Summary
This paper introduces an improved model for describing the liquid-loading
process in gas wells. The model is an extension of the model proposed by Dousi
et al. (2006).
The Dousi model handles the downhole inflow and outflow between the well and
the reservoir in a simple manner. The new model improves this aspect and makes
more-realistic and -detailed assumptions with respect to the production and
injection interval. Analysis of the results this new model produces improves
the understanding of the processes occurring downhole. This analysis can also
be used to predict future behavior of the well in a more realistic fashion. As
in the Dousi model, two typical flow rates could be found, with one at full
production with all the fluids produced to the surface and the other one a
metastable rate in which produced fluids are being reinjected into the
reservoir. Field observations confirm the existence of two possible flow rates
in many wells. The difference between the new model and the Dousi model is that
changes in flow rates occur more slowly when liquid loading starts, reflecting
the more-realistic inflow-performance assumptions.
With this model, liquid-loading processes in the well can be understood
better and predicted. This is important for optimization of well performance
and for the economic assessment of the well and field.
Introduction
In maturing gas fields, liquid loading is a serious problem. The
liquid-loading process occurs when the gas velocity within the well drops below
a certain critical gas velocity. The gas is then unable to lift the water
coproduced with the gas (either condensed or formation water) to surface. The
water will fall back and accumulate downhole. A column is formed, which imposes
a backpressure on the reservoir and, thus, reduces gas production. The process
results eventually in intermittent gas production, and then the well dies.
The liquid-loading phenomenon has been known for many years. A number of
papers have been published describing the process and giving options to tackle
the loading of the well. The first breakthrough in understanding the process
was made by Turner et al. (1969). They created two models for the transport of
the liquids, one for transport by way of a liquid film on the wall of the
tubing where the upward movement is created by interfacial shear, and the other
by way of entrained liquid droplets in a vertically moving gas stream. The
minimum gas velocity to remove all the liquids from the well was lowest in the
second model, which is the liquid-droplet model. The droplet model predicts the
free-falling velocity of the biggest droplet in the flow. The minimum gas
velocity to remove all the liquids is assumed to be above the free-falling
velocity of that droplet. This is referred to as the critical Turner rate
(Turner et al. 1969).
The symptoms of liquid loading were discussed by Lea and Nickens (2004).
According to them, liquid loading is recognizable by sharp drops in the decline
curve, onset of liquid slugs at the surface, an increasing difference between
the tubing and casing pressures with time, and sharp changes in gradient on a
flowing-pressure survey.
Possible ways to reduce liquid loading are also discussed by Lea and Nickens
(2004). These include production-string sizing in which a smaller tubing size
is chosen to increase the gas velocity above the critical Turner rate;
compressor installation that lowers the tubinghead pressure to increase the gas
velocity above the critical Turner rate; a plunger lift to lift all the liquids
by use of the gas pressure during shutdown of the well; pump installation to
pump up the liquids during production; foaming the liquids so that it is easier
for the gas to lift all the fluids, thus reducing the critical Turner rate; and
gas lifting by use of gas from other wells that have no liquid loading to
decrease the pressure loss in the tubing and increase the velocity. The best
solution for a given well depends on the properties of that particular
well.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
1 February 2007
- Meeting paper published:
31 March 2007
- Revised manuscript received:
12 March 2008
- Manuscript approved:
12 March 2008
- Version of record:
15 November 2008
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