Page 194 - Formation Damage during Improved Oil Recovery Fundamentals and Applications

168 Thomas Russell et al.

industry are the homogeneity of the reservoir and the simplicity of the
reservoir fluid. The spatial distributions of permeability and porosity are
already recognized as critical for proper simulation of fluid flow in petro-
leum reservoirs. The model parameters characterising the susceptibility of
rocks to damage by fines migration will similarly vary substantially within
reservoirs. Quantifying the spatial variability of these parameters will most
likely come from correlations with porosity and permeability. Such corre-
lations are at the moment unclear and remain a limiting factor for the
practical application of fines migration modeling on the field scale.
Fluid compressibility and the validity of Darcy’s law are two other
assumptions that currently limit the range of application of fines migra-
tion. Extension of the models to include these effects would allow the
prediction of fines migration in the presence of complex fluids such as in
natural gas reservoirs.
Despite the possibilities for extensions to the presented models, the exist-
ing literature provides petroleum engineers with sufficient tools to make
informed decisions in relation to formation damage due to fines migration.

NOMENCLATURE

A Total pore surface area, L 2
A 132 Hamaker constant
c Suspended particle concentration, L 23
C Dimensionless suspended particle concentration
D Shock front velocity in coordinates (X, T)
e Elementary electric charge, IT
21 22
E Young’s modulus, ML T
F d Drag force, MLT 22
F e Electrostatic force, MLT 22
F g Gravitational force, MLT 22
F l Lift force, MLT 22
f Fractional flow
h Surface-to-surface separation distance, L
h c Critical internal cake thickness, L
II Injectivity index
J Impedance
Impedance in the damage zone
J D
Impedance in undamaged zone
J UD
Kinetic detachment coefficient
k det