Summary
Predicting long-term reservoir performance with realistic wellbore models is
fraught with uncertainty owing to the complexity of two-phase flow. That is
because even a calibrated two-phase-flow model departs from its expected
performance trend when changes in flow conditions occur. These inevitable
changes include gas/liquid ratio, wellhead pressure, and flowline pressure with
time, among others. Influx of water further exacerbates the prediction
problem.
This study explores the possibility of using simplified approaches to
compute bottomhole pressure (BHP) from wellhead pressure (WHP), measured rates,
gravity of producing fluids, and tubular dimensions. BHP computations on three
independent data sets comprising 167 gas/condensate-well tests suggest that the
no-slip homogeneous model applies quite well. Statistical results show the
homogeneous model compares quite favorably with mechanistic two-phase-flow
models. However, the main advantage of the simplified model is that its
recalibration with field data is not required because the gas/oil ratio
increases with time, thereby making the model increasingly reliable.
Most field data sets suggest random error in BHP calculations; uncertainty
in rate measurements appears to be the most probable cause.
High-gas-liquid-ratio (GLR) systems can tolerate large errors in rate
measurements, but low-GLR wells demand greater accuracy because of increasing
importance of the hydrostatic head.
Introduction
Two-phase-flow modeling for gas/condensate wells has not received as much
attention as that for oil wells. Recent SPE books (Brill and Mukherjee 1999;
Hasan and Kabir 2002) on this topic make very little mention of this flow
condition, presumably because modeling is supposed to conform to that offered
for oil wells. This study probes this premise, among other issues.
The popular Gray correlation (User’s Manual for API 14B 1978) appears to do
a good job in most gas/condensate wells. However, applicability of this
correlation outside the bounds of its specified parameters remains unclear.
Take the upper limits of condensate/gas ratio (CGR) of 50 STB/MMscf, or
flow-string diameters of 3.5 in., for instance. Questions arise whether one
should use a different model when one of these criteria, as set by Gray, is not
met.
Boundaries of applicability often get violated beyond a correlation’s
original intent; Gray’s correlation is no exception in this regard.
Practicality demands that a user specifies one computational approach for flow
in pipes when long-term integrated reservoir/wellbore/flowline performance is
sought over a field’s producing life. Declining CGR and increasing water
production with time have the potential to complicate any modeling effort. What
also remains unclear is how to treat the multicomponent fluid mixture entering
the wellbore/flowline system after undergoing compositional calculations in the
reservoir.
Besides the two-component gas/liquid Gray correlation (User’s Manual for API
14B 1978) other approaches have emerged for modeling gas/condensate flow. The
semimechanistic model of Govier and Fogarasi (1975) represents the
multicomponent approach with flash calculations. In contrast, the wet-gas
concept offered by Peffer et al. (1988) suggests extreme pseudoization with
single-component gas. Nonetheless, the simplified approach of Peffer et al.
with good accuracy is appealing. A minor drawback of both methods is exclusion
of the accelerational term, which may be significant in wells producing fluids
at high GLR.
This paper advocates the use of a two-component homogeneous model to
circumvent issues with any rigorous two-phase-flow modeling, such as
delineating flow-pattern boundaries, estimating slip between phases, and doing
flash calculations. We show that Gray’s correlation is essentially a
homogeneous model, and the model of Ansari et al. (1994) also simplifies to a
homogeneous model when mist flow is assumed in gas/condensate wells. The
steady-state version of the transient simulator OLGA (Bendiksen et al. 1991)
also lends support to the notion of homogeneous modeling.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
4 June 2004
- Revised manuscript received:
13 June 2005
- Manuscript approved:
15 June 2005
- Version of record:
20 February 2006
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