by Norm Lieberman
The best way to enhance SRU capacity is to reduce the hydrocarbon content in NH3 off-gas, from the Sour Water Stripper. Each mole of light hydrocarbons in Sour Water Stripper off-gas consumes ten times as much air, as does a mole of H2S in the Thermal Reactor.
The best method of reducing hydrocarbons in SRU feed is to not over-strip the Sour Water, in order to reach too low an NH3 content of sour water stripper bottoms. Most of the sour water stripper bottom’s flow flows to either the crude unit desalter, or directly to the wastewater treatment plant. A typical NH3 content in the sour water stripper feed is 20,000 – 30,000 ppm. A typical hydrocarbon content of the sour water stripper feed is 0.5% volume of a naphtha boiling range component.
My field testing has indicated that if the sour water stripper reboiler steam flow is set high enough to reduce the NH3 content of stripper bottoms to less than 10 ppm, then essentially all of the naphtha will be stripped out into the SRU feed gas, with the NH3 and H2S. However, if the sour water stripper steam flow is adjusted, so that 30 – 40 ppm of NH3 is left in the stripped water, then about 90% of the naphtha in the feed is left in the stripped sour water.
I once greatly reduced the combustion air consumed at the Co-Op Refinery (southern Indiana) SRU by use of this technique. This permitted 10% – 20% more H2S feed to the SRU, which had been limited by the combustion air flow and high front-end pressures.
CO2 Absorption Reduced
Another method to reduce SRU inlet pressure is to diminish the CO2 content of acid gas feed. High CO2 content is a consequence of excessive CO2 absorption in the amine fuel gas absorber. I used this technique at an amine fuel gas absorber that I designed for the American Oil Refinery in Texas City. The new absorber had 20 trays and three lean amine feed points at:
- Tray 20 (top tray)
- Tray 10 (mid tray)
- Tray 5 (from bottom)
H2S is more readily absorbed in lean amine than is CO2. By the plant operator optimizing the lean amine feed tray location:
- 99%+ of the H2S could be absorbed
- However, less than 50% of the CO2 was absorbed
The operators would adjust the lean amine feed tray location to meet their H2S spec in fuel gas, but also try to MINIMIZE the CO2 content of the rich amine flowing to the amine regeneration tower. Especially when scrubbing the wet gas effluent from a refinery FCU, this can make a sizable contribution to increasing the capacity of the sulfur recovery unit to handle H2S acid gas on sulfur plants limited by front-end pressure by reducing CO2 absorption.
About the Author
Norm Lieberman graduated from Cooper Union (New York) as a Chemical Engineer in 1964. He has spent 59 years troubleshooting refinery process problems. Norm has written 12 books on this subject, and has instructed 1,030 in-house seminars for his clients. To avoid aging, Norm runs three miles every day. For information about Lieberman’s troubleshooting seminar, email norm@lieberman-eng.com.
Note: The views, thoughts, and opinions expressed in the content above belong solely to the author and do not necessarily reflect the opinions and beliefs of Refining Community or its parent company, CRU Group.
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