Modified Claus Process with Tailgas Cleanup
In applications where a high level (more than 99.5%) of overall sulfur recovery is required, Ortloff has chosen to employ the Modified Claus Process coupled with an amine-based tailgas cleanup process. We believe this process is the best widely-proven technology available in the industry for achieving overall sulfur recovery performance up to 99.9%. Ortloff has performed the detailed process engineering, specification, and design of more than fifteen amine-based tailgas cleanup units.
The tailgas cleanup process reduces all of the sulfur compounds in the tailgas leaving the front-end Claus sulfur plant back to hydrogen sulfide (H2S), then uses selective amine absorption to remove the H2S while allowing most of the carbon dioxide (CO2) to “slip” by. The H2S and CO2 removed by the amine are stripped from the amine and recycled back to the Claus plant, allowing an overall sulfur recovery in excess of 99.5%. Depending on the performance required, the effluent from the tailgas cleanup unit (TGCU) can contain as little as 10 PPM of H2S. This effluent is normally routed to a Tailgas Thermal Oxidizer to incinerate the H2S and any other remaining sulfur compounds to sulfur dioxide (SO2) before dispersion to the atmosphere.
1 – The front-end Modified Claus Process sulfur plant typically recovers 93-96% of the sulfur in its feed streams, which includes a recycle acid gas stream from the TGCU. By capturing and recycling the unrecovered sulfur leaving in the sulfur plant tailgas, the TGCU can raise the overall sulfur recovery efficiency to 99.9% or higher, even though the once-through recovery in the sulfur plant is only 93-96%.
2 – The hydrogenation/hydrolysis section reduces the sulfur compounds in the sulfur plant tailgas back to H2S.
3 – The quench section cools the hot gas leaving the hydrogenation/hydrolysis section and removes trace components that could degrade the downstream amine solvent.
4 – The contacting section uses a selective amine solvent to remove essentially all of the H2S from the gas stream while allowing most of the CO2 to “slip” by and remain in the gas stream.
5 – The treated gas from the contacting section is routed to a Tailgas Thermal Oxidizer to incinerate the residual H2S and any other remaining sulfur compounds to SO2 before dispersion to the atmosphere.
6 – The solvent regeneration section strips the H2S and CO2 from the amine solvent and recycles the acid gas stream to the front-end Claus plant.
In order to remove the sulfur compounds from the sulfur plant tailgas with amine solution, the sulfur compounds must first be converted back into H2S. This is accomplished by catalytic reaction of hydrogen and water vapor with the sulfur compounds.
1 – The sulfur plant tailgas typically enters the TGCU at 250-300°F, but the reaction initiation temperature for the hydrogenation and hydrolysis reactions is 475-500°F. The most common means of heating the tailgas before it enters the reactor is with an in-line burner, although indirect heaters have also been used. The burner combusts fuel gas with stoichiometric air (so that free oxygen does not escape and damage the downstream catalyst bed) to generate heating gas.
2 – The burner effluent combines with the tailgas in the mixing chamber to directly heat the tailgas to the desired temperature. External hydrogen is also added to the mixing chamber to supplement the reducing gas in the tailgas. If external hydrogen is not available, the burner operating mode can be modified to generate reducing gas. When operated with less than stoichiometric air, the burner will partially oxidize the fuel, producing hydrogen and carbon monoxide (CO). As discussed below, the reactor catalyst will “shift” carbon monoxide to hydrogen, so CO is also an effective reducing gas.
3 – When the burner must generate a significant portion of the reducing gas, the gas leaving the mixing chamber may need to be cooled before entering the reactor. In these cases, a waste heat boiler generating medium pressure steam (40-100 PSIG, typically) can be used to cool the reactor feed gas.
4 – The reactor contains a 36″-48″ deep bed of cobalt-molybdenum catalyst that allows the reducing atmosphere to hydrogenate or hydrolyze most of the sulfur compounds to H2S:
(1) H2S + 3/2 O2 ⇌ SO2+H2O
(2) 2 H2S + SO2 ⇌ 3/nSn + H2O
(3) 3 H2S + 3/2 O2 ⇌ 3/nSn + 3H2O
(4) CS 2 + 2 H2O ⇌ 2 H2S + CO2
Carbon monoxide in the process gas also reacts with the water vapor in the gas to form hydrogen, the classic “water gas shift” reaction:
(5) CO + H2O ⇌ H2 + CO2
5 – A waste heat boiler generating medium pressure steam is often used to partially cool the hot gas stream leaving the reactor before it enters the quench section.
Before the amine solvent can be used to remove the H2S from the process gas, the gas must be cooled to an acceptable contact temperature. This is accomplished by direct contact of the gas stream with a circulating stream of quench water.
1 – The partially cooled gas enters the bottom of the quench column and is cooled by direct contact with a circulating stream of quench water. As the gas is cooled to 100-120°F, most of the water vapor produced by the upstream reactions (Claus, combustion, and hydrogenation) is condensed and removed from the gas stream. In addition to cooling the gas, direct contact with the quench water serves to absorb trace quantities of SO2 that may “break through” the reactor periodically. SO2 will react with amines to form heat-stable salts, so the “washing” action of the quench water helps minimize the degradation of the amine solvent. The cooled gas stream proceeds to the contacting section.
2 – The quench water leaving the bottom of the column is pumped to filtration and the cooler.
3 – A side stream of the quench water is filtered to remove solids from the quench water system. A portion of the filtrate is bled from the system to balance the water condensed from the gas in the quench column, and the remainder returns to the pump suction.
4 – Before returning to the quench column, the quench water is cooled to reject the heat removed in the column. Water and/or air cooling may be used in this service.
The contacting section uses a selective amine solvent to remove essentially all of the H2S from the gas stream while allowing most of the CO2 to “slip” by and remain in the gas stream. This is accomplished using a conventional gas/amine contactor.
1 – As the cooled gas flows upward through the packing or trays in the contactor, it is contacted by the amine solvent to selectively remove nearly all of the H2S from the gas stream while “slipping” most of the CO2. The most common solvent employed is a 25-50 wt% aqueous solution of methyldiethanolamine (MDEA), often with minor amounts of other amines or other chemicals to enhance the H2S removal. The reactions between the acidic gases and the basic amine solution can be represented by:
(6) H2S + CH3(CH2OHCH2)2N ⇌ CH3(CH2OHCH2)2NH+ + HS–
(7) CO2 + CH3(CH2OHCH2)2N + H2O ⇌ CH3(CH2OHCH2)2NH+ + HCO3
The selectivity of tertiary amines like MDEA for H2S is a result of the indirect reaction that must occur between the amine and CO2. Unlike primary amines (such as MEA) and secondary amines (such as DEA), tertiary amines do not react directly with CO2. Instead, the CO2 must first be ionized into a bicarbonate ion (a slow reaction) before it will react with the amine. Since MDEA reacts directly (and quickly) with H2S, proper selection of the contact time between the amine and the process gas allows preferential removal of the H2S.
2 – The treated gas leaving the contactor is routed to a Tailgas Thermal Oxidizer to incinerate the small amount of H2S remaining in the gas to SO2 before dispersing the effluent to the atmosphere.
3 – The rich solvent leaving the bottom of the column is pumped to filtration and the lean/rich exchanger.
4 – The rich solvent is usually filtered before it flows to the lean/rich exchanger to remove accumulated solids from the system and minimize fouling of the exchanger.
5 – The lean/rich exchanger uses the hot lean solvent to preheat the rich solvent before it flows to the solvent regeneration section. This also partially cools the lean solvent, reducing the load on the downstream cooler. Plate and frame type exchangers are often a cost-effective choice for this service.
6 – A slipstream of the lean solvent is usually filtered, also. In addition to mechanical filtration, a carbon filter is normally used to remove degradation products from the amine that could lead to foaming and/or corrosion.
7 – Before returning to the contactor, the lean solvent is cooled to ambient temperature or below (90-120°F). Lower temperatures improve the selectivity of the solvent for H2S. Water and/or air cooling may be used in this service.
Solvent Regeneration Section
The solvent regeneration section strips the H2S and CO2 from the amine solvent and recycles the acid gas stream to the front-end Claus plant. This is accomplished using a conventional amine stripping system.
1 – As the rich solvent flows down the stripper, the absorbed H2S and CO2 are stripped from the MDEA by countercurrent contact with stripping steam rising upward. Most strippers use trays rather than packing to contact the solvent with the steam.
2 – The stripping steam is generated in the reboiler, generally by using medium pressure steam or heating oil as the heat input.
3 – The stripping steam supplies the heat of reaction to reverse reactions (6) and (7), and carries the H2S and CO2 overhead to the condenser where the steam is condensed as the stream is cooled to 100-120°F. Water and/or air cooling may be used in this service.
4 – The condensed water is removed by the reflux drum and returned to the tower as reflux by the reflux pump. The H2S and CO2, along with a small amount of uncondensed water, exit the drum and recycle back to the sulfur plant to become part of the acid gas feeds.
5 – The regenerated solvent from the bottom of the stripper is pumped back to the contacting section.
The Modified Claus Process with Tailgas Cleanup is used when very high sulfur recovery is necessary, such as for sulfur plants in petroleum refineries in the U.S. The U.S. EPA regulations normally require that the incinerated effluent from refinery sulfur plants contain no more than 250 PPM SO2 on a dry, oxygen-free basis. This usually corresponds to an overall sulfur recovery of 99.8-99.9%. If necessary, still higher recoveries are possible using special solvent formulations and other design features, so that the TGCU effluent contains as little as 10 PPM of sulfur. If lower recoveries are allowed by regulations, however, the Cold Bed Adsorption Process is a more cost-effective choice for the intermediate range of 97.5-99.5% sulfur recovery.