A well test analysis model for fractured and vuggy carbonate reservoir of wells drilling in large scale cave considering wellbore storage and skin factor is established in this paper. The Laplace transformation and Stehfest numerical inversion are applied to obtain the results of wellbore pressure. Through the sensitivity analysis of different parameters for the well test typical curves, it is found that the change of the well test curves is in accordance with the theoretical analysis. With the increase of skin factor, the hump of well test typical curves is steeper. The storage ratio influences the depth and width of the concave in the pressure derivative curves. The cross flow coefficient mainly affects the position of the concave occurrence in the pressure derivative curves. The dimensionless reservoir radius mainly affects the middle and late stages of the log-log pressure type curves, and the later well test curves will be upturned for sealed boundary. The duration of the early stage of the log-log curves will become longer when drilling in large scale cave. The effective well radius is increased to a certain extent, which is in full agreement with the conclusions in this paper. The size of the caves has the same effect on the well test typical curves as wellbore storage coefficient. Due to acidification, fracturing, and other reasons, the boundary of the cave will collapse. Therefore, considering the wellbore storage coefficient and skin effect is very important during well testing. However, the existing models for well testing of fractured and vuggy carbonate reservoir often ignore the wellbore storage coefficient and skin effect. For fractured and vuggy carbonate reservoirs of well drilling in large scale cave, the existing models are not applicable. Since the previous models are mostly based on the triple-porosity medium and the equivalent continuum. The well test model for well drilling in large scale cave of fracture-cavity carbonate reservoirs with wellbore storage coefficient and skin factor in this work has significant application value for oil field.

The steady flow is usually assumed on traditional inflow performance relationship (IPR) curves, not as a function of time. However, tight oil reservoirs may take several years to reach stabilization due to the extremely low permeability. As a result, it is urgent need for the establishment of transient inflow performance relationship for multi-fracture horizontal wells (MFHWs) for complex production rules conditions. Accordingly, a semi-analytical flow model of multiple-fracture horizontal wells (MFHWs) based on trilinear flow and superposition principle is established in this paper. The approach can be used to generate the IPR curves with consideration of production history under production rules of constant flowing wellbore pressure, constant production rate, intermittent production, or even more complex production rules conditions. A remarkable advantage of the proposed method is that the model is no longer limited by constant flowing wellbore pressure or production rate conditions in comparison to the previous analytical model, so the transient IPR curves can be generated based on production history matching. On the traditional IPR curve, the intercept is the average reservoir pressure, however, the transient IPR intercept is not representative of the average reservoir pressure but equals the well pressure if the well were shut-in for that duration, and the curves are affected by the production history. It is essential to plot transient IPR curves, and the change of production history should be considered in tight oil reservoirs. The methodology and results can be used directly for production forecasting and nodal analysis of MFHWs in tight oil reservoirs.

Water influx calculations in high-permeability sandstone gas reservoirs often overlook the contributions of dissolved gas evolution and residual gas expansion within the aquifer. To address this limitation, a novel material-balance-based water influx model is developed for confined gas reservoirs. The model comprehensively integrates six physical mechanisms: gas-zone pore volume contraction, irreducible water expansion, aquifer water expansion, aquifer pore contraction, residual gas expansion, and dissolved gas evolution. A dimensionless water influx intensity type-curve and an analytical expression for component-wise water influx are derived, enabling quantitative decomposition of the contribution from each driving mechanism. The proposed method is applied to 11 production wells in the W Gas Field. Water influx is identified using three approaches—production performance analysis, the apparent reservoir pressure method, and the multi-factor type-curve method—and the calculated water influx volumes are systematically compared. Results show that the production performance method can only detect wells with a strong water influx response. The apparent reservoir pressure method yields physically unreasonable negative water influx values in confined gas reservoirs, indicating limited applicability. In contrast, the proposed model agrees well with the type-curve method, with relative errors below 10%. Component-wise calculations reveal that during early development, aquifer water expansion and aquifer pore contraction together account for over 60% of the total water influx, dominating the process. As reservoir pressure declines continuously, the contribution of dissolved gas evolution increases substantially, exceeding 30% in the middle-to-late development stage and becoming a non-negligible factor. Based on the component-wise water influx results, aquifer drive energy and activity are evaluated using the water-drive index and the water influx constant. Gas Group IV and the Lower Gas Group I exhibit “strong water drive + active” characteristics. Furthermore, gas–water contact rise height and advancement distance are calculated using both the volumetric method and a pore volume iteration method that accounts for actual structural geometry. The volumetric method systematically overestimates results by 15–30%, whereas the structural geometry-based method provides higher accuracy. According to the rise magnitude, the study area is classified into high-, moderate-, and low-risk water breakthrough zones. Wells A3H and A8 in Gas Group IV exhibit the highest risk, with rise magnitudes of 30.19% and 37.75%, respectively. This study provides a theoretical foundation and technical support for water influx performance prediction and differentiated water-control development in analogous high-permeability sandstone gas reservoirs.