## 4 Results  
The 1D seismic fluid mobility attributes have indicated that the MP-EEMD-based seismic fluid mobility technology is effective in distinguishing the gas wells from the gas-free wells. Here, the MP-EEMD-based seismic fluid mobility attribute technology is applied to predict the spatial distribution of shale gas accumulation zone in Longmaxi Formation of the whole study area (indicated with blue rectangle in Figure 1a). As shown in Figure 1b, wells S-2, S-3, and SX-1 are located near the seismic line L4 (blue dashed line), and well S-4 is located near the seismic line C2 (green dashed line). Therefore, we next focus on showing and analyzing the seismic fluid mobility attribute extracted from seismic lines L4 and C2. Figure 10a displays the seismic section of seismic line L4 (blue dashed line in Figure 1b) near the gas wells SX-1 and S-2, Figure 10b displays the normalized seismic fluid mobility section extracted from Figure 10a, and Figure 10c displays the logging data of the deviated well SX-1. The actual well data in Figure 3 indicates a good shale gas display at the bottom section of well S-2, and the TOC curve in Figure 10c indicates a good and discontinuous shale gas display in the horizontal section (from A to B) of well SX-1. However, little information about shale gas can be seen from the post-stack seismic section (Figure 10a). It is clear from the seismic fluid mobility attribute section (Figure 10b) that the shale gas near S-2 and SX-1 is vertically concentrated at the bottom of the Longmaxi Formation, but laterally distributed in a discontinuous manner. Specifically, for the vertical well S-2, the gas-accumulation zone predicted from seismic fluid mobility attribute section is located at the bottom section with high GR and high TOC values (Figure 2). For the deviated well SX-1, the predicted gas-bearing condition from A to B has a trend of getting better, which is basically consistent with the horizontal variation of TOC curve in Figure 10c. Based on the predicted result, we have learned that the shale gas enrich areas in the study area are located near the bottom of the Longmaxi Formation. In addition, the seismic fluid mobility attribute is driven only by the post-stack seismic data, eliminating the need for excessive well control. Therefore, the spatial distribution of shale gas reservoirs predicted from seismic fluid mobility attribute can help researchers design the direction and trajectory of directional drilling, reduce the exploration risk, and optimize the production, even in the early stages of exploration and development. Figure 9: Seismic record (**left**) ad seismic fluid mobility attribute (**right**) near gas well S-4. According to the results of well-seismic calibration, the gas zone in well S-4 (depth 2748.3–2761.3 m) is located at time 1.313–1.319 s (red rectangle). represents the middle-velocity pure siltstone, the green represents the transition between shale and siltstone in the target formation, and the red color represent the high-velocity limestone outside the target formation. The inverted velocity section reveals that the target formation mainly contains two sets of low-velocity shale reservoirs (marked by black arrows in Figure 12), which is consistent with the lithology data in Figure 2. In addition, it can be seen from the TOC data of Figure 2 that the gas content of the bottom shale reservoir is greater than that of the top shale reservoir. We can also see that the predicted two shale gas zones (marked by red arrows) in Figure 11b are located at the bottom shale reservoir in Figure 12 by comparing the inverted velocity and the seismic fluid mobility. Figure 11: Seismic amplitude section (**a**) and seismic fluid mobility section (**b**) connecting gas-free well S-3. NW and SE denote the northwest and southeast directions of the study area, respectively. The two white lines are the top and bottom interfaces of Longmaxi Formation.