Connectivity between fractures and pores in hydrocarbon-rich mudrocks

Principal Investigator: Huge Daigle (in collaboration with Nicholas W. Hayman (UTIG), Kyle Spikes, UT Department of Geological Sciences, Julia Gale, Peter Eichhubl, Kitty L. Milliken (BEG))


Several lines of evidence show that the majority of pores in mudrocks are at the nano-scale, many of them even below the resolution of electron microscopy. In contrast, natural fractures are not widely evident at sub-centimeter scales. In natural mudrocks, fine-scale fractures define rarely occurring mineral-filled microcracks. Because most of these natural fractures are mineral-cemented, their importance is unclear in larger fluid-flow regimes that concentrate hydrocarbons. In laboratory- and reservoir-scale experiments and production efforts, fractures appear to govern the permeability of mudrocks. Although few detailed studies have been done, most of these induced and natural fractures appear to be spaced at approximately the centimeter scale or greater, raising the possibility that the surrounding rock deforms poroelastically. If so, then the nanoporosity largely hosted within the organic component in mudrocks may remain isolated from both natural and artificial fracture networks. This potential mismatch between the scales of fractures and of pores raises the question: Do fracture systems induced during production form a network of connected flow pathways that access nano-scale porosity in a way that is important to the overall flow regime through mudrock?

To pursue an answer to this question we propose to:

  • Experimentally induce fractures in core-scale samples and establish stress-strain conditions during failure
  • Monitor fluid flow during failure via syn-deformational changes in nuclear magnetic resonance (NMR) T2 response to “map” changes in pore structure during fracture
  • Characterize samples before and after experiments at the micron and sub-micron scale with SEM and 3D FIB imaging to determine the physical effects of fracture relative to porosity evolution
  • Determine the seismic properties of pre- and post-experiment samples to determine the dynamic elastic properties and anisotropy of mudrocks
  • Model the seismic response using effective medium theory and numerical wave propagation methods pre- and post experiment
  • Use the physical and geophysical characterizations of samples to generate a borehole-to reservoir-scale description of how fractures and pores interact during fracturing


The key deliverables of the project will be:

  • A suite of images and mechanical data will illustrate the nature and scales of fracturing and porosity-structure during deformation of mudrock cores from an actively producing hydrocarbon reservoir.
  • Geophysical characterization of pre- and post-experimental cores that can provide elastic moduli from which seismic properties can be predicted and potentially upscaled to wellbore- and reservoir-scale systems.
  • The detailed experimental data and characterizations will in turn illustrate changes in mudrock physical properties leading up to, and in response to, fracturing.
  • Collectively, this effort will lead to a model of flow pathway evolution during deformation of mudrocks, and data and models will be integrated with an industry-partner-provided dataset on samples and reservoir data.

Connectivity between fractures and pores in hydrocarbon-rich mudrocks

We simulate two possible flow regimes. (a) Hydraulic fracture produces a fracture system that produces hydrocarbons only from the area immediately around the fracture. (b) Additional fractures develop in the rock matrix due to local stress changes during production.

Research supported by the Research Partnership to Secure Energy for America/United States Department of Energy
For more information, please contact: Hugh Daigle (hugh_daigle@mail.utexas.edu)