Page 314 - Petroleum and Gas Field Processing

It is of importance to mention that when hydrate inhibitors in general are
injected in gas flow lines or gas gathering networks, installation of a high-
pressure free-water knockout at the wellhead is of value in the operation.
Removing of the free water from the gas stream ahead of the injection
point will cause a significant savings in the amount of the inhibitor used.

The amount of chemical inhibitor required to treat the water in order
to lower the hydrate formation temperature may be calculated from the
Hammerschmidt equation:

KW
T ¼ ð2Þ
Mð100 W Þ

where T is the depression in hydrate formation temperature ( F), W is
weight percent of inhibitor for water treatment, K is a constant that depends
on the type of inhibitor, and M is the molecular weight of the inhibitor.
Values of M and K for various inhibitors are given in Table 1 [2].

Table 1 Properties of Chemical Inhibitors

Inhibitor M K
Methanol 32.04 2335
Ethylene Glycol 62.07 2200
Propylene Glycol 76.10 3590
Diethylene Glycol 106.10 4370

Example 3
A gas well produces 10 MMSCF/day along with 2000 lbs of water and
700 barrels per day (BPD) of condensate having a density of 300 lbs/bbl. The

hydrate formation temperature at the flowing pressure is 75 F. If the

average flow line temperature is 65 F, determine the amount of methanol
needed to inhibit hydrate formation in the flow line given that the methanol
solubility in condensate is 0.5% by weight and that the ratio of the lbs
methanol in vapor/MMSCF of gas to the weight percent of methanol in
water is 0.95.

Solution
To prevent hydrate formation in the flow line, we need to lower the hydrate

formation temperature to 65 F or less. Therefore, the depression in hydrate
formation temperature, T,is

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