FRACTURE AND PORE NETWORK CONNECTIVITY IN SHALES RELATED TO INCREASED HYDROCARBON PRODUCTION

Intrinsic shale anisotropy is a well-known fact to geologists both in and out of the industry. What proves more difficult when producing these assets is the pore network lacks a high degree of connectivity, which would promote fluid migration (Healy, 2009, Hu and Ewing, 2014). Hu (2012) has found very low, edge-only effective porosity values – laboratory samples show porosity only accessible new the edges of shale cubes – believed to be the product of low permeability and a disconnected pore network. With pore connectivity inherently poor in shales, optimizing a reservoir’s permeability, and therefore diffusion radius and reservoir efficiency, relies on inducing connectivity through the fracture network – specifically whether the induced fractures promote or discourage further pore-fracture connectivity. Vincent (2011) describes his troubles in network connectivity indirectly through the inability to increase fracture height across shale bedding planes.

Further investigation requires a dual, comprehensive look at petrophysical properties governing fluid migration and geomechanics to optimize hydrocarbon extraction. Improving the network’s connectivity (natural/induced fractures with nano-pores) requires the stress manipulation around the well taking many factors such as in situ stresses, surrounding wells’ influences on local stresses, rock heterogeneity, fracing fluid viscosity and production-driven depletion (and its subsequent effects on effective stresses) into account (Gupta, 2013). The extent of fracture growth and fracture spacing as well as their influences on the diffusive capabilities of assets by increasing the permeability is the target of study.

The work planned to solve the above problem involves an initial characterization of pore structure and connectivity and petrophysical properties governing fluid diffusion. Geomechanical properties such as fracture toughness and Young’s modulus will be gathered before the samples will be fractured and mapped to observe the induced crack network. Samples will then be flooded to observe the fluid-mechanical influences through time-lapsed neutron tomography images. This coupled approach is aimed at further understanding the mechanical influences on migration of hydrocarbons with shales.