Novel Analytical Core-Sample Analysis Indicates Higher Gas Content in Shale-Gas Reservoirs

Summary Accurate estimation of gas content in shale-gas reservoirs is challenging. Gas-evolution data from retrieved core samples are used to estimate gas content in shale-gas reservoirs. Current data analysis was developed for coalbed methane (CBM) which only accounts for sorbed gas. The CBM method underestimates gas content for the shale core samples because it neglects free gas in nanopores. In this study, we present a rigorous mathematical model to model temporal gas-volume release from the surrounding and top/bottom surfaces of a nanoporous core. Our model accounts for both gas expansion and desorption. With the model, we first match gas-evolution data to determine average core pressure. Then, we calculate the amount of the free and sorbed gas in the core at reservoir condition. With our novel model, we estimated gas content at reservoir condition in many tested core samples to be much higher than values reported on the basis of traditional analysis.