Summary
Loading up of liquids in wellbore has been recognized as one of the severe
problems in gas production for many years. Accurate prediction of the problem
is vitally important for taking timely measures to solve the problem. Although
previous investigators have suggested several methods to predict the problem,
results from these methods often show discrepancies. Also, these methods are
not easy to use because of the difficulties with prediction of bottomhole
pressure in multiphase flow. An accurate and easy-to-use method is highly
desirable. This paper fills the gap.
Starting from Turner’s analysis for prediction of the minimum gas velocity
for liquid removal, the minimum kinetic energy of gas that is required to lift
liquid droplets was determined in this study. In order to compare gas kinetic
energy with the minimum required kinetic energy, a four-phase (gas, oil, water,
and solid particles) flow model was developed for mist flow. Applying the
minimum kinetic energy criterion to the four-phase flow model resulted in a
closed-form analytical equation for predicting the minimum gas-flow rate.
The kinetic energy theory indicates that the controlling conditions for
liquid drop removal in gas wells are bottomhole conditions rather than tophole
conditions. Our case studies show that Turner’s method with 20% adjustment
still underestimates the minimum gas velocity for liquid removal, and the newly
developed equation is more accurate than Turner’s method. The new method is
easier to use than other existing methods. This paper provides production
engineers with a systematic approach to predicting the minimum gas production
rate for the continuous removal of water and oil from gas wells. Engineering
charts are provided for two typical tubing sizes and wellhead pressures.
Introduction
Gas wells usually produce natural gas carrying liquid water and/or
condensate in the form of mist. As the gas flow velocity in the well drops
owing to the reservoir pressure depletion, the carrying capacity of the gas
decreases. When the gas velocity drops to a critical level, liquids begin to
accumulate in the well, and the well flow can undergo annular flow regime
followed by a slug flow regime. The accumulation of liquids (liquid loading)
increases bottomhole pressure that reduces gas-production rate. Low
gas-production rate will cause gas velocity to drop further. Eventually, the
well will undergo bubbly flow regime and cease producing.
Several measures can be taken to solve the liquid-loading problem. Foaming
the liquid water can enable the gas to lift water from the well. Using smaller
tubing or creating a lower wellhead pressure sometimes can keep mist flow. The
well can be unloaded by gas lifting or pumping the liquids out of the well.
Heating the wellbore can prevent liquid condensation. Downhole injection of
water into an underlying disposal zone is another option. However, liquid
loading is not always obvious, and recognizing the liquid-loading problem is
not an easy task. A thorough diagnostic analysis of well data needs to be
performed. The symptoms to look for include onset of liquid slugs at the
surface of the well, increasing difference between the tubing and casing
pressures with time, sharp changes in gradient on a flowing pressure survey,
and sharp drops in a production decline curve.
Turner et al. (1969) were the pioneer investigators who analyzed and
predicted the minimum gas flow rate to prevent liquid loading. They presented
two mathematical models to describe the liquid-loading problem: the film
movement model and entrained drop movement model. On the basis of analyses of
field data, they concluded that the film movement model does not represent the
controlling liquid-transport mechanism.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
7 June 2005
- Revised manuscript received:
7 July 2005
- Manuscript approved:
12 July 2005
- Version of record:
20 February 2006
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