Investigating various cooling scenarios to increase the capacity of an
Iranian natural gas treating unit
A. Shahsavand
Chemical Engineering Department, Faculty of Engineering Ferdowsi University of Mashhad
P.O. Box, 91775-1111, Mashhad, I.R. IRAN,
Tel. +98 0915 514 9544; Fax. +98 511 88166840; E-mail address: shahsavand@um.ac.ir
Khangiran refinery sour gas feed has been acquired from Mozdouran reservoir in the past
twenty seven years. In this period, the reservoir pressure has been dropped severely. It is
anticipated that the pressure decrease will continue in the near future. This considerable
reduction in reservoir pressure has lead to appreciable increase in sour gas temperature
entering the gas treating unit (GTU) due to Joule-Thompson effect. Such temperature increase
had various adverse effects on the performance of the GTU process (e.g. higher contactors
temperature peaks and larger antifoam consumptions).
A variety of cooling scenarios have been considered in the present article. The required
cooling facilities were designed for lowering the temperature of sour gas or lean solvent by air
or water. The corresponding entire GTU processes were then simulated using Aspen software.
The simulation results indicate that the sour gas cooling scenario is not sufficiently effective
because of the temperature peak encountered in the absorption towers. Furthermore, although
the solvent cooling strategy was more effective from both economical point of view and its
impact on the contactor temperature profile, however it may lead to some operational
difficulties resulting from heavy hydrocarbons condensation. To avoid such predicaments,
both sour gas and lean solvent streams should be cooled simultaneously via air coolers.
The Khangiran sour gas contains about 10% carbon dioxide and hydrogen sulfide which
should be separated using suitable amine solution in an absorption tower. The performance of
amine contactor column is highly sensitive to the entering temperature of both sour gas and
lean solvent. The optimal absorption temperature of H2S and CO2 by DEA solution is about
38°C and 49°C, respectively. The operational temperature for MDEA solvent is usually about
50°C. It is well known that the gas temperature inside the contactor goes through a maximum
inside the contactor and then drops to the outlet temperature. Evidently, increasing the
entering gas and liquid temperatures boost the maximum peak inside the absorber to a value,
and hence decreases the separation efficiency.
Mozdouran reservoir pressure has been dropped from 6600 psia to less than 5400 psia during
the past twenty seven years (1982-2009). The reservoir gas temperature was always around
250°F (121°C). The sour gas cools down to a temperature of 55°C (in winter) or 65°C (in
summer) when entering the refinery at the pressure of about 1070 psia. Both Joule-Thompson
effect and heat transfer to the environment are responsible for this large temperature decrease
( T  60  C ). It is shown elsewhere [1] that about 80 percent of the overall temperature drop is
due to Joule-Thompson effect for a pressure decrease of P  4300 psi . The heat transfer
phenomenon plays a less essential role because all the pipelines are buried underground.
To prevent heavy hydrocarbons condensation, the lean amine temperature should be
sufficiently higher than the entering sour gas. It was shown that increasing the feed gas
temperature from 52°C to 66°C will raise the maximum peak temperature inside the contactor
(up to 95°C) and hence drastically reduces the separation performance of absorption column.
The entire GTU process was simulated using Aspen software under the actual operating
conditions and worst case (both sour gas and lean amine entering the contactor at 70°C).
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Furthermore, the simulation software was used to investigate the performance of the contactor
under following cooling scenarios:
Scenario 1 (S1): Only cooling sour gas to 50°C.
Scenario 2 (S2): Only cooling lean solvent to 50°C.
Scenario 3 (S3): Cooling both sour gas and lean solvent to 50°C.
Figure 1 illustrate the predicted distributions for temperature across the entire contactor using
and Aspen software at normal operating conditions for various assumed Murphree
efficiencies and different solvents (DEA 34% and MDEA 45% in water). The stages were
numbered from the top of absorber column and stage 21 represents the entering sour gas
conditions. The Electro Insert data package was imported for efficient simulation.
11
Stage (G)
21
1
70
T (°C)
ME=0.4, T
ME=0.7, T
ME=1, T
ME=0.4,G
ME=0.7, G
ME=1, G
7000
70
6500
50
50
1
11
Stage (T)
1
Stage (G)
7500
G
(kmol/h)
T (°C)
Solvent: DEA
11
90
7500
21
Solvent: MDEA
G
(kmol/h)
21
90
ME=0.4, T
ME=0.7, T
ME=1, T
ME=0.4,G
ME=0.7, G
ME=1, G
7000
6500
1
11
Stage (T)
21
Figure 1: Simulated contactor temperature distributions for and different solvents.
Figures 2 compares the predictions of Aspen software for worst case operating conditions
with various cooling scenarios, using different solvents (DEA 34% and MDEA 45%).
T(°C)
WC,T
S2,T
WC, G
S2, G
Stage (G)
7500 110
S1,T
S3,T
S1, G
S3, G
80
50
1
11
Stage (T)
21
1
7000
80
6500
50
WC,T
S2,T
WC, G
S2, G
Stage (G)
1
7500
S1,T
S3,T
S1, G
S3, G
7000
6500
1
21
Solvent: MDEA 11
G
(kmol/h)
11
T(°C)
110
Solvent: DEA
G
(kmol/h)
21
11
Stage (T)
21
Figure 2: Simulated temperature distributions across the contactor for various solvents and
different cooling scenarios.
Evidently, the temperature changes of both gas and liquid feeds have significant effect on the
absorption capacity of contactors. Decreasing the sour gas feed temperature practically does
not affect the contactors performance because of its low heat capacity. On the other hand, any
temperature drop in DEA solvent stream drastically improves the absorber performance as
shown in Figure 2. It was also observed that, in all cases, the mole fraction of carbon in sweet
gas stream is higher than the allowable standard values.
6) Reference
A. Shahsavand, "Investigation of various cooling scenarios effects on the performance of
Khangiran gas treating units", NIOC research project, 2008
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