Although improving the recovery of water-invaded gas reservoirs has been extensively studied in the natural gas industry, the nature of the efficiency of water-invaded gas recovery remains uncertain. Low-field nuclear magnetic resonance (NMR) can be used to clearly identify changes in water saturation in the core during high-pressure water-invasion gas. Here, we provide four types of water-invasion gas experiments (spontaneous imbibition, atmospheric pressure, high-pressure approximate equilibrium, and depletion development water-invasion gas) to reveal the impact of the water-invasion gas efficiency on the recovery of water-invasion gas reservoirs. NMR suggested that imbibition mainly occurs in medium to large pores and that residual gas remains mainly in large pores. The amount of gas driven out from the large pores by imbibition was much greater than that driven out from the small pores. Our findings indicate that the initial gas saturation, contact surface, and permeability are the main factors controlling the residual gas saturation, suggesting that a reasonable initial water saturation should be established before the water-invasion gas experiments. Additionally, the water-invasion gas efficiency at high pressures can be more reliably obtained than that at normal pressures. After the high-pressure approximate equilibrium water invasion for gas displacement, a large amount of residual gas remains in the relatively larger pores of the core, with a residual gas saturation of 42%. In contrast to conventional experiments, the residual gas saturation and water displacement efficiency of the high-pressure approximate equilibrium water invasion for gas displacement did not exhibit a favorable linear relationship with the permeability. The residual gas saturation ranged from 34 to 43% (avg. 38%), while the water displacement efficiency ranged from 32 to 45% (avg. 40%) in the high-pressure approximate equilibrium water invasion for gas displacement. The residual gas saturation in the depletion development water-invasion gas experiment was 26–40% (average: 33%), with an efficiency ranging from 45 to 50% (average: 48%), indicating that the depletion development experiment is closer to the actual development process of gas reservoirs. Our findings provide novel insights into water-invasion gas efficiency, providing robust estimates of the recovery of water-invasion gas reservoirs.

Low permeability porous carbonate rocks occupy a certain proportion in the Middle East. Horizontal injection-production well pattern development is often adopted. Due to the influence of well type and wellbore, reservoir dynamic monitoring is mainly based on conventional daily measurement data, well test and pressure monitoring. Therefore, it is particularly important to combine well test interpretation with production dynamic analysis to diagnose the main control factors and production characteristics of this type of reservoir. In this paper, the point source function is used to obtain the pressure variation function of a horizontal well in infinite formation with upper and lower closed boundary. The difference between the horizontal well test curve of A reservoir and the typical horizontal well test curve is compared and analyzed, and the abnormal well test curve of horizontal wells is characterized by a linear flow phase with a slope of 1/3 or 1/4. The abnormal well test curve accounted for 33.34%. The main influencing factors are the permeability around the well and the well trajectory. By combining well test interpretation with dynamic inversion method, the correlation between well test interpretation and dynamic characteristics of horizontal wells with different characteristics is classified and clarified. The main controlling factors that affect the difference in the water injection development effect of different horizontal wells are further clarified, and provide an important reference for the adjustment of injection-production parameters and the optimal deployment of schemes.

Determining the timing of hidden faults that terminate beneath the subsurface remains a significant challenge. For this contribution, seismic fault interpretation, fracture diagenesis analysis, and U-Pb dating of fracture cements are integrated to constrain the activity of hidden thrust faults in the southeastern Sichuan Basin. The results show that the EW- and NW-trending hidden thrust faults developed in the Permian, while the NE-trending faults have inherited later fault activity till the Cenozoic. The hidden thrust fault propagates upward from the top of the Upper Permian to the Lower Triassic strata. Fault inversion within the Permian is firstly identified by the thickness variation between the two fault walls. Core-based fracture diagenesis analysis indicates that multiple fractures and associated dissolution porosity developed within the tight matrix reservoir. In situ U-Pb dating of fracture cements yields ages of 247.4 ± 2 Ma and 234.8 ± 9.1 Ma, indicating that the hidden fault activity predates the Early Triassic. The absence of strata, evidence of structural uplift, and fault inversion collectively suggest that the first faulting in the eastern Sichuan Basin occurred at the end of the Middle Permian. The findings highlight that fracture–cave reservoir along the hidden thrust fault zone has been controlled by the coupling of the fracturing and karstification at the end of the Middle Permian, and is the key target for high gas production.

The calculation of the influx index is one of the most contentious issues in dynamic reserve evaluation of gas reservoirs’ development. For the influx index, it is key to obtain information on the pore compressibility coefficient under realistic gas reservoir pressure. So far, little is known about the assessment of the pore compressibility coefficient at a laboratory scale. Here, we combine observations of gas flowmeter, ISCO booster pump, intermediate container, and rock samples to quantify the pore compressibility coefficient from the KL2-13 well in the Kela-2 reservoir. Additionally, the iterative method (combined the static and dynamic methods) is proposed based on the experimentally obtained pore compressibility coefficient (C_f), dynamic reserve (G), water body multiple (β), and material balance equation to calculate the influx index. The combined iterative method adjusts the values of G and N by comparing the results of the static and dynamic methods, and iteratively corrects C_f using a binary search method until the results of the static and dynamic methods are consistent. The results of our study reveal that the influx index calculated by the dynamic and static methods was consistent, and the gas production per unit pressure drop matched the actual production. These results strongly suggest that there exists a correlation between formation pressure and the influx index, wherein the latter exhibits a gradual decrease as the former decreases. Conversely, the displacement index of both the rock and connate water do not demonstrate a significant dependence on pressure. Furthermore, the impact of pressure on the pore compressibility factor and reservoir water compressibility factor appears to be minimal. These findings hold substantial implications for understanding the behavior of gas reservoirs under varying pressure conditions.