Impact of Induced Fractures on Sweep and Reservoir Management in Pattern Floods

It is well established within the Industry that water injection almost always takes place under fracturing conditions. Particularly when large quantities of very contaminated water are injected –either for voidage replacement or disposal- large fractures may be induced over time. This paper presents the results of a study addressing the impact of induced fractures on the "present value" recovery and on the reservoir management in pattern waterfloods. The background of this study is that there exists a general perception that long fractures have a negative impact on recovery. However, this perception is largely based on past studies where only attention was given to recovery as a function of pore volumes injected, not time. In addition, the impact of injection water contamination was never addressed. Based on streamline simulations on two types of patterns (five-spot and nine-spot), in which the fracture lengths and orientations, in addition to the fluid mobility ratios, were varied, it is concluded that induced fractures in pattern floods generally result in a significant recovery improvement, even for cases in which the induced fractures are "long" (i.e. exceeding roughly 25% of the pattern unit cell size). In the nine-spot pattern, induced fractures result in by far the largest recovery improvement. It is shown that in this case, the recovery for fractured injection is still significantly above that for matrix injection even when the induced fracture closely approaches one of the producer wells in the pattern unit cell. Furthermore, it is shown that for sufficiently long fractures, the impact of contamination of the injection water on recovery generally is very limited. Finally, it is demonstrated that depending on pattern type, fracture orientation, and injection water contamination, there exists an optimum induced fracture length that maximizes recovery. This optimum induced fracture length corresponds to that specific injection rate that yields a maximum oil production rate. Because of changing average reservoir fluid mobility over time, this optimum fracture length can only be maintained if injection rates change over the field life. An optimum reservoir management policy should attempt to maintain the induced fracture at its optimum length over the field life by appropriate adjustment of injection rates.