Maxwell Creep of Formation Layer Causes Better Production of Second Fracture (2007)

Abstract The placement of two or more hydraulic fractures at close proximity has generally been discouraged by most stimulation related publications within the industry. The general consensus has been that the fractures tend to interfere with each other in producing the same hydrocarbon source. The rule of thumb for this practice is to place hydraulic fractures substantially separated from one another in a horizontal wellbore or in different layers in a vertical well. Another possibility is to place a subsequent hydraulic fracture perpendicular to the earlier hydraulic fracture at the same wellbore location so that production sharing only occurs near the wellbore. This is achieved by temporarily modifying the stresses in the formation using the first fracture immediately prior to creating the second fracture. It is understood that stress modification can be accomplished in two ways: in the linear elastic range, or in a nonlinear plastic region. This paper proposes the theory that fractures generated in the elastic range may not be effective for this procedure, and that primary efforts should be directed instead toward placement in the realm of "far" plasticity; all the way into the behaviorally fluidized sector. This paper will apply a modified Maxwell creep motion to a relatively homogeneous, soft- to medium-strength formation to maximize the reach of the second fracture and substantially improve production. Introduction Stresses in a subterranean rock formation are known to change over time. A major factor contributing to such change is the movement of the rock formation, most probably caused by tectonic activities in the area. Other actions may be initiated by human intervention, such as production (removal) of formation fluids or injecting into the rock formation (i.e. stimulation, flooding, pressure maintenance). Results from the Mounds Drill Cutting Injection Field Experiment Executive Committee, reported by Moschovidis,1 showed that repeated short-time refracturing of both reservoir and shale formations results in a changed hydraulic fracture direction, even with small injection volumes. It also is well known that this phenomenon is caused by the reduction of pressure directly related to the removal of the fluids in the formation. Changes in fracture direction most likely depend on how much of the formation was depleted during the production stage. Warpinski,2 had previously demonstrated that stresses can be changed by means of hydraulic fracturing stimulation. A minifrac (i.e. small volume data gathering hydraulic fracturing treatment) in one well has been shown to modify stresses in a well nearby. The distance between the two wells was shown to be a primary factor in the ability to modify fracture direction. It is the opinion of the author that the size (volume) of the hydraulic fracture was also a determining factor. In earlier publications,3–5 it was demonstrated that the ability of directional modification of hydraulic fractures could lead to substantial productivity improvements. Therefore, understanding the behavior of rock for the sole purpose of controlling its response to fracture stimulation is of utmost importance. Many models can be applied to rock behavior. Conventional approaches generally concentrate on the solid properties of the rock itself. In this study, the elastic response of the rock would dominate the mode of reasoning, and behavior would only reflect laboratory conditions. In reality, the formations being evaluated are thousands or even millions of times larger than laboratory rock samples; therefore, theories bound by limited space will not apply and will not be used. Plastic response, on the other hand, would fit the infinitude of formation rock, meaning that moving surfaces cause reactive forces that slowly disappear into the realm of infinity. In short, in a closed system such as a formation, the notion that formation rock behaves in a fluid-like manner, as represented by Maxwell elements, can be easily accepted. This would be even more applicable if the formation rock is soft (not elastic) or even of medium-strength rock (only moderate elasticity).