What Can Outcrop and Core Based Observations Tell Us About Natural Fractures in Unconventional Reservoirs?

Natural fractures can significantly influence production in tight-gas sandstone (TGS) and shale gas (SG) reservoirs: 1. Open and partially cemented natural fractures provide flow pathways connecting matrix pores to hydraulic fractures and the wellbore. 2. Cemented and some partially cemented fractures may inhibit matrix flow in TGS reservoirs. 3. Open fractures may arrest or divert hydraulic fracture propagation through fluid loss and tip blunting. 4. Open fractures and fractures cemented with weak cement may be reactivated in opening or shear during hydraulic fracture stimulation increasing fracture surface and drainage volume. Characterization and prediction of natural fractures and their attributes are thus essential in unconventional reservoir development.

Conventional core and borehole imaging surveys tend to undersample natural fractures. We avoid this sampling bias by applying an integrated structural, geochemical, experimental, and numerical approach combining observations from vertical and horizontal core and select outcrop analogs that share relevant fracture parameters with producing reservoirs. This approach includes 1. scaling analyses of micro- to macro-fracture aperture and frequency, 2. fracture diagenetic studies addressing fracture porosity structure, cement distribution, and timing of cementation relative to hydrocarbon charge, 3. matrix diagenetic studies designed to predict degree of fracture cement precipitation, 4. laboratory tests of critical and subcritical fracture properties and cement strength, and 5. numerical simulations of fracture network evolution and hydraulic-natural fracture interaction.

Successful implementation of this approach demonstrates that fracture aperture sizes in many TGS reservoirs and their outcrop analogs follow a power-law distribution with similar exponent but variable intercept allowing extrapolation of macrofracture spacing over inter-well distances. Fracture degradation is linked to host rock diagenesis and thus controlled, to first approximation, by sediment composition and burial diagenetic evolution. Fracture network evolution and hydraulic properties are affected by host rock diagenetic state and pore fluid pressure evolution, parameters that can be reconstructed and calibrated for individual producing intervals. In SG reservoirs, fractures are frequently occluded by cement with the tendency to reactivate along the cement-host rock interface thus likely to interact with hydraulic fractures.

AAPG Search and Discovery Article #90142 © 2012 AAPG Annual Convention and Exhibition, April 22-25, 2012, Long Beach, California