The cost of controlling air emissions generated by FCCUs

With the trend towards processing heavy and sour feed stock and the strengthening of environmental regulations, refiners are looking for cost effective ways to control air emissions generated by fluidised catalytic cracking units (FCCUs).

Kevin R Gilman, Hugues B Vincent and Thomas F Walker
Belco Technologies Corporation (Now BELCO Clean Air Technologies)

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Article Summary

This paper reviews the environmental technologies available today to control SOx and particulate of FCCU stack emissions, including deSOx additives, electrostatic precipitators, wet scrubbing, hydrotreating, etc. Also provided is an analysis of the cost of controlling SOx emissions, for various feedstock scenarios, which can be used as a planning guide for operators of FCCU.


In most refineries, the FCCU represents the greatest single air emission source. The FCCU regenerator flue gas contains significant quantities of catalyst fines and sulphur dioxide. The quantity of sulphur dioxide emitted by the FCCU regenerator depends primarily on the sulphur content of the feedstock. Shifting to a more economical, higher sulphur feed would improve the refining margin at the expense of increased sulphur recovery and FCCU regenerator stack emissions. With the trend towards processing heavy and sour feedstock and the strengthening of environmental regulations, refiners are looking for cost effective ways to control and lower air emissions generated by FCCUs.

In the US, the 1989 New Source Performance Standard (NSPS) for FCCU currently sets national standards for emissions of particulate matter (PM) and sulphur in the oxidised form (SOx = SO2 and SO3) (See Appendix 1). Furthermore, the Maximum Available Control Technology (MACT) rules proposed by EPA may virtually eliminate grandfathered permits and force those refiners to reduce drastically particulate emissions. To a large extent, some US refiners are already controlling particulate emissions through the use of cyclones, electrostatic precipitators or wet scrubbers.

For SOx emissions, many US refiners have grandfathered air permits that allow them to operate at current emission levels but severely restrict them from expanding the FCCU throughput capacity, or adding new units or processing more economical, higher sulphur feeds. Also, local regulations limiting individual refinery “bubble” emissions will eventually require refiners to address SOx emissions on grandfathered FCCUs. In summary, there is an urgent need for new sulphur management strategies supported by adequate control technologies in view of debottlenecking the FCCU operation.

SOx control technologies
In the FCCU reactor 70% to 95% of the incoming feed sulphur is transferred to the acid gas and product side in the form of H2S. The remaining 30 to 5% of the incoming feed sulphur is attached to the coke and is oxidised into SOx emitted with the regenerator flue gas as shown in Appendix 2. The sulphur distribution is dependent on the sulphur species contained in the feed, and in particular thiophenic sulphur. Ways to reduce the SOx stack emissions include hydrotreating the FCC feed to reduce its sulphur content, transferring more sulphur to the acid gas side (reactor side) through the use of transfer catalysts or scrubbing SOx out of the flue gas.

Upstream feed hydrotreating preferentially removes non-thiophenic feed sulphur, so H2S and gasoline sulphur are reduced. While the absolute level of sulphur in the coke goes down, the percent of the feed sulphur that goes to the coke, i.e. to the stack as SOx, is increased. Also, although hydrotreating provides other benefits on the products side, it is a very capital intensive solution and cannot be economically justified when reduction of FCC flue gas SOx emissions is the only incentive.

Transfer catalysts
Also called deSOx additives, they have been used by several refineries, most of them processing relatively sweet crudes. They transfer more sulphur to the acid gas and product side in the form of H2S, thus possibly limiting the capacity factor of the Sulphur Recovery Unit (SRU) and increasing the product desulphurisation requirements.

The equivalent cost of catalytic deSOx  is typically between $1,000 to $3,000 per ton of sulphur transferred for only 40 to 50% SOx control efficiency. This cost would increase for higher performance requirements. The additive consumption is highly unpredictable because it depends on multiple factors. Sudden loss of activity is not unusual. Also, deSOx additives typically have a poor SOx pick-up factor for partial burn regenerators. In practice, an additive trial is required to estimate the cost of catalytic deSOx at any given time7.

Consequently, its use has been restricted to refiners who only occasionally exceed SOx permit limits or to refiners targeting the 9.8 lb SO2/1000 lb coke burn under NSPS without an add-on SO2 control device. For 50% SOx control efficiency this corresponds to an application limit of less than 20 lb SO2/1000 lb coke burn (equivalent to 1% sulphur in coke), i.e. in practice, for FCC feed containing less than about 0.5% sulphur.

Wet scrubbing
Wet scrubbing is used successfully on the FCCU application, in the US and in Asia, to control both particulate and SOx. Most scrubbers so far are using caustic soda (NaOH) to absorb SOx and discharge it in the form of a soluble sodium sulphate salt, but alternative alkali or regenerative processes are becoming available to optimise final residue disposal and operating costs.

The costs presented in this section are based on the EDV wet scrubbing technology offered by Belco Technologies Corporation for both particulate and SOx control. Indeed, another demonstrated technology has only used caustic as a scrubbing media and has proven to be more expensive in terms of capital costs. As a result, recently, most refiners purchasing wet scrubbers have selected the EDV technology for their FCCU applications. The EDV technology has been described in previous papers2,3.

Caustic scrubbing
The first EDV system supplied for an FCCU application started up in October 1994 at the Valero refinery, Corpus Christi, Texas. The EDV system has shown excellent performance and reliability2. More than 3 years of operation now logged allows a meaningful calculation of the cost of controlling emissions for that FCCU. The FCCU processes a hydrotreated feed containing approximately 0.6% sulphur. Its capacity has gradually been expanded from 65,000 BPSD (last turnaround in 1994) to 80,000 BPSD (next turnaround in 1998).

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