Because of major advances in hydraulic fracturing and horizontal drilling technology, vast tracts of gas bearing shale formations have become a significant source of hydrocarbon production in North America and beyond. These formations are called unconventional resources because they cannot be developed and produced by conventional production methods. As a result of their low permeability, higher intensity operations such as drilling a horizontal wellbore in the formation and creating multiple transverse hydraulic fractures crossing this wellbore are essential to make unconventional reservoirs economically viable. Although the type of formation and experience with horizontal wells in a specific formation will dictate the most appropriate type of well completion to be used, a commonality is the use of simultaneous injection into multiple entry points (i.e., clusters of perforation holes made in the casing and cement) with the intent of creating multiple hydraulic fractures in each of multiple, repeated stages (see Figure 1). Typically, each stage comprises three to six perforation clusters, and each stage is repeated 20-40 times on each well. The goal of this completion technique is to generate uniform hydraulic fractures from all perforation clusters within a stage; hence, to create high conductivity pathways to the formation for oil and gas production that uniformly stimulate the reservoir rock. However, industry experience with field data analysis (i.e., production logging during which a flow sensor is moved through the well to measure the contribution of each perforation cluster to the overall production rate) and predictions from simulations make it clear that uniform stimulation can be an elusive goal. For example, Miller et al. (2011) interpreted hundreds of production logs from multiple basins, concluding that approximately two thirds of perforation clusters contribute to well production. Similarly, Molenaar et al. (2012) published one of the first studies using distributed acoustic sensing (DAS) technology with fiber optic cables in a horizontal wellbore, thereby detecting that
Deformation Rate Analysis (DRA) was carried out on rock samples from a characterization well at the former FutureGen2 site in Morgan County, Illinois. Although the experience with DRA reported in the literature is typically focused on shallower formations encountered in mining applications, the method was explored here using triaxial compression experiments for core retrieved from 1150-1350 meters depth. Consistent with past manifestations of the DRA method, core samples were subjected to two identical cycles of loading that started below the likely range of in-situ stress magnitudes and peaked above them, after which the core was unloaded in an identical manner to form a “saw-tooth” load/unload path. The inflections in the difference between the stress-strain relationship comprise the focus of the analysis. The inflection stresses closely follow vertical stress inferred from integrating the density logs for the vertically-oriented core plugs. The horizontal minimum stress inferred from horizontal core plugs matches well with bounds obtained by hydraulic fracture stress testing and corresponding to an average minimum tectonic strain of 170 microstrain. The maximum stress is found to track between the minimum horizontal and vertical stress in the sedimentary formations, implying a normal faulting regime. With a similar level of implied tectonic strain (average of about 350 microstrain), the maximum horizontal stress in the stiffer Precambrian Basement exceeds the vertical stress and implies strike-slip stress regime. Hence, the DRA method is found to be useful for bounding all three principal stress magnitudes and for detecting a shift in tectonic regime between units that was suspected but unable to be verified prior to these experiments.
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