Best practices for SOx emissions control
Applying the key elements of experience gained since the introduction of â€¨SOx-reducing additives for FCC operations
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SOx-reducing additives were first introduced into the FCC world in 1984 by Arco Refining. Clean air legislation enforced by the Environmental Protection Agency required FCC units operating with the US to begin introducing SOx-reducing additives as one of the best available control technologies. The use of these additives quickly spread throughout the refineries in North America.
A substantial body of experience has been accumulated within the industry since SOx additives were first injected into FCC units. This experience spans a very wide range of operations, including “mild reductions”, in which modest levels of SOx reductions were required, up to and including ultra-deep reductions to 5 ppm or less. These operations span full-, partial- and two-stage combustion regenerators.
Refineries operating in strict compliance zones have been required to reduce SOx emissions for decades. Some refiners have chosen the path of large capital investment via the installation of catalytic feed hydrotreaters or flue gas scrubbers to control SOx emissions. Many refiners have chosen to use additives as a capital-free route to control emissions.
As regulations spread more widely, many refiners are now being required to reduce SOx emissions. This article is intended to enable these refiners to take advantage of the experience accumulated within the industry and crystallises the most useful lessons learned since the mid-1980s.
The term SOx is used throughout this article to represent total oxidised sulphur in the form of SO2 plus SO3, which is emitted from the FCC flue gas stack.
SOx emissions chemistry
The reactions related to sulphur combustion are well understood. A simplified overview of these reactions is helpful in understanding how to control SOx emissions within the FCC regenerator.
In full-combustion operations, 100% of the sulphur contained within the coke will be oxidised. Approximately 90% of this oxidised sulphur will be in the form of SO2, with the remainder being oxidised to SO3. SOx-reducing additives absorb SO3. Most SOx-reducing additives contain cerium, which functions as an “oxygen sponge” and catalyses SO2 to SO3. The SO3 is then reacted with magnesium-forming magnesium sulphate. The magnesium sulphate is transported into the reducing atmosphere of the reactor vessel, where sulphur is released as H2S. The magnesium is then regenerated to MgO and is available for additional absorption reactions within the regenerator. These reactions are:
S + O2 â†’ SO2 (1)
SO2 + Â½ O2 â†’ SO3 (2)
SO3 + MgO â†’ MgSO4 (3)
MgSO4 + 8[H] â†’ MgO + H2S + 3H2O (4)
Sulphur combustion within the partial-combustion regenerator is very similar to combustion within the full-burn regenerator. The â€¨notable exception is insufficient oxygen to fully oxidise the sulphur to SO2. A portion of the sulphur will be partially oxidised to COS, as shown below:
S + CO â†’ COS (5)
COS + H2O â†’ CO2 + H2S (6)
Two-stage regenerators are unique in that the first stage operates in partial combustion, while the second stage normally operates in full combustion. The first-stage regenerator’s sulphur combustion reactions are dominated by reactions 1 and 5, while in the second-stage regenerator reactions 1 and 2 predominate.
Predicting SOx emissions
Development of an accurate uncontrolled SOx emissions model is the first step when initiating a SOx additive trial. Baseline data are used to develop a correlation that accurately predicts SOx emissions. The additive of choice is then injected into the unit. SOx emissions will drop rapidly as the additive begins to circulate within the unit. The correlation is used to calculate the uncontrolled SOx emissions for comparison with observed emissions. This enables the process engineer to calculate the efficiency of the SOx reduction and additive.
SOx emissions will correlate with feed sulphur in some but not all units (see Figure 1). The sulphur present within the FCC feedstock partitions differently between coke and liquid products, depending on the type of sulphur molecules â€¨present within each feedstock. Those refiners experiencing frequent feed slate variation will generally have difficulty using the feed sulphur correlation.
A better correlation developed by the engineers of Gulf Oil correlates coke sulphur to slurry sulphur within a power function, as shown below:
Coke S = UF * (slurry S) 1.265 (6)
The unit factor (UF) and the exponential term are typically modified to match the operating data. The Gulf correlation is often the most accurate tool for predicting coke sulphur. Unfortunately, though, the Gulf correlation does not fit the data from every unit. In these instances, the process engineer is required to investigate other correlations (multivariable linear regressions, and so on) for more accurate matching of the baseline data.
Figure 2 demonstrates graphically how two separate units were able to correlate flue gas SOx emissions extremely well using the Gulf correlation. In Figure 1, the feed sulphur correlation has a variation of up to 200 ppm, while the Gulf correlation in Figure 2 has a variation of approximately 10 ppm.
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