Failure of cap-rock seals as determined from mechanical stratigraphy, stress history, and tensile-failure analysis of exhumed analogs

The sedimentologic and tectonic histories of clastic cap rocks and their inherent mechanical properties control the nature of permeable fractures within them. The migration of fluid through mm- to cm-scale fracture networks can result in focused fluid flow allowing hydrocarbon production from unconventional reservoirs or compromising the seal integrity of fluid traps. To understand the nature and distribution of subsurface fluid-flow pathways through fracture networks in cap-rock seals we examine four exhumed Paleozoic and Mesozoic seal analogs in Utah. We combine these outcrop analyses with subsidence analysis, paleoloading histories, and rock-strength testing data in modified Mohr–Coulomb–Griffith analyses to evaluate the effects of differential stress and rock type on fracture mode. Relative to the underlying sandstone reservoirs, all four seal types are low-permeability, heterolithic sequences that show mineralized hydraulic-extension fractures, extensional-shear fractures, and shear fractures. Burial-history models suggest that the cap-rock seal analogs reached a maximum burial depth >4 km (2.5 mi) and experienced a lithostatic load of up to 110 MPa (15,954 psi). Median tensile strength from indirect mechanical tests ranges from 2.3 MPa (334 psi) in siltstone to 11.5 MPa (1668 psi) in calcareous shale. Analysis of the pore-fluid factor () through time shows changes in the expected failure mode (extensional shear or hydraulic extension), and that failure mode depends on a combination of mechanical rock properties and differential stress. As expected with increasing lithostatic load, the amount of overpressure that is required to induce failure increases but is also lithology dependent.