Abstract - Determination of input parameters for dual porosity
models, used to predict multi-phase flow in fractured hydrocarbon reservoirs,
is hindered by a lack of fundamental knowledge on how natural fracture
systems influence fluid flow. Studies of four analogues for fractured reservoirs
are summarized. The analogues comprise limestones from Ireland, sandstones
from western Norway and from Tayma, Saudi Arabia, and chalk from Denmark,
in all of which the fracture systems are dominantly joints (tension fractures).
The nature of lithological layering was found to be an important controlling
factor in fracture system geometry and scaling. Where layers are mechanically
decoupled, the fracture systems are 'stratabound', i.e. fracture networks
in adjacent layers are independent, fracture sizes span a narrow scale
range and fracture spacing is regular. In more massive rocks, fracture
systems are 'non-stratabound', with fractures spanning a large scale range
(often with power-law length distributions), and spatially clustered. These
differences influence the fluid flow properties of the fractured rock mass,
by their effects on the size of fractures that dominate flow, on the rock
mass volume for which an equivalent porous media approach is valid, and
on the bulk rock permeability anisotropy.
Petroleum Geoscience, 5, 374-384, 1999.