Summary
The ability to predict well deliverability is a key issue for the
development of gas/condensate reservoirs. We show in this paper that well
deliverability depends mainly on the gas relative permeabilities at both the
endpoint and the near-wellbore saturations, as well as on the reservoir
permeability. We then demonstrate how these parameters and the base capillary
number can be obtained from pressure-buildup data by using single-phase and
two-phase pseudopressures simultaneously. These parameters can in turn be used
to estimate gas relative permeability curves. Finally, we illustrate this
approach with both simulated pressure-buildup data and an actual field
case.
Introduction and Background
In gas/condensate reservoirs, a condensate bank forms around the wellbore
when the bottomhole pressure (BHP) falls below the dewpoint pressure. This
creates three different saturation zones around the well. Close to the
wellbore, high condensate saturation reduces the effective permeability to gas,
resulting in severe well productivity decline (Kniazeff and Nvaille 1965;
Afidick et al. 1994; Lee and Chaverra 1998; Jutila et al. 2001; Briones et al.
2002). This decline is reduced at high gas rates and/or low capillary forces,
which lower condensate saturation in the immediate vicinity of the wellbore,
resulting in a corresponding increase in the gas relative permeability. This is
called the capillary-number effect, positive coupling, viscous stripping, or
velocity stripping (Boom et al. 1995; Henderson et al. 1998, 2000a; Ali et al.
1997a; Blom et al. 1997). High gas rates, on the other hand, induce inertia
(also referred to as turbulent or non-Darcy flow effects), which reduces
productivity. Well productivity is thus a balance between capillary number and
inertia effects (Boom et al. 1995; Henderson et al. 1998, 2000a; Ali et al.
1997a, 1997b; Blom et al. 1997; Mott et al. 2000.).
Well-deliverability forecasts for gas/condensate wells are usually performed
with the help of numerical compositional simulators. Compositional simulation
requires fine gridding to model the formation of the condensate bank with the
required accuracy (Ali et al. 1997a). Non-Darcy flow and capillary-number
effects (Mott 2003)are accounted for through empirical correlations, which
require inputs such as the base capillary number (i.e., the minimum value
required to see capillary-number effects), the reservoir absolute permeability,
and the relative permeability curves. These are usually determined
experimentally, but laboratory measurements at near-wellbore conditions are
very difficult and expensive to obtain. An alternative, as shown in this paper,
is to obtain them from well-test data.
Well-test analysis is recognized as a valuable tool for reservoir
surveillance and monitoring and provides estimates of a number of parameters
required for reservoir characterization, reservoir simulation, and
well-productivity forecasting. In gas/condensate reservoirs, when the BHP is
below the dewpoint pressure, the effective permeability to gas in the
near-wellbore region and at initial liquid saturation can be estimated with
single-phase pseudopressures (Al-Hussainy et al. 1966) and a two- or
three-region radial composite well-test-interpretation model (Chu and Shank
1993; Gringarten et al. 2000; Daungkaew et al. 2002), whereas the reservoir
absolute permeability may be determined with two-phase steady-state
pseudopressures (Raghavan et al. 1999; Xu and Lee 1999). In this paper, we show
that well-test analysis can provide additional parameters, such as the gas
relative permeabilities at both the endpoint and the near-wellbore saturations
and the base capillary number. These in turn can be used to generate estimated
relative permeability curves for gas.
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
21 March 2005
- Meeting paper published:
13 June 2005
- Revised manuscript received:
24 July 2006
- Manuscript approved:
4 January 2007
- Version of record:
20 April 2007
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