## 1 Introduction
Isothermal methane adsorption experiments can be divided into volumetric and gravimetric methods. After extensive research and comparison by scholars, it has been found that the accuracy of the gravimetric method is much higher than that of the volumetric method [33; 34; 35]. There are many models for excess adsorption and the absolute adsorption of methane using the gravimetric method, including the Langmuir single-layer adsorption model and multi-layer adsorption model, the modified Brunauer-Emmett-Teller (BET) multi-layer model, the Dubinin-Radushkevich (DR) micropore filling model, the Freundlich model, and others [36; 37; 38; 39]. When comparing the fitting results of different models, it is believed that the Langmuir multi-layer adsorption and DR models are more reliable, with a similarity greater than 90% [40; 41; 42]. [PERSON] et al. (2022) compared and analyzed the differences in the results between the gravimetric isothermal methane adsorption and NMR methane adsorption methods for testing adsorbed gas [43] and reported that NMR methane adsorption is limited by the lower limit of the equipment's testing range and so cannot fully characterize the adsorbed gas. Therefore, this study used a Langmuir multi-layer adsorption model to analyze the isothermal methane adsorption data. The samples used for measuring the gas content of shale in the laboratory mostly comprise crushed samples, which may damage the micro-fractures and macrospores, leading to an inability to characterize the free gas, mainly characterizing the adsorbed gas. Therefore, free gas is usually directly calculated using the total porosity and gas saturation of shale rocks [44]. However, in the process of calculating free gas, due to the difficulty in accurately measuring the total porosity [45; 46] and correcting the adsorption phase volume [40], there are significant errors in the calculation of free gas. At present, the experimental conditions mostly use a low temperature (room temperature) and a low pressure (<10 MPa) for the saturated methane NMR testing of free gas [43; 47]. There are few reports on the experimental measurement of free methane gas in shale under high-temperature and high-pressure conditions, leading to challenges in making an accurate evaluation of gas content in situ. The second type of shale gas content measurement is on-site desorption, including atmospheric [48; 49] and pressure-holding coring measurement [50]. Because the coring time of shale gas wells is generally long, the level of natural gas loss could be large [51; 52; 53]. This has led to controversy over the results of atmospheric on-site desorption. Using pressure-holding coring on-site desorption measurements to determine the gas volume during the pressure drop process is a relatively direct and accurate method. However, although this method can accurately measure the total gas content, it is difficult to measure the free gas content and the cost is very expensive, meaning that it is difficult to make it widely applicable. The purpose of this study is to determine the gas content characteristics of shale gas reservoirs in situ at different burial depths more efficiently and accurately and to identify the controlling factors. The pore structures of shale reservoirs with different burial depths were characterized using FE-SEM, followed by image splicing and processing techniques. The pressure-holding coring for the on-site desorption results was used as an accurate way to determine the total gas content of shale reservoirs. In response to the lack of experimental testing for the total gas content of shale reservoirs in situ, especially for free gas testing, a combined characterization of free gas and adsorbed gas in shale reservoirs was established, using saturated NMR for the plug-sized samples and isothermal methane adsorption for the crushed samples, under high-temperature and high-pressure conditions.