Hydrocarbon Processing - August 2021 - GP-29

ENGINEERING AND DESIGN
steam (0.2 lb steam/gal of water) compared to the design supply
of 63 lb/hr steam (1.05 lb steam/gal water). Note: During
this test, a number of main equipment pieces were not available,
including filters, the sour water feed pump and the treated
water pump. Furthermore, the system was operated manually.
TABLE 2 shows the results extracted from the lab report for Field
Test 1. The recommendation was to repeat the test at a higher
steam supply, which was implemented for Field Test 2.
Field Test 2 was conducted at a higher steam rate of approximately
48 lb/hr steam per 1 gal/min feedwater, which is
0.75 lb steam/gal water. The results showed that the H2
S in
treated water was on specification. However, the system was
not stable due to both the feed and treated water pumps not
being in service. TABLE 3 shows the results extracted from the
lab report for Field Test 2.
For Field Test 3, the test was repeated with a similar high
steam rate (average of 45 lb/hr steam per 1 gal/min water,
which is 0.75 lb steam/gal water) as in Field Test 2, while both
the feed and treated water pumps were in service. The test was
very successful, with all test points up to 150 gal/min (about
5,000 bpd) showing that the H2
S in treated water was within
the limit and that the system was stable and under auto control.
TABLE 4 shows the results extracted from the lab report
for Field Test 3.
During Field Test 3, it was observed that the actual steam
injection rate was lower than the recommended unit PFD value,
as shown in FIG. 8. In addition, the column top temperature
was higher than the unit PFD, even though the steam injection
rate was lower. The simulation results shown in FIG. 7 supported
the actual test results. The calculated steam injection
was slightly higher than the actual steam injection, which can
be attributed to the column internals or the correlation used
in the simulation.
Health checks for process equipment. Based on unit simulation
runs and actual field tests, the following observations
were recorded for each piece of SWS equipment:
* Pre-flash drum: The vessel was working normally,
with operating pressure as per PFD conditions.
The frequency of sand jetting occured only once a
week, which was not sufficient to effectively remove
the sludge accumulation in the pre-flash drum and
downstream equipment.
* Sour water filter pump: The pump was still being
operated with a temporary suction strainer. In addition,
only a single pump was available onsite without any
standby, which limited the unit operation in case of
failure on the pump.
* Sour water mechanical filter: Only one filter was
provided with the bypass line for the sour water stripper
column, which was not adequate due to high solids
content in the sour water. Frequent cleaning and filter
change-out are required for this filter. Furthermore,
during the isolation of this filter, solids accumulated
in the stripper column, which created fouling in the
stripper column and reduced its performance.
* Sour water stripper column: Pressure control was
not working properly for the stripper column while
it was running on manual control. Also, the reflux
pump experienced some issues due to solids in the
water, which made the column operation unstable
and caused difficulty in controlling the pressure
and level in the column.
* Treated water pumps: The pumps were not running
due to a mechanical issue, which was fixed for Field Test
3. Also, a temporary suction strainer was installed that
caused a blockage with solids, creating cavitation.
* Process control system: During Field Test 1 and Field
Test 2, it was observed that the system was unstable in
manual mode. This instability was mainly due to the
fact that the feed and treated water pumps were not in
service to maintain column pressure to drain the treated
water to the evaporation pond. During Field Test 3, the
SWS unit ran stable on auto mode, when all feed and
treated water pumps were in operation.
Integration of existing SWS with new SWS train. Based
on the actual performance test and a desktop study of the exTABLE
2. Lab results for Field Test 1
Number of test
1
2
3
45
65
85
Feed flow, gal/min Sample results H2
70
168
51
TABLE 3. Lab results for Field Test 2
Number of test
1
2
3
120
150
TABLE 4. Lab results for Field Test 3
Number of test
1
2
3
4
5
6
5,000
6,000
7,000
8,000
4,000
3,000
2,000
1,000
40
60
80
100
Steam injection rate
120
Sour water feedrate, gal/min
H2S in treated water
FIG. 8. H2S in treated water vs. steam injection rate for Field Test 3.
Gas Processing & LNG | JULY/AUGUST 2021 29
140
160
45
65
85
S, ppmw
Feed flow, gal/min Sample results H2
100
< 0.4
1.7
4.1
S, ppmw
Feed flow, gal/min Sample results H2
< 0.4
100
120
150
< 0.4
< 0.4
< 0.4
< 0.4
< 0.4
0.35
0.4
0.1
0.2
0.3
0.25
0.05
0.15
S, ppmw
Steam injection rate, lb/hr
H2S in treated water, ppmw
Hydrocarbon Processing - August 2021

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