The loss of shale gas from conventional wells during coring directly affects the accuracy of measurement of shale gas content and the efficient development and utilization of shale gas. The existing methods to determine shale gas loss are not sufficiently accurate. This study used the forward modeling approach with consideration of the main influencing factors [FM (a, b)] to accurately calculate the volume of shale gas loss. Simulations of shale gas loss were run in an independently developed indoor experimental platform. A comparative analysis with established fitting methods showed that shale gas mainly exists in either a free state or an adsorbed state, and a pressure differential between the interior and exterior of the core is the primary cause of shale gas loss during coring. The FM (a, b) model simulations of shale gas loss showed reductions in average error of 16.77% and 4.6% compared to that of the improved US Bureau of Mines Method (USBM) and the curve fitting method, respectively. This study established a novel, highly accurate and widely applicable method of calculating the volume of lost shale gas.

The interaction between shale and CO2 is of great significance to CO2 storage and shale gas production; however, there are few reports on chemical changes after CO2 injection into shale reservoirs. We used Fourier transform infrared spectroscopy to study the chemical structure changes of shale samples before and after CO2 injection. In this paper, self-developed high-temperature and high-pressure vessels were used to examine CO2 treatment of shale to simulate the stratigraphic environment and infrared was used to study the influence of changes in pressure and temperature on the chemical interaction between shale and CO2. These results showed that: (1) after shale CO2 treatment, the number of functional groups remained unchanged, though the content and structure of the shale did change; (2) pressure increases reduced hydroxyl and aliphatic group levels in the shale; the branched-chain and aromaticity indexes of the shale were reduced by 81.5% and 53.8%, respectively, relative to untreated samples; (3) below 60°C, free water in the shale increased with temperature increases and dissolution of the shale increased; however, above 60°C, dissolution was inhibited which resulted in precipitation; (4) the dissolution degree of shale carbonate minerals positively correlated with CO2 pressure and temperature, while silicate minerals were unchanged CO2 pressure and temperature. Finally, the change of CO2 pressure had a more significant influence on the chemical structure of shale. These results provide a basis for the continuing study of the influence of chemical structure change of shale caused by CO2 on shale wettability and enhance the theoretical level of CO2 shale mining.