American Oil and Gas Reporter - August 2021 - 49

SpecialReport: Production Monitoring
formation and freeze-offs, even at shallow-ground
pipeline burial depths. Figure
1 shows typical hydrate formation conditions
as a function of gas gravity.
Minimum winter temperatures at typical
pipeline burial depths range from
~35 degrees F in northern Alberta to ~55
degrees in the southern United States.
For a typical 0.65 SG gas, a flowing temperature
of 35 degrees corresponds to a
hydrate pressure of ~135 psig, while a
temperature of 55 degrees corresponds
to a hydrate pressure of ~535 psig.
Depending on the type of gas plant
used for processing, plant inlet pressures
(excluding inlet compression) normally
range from 1,050 to 1,400 psig, with the
highest end of this range typical of a
Joule-Thomson (JT) type of plant. With
the majority of processing facilities either
refrigeration or turbo-expander plants,
typical operating pressures are 1,1001,300
psig for most high-pressure GGS-
within hydrate formation territory for
buried pipeline flowing gas temperatures.
Would it be a feasible hydrate prevention
strategy to design and operate
the gathering system at pressures below
the hydrate forming pressure at the minimum
expected flowing temperature? This
definitely would be an option for shallow,
low-pressure gas fields, but is probably
not desirable for higher-pressure fields
because achieving the necessary low pressures
requires early compression installation,
and low-pressure operation in early
field life when gas flows are highest requires
larger-diameter pipe because of
the low gas density.
Certainly, as reservoir pressures decline
with time and compression is added, a
field may reach a point in which operating
pressure drops below hydrate formation
pressure at the minimum prevailing GGS
temperature condition. Depending on system
design, it may be possible to discontinue
hydrate prevention measures to save operating
costs, but that means changing
from a dry to a wet system. The implications
of that must be considered carefully.
Assuming a GGS initially will operate
at high line pressures, three options are
available for hydrate prevention, each
with pros and cons:
· Removing water by dehydrating
the gas;
· Keeping the gas/well stream above
the hydrate formation temperature at the
prevailing pressure; and
· Utilizing hydrate-inhibiting chemicals.
Dehydration
Methods
Figure 2 shows the water content of a
typical saturated natural gas stream. Although
the water removal requirements for field
dehydration are not necessarily the same
as sales gas specifications, they are typically
similar, with the main requirement to prevent
condensation of free water out of the gas
during transportation. Values of three-seven
pounds per million cubic feet are typical,
depending mainly on minimum
ambient/flowing temperatures.
Two common dehydration methods
are glycol (triethylene glycol) dehydration
(which probably makes up more than
90% of field gas dehydration applications)
and mole sieve dehydration. A third potential
dehydration option is calcium chloFIGURE
2
Water Content for 0.65-0.75 SG Sweet Natural Gas
10,000
8,000
6,000
5,000
4,000
3,000
2,000
1,000
800
600
500
400
300
200
100
80
60
50
40
30
20
10
8
6
5
4
3
2
1
-40
40
80
120
Water Dewpoint, °F
AUGUST 2021 49
160
200
240
ride (CaCl2), but it is typically more of a
niche application for low flow rates and
low-to-moderate gas temperatures.
Gas dehydration also has significant
benefits with respect to GGS corrosion
control and materials selection. The required
dried gas outlet spec is dictated by the
dewpoint corresponding to the minimum
flowing gas temperature in the gathering
system at the worst-case (highest) operating
pressure condition likely to be experienced.
In general, the minimum flowing temperature
is a function of latitude, and to a
lesser extent, pipeline burial depth.
Normally, a vertical separator with
metering of all three phases is installed
upstream of the dehydrator, or incorporated
into the bottom of the glycol contactor
Water Content of Sweet Natural Gas, lbm/MMcf (at 14.7 psia and 60 °F)
3000 psia
2000 psia
800 psia
600 psia
1000 psia
1500 psia
10,000 psia
5000 psia
100 psia
300 psia
200 psia
500 psia
400 psia
14.7 psia
50 psia
25 psia
American Oil and Gas Reporter - August 2021

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