Summary
For applications in which enhanced-oil-recovery (EOR) polymer solutions are
injected, we estimate injectivity losses (relative to water injectivity) if
fractures are not open. We also consider the degree of fracture extension that
may occur if fractures are open. Three principal EOR polymer properties are
examined that affect injectivity: (1) debris in the polymer, (2) polymer
rheology in porous media, and (3) polymer mechanical degradation. An improved
test was developed to measure the tendency of EOR polymers to plug porous
media. The new test demonstrated that plugging tendencies varied considerably
among both partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers.
Rheology and mechanical degradation in porous media were quantified for a
xanthan and an HPAM polymer. Consistent with previous work, we confirmed that
xanthan solutions show pseudoplastic behavior in porous rock that closely
parallels that in a viscometer. Xanthan was remarkably resistant to mechanical
degradation, with a 0.1% xanthan solution (in seawater) experiencing only a 19%
viscosity loss after flow through 102-md Berea sandstone at a pressure gradient
of 24,600 psi/ft.
For 0.1% HPAM in both 0.3% NaCl brine and seawater in 573-md Berea
sandstone, Newtonian behavior was observed at low to moderate fluid fluxes,
while pseudodilatant behavior was seen at moderate to high fluxes. No evidence
of pseudoplastic behavior was seen in the porous rock, even though one solution
exhibited a power-law index of 0.64 in a viscometer. For this HPAM in both
brines, the onset of mechanical degradation occurred at a flux of 14 ft/d in
573-md Berea.
Considering the polymer solutions investigated, satisfactory injection of
more than 0.1 pore volume (PV) in field applications could only be expected for
the cleanest polymers (i.e., that do not plug before 1,000
cm3/cm2 throughput), without inducing fractures (or
formation parts for unconsolidated sands). Even in the absence of face
plugging, the viscous nature of the solutions investigated requires that
injectivity must be less than one-fifth that of water if formation parting is
to be avoided (unless the injectant reduces the residual oil saturation and
substantially increases the relative permeability to water). Since injectivity
reductions of this magnitude are often economically unacceptable, fractures or
fracture-like features are expected to open and extend significantly during the
course of most polymer floods. Thus, an understanding of the orientation and
growth of fractures may be crucial for EOR projects in which polymer solutions
are injected.
Introduction
Maintaining mobility control is essential during chemical floods (polymer,
surfactant, alkaline floods). Consequently, viscosification using water soluble
polymers is usually needed during chemical EOR projects. Unfortunately,
increased injectant viscosity could substantially reduce injectivity, slow
fluid throughput, and delay oil production from flooded patterns. The
objectives of this paper are to estimate injectivity losses associated with
injection of polymer solutions if fractures are not open and to estimate the
degree of fracture extension if fractures are open. We examine the three
principal EOR polymer properties that affect injectivity: (1) debris in the
polymer, (2) polymer rheology in porous media, and (3) polymer mechanical
degradation. Although some reports suggest that polymer solutions can reduce
the residual oil saturation below values expected for extensive waterflooding
(and thereby increase the relative permeability to water), this effect is
beyond the scope of this paper.
© 2009. Society of Petroleum Engineers
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History
- Original manuscript received:
1 July 2008
- Meeting paper published:
21 September 2008
- Revised manuscript received:
3 October 2008
- Manuscript approved:
16 October 2008
- Published online:
28 October 2009
- Version of record:
28 October 2009
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