Nov-2016

Regenerable tail gas treatment

Cost assessment of tail gas treating technologies that recycle H2S or SO2 to the Claus unit.

Martin Lebel, Shell Cansolv
Manuel Jacques, Technip

Article Summary

With more difficult oil sources and severe product specifications, refiners are facing growing challenges in meeting stringent SOx emission restrictions promulgated by the environmental agencies, including for their sulphur recovery units (SRU), which are often targeted directly by SO2 emission limits imposing sulphur recovery efficiencies 
in excess of 99.9%, requiring dedicated tail gas treatment units.

This article compares the process configurations of regenerable tail gas treatment technologies that recycle either H2S or SO2 to the Claus unit, and their impact on the optimisation of the design and operation of the SRU, according to the acid gas characteristics and in particular the ammonia content of the acid gas feeds.

Two technologies are compared for two refinery case studies, representative of different situations in terms of sour water stripper gas load and overall ammonia to sulphur ratio.

Sulphur recovery units
In refineries, SRUs process the H2S and ammonia formed by sulphur and nitrogen contained in the crude feedstock, and ultimately sent to the SRU in:
• Acid gas from the amine regeneration units
• Sour water stripper off-gas.

In the SRU, H2S is converted to marketable sulphur (in liquid or solid form), while ammonia is thermally destroyed (see Figure 1).

The SRU relies on the modified Claus process to convert H2S to sulphur: H2S reacts with SO2 to form elemental sulphur, the SO2 required for reaction being generated by partial combustion of the feed gas, which converts about one- third of the H2S to SO2:
                                                        
Because reaction 2 is thermodynamically limited, conversion in this initial thermal stage is limited to about 50-70%.
Elemental sulphur is recovered from the gas phase in a condenser (and then sent for further processing and storage), and the conversion is pushed further in catalytic stages that each include a gas re-heater, a catalytic reactor and a condenser. Additional catalytic stages increase overall sulphur conversion and recovery, but the marginal gain quickly drops with each additional stage.

Typical SRU configurations include two or three catalytic stages, which usually allow overall conversion of 94-98%.
Ammonia destruction to N2 and water takes place in the thermal stage and requires temperatures in excess of 2300°F (1260°C) to achieve low residual ammonia concentrations that are acceptable in the downstream catalytic stages (typically less than 150 ppmv).

Tail gas treatment
Although Claus units can achieve sulphur recoveries up to 98%, increasingly stringent SOx emissions restrictions promulgated by the environmental agencies often impose sulphur recovery efficiencies in excess of 99% and even 99.9%.

US refineries currently have to achieve 250 ppmv (dry gas, 0 vol% O2), while the World Bank standards for SO2 emissions from SRUs are 150 mg/Nm3 or 100 ppmv (dry gas, 3 vol% O2).

Additional catalytic stages dedicated to tail gas clean-up (such as sub-dew point technologies or selective direct oxidation to sulphur) can achieve overall conversions of about 99%. In order to meet tighter environmental specifications, further treatment 
of the SRU tail gas is 
required.

Two regenerable tail gas treatment routes can be taken to meet higher sulphur recovery efficiencies, processing either hydrogenated or oxidised sulphur species.

H2S and SO2 tail gas clean-up routes
The most commonly applied hydrogenation SRU tail gas treatment technology, both downstream and upstream, is Shell Claus Off-gas Treatment (SCOT). A SCOT unit operates on similar premises as other amine units in the refinery but does so at a low pressure. The tail gas from the SRU is hydrogenated in a catalytic reactor to convert all sulphur species to H2S, then sent to a quench tower to lower the gas temperature and water content before finally contacting amine in the SCOT absorber. The gas from the SCOT absorber is then sent to the thermal oxidiser for final H2S oxidation and dispersion of exhaust gas (see Figure 2). Various amine based absorbents can be used and can sometimes be shared with other refinery amine units. In addition to the use of multiple absorbents, several hydrogenation catalysts have been developed over time to address better conversion, lower operating temperature, or a lower pressure drop.

 In the oxidised tail gas treatment option, the Cansolv SO2 scrubbing system uses a similar amine system line-up tailored to absorption of SO2 instead of H2S. The Claus tail gas and sulphur degasser off-gases are both routed to the thermal oxidiser where all sulphur compounds are converted to SO2. The gas from the thermal oxidiser waste heat boiler is then quenched and cooled before contacting a proprietary amine based absorbent. The absorbent selectively removes SO2 and is regenerated with indirect steam stripping. The product is a pure, water saturated SO2 stream that can be recycled back to the front end of the SRU as feedstock for the Claus reaction.

Both options allow for sulphur recovery efficiencies in excess of 99.9%, however the differences in line-up and in the recycled product to the SRU have different implications for the design and operation of the SRU.

When SO2 is recycled instead of H2S, less H2S from the feed gas has to be combusted to achieve the desired H2S:SO2 ratio. Looking at reaction 1, it appears that recycling one mole of SO2 reduces the combustion oxygen requirement by 1.5 moles, and thus the combustion air demand by 7.5 moles, significantly reducing the gas volume at the outlet of the thermal stage.

For the Claus unit this theoretically results in higher acid gas processing capacity for the same hydraulic capacity, or a smaller size for the same gas processing capacity. However, for standard conventional TGT configurations the amount of recycled SO2 is small and this capacity effect is limited to a few per cent.

This also results in a decrease of the combustion energy released, and thus of the operating temperature of the front-end furnace. Such a drop in temperature can be detrimental in particular for the destruction of ammonia (if it falls below 2300°F, 1260°C), or other contaminants (in particular BTEX for which destruction requires a temperature of 1900°F, 1038°C). 

However in the standard configuration described above, the recycled SO2 accounts for only a few per cent of the total sulphur and the temperature decrease is limited.