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

Abstract

The Sichuan Basin, covering an area of 180 × 103 km2, 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 × 1012 m3. 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 × 1012 m3 and 648.8 × 109 m3, respectively. The CO2 components and the correlation with relevant parameters for 243 samples from 22 gas fields indicate that CO2 in the Sichuan Basin display the following two characteristics: (1) Relatively low CO2 content of 0.02%–22.90% with an average of 2.96%, which guaranteed the commerciality of natural gas exploration and production; (2) cratonic CO2, which is characterized by low CO2 contents (<5%) and low R/Ra ratios (<0.24). According to the δ13CCO2 values and the relationship with R/Ra, δ13C1, CO2 contents, and wetness coefficient (W) for 263 gas samples, the δ13CCO2 values display three characteristics: (1) The highest δ13CCO2 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 δ13CCO2 values can be applied to identify the CO2 origin of natural gas in the Sichuan Basin: type A, organic origin from thermal decomposition of organic matter, with an average δ13CCO2 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 δ13CCO2 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 δ13CCO2 value of −1.8‰ and average wetness coefficient of 0.85% for 175 samples. (3) δ13CCO2>δ13CCH4. This is a common characteristic shared by all geological age (from Z2dn to J2s) gas reservoirs and various gas types (coal-derived gas, oil-associated gas, and shale gas).