Development of connected permeability in massive crystalline rocks through hydraulic fracture propagation and shearing accompanying fluid injection. Issue 1 (24th September 2014)

• Record Type: Journal Article
• Authors: Preisig, G.; Eberhardt, E.; Gischig, V.; Roche, V.; van der Baan, M.; Valley, B.; Kaiser, P. K.; Duff, D.; Lowther, R.
• Is Part Of: Geofluids. Volume 15:Issue 1/2(2015)
• Page Start: 321
• Page End: 337
• Publication Date: 2014-09-24
• Subjects: fracture network -- hard rocks -- hydraulic fracturing -- numerical modeling -- permeability -- reservoir enhancement -- shearing -- stress transfer; Hydrogeology -- Periodicals; Sedimentary basins -- Periodicals; Fluids -- Migration -- Periodicals; Groundwater flow -- Periodicals; Geothermal resources -- Periodicals; Fluid dynamics -- Periodicals; Earth -- Crust -- Periodicals; 551.49
• DOI: 10.1111/gfl.12097
• Languages: English
• ISSNs: 1468-8115

Abstract

Abstract: The ability to generate deep flow in massive crystalline rocks is governed by the interconnectivity of the fracture network and its permeability, which in turn is largely dependent on the in situ stress field. The increase of stress with depth reduces fracture aperture, leading to a decrease in rock mass permeability. The frequency of natural fractures also decreases with depth, resulting in less connectivity. The permeability of crystalline rocks is typically reduced to about 10 −17 –10 −15 m 2 at targeted depths for enhanced geothermal systems (EGS) applications, that is, >3 km. Therefore, fluid injection methods are required to hydraulically fracture the rock and increase its permeability. In the mining sector, fluid injection methods are being investigated to increase rock fragmentation and mitigate high‐stress hazards due to operations moving to unprecedented depths. Here as well, detailed understanding of permeability and its enhancement is required. This paper reports findings from a series of hydromechanically coupled distinct‐element models developed in support of a hydraulic fracture experiment testing hypotheses related to enhanced permeability, increased fragmentation, and modified stress fields. Two principal injection designs are tested as follows: injection of a high flow rate through a narrow‐packed interval and injection of a low flow rate across a wider packed interval. Results show that the development of connected permeability is almost exclusively orthogonal to the minimum principal stress, leading to strongly anisotropic flow. This is because of the stress transfer associated with opening of tensile fractures, which increases the confining stress acting across neighboring natural fractures. This limits the hydraulic response of fractures and the capacity to create symmetric isotropic permeability relative to the injection wellbore. These findings suggest that the development of permeability at depth can be improved by targeting a set of fluid injections through smaller packed intervals instead of a single longer injection in open boreholes. Abstract : In this paper a set of distinct‐element models illustrates key factors limiting the development of connected rock mass permeability by fluid injection. Stress transfer accompanying the opening of a pressurized fracture confines nearby natural and incipient fractures limiting their response. This promotes a limited development of permeability focused to a relatively thin layer of rock instead of across a large volume.