Due to the coexistence of multiple types of reservoir bodies and widely distributed aquifer support in karst carbonate reservoirs, it remains a great challenge to understand the reservoir flow dynamics based on traditional capacitance–resistance (CRM) models and Darcy’s percolation theory. To solve this issue, an improved injector–producer-pair-based CRM model coupling the effect of active aquifer support was first developed and combined with the newly-developed Stochastic Simplex Approximate Gradient (StoSAG) optimization algorithm for accurate inter-well connectivity estimation in a waterflood operation. The improved CRM–StoSAG workflow was further applied for real-time production optimization to find the optimal water injection rate at each control step by maximizing the net present value of production. The case study conducted for a typical karst reservoir indicated that the proposed workflow can provide good insight into complex multi-phase flow behaviors in karst carbonate reservoirs. Low connectivity coefficient and time delay constant most likely refer to active aquifer support through a high-permeable flow channel. Moreover, the injector–producer pair may be interconnected by complex fissure zones when both the connectivity coefficient and time delay constant are relatively large.

Good polymer flood performance evaluation requires an understanding of polymer injectivity. Offshore reservoirs are characterized by unfavorable water–oil mobility ratios, strong heterogeneity, and multilayer production, which collectively contribute to unique challenges. Accordingly, this article presents a semi-analytical model for the evaluation of commingled and zonal injectivity in the entire development phase, which consists of primary water flooding, secondary polymer flooding, and subsequent water flooding. First, we define four flow regions with unique saturation profiles in order to accurately describe the fluid dynamic characteristics between the injector and the producer. Second, the frontal advance equation of polymer flooding is built up based on the theory of polymer–oil fractional flow. The fluid saturation distribution and the injection–production pressure difference are determined with the method of equivalent seepage resistance. Then, the zonal flow rate is obtained by considering the interlayer heterogeneity, and the semi-analytical model for calculating polymer injectivity in a multilayer reservoir is established. The laboratory experiment data verify the reliability of the proposed model. The results indicate the following. (1) The commingled injectivity decreases significantly before polymer breakthrough and increases steadily after polymer breakthrough. The change law of zonal injectivity is consistent with that of commingled injectivity. Due to the influence of interlayer heterogeneity, the quantitative indexes of the zonal flow rate and injection performance are different. The injectivity of the high-permeability layer is better than that of the low-permeability layer. (2) The higher the injection rate and the lower the polymer concentration, the better the injectivity is before polymer breakthrough. An earlier injection time, lower injection rate, larger polymer injection volume, and lower polymer concentration will improve the injectivity after polymer breakthrough. The polymer breakthrough time is a significant indicator in polymer flooding optimization. This study has provided a quick and reasonable model of injectivity evaluation for offshore multilayer reservoirs.

Due to the complex reservoir types and strong heterogeneity of fractured–vuggy reservoirs with aquifers, evaluating such reservoirs’ dynamic reserves and aquifer size is challenging. This paper established a segmented elastic-drive material balance equation based on the material balance principle by combining the functional relationships among the crude oil volume factor, crude oil compressibility, and formation pressure. The PELT algorithm was used to segment the water invasion stages, and nonlinear least squares fitting was employed to determine the rock compressibility, dynamic reserves, and aquifer size of fractured–vuggy reservoirs. This study shows that production in fractured–vuggy reservoirs with aquifers can be divided into three stages: no water invasion, initial water invasion, and full water invasion. Rock compressibility and dynamic reserves can be calculated using production data from the no water invasion stage, while the aquifer size can be determined from data in the water invasion stage. Influenced by connectivity and production regulations, aquifers may not be fully affected by pressure waves, causing the aquifer size to increase gradually until stabilization. Compared with numerical simulation data, the method presented in this paper achieves errors of 0.34%, 0.67%, and 1.19% for rock compressibility, dynamic reserves, and aquifer size, respectively.

Understanding subsurface natural fracture systems is crucial to characterize well production dynamics and long-term productivity potential. In addition, the placement of future wells can benefit from in-depth fracture network connectivity investigations, vastly improving new wells’ profitability and life cycles if they are placed in dense, well-connected natural fracture zones. In this study, a novel natural fracture calibration workflow is proposed. This workflow starts with the extraction of sector geology and a natural fracture model from the pre-built full-field model. Then, a cross wellbore discrete fracture network (CW-DFN) is created using a novel CW-DFN generation tool, based on image log data. An innovative fracture network identification tool is developed to detect the interconnected regional fracture network (IcFN) with CW-DFN. The non-intrusive embedded discrete fracture model (EDFM) is utilized to numerically incorporate the complex IcFN and CW-DFN in a reservoir simulation, and it is history-matched by tuning their conductivities. This workflow is applied to a single vertical well within a natural fracture carbonate reservoir in Northwest China. The study results show that the number of CW-DFNs is 11, and the number of IcFNs is 72. The non-intersected natural fractures only account for 5.5% of the production, and thus can be removed to improve simulation efficiency. The history-matching absolute average relative deviation (AARD) is 15.16%. The calibrated effective fracture permeability is 280 millidarcy, with an aperture of 0.001 m, equating to a conductivity of 0.28 millidarcy-meter. The 30-year gas production forecast is estimated to be 1.66 billion cubic meters based on a history-matched model. Finally, if the well is drilled to the east of the sector, 30-year production declines to 1.33 billion cubic meters (a reduction of 20%). However, if the well is drilled to the west of the sector, 30-year production increases to 2 billion cubic meters (an improvement of 20.5%).

Seasonal energy storage effectively addresses seasonal electricity supply–demand imbalances. This study proposes a cross-seasonal compressed air energy storage system using a depleted gas reservoir as the storage reservoir. A six-stage compression–expansion system with intercooling and reheating is designed. Also, the heat of compression is recovered for district heating, and the expansion of cold energy is for cooling supply, thereby avoiding cross-seasonal heat storage costs. For the YD1 depleted gas reservoir case, the system achieves a round-trip efficiency of 57.85% and an exergy efficiency of 70.9%. The total energy utilization ratio, which represents the combined utilization of the electricity, heating, and cooling outputs relative to the corresponding energy input, reaches 166.6%. Incorporating revenue from the heating and cooling sales, the dynamic payback period is 2.38 years, and the investment recovery ratio reaches 4.40. Parametric analysis indicates that thermodynamic performance improves with the increase in discharge pressure and decrease in discharge power. Economic performance improves with longer daily operating hours and plant lifetime. This study demonstrates that depleted gas reservoirs combined with well-designed surface combined cooling, heating, and power systems offer a new research and development direction for large-scale, long-duration seasonal storage, facilitating renewable energy integration and grid stability.