Understanding Induced Fracture Complexity in Different Geological Settings Using DFIT Net Fracture Pressure

Abstract

A review of several hundred Diagnostic Fracture Injection Tests (DFITs) from vertical and horizontal wellbores in a variety of lithologies (tight sandstone, siltstone and shale) within a spectrum of geological settings (passive margin, foreland, and active strike-slip/thrust basins) was conducted to determine potential controls on stimulation complexity determined from the DFIT Net Fracture Pressure (NFP). Not surprisingly large differences in NFP complexity exist within this diverse data set and the variability is best explained by grouping the data according to the tectonic setting of the basin. Tectonic setting is interpreted as the first order control on NFP complexity since increasingly complex tectonic and burial histories elevate stresses and create tectonic fractures that promote increasingly complicated interactions between induced hydraulic fractures and intrinsic rock fractures. As a result, rocks in the Gulf Coast passive margin basin (Haynesville, Bossier) which have relatively simple burial and tectonic histories exhibit the lowest NFP complexities whereas rocks in strike-slip/thrust basins with high present day tectonic stress and abundant tectonic fabric have the largest complexity. Rocks in foreland basins (Montney, Horn River, Cretaceous Deep Basin sandstones) have NFP complexity that is generally variable between passive margin and strike-slip/thrust basins. Within any particular tectonic setting, NFP complexity is controlled by a complicated interplay between the natural fracture intensity, net horizontal stress (NHS) and wellbore geometry. Increasingly stiff and brittle rocks are commonly increasingly naturally fractured and this favours greater NFP complexity, and DFITs from vertical wellbores generally exhibit lower NFP complexity as fracture initiation and growth is simpler from vertical wells than from horizontal wells. Relations between NFP complexity and NHS (closure – pore pressure) are complicated by the degree to which tectonics has diminished and overprinted the pore pressure control on closure stress. In the Gulf Coast passive margin setting (eg.Haynesville shale) pore pressure is the dominant control on closure stress and NFP complexity is increased where pore pressures are lower, possibly due to frac geometry changes associated changing stress profiles. In more tectonically complex settings (foreland and strike-slip/thrust basins) pore pressure exerts less influence on closure while tectonic stresses increasingly influence regional NFP complexity.

Slip-corrected liquid permeability and its effect on hydraulic fracturing and fluid loss in shale

“…For stimulation to propagate further, fluid pressure had to rise high enough to open the natural fractures, which were oriented close to perpendicular to the minimum principal stress. Our results are reasonable because high apparent fracture toughness (causing shorter fractures and higher injection pressure than expected) is common in field data [31][32][33]. The injection pressure fluctuated and showed a general upward trend, features that are commonly observed during formation of a ''complex" fracture network [34].…”

The Critical Role of In-Situ Pressure on Natural Fracture Shear and Hydraulic Fracturing-Induced Microseismicity Generation

“…At the end of injection, the net pressure for the isotropic stress cases was about 6 MPa higher than the one for the 10% deviatoric stress cases. Abnormally high net pressures have been reported for some shale gas plays (e.g., Potocki, 2012). The reason for this might be due to a non-planar hydraulic fracture path resulting from complex hydraulic fracture propagation.…”

Interaction between hydraulic fractures and natural fractures: current status and prospective directions

“…As the HF growth is slowed down by the pre-existing NF, the fluid lag and time is increased, while a decrease in pressure will be expected. The increase in net fracture (NFP) gradient will tend to increase the in situ stress, and thereby promoting the likelihood of complex HF-NF interaction behavior and fluid lag to be created (Potocki 2012). Yang (2008) investigated how the presence of pre-existing natural fractures affects formation breakdown pressures recorded during pre-frac tests.…”