Hydraulic fracturing is a reservoir stimulation technique which in unconventional (e.g., shale gas or oil) plays is required to generate sufficient reservoir contact to enhance production. Frac design approaches use fracture spacing, sequence, and other parameters to enhance fracture complexity through modification of the local stresses within the stimulated area. Conventional frac designs consist of a series of stages within a well stimulated sequentially, from toe to heel. A newer promising design is a Zipper frac, where two or more parallel horizontal wells are stimulated stage by stage alternating between wells in a "Zipper" pattern. The effectiveness of Zipper fracs has been demonstrated by industry; however, the treatment optimization is still under development. In this paper a fully 3-D reservoir model is used to capture some of the fundamental effects which influence fracture growth during stimulation using three different stimulation approaches, for two different well spacings. The three designs are investigated are: Conventional, in which all stages in sequence are stimulated first in Well 1, followed by Well 2 and then Well 3; Zipper frac, in which Stage 1 is stimulated in Wells 1, 2, and 3 and then Stage 2 is stimulated in each of the wells, repeating until all stages are stimulated; and Modified Zipper frac, in which Stage 1 is stimulated in Well 1, then in Well 3, then in Well 2, and the same sequence is repeated. Following each stage the fractures are numerically propped so that their residual aperture is 50% of the total aperture, eliminating any surfaces with apertures smaller than 0.0025 meters as too small to receive proppant. In this way we can compare the relative fracture surface area which remains productive among the different approaches. The results reveal subtle but significant changes in the stress state due to the different stagings both as a function of time during the stimulation (which will affect subsequent propped aperture) as well as after the entire sequence is pumped. The greatest area is achieved for the modified Zipper sequence; the improvement is larger for the closer spacing of the wells. These changes in turn result in differences in total propped area which will lead to differences in IP. One interesting consequence of the analysis is that although the initial propped area is larger if wells are farther apart, the ratio of propped area to total area available to be drained is smaller suggesting that the initially higher IP for the larger well spacing is achieved at the cost that ultimate recovery for the field is likely to be lower.


One of the primary goals of hydraulic fracturing is to maximize the effective fracture surface area that connects the reservoir volume to the wells. The operational parameters that can be relatively easily manipulated include fracturing fluid properties, injection rate, proppant quantity and schedule, and the spacing and stimulation sequence of stages in a multi-well multistage system (pad). Recent studies (Roussel et al., 2011; Rafiee et al., 2012; Rios et al., 2013,) have suggested that it is possible to achieve greater "complexity" of the resulting fracture network through appropriate engineering of the staging and cross-well stimulation sequences. There is no clear definition on which the above papers agree for the term "complexity," nor is it clear how they treat each fracture after injection into that fracture is complete. Rather than address this issue here, we focus in this paper on the differences among the different effective surface areas of the primary fractures. And, we clearly define the behavior of each fracture after it has been pumped and propped.

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