Summary
Gas/condensate reservoirs usually exhibit complex flow behaviors owing to
the buildup of condensate banks around the wells when the bottomhole pressure
drops below the dewpoint pressure. The formation of this liquid saturation can
lead to a severe loss of well productivity and, therefore, lower gas recovery.
Several studies have examined various ways to minimize the pressure drop in
order to reduce liquid dropout and related problems. One solution implemented
over the past decade is the use of horizontal wells.
There is a lack of published knowledge on the flow behavior of horizontal
wells in gas/condensate reservoirs. The limited studies in this area (Muladi
and Pinczewski 1999; Dehane et al. 2000; Harisch et al. 2001) focused on well
performance rather than on well-test behavior. There has been no evidence of
condensate dropout effects in published horizontal-well-test data.
This paper presents preliminary results from a study aimed at establishing
an understanding of the near-wellbore well-test behavior in horizontal wells in
gas/condensate reservoirs, with a focus on the existence of different mobility
zones caused by condensate dropout.
We used a 3D fully compositional model to develop derivative shapes to be
expected from horizontal-well-test data in gas/condensate reservoirs below the
dewpoint under various conditions. We then analyzed actual well-test data that
exhibit such derivative characteristics, using a uniform flux horizontal well
with wellbore storage and skin model and appropriate reservoir boundaries. The
condensate drop effects in the production tests have been accounted for through
changes in the values of the total skin effect. Finally, we used a
compositional model to verify the results obtained from conventional well-test
analysis.
It was found that condensate deposit near the wellbore yields a well-test
composite behavior similar to what is found in vertical wells, but superimposed
on horizontal-well behavior, which makes it much more complex.
Introduction
Many studies (Fussel 1973; Barnum et al. 1995; Afidick et al. 1994) have
reported significant losses of well deliverability in gas/condensate reservoirs
because of condensate blockage. The level of productivity decline depends on
several factors, including critical condensate saturation, relative
permeabilities, non-Darcy flow, and high capillary number effects.
Retrograde condensation occurs when the flowing bottomhole pressure falls
below the dewpoint pressure (Kniazeff and Naville 1965; Gringarten et al.
2000), creating three regions in the reservoir with different liquid
saturations. Away from the well, an outer region has the initial liquid
saturation; next, nearer the well, there is a rapid increase in liquid
saturation and a decrease in the gas mobility. Liquid in that region is
immobile. Closer to the well, an inner region is formed in which liquid
saturation is higher than a critical condensate saturation and both the oil and
gas phases are mobile. Finally, in the immediate vicinity of the well, there is
a region with lower liquid saturation owing to capillary number effects, which
represents the ratio of viscous to capillary forces. Such a region has been
inferred from a number of experimental core studies at low interfacial tension
and high flow rates (Henderson et al. 1998; Ali et al. 1997). The existence of
the fourth region is important because it counters the reduction in
productivity caused by liquid dropout.
The various mobility zones described above can be identified by well-test
analysis using a variety of analytical and numerical models. Well-test analysis
is commonly used to identify and quantify near-wellbore effects, reservoir
behavior (i.e., zones of different mobilities and storativities), and reservoir
boundaries. Finding all this information from well tests in gas condensate
reservoirs, however, is challenging, because of changes in the composition of
the original reservoir fluid and the impact of wellbore dynamics. Nonetheless,
gas/condensate flow behavior is now reasonably well understood for vertical
wells, in which the fluid flow toward the well can be modeled with a simple
radial-flow geometry. A number of publications (Afidick et al. 1994; Daungkaew
et al. 2002; Marhaendrajana et al. 1999; Saleh and Stewart 1992) have
documented vertical well tests in gas/condensate reservoirs that exhibit
regions of decreasing gas mobility near the wellbore and include an increased
gas mobility region in the immediate vicinity of the wellbore (the fourth
region mentioned above) (Gringarten et al. 2000; Daungkaew et al. 2002).
However, the situation is different in horizontal wells. The pressure
drawdown is less than in vertical wells under the same conditions; therefore,
liquid dropout in gas/condensate well tests is reduced, although it would still
occur as the flowing bottomhole pressure drops below the dewpoint. Among the
limited publications in this area, only the paper by Harisch et al. (2001)
focuses on the multiphase effects on horizontal-well-test behavior. In that
paper, the authors successfully history matched 1 year of production data
obtained from permanent downhole gauges in a horizontal gas/condensate well.
They used a numerical model that incorporated Coats’ extended black-oil
pressure/volume/ temperature (PVT) model (Coats 1985). A simulation with a dry
gas, however, provided the same pressure responses for the same reservoir and
horizontal-well parameters. The authors concluded that multiphase flow had no
effects on their particular horizontal well test because the test was performed
with drawdown pressures just below the dewpoint. The expected well test
behavior when a horizontal well test is conducted with drawdown pressures
significantly below the dewpoint was not addressed.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
7 June 2004
- Meeting paper published:
26 September 2004
- Revised manuscript received:
28 September 2005
- Manuscript approved:
8 December 2005
- Version of record:
20 February 2006
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