How low can it go?

The Shell Claus Offgas Treating (SCOT) process has been developed to remove sulphur compounds from Claus tail gas to comply with even more stringent emission regulations. The standard SCOT process is able to easily meet less than 250 ppmv total sulphur in the SCOT off gas, which corresponds to an overall sulphur recovery efficiency of 99.9% on intake.

Gerrit Bloemendal and Frank Scheel
Jacobs Nederland B.V.

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Article Summary

Conventional SCOT type tail gas units operate with inlet gas temperatures to the reduction reactor of 280-300°C in order to achieve a full conversion of the sulphur species to H2S. In most cases this temperature requires the use of an inline burner since typical steam conditions in refineries and gas plants are not high enough to raise the temperature of the gas to this level.

Jacobs Comprimo® Sulphur Solutions recognised that the ability to operate at a lower temperature offered the potential to reduce energy costs, reduce equipment sizes and eliminate the high maintenance burner from the tail gas treating plant. A catalyst was developed by catalyst manufacturers that could achieve high levels of sulphur species reduction at lower temperatures, specifically below 240°C. This temperature would allow steam heating to replace the inline burner.
The Low Temperature SCOT (LT-SCOT) process essentially consists of a reduction section and an ADIP absorption section of special design. In the reduction section all the sulphur compounds (other than H2S) present in the Claus tail gas (SO2, COS, CS2 and elemental S) are completely converted into H2S over a cobalt/ molybdenum catalyst at 220°C in the presence of reducing gas components such as H2 and CO. The Claus tail gas feed to the SCOT process is heated to 220°C with heat exchanger with optionally H2 or a mix of H2/CO added.

If reducing gas, H2 or CO, is unavailable, an inline burner (RGG) is required to produce reducing gas. The heated gases then flow through a catalyst bed where sulphur compounds, including CS2 and COS, are reduced to H2S. Water vapour in the process gas is condensed in a quench column by direct contact cooling with water and the condensate is sent to a sour water stripper. The cooled gas, which normally contains up to 3 vol% H2S and up to 20 vol.% CO2 or more is counter currently washed with a selective alkanolamine solvent in an absorption column designed to absorb almost all H2S but relatively little CO2. The treated gas from the absorption column contains only traces of H2S and is burned in a standard Claus incinerator. The concentrated H2S is recovered from the rich solvent in a conventional stripper and is recycled to the Claus unit. The LT-SCOT units are designed for minimum pressure drop so that they can be easily added to existing Claus units. If insufficient pressure is available, a gas booster can be installed, preferably between the cooling tower and the absorption tower.

LT-SCOT versus regular SCOT
• It may be obvious from the above that for new units an inline burner is no longer mandatory in a SCOT unit: a simple 40 bar steam reheater can provide sufficient temperature for this catalyst. For new units this 40 bar stream is typically generated in the Claus WHB.
• Indirect savings occur from eliminating the combustion air, thus saving blower energy, and from the fact that the SCOT unit has a lower backpressure due to the lower total gas flow. The reduced gas flow subsequently also reduces the quench water and the amine circulation requirements; a 5% reduction of amine flow is achieved. This decreases the TIC of the LT-SCOT with about 10-15% compared to a conventional SCOT.
• Integration with the amine treater upstream the Claus plant can lead to considerable equipment savings. The add-on LT-SCOT in Figure 1 has a complete independent solvent system.

Case history
In 2003 Jacobs Netherlands was approached by Ruhr Oel GmbH (ROG) represented by the BP Gelsenkirchen - Horst refinery to assist in the upgrade of the sulphur recovery units to meet the more stringent future emission requirements.

At that moment, the refinery had three sulphur plants, two units from the early eighties provided with a common subdewpoint stage, and one unit from the early nineties consisting of a two stage Claus section and a conventional SCOT unit.

In line with the ROG/BP strategy, an appraise stage was started, and several options were evaluated. All options pointed towards replacement of the subdewpoint system, either partially by adding a SCOT type process to the existing old sulphur plants or completely by installing a new, integrated Claus and SCOT unit.

To minimise investment cost, options were evaluated to provide amine solvent to the new SCOT section using the existing equipment in the refinery.

The refinery, at that point in time, used DIPA as a solvent for both the refinery absorbers and the existing SCOT absorber. After an extensive study a scenario was developed in which an existing regenerator could be made available to provide the solvent for the two SCOT units.

As a side-effect, this opened the possibility to change the solvent for the SCOT units from DIPA to MDEA, thus increasing the selectivity and minimising the CO2 recycle. However, the capacity of the regenerator was still limited, making it mandatory to minimise the Claus off gas flow.

More or less parallel to these studies, Jacobs gained awareness of the fact that Axens had developed a new type of catalyst for tail gas treatment, the TG-107, which could operate at temperatures below 240°C rather than at 280°C. However, Axens at that point in time did not have much commercial/practical experience with this new TG-107.

Since the catalyst in the existing SCOT unit had been in operation for more than 10 years, it was considered an operational risk to continue operation with this aged catalyst for another of 5 years cycle, and budget had already been allocated to replace the catalyst. Since it was known that for the new sulphur plant the refinery was running short of solvent regeneration capacity, the decision was made to replace the aged catalyst with TG-107, opening up the potential for low temperature operation and minimising tail gas flow. As the old unit was provided with an inline burner, the escape in case of non-functioning of the TG-107 was to operate the catalyst at ‘conventional’ temperatures, making it a unique opportunity to test the TG-107.

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