We present observational data and modeling results which support the hypothesis that the degree of vertical to horizontal hydraulic fracture propagation during multi-stage hydraulic fracturing is largely controlled by variations of the least principal stress with depth. It is obvious that monotonic variations of the least principal stress with depth imply either upward or downward hydraulic fracture growth. More interestingly, we present several case studies in which direct measurements show layer-to-layer stress variations of the least principal stress as large as ~10 MPa (~1500 psi) which are lithologically controlled. Using two different types of analysis approaches, we investigate complex patterns of vertical and horizontal hydraulic fracture growth from the Midland Basin. In each case, we show that pattern of hydraulic fracture propagation (and resultant drainage volumes) are largely governed by the detailed variation of the magnitude of the least horizontal stress with depth and exact position of a given stage. In gun barrel view, this complex pattern we refer to as a frac fingerprint for convenience. The frac fingerprint depends on the exact vertical position of a frac stage with respect to the variations of the least principal stress in the layers both above and below the stage depth. We show how frac fingerprints can vary along the length of a well because of the way its trajectory encounters lithofacies along its length. We briefly discuss the implication of these concepts for choosing optimal well spacings and landing depths and the relationships between hydraulic fracture geometry and drainage volumes.


It was established 65 years ago that hydraulic fractures should propagate perpendicular to the minimum horizontal principal stress, Shmin (Hubbert and Willis, 1957). While there have been abundant observations consistent with this concept, recent experiments in the Eagleford Formation (Raterman et al., 2017) and the Permian Basin at HFTS-1 and HFTS-2 (Gale et al., 2018: 2021) have added appreciable new data confirming this concept. Hubbert and Willis (1957) also argued that the magnitude of the least principal stress governs the pressure required for propagation of hydraulic fractures. In most areas, of interest to development of unconventional oil and gas reservoirs, the least principal stress is the least principal horizontal stress, Shmin (see recent review by Lund Snee and Zoback (2022) of stress orientations and magnitudes in unconventional sedimentary basins in North America). Thus, knowledge of Shmin and its variations with depth is especially important in unconventional oil and gas reservoirs exploited with multi-stage hydraulic fracturing in horizontal wells. Of specific interest in this paper is the variation of Shmin with depth. The least principal stress governs the degree to which hydraulic fractures propagate vertically, either upward or downward, depending on Shmin magnitudes above, within and below the horizontal section of well commonly referred to as the lateral. Significant vertical propagation can limit successful exploitation of the targeted formation and defines the number of laterals required to exploit productive zones at multiple depth intervals or stacked pay. Hence, optimizing the depths and number of laterals needed to exploit stacked pay as well as the optimal well spacing at different depths will be closely related to how the magnitude of Shmin varies with depth.

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