Summary
Measurement of gas and condensate relative permeabilities typically is
performed through steady-state linear coreflood experiments using model fluids.
This study addresses experimental measurement of relative permeabilities for a
rich-gas/condensate reservoir using a live, single-phase reservoir fluid. Using
a live, single-phase reservoir fluid eliminates the difficulties in designing a
relatively simple model fluid that replicates the complicated thermodynamic and
transport properties of a near-critical fluid. Two-phase-flow tests were
performed across a range of pressures and flow rates to simulate reservoir
conditions from initial production through depletion. A single-phase multirate
experiment was also performed to assess inertial, or non-Darcy, effects.
Correlations were developed to represent both the gas and condensate relative
permeabilities as a function of capillary number. A nearly 20-fold increase in
gas relative permeability was observed from the low- to high-capillary-number
flow regime. Compositional simulations were performed to assess the impact of
the experimental results for vertical- and horizontal-well geometries.
Introduction
Well-deliverability estimates for gas/condensate systems require accurate
prediction of both gas and condensate effective permeability. This is
particularly important within the near-wellbore region where the pressures
often fall below dewpoint causing retrograde condensation. Within this region,
pressure gradients in both flowing phases are large and the interfacial tension
between the gas and condensate is low. This results in relative permeabilities
that are rate sensitive. Under these conditions, both capillary number and
non-Darcy effects must be considered in modeling of gas/condensate flows. The
relative permeabilities increase with increasing capillary number and are
reduced by inertial, or non-Darcy, flow effects.
Gas and condensate relative permeabilities are typically determined by
steady-state linear coreflood experiments. Numerous experimental studies have
been performed demonstrating an improvement in both gas and condensate relative
permeability at high velocities and at low interfacial tension (Henderson et
al. 1998; Henderson et al. 1997; Ali et al. 1997). These studies used model
fluids to represent the reservoir fluid, which generally represented leaner
gas/condensate systems. Chen et al. (1995) performed similar experiments using
a recombined gas/condensate system from a North Sea field. Proper recombination
with surface gas and condensate samples, however, assumes that the correct
condensate/gas ratio is known. Using single-phase downhole samples obtained at
pressures above the dewpoint eliminates this uncertainty.
Fevang and Whitson (1996) have shown that krg for a
steady state process is a function of the
krg/kro ratio, where the
krg/kro ratio is a function of pressure.
The dependency of krg on both the capillary number
(Nc) and the krg/kro
ratio for a pseudosteady-state process has been demonstrated experimentally by
Whitson et al. (1999) and Mott et al. (1999). These studies used either model
fluids or recombined reservoir fluids with
krg/kro ratios primarily within the range
of 1 to 90. The lower krg/kro ratios
represent richer fluids, while the higher
krg/kro ratios represent leaner fluids. The
fluids studied in this paper, however, are significantly richer, with
krg/kro ratios in the range of 0.05 to 0.15
on the basis of fluid compositions at initial reservoir conditions.
Non-Darcy or inertial effects reduce relative permeabilities. This has been
demonstrated through linear coreflood experiments by several investigators
(Lombard et al. 2000; Henderson et al. 2000; Mott et al. 2000). Multirate
non-Darcy single-phase experiments were performed as part of this study because
of the anticipated high flow rates from this reservoir.
The objectives of this study were (1) to experimentally measure gas and
condensate relative permeabilities for a rich gas/condensate system using a
live, single-phase reservoir fluid; (2) assess the magnitude of inertial
effects through the measurement of the non-Darcy coefficient; and (3) evaluate
the impact of the capillary-number-dependent relative permeabilities and
non-Darcy effects on the performance of vertical and horizontal wells.
© 2009. Society of Petroleum Engineers
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History
- Original manuscript received:
2 August 2007
- Meeting paper published:
11 November 2007
- Revised manuscript received:
14 October 2008
- Manuscript approved:
24 October 2008
- Published online:
15 April 2009
- Version of record:
15 April 2009
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