## 4 Results and Discussions  
### Effect of CO\({}_{2}\) Injection on Coalled Methane Production  
#### 4.1.1 Variation of Reservoir Pressure  
Figure 7 shows the distribution of reservoir pressure. During the CBM process, the reservoir pressure gradually decreases with time (Figure 7a). Affected by the pressure relief of the production well, the reservoir pressure begins to decrease from the production well and gradually diffuses into the reservoir. During the CO\({}_{2}\)-ECBM process (Figure 7b), reservoir pressure gradually increases with time. At the same production time, CO\({}_{2}\) injection has an enhancement effect on reservoir pressure. When CO\({}_{2}\) is injected, the reservoir pressure near the bottom of the well is greater. As the distance from the well increases, the pressure decreases in a step-wise manner, which indicates that CO\({}_{2}\) mainly accumulates at the bottom of the well and near the well. According to the Langmuir adsorption theory, the pressure gradient in the reservoir will directly affect the adsorption and desorption of gas in the reservoir (Equation (5)). During the CO\({}_{2}\) injection process, a large amount of CO\({}_{2}\) is adsorbed in the near-well reservoir, which will lead to the rapid decrease of reservoir permeability around the bottom of the well. Finally, it will limit the flow capacity of CO\({}_{2}\) and cause a decrease in injection capacity. Figure 7: 300 days, 500 days, 1000 days, 1500 days reservoir pressure distribution cloud (**a**) \(CBM\) (**b**) \(CO_{2}\)-\(ECBM\). \begin{table}
\begin{tabular}{l c l c} \hline \hline
**Parameter (Unit)** & **Value** & **Parameter (Unit)** & **Value** \\ \hline Thermal expansion coefficients (K\({}^{-1}\)) & 2.4 \(\times\) 10\({}^{-5}\) & Langmuir volumetric strain constant of CH\({}_{4}\) (-) & 0.0128 \\ Universal gas constant (J/(K-mol)) & 8.314 & Langmuir volumetric strain constant of CO\({}_{2}\) (-) & 0.0237 \\ Initial porosity (-) & 0.08 & Langmuir pressure of CH\({}_{4}\) (MPa) & 3.82 \\ Initial permeability of coaled (mD) & 0.5 & Langmuir pressure of CO\({}_{2}\) (MPa) & 2.35 \\ Density of coal (kg/m\({}^{3}\)) & 1785 & Langmuir volume constant of CH\({}_{4}\) (m\({}^{3}\)/kg) & 0.01237 \\ Coaled temperature (K) & (289) & Langmuir volume constant of CO\({}_{2}\) (m\({}^{3}\)/kg) & 0.04607 \\ Specific heat capacity of coal (J/(K-kg)) & 1255 & Hydrodynamic dispersion coefficient of CH\({}_{4}\) (m\({}^{2}\)/s) & 3.6 \(\times\) 10\({}^{-11}\) \\ Initial coaled pressure (MPa) & 1.6 & Hydrodynamic dispersion coefficient of CO\({}_{2}\) (m\({}^{2}\)/s) & 5.8 \(\times\) 10\({}^{-11}\) \\ Thermal conductivity of coal (W/(m\(\cdot\)K)) & 0.12 & Bulk modulus of coal (MPa) & 2500 \\ Poisson’s ratio & 0.25 & Bulk modulus of coal skeleton (MPa) & 8134 \\ \hline \hline \end{tabular}
\end{table} 
Table 5: Numerical simulation core parameters (refer to CSEMP project). Figure 8 presents the distribution of gas pressure along the diagonal. After 1500 days of production, the gas pressure near the injection well is reduced to 1.06 MPa (Figure 8a). Taking the initial gas pressure as a reference, when the production is 300 days, 500 days, 1000 days, 1500 days, the gas pressure near the injection well is 87%, 81%, 75%, 66% of the initial pressure, respectively. During the CO\({}_{2}\)-ECBM process, the gas pressure gradually decreases from the injection well to the middle of the reservoir and then to the production well, and the gas pressure increases with time (Figure 8b). The pressure differential between the production well and the injection well is greatly increased compared with the direct exploitation. It is because of a higher pressure differential, gas will accelerate its migration to the production well. Figure 9 illustrates the distribution of gas pressure at reference point B. The reservoir pressure of point B near the injection well decreases with time. The rate of reservoir pressure reduction is relatively slow at the initial stage because point B is far away from the production well.