Summary
This paper addresses the combined effect of formation damage and non-Darcy
flow in naturally fractured reservoirs using simplified analytical solutions
and a 2D numerical simulator. Pressure drawdown, buildup, and isochronal tests
simulated in this work indicate that, despite high fracture permeability, skin
damage may accentuate the non-Darcy flow effect and drastically influence
pressure-transient characteristics of low-pressure, naturally fractured
reservoirs. In high-pressure reservoirs, this effect is significant only at
high rates. Non-Darcy flow does not usually mask the typical pressure-transient
characteristics of dual-porosity and dual-permeability reservoirs, but the
conventional interpretation of the early-time data may lead to erroneous
results. If the exponent, n, of the isochronal tests approaches 0.5
while the matrix permeability is low and flow rate is rather high, this would
indicate the predominance of fracture flow. Under these conditions, small
contributions from skin damage may greatly reduce gas-well performance in
naturally fractured reservoirs.
Introduction
High velocity flow through porous media and fractures causes a higher
pressure drop than predicted by the Darcy equation. This phenomenon, generally
referred to as non-Darcy flow, was first described by Forchheimer (1901). Since
then, it has been well established that the main variables that affect
non-Darcy flow are the velocity, density, and saturation of the fluid and the
permeability and porosity of the reservoir. Reservoir properties may be
correlated to a single parameter, known as the non-Darcy flow coefficient,
beta. Very little is known about the effect of other parameters, such as
physical skin damage, on non-Darcy flow and their consequences in well
performance. In fact, a recent literature review on non-Darcy flow by Li and
Engler (2001a) indicates that most of the work has been focused on finding an
accurate correlation for the non-Darcy flow coefficient, beta. There is also
the issue of non-Darcy flow in dual-porosity and dual-permeability reservoirs,
where high local velocities are prominent in the fractures. This paper pertains
specifically to this issue.
In general, the lower the formation permeability, the greater the non-Darcy
pressure gradient. Formation damage in the near-wellbore region causes a
drastic reduction in formation permeability, which potentially could be even
more prominent in naturally fractured reservoirs. Thus, a greater non-Darcy
flow effect could result in the wellbore region of a dual-porosity reservoir.
The literature explaining the combined effect of physical damage and non-Darcy
flow in single-porosity reservoirs is abundant (Berumen-C. et al. 1989;
Camacho-V. et al. 1993; Fligelman et al. 1981); however, there is little
information about such effects in dual-porosity and dual-permeability
reservoirs.
A finite-difference, 2D simulator in cylindrical coordinates was constructed
to simulate pressure-drawdown and -buildup tests. By analyzing the simulated
pressure drawdown and buildup tests, it was possible to decipher the combined
effect of the skin damage and non-Darcy flow in fractured reservoirs. Both
dual-porosity and dual-permeability idealizations of fractured reservoirs were
considered.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
8 June 2004
- Revised manuscript received:
22 August 2005
- Manuscript approved:
31 July 2006
- Version of record:
20 October 2006
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