Hydrocarbon Processing - April 2022 - GP-39

MAINTENANCE/LEAK DETECTION
turbulence and pump vibration,
significantly affecting seal life.
If an increase in the current
process flowrate is not expected,
consideration should be given to
re-rate the pumps for the actual
operating condition. This will
help improve pump and seal
performance, and reduce pump
power consumption.
4. The process operating
temperature ranges from
260°F-270°F (127°C-132°C),
which is higher than the normal
operating temperature of 246°F
(119°C) specified in the
pump datasheet.
5. The failure analysis of the
final failed seal showed pitting
corrosion in critical locations,
including O-ring surfaces. A
sample of the condensate liquid
between the main and backup
seals was sent for analysis to
identify the cause of pitting. The
analysis showed no indication
of any major corrosive agents.
Pitting may be caused by an
isolated incident due to a process
upset. If future data shows
pitting, material upgrade to
duplex or super duplex should
be considered.
Seal system design analysis. A design
assessment was conducted for the seal
design parameters and the seal auxiliary
system to identify any potential design
concerns. The main points that may have
contributed to the low reliability of the
seal include:
1. The datasheet shows that the
liquid specific gravity is < 0.5
with an operating temperature
of 246°F (119°C). The pump
specialists experienced low
seal reliability for many pumps
in such applications supplied
with vendor seals. Low specific
gravity liquids are considered
to be difficult to seal. For this
reason, API 682 recommends
Arrangement 3 seals for liquids
with < 0.5 specific gravity,
such as this pump with a
specific gravity of 0.497.
2. The site temperature
measurement for seal API Plan
21 flushing liquid during the
site visit showed that the inlet
and outlet temperatures for
the cooler were 176°F (80°C)
and 140°F (60°C), respectively.
Although this is not in line with
the typical process temperature,
it shows that sufficient cooling
is happening at the cooler. For
proper seal performance, pump
standards mandate that the
stuffing box pressure exceed
the vapor pressure by at least
50 psi. This can be accomplished
by increasing the stuffing box
pressure or decreasing the liquid
vapor pressure via cooling
methods. In this pump case,
the process data indicated that
sufficient cooling was provided.
3. The seal drawing shows that two
0.125-in. orifices designed to
achieve a seal flush flowrate of
3 gal/min were used for API Plan
21. Calculations showed that
flowrate will be less than 3 gal/
min since the takeoff for API
Plan 21 was from the discharge
of the first stage. For that reason,
the seal vendor was contacted
to verify orifices requirements.
Based on the vendor response, it
was recommended to leave one
of the restrictive orifices as it was
and to open the other to full bore,
as shown in FIG. 5.
4. The current seal follows API
Plan 76 while company standards
mandate API Plan 75. FIG. 6
shows the difference between
these two API 682 seal plans. Plan
75 should be used whenever the
liquid has heavy ends to prevent
the liquid accumulation between
the two seals. When Plan 76 is
used, the liquid will accumulate
between the two seals; this can
cause a failure of the dry running
backup seal, as it is designed
for a gas phase in normal
operation. For that reason, it is
recommended to change the
seal plan from Plan 76 to Plan
FIG. 4. Unit A and B operating flow and head.
FIG. 5. Location of orifices.
Gas Processing & LNG | MARCH/APRIL 2022 39
Hydrocarbon Processing - April 2022

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