Dong Chen

In order to reveal the stress sensitivity characteristics of the Kuqa deep gas reservoir, this study investigates the problem from two complementary aspects. First, conventional variable confining pressure experiments and well-test interpretation are employed to clarify the basic stress sensitivity characteristics of the Kela 2 gas field under conditions of monotonically increasing effective stress. Second, considering that field operations such as gas injection and temperature rise may cause periodic pore-pressure fluctuations under nearly constant overburden pressure, this paper establishes a novel physical simulation method for multi-round charging and depletion recovery to investigate the additional reservoir responses under cyclic effective-stress evolution. The results show that (1) when the confining pressure increases from 5 MPa~40 MPa, the permeability of the core generally decreases, with a decrease of 5~85%. In contrast, the porosity decreased by only 2% to 12%. The number of cores with conventional air permeability greater than or equal to 1 mD in the Kela 2 gas field reservoir accounts for 63.4%. The stress sensitivity causes the permeability to decrease by less than or equal to 40%, and the overall stress sensitivity is not strong. (2) Post-test observations showed fracture development in some cores after the experiment, indicating that during the gas reservoir mining process, the stress cycle changes will cause some closed cracks in the core to reopen or produce new cracks, which will play a role in increasing permeability. After the crack is opened, the comprehensive recovery degree at the end of the stable production period increases by 21.7 percentage points, and 9.9 percentage points increase the comprehensive recovery degree at the end of the abandoned production. (3) The new understanding of this experiment has changed the traditional understanding that stress sensitivity can only lead to reservoir damage, and also pointed out a new technical direction for the field to improve reservoir physical properties and enhance oil recovery by changing stress effects such as heating-condensation, intermittent gas injection, and directional blasting.

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%).

Fractures are common features in deep gas reservoirs with strong heterogeneity, which are generally evaluated by well-testing analysis. Based on the characteristics of a variety of spatial scales from microscopic fractures to macroscopic faults in the Kuche area, this paper investigated the pressure behavior of naturally fractured gas reservoirs by using four typical patterns, including the Warren–Root model, radial composite model, dual-flow-state model, and local heterogeneity model. As a result, typical well-testing curves and parameter sensitivity analysis were demonstrated in detail. Furthermore, the pressure transient behavior of multi-scaled fractured reservoirs was identified by use of a state-of-the-art workflow. The analysis shows that the four patterns and their identification processes were feasible for the inversion of reservoir parameters in fractured gas reservoirs. Combined with dynamic data, the proposed method could further guide the optimization of development schemes and is of great significance for the development of fractured gas reservoirs.