Page 309 - Petroleum and Gas Field Processing

Example 2
Natural gas, saturated with water vapor at conditions of

1000 psia and 90 F is exposed to cooling in a flow line due to
heat losses, where the temperature reaches 35 F and the pressure

remains the same.
(a) Calculate how much liquid water will drop out of the gas.
(b) Assuming that the gas flowing through the pipeline is to
reach a delivery point at 300 psia pressure, find the corre-
sponding dew point of the gas.

Solution

(a) From Figure 2, we obtain the following:
Water content of the gas stream at the initial conditions

(1000 psia and 90 F) is 46 lb/MMCF (MMCF: 10 6 cubic
feet).
Water content of the gas stream at conditions of 1000 psia

and 35 F is 7.6 lb/MMCF.
Water to be separated is 46 7.6 ¼ 38.4 lb/MMCF
(MMCF: 10 6 cubic feet).
(b) The natural gas, once it reaches the delivery point at 300 psia,
carries with it a water content of 7.6 lb/MMCF. Applying
these two parameters to Figure 2, one can read the dew point
temperature of 12 F.

12.2.2 Analytical Methods

The calculations presented in this section are concerned with finding
the hydrate formation temperature T at a given pressure P, or the pressure P
at which hydrate formation takes place for a given operating temperature
T. A knowledge of the temperature and pressure of a gas stream at the
wellhead is important for determining whether hydrate formation can be
expected when the gas is expanded into the flow lines. In general, the
temperature at the wellhead can change as the reservoir conditions or
production rate change over the production life of the well. Wells,
therefore, that initially flowed at conditions where no hydrate formation
occurred in downstream equipment may require hydrate inhibition, or vice
versa. The computational approach is analogous to the one used in the

Copyright 2003 by Marcel Dekker, Inc. All Rights Reserved.