Shut-In Effect in Removing Water Blockage in Shale-Oil Reservoirs With Stress-Dependent Permeability Considered

Summary It is widely known that only a small fraction of the water injected during hydraulic fracturing is recovered during the flowback period. The water that remains in the reservoir is believed to imbibe into the matrix. Because of the capillary discontinuity between the matrix and the fracture, water blockage is formed near the matrix/fracture interface and reduces the hydrocarbon relative permeability. Therefore, shut-in is often performed just after hydraulic fracturing to alleviate water blockage by redistributing the water deeper into the reservoir through capillary imbibition. However, field data show mixed observations on shut-in performance: some report shut-in as beneficial, while others suggest that it is detrimental. On the basis of laboratory experiments, shut-in is shown to increase the hydrocarbon relative permeability upon flowback. However, most of the laboratory-scale experiments might not simulate the stress-dependent permeability (SDP) observed in hydraulically fractured reservoirs. SDP is a behavior of a porous medium in which its permeability changes depending on the pressure/stress change which, in turn, affects the grain compaction/dilation or fracture aperture and hence permeability. As reported in many experiments, SDP inevitably occurs because the pore pressure changes significantly during both the fracturing and the production stage in hydraulically fractured reservoirs. Therefore, there have been questions concerning the applicability of such laboratory-scale experiments to explain the field-scale phenomena. Because reservoir simulation allows the inclusion of SDP, several papers used the simulation approach to investigate shut-in benefits while including the SDP. However, most of the previous simulation studies used an unrealistic input for the matrix SDP and an asymmetric model segmentation, or even did not validate their numerical model with field-data history matching. This paper will show that such unrealistic input, and such an improper modeling approach, can yield misleading conclusions on shut-in benefits. Therefore, the first objective of our study is to demonstrate an improved modeling workflow to simulate flowback upon water fracturing. Afterward, we aim to evaluate shut-in benefits in terms of hydrocarbon recovery and net present value (NPV). The NPV allows a more realistic economic evaluation of shut-in benefits, because it discounts the higher initial production rate because of shut-in that happens in the future. A parametric study on the injection volume, matrix absolute permeability, and economic parameters is also presented. Given the more realistic modeling approach, our model is successfully history matched with field production data from the Middle Bakken Shale reservoir. This model quantitatively shows that shut-in does not significantly affect the ultimate oil recovery in shale-oil reservoirs. In fact, the model shows that longer shut-in tends to decrease the NPV because the higher initial production rate upon shut-in cannot be maintained for long enough to compensate for the production loss during the shut-in period. Our model suggests that such higher initial production rates are unsustainable because even after shut-in, water will reaccumulate toward the fractures and create water blockage. In addition, the high pressure buildup during fracturing only marginally increases the average reservoir pressure and will be expended quickly once flowback starts. In other words, shut-in seems to only delay the water-blockage issue, although it allows the early-time flowback to start in a milder water-blockage situation. As a result, in this study we propose immediate flowback as a more profitable flowback strategy.