: The sedimentary rocks are 6,000–12,000 m thick with high maturity of source rocks, and nine sets of primary gas source rocks are developed in the basin with a gas–oil ratio of 80:1, and thus it is a gas basin. The remaining recoverable reserves of conventional and unconventional natural gas are up to 13.6404 × 10 12 m 3 . Multiple gas-bearing systems are developed with 25 conventional and tight oil and gas producing layers and 135 discovered gas fields, and the total proved geological reserves and cumulative production of natural gas by the end of 2019 were 5.7966 × 10 12 m 3 and 648.8 × 10 9 m 3 , respectively. The CO 2 components and the correlation with relevant parameters for 243 samples from 22 gas fields indicate that CO 2 in the Sichuan Basin display the following two characteristics: (1) Relatively low CO 2 content of 0.02%–22.90% with an average of 2.96%, which guaranteed the commerciality of natural gas exploration and production; (2) cratonic CO 2 , which is characterized by low CO 2 contents (<5%) and low R/Ra ratios (<0.24). According to the δ 13 C CO2 values and the relationship with R/Ra, δ 13 C 1 , CO 2 contents, and wetness coefficient (W) for 263 gas samples, the δ 13 C CO2 values display three characteristics: (1) The highest δ 13 C CO2 value (10.4‰) in China is found in the Fuling shale gas field, which extends the interval values from previous −39‰–7‰ to −39‰–10.4‰. (2) The δ 13 C CO2 values can be applied to identify the CO 2 origin of natural gas in the Sichuan Basin: type A, organic origin from thermal decomposition of organic matter, with an average δ 13 C CO2 value of −12.8‰ and average wetness coefficient of 7.8% for 44 samples; type B, organic origin from thermal cracking of organic matter, with an average δ 13 C CO2 value of −15.7‰ and average wetness coefficient of 1.30% for 34 samples; type C, inorganic origin from thermal decomposition or organic acid dissolution of carbonate rocks or minerals, with an average δ 13 C CO2 value of −1.8‰ and average wetness coefficient of 0.85% for 175 samples. (3) δ 13 C CO2 >δ 13 C CH4 . This is a common characteristic shared by all geological age (from Z 2 dn to J 2 s) gas reservoirs and various gas types (coal-derived gas, oil-associated gas, and shale gas).