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SO2 scrubbing in 
refinery applications

Emissions control and by-product capture can add value from flue gas streams generated by FCCU, process heaters, sulphur plants and spent acid regeneration units. Process flow sheet information and utility consumption guidelines are presented for an SO2 scrubbing system

Rick W Birnbaum
Cansolv Technologies
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Article Summary
Tighter regulations, an increasing spread between sweet and sour crude prices, and attractive revenue opportunities for sulphur and its by-products have led refiners to increase their use of high sulphur fuels internally and install flue gas desulphurisation systems to capture SO2. 

The Cansolv SO2 scrubbing system has been in use commercially since 2002 and a total of nine units are now operating worldwide. These units capture SO2 from FCCU regenerator offgas, fluid coker CO boiler offgas, lead and copper smelter offgas, sulphur plant tail gas and sulphuric acid plant tail gas.

Higher API gravity and sulphur content
Environmental pressures and refining costs are two challenges that face refiners on a daily basis. The spread between sweet and sour crudes is increasing as supplies of sweet crudes become tighter. Environmental pressures continue to tighten, reducing the refiner’s options to dispose of high sulphur products into the marketplace, into the air or into refinery wastewater streams.

Long-term trends for crude feed quality to refiners are clear. For example, the US EPA, through its Energy Information Administration (EIA), reports that the average diet of crudes fed to US refineries has become heavier and higher in sulphur content over the last 25 years. Figure 1 shows the overall trend. In 1984, the average refinery was fed 32.7 °API oil containing 0.9 wt% sulphur. In 2008, these numbers changed to 30.3 °API and 1.4 wt % sulphur. On a planning basis, it would not be inappropriate to anticipate that crude in 20 years’ time might consist of 28.3 °API oil containing 1.8 wt% sulphur.

Oil price trends are also clear. The cost of crude is rising and the split between the cost of heavy and light crudes has grown to nearly $10/Bbl. The incentive to configure the refinery to process these cheaper, opportunity crudes is significant. The cost base of a 250 000 bpd refinery, for example, would drop by nearly $900 MM annually if the refiner were able to take advantage of the full spread between light and heavy crudes.

However, various technical issues must be addressed in order to take advantage of the price gap between light and heavy crudes. By definition, heavy crudes produce a heavier slate of products containing greater amounts of sulphur. Major investments in bottoms processing capacity are required that would also need additional investments in hydrogen and hydroprocessing capacity for all products, and additional sulphur conversion capacity. Processing schemes must also be reviewed to ensure product quality does not suffer. Additional investment may be needed to preserve octane, cetane and vapour pressure requirements of distillate products or to remove benzene and other aromatics generated by new bottoms processing units. Changing markets for bottoms products, tighter environmental regulations and increasing costs for natural gas will require renewed examin-ation of utility systems, such that:
—  Shrinking markets for high sulphur residuum or coke will incentivise the refiner to incorporate these materials into their refinery fuel balance. Cogeneration or heater refuelling projects can absorb part of an unmarketable bottoms stream, but additional SOx, NOx and particulate controls will be needed to accommodate the use of poorer quality fuels

—  Increasing prices for natural gas or refinery gas will incentivise the refiner to conserve these commodities for use as hydrogen plant feed. Converting process heaters from gas to oil may be justifiable

—  Demand for fertilisers by India, China and the worldwide biofuels markets is expected to continue to exert pressure on sulphur and its by-products for the foreseeable future. If by-product sulphur prices remain high, regenerable SO2 capture projects will be better positioned to serve refinery-wide emission reduction campaigns

—  Higher alkylate demand, higher sulphuric acid costs and tighter markets for acid may compel the refiner to install standalone spent sulphuric acid regeneration (SAR) systems. Excess acid capacity, beyond alkylation needs, would provide an additional outlet for H2S generated by the refinery, a partial backup to existing sulphur recovery units (SRUs) and a second revenue stream for sulphur.

Environmental pressures must also be addressed. Permits to expand or modify processing units will void “grand-fathered” emissions allowances and force the installation of additional end-of-pipe wastewater and flue gas treatment systems. Tighter environmental emission limits can be met by redirecting sulphur compounds that are now discharged into the wastewater and the air to other disposal points, such as the SRU.

Many of the strategic pressures facing the refiner will require additional attention to be paid to its overall sulphur balance. Non-regenerable SO2 scrubbing systems will only increase costs as the cost for reagents such as sodium hydroxide, lime or limestone increase. Further, tighter environmental controls will likely limit the ability to dispose of gypsum to landfill or to dispose of sodium sulphate into refinery wastewater streams. Regenerable SO2 scrubbing systems can help ease many of the environmental- and market-induced pressures that are associated with the use of greater quantities of opportunistic crudes. The Cansolv SO2 scrubbing system has been able to satisfy all of these SO2 capture needs previously described, including:
—  FCCU and fluid coker CO boiler flue gas SO2 scrubbing applications for two years

—  Since 2002, for removal of SO2 produced by a Claus SRU and a SAR unit

—  An SO2 scrubbing system will soon be operating in a coal-fired cogeneration facility in China. This unit captures SO2 from a 240 MW power facility and directs the SO2 by-product to a sulphuric acid unit. The by-product revenue from this project will pay for the capital costs within three years

—  SO2 scrubbing systems have also been licensed to refiners who will use it to capture SO2 from flue gas generated by resid fired crude unit process heaters and utility boiler systems.

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