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Maximising profitability with FCC feeds from opportunity crudes

Case studies show how to achieve optimal monetisation value with opportunity feeds through operating strategies, innovative catalysts and technical stewardship.

Alexis Shackleford
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Article Summary
In today’s competitive refining landscape, refiners can take advantage of processing lower cost opportunity crudes to improve margins. Two very different types of crude may be available to refiners in North America. Light tight oil (LTO) crudes are typically light, sweet, paraffinic and have low residual content. Alternatively, heavy crudes such as oil sands derived crudes are sour, aromatic, and high in concarbon and contaminants. In the US, it is projected that by 2025 over 50% of the crude slate to refineries will be comprised of tight oils and Canadian imports.1 Whether the refinery chooses to operate with one or both types of feed, operation of the fluidised catalytic cracking (FCC) unit will encounter new challenges. Every situation is unique and requires a tailored catalyst solution.

Crude diversity
The term ‘opportunity crude’ was once used to describe contaminated or distressed cargoes. With increasing feedstock diversity in recent years, this term has become almost universally used to describe crudes such as unconventional oils, heavy crudes and high acid number crudes that can only be processed in limited quantities in most refineries. Opportunity crudes are purchased at a discount to marker crudes, presenting an advantage to those refiners that can feed a larger quantity of these challenging lower cost crudes to the refinery.

In North America, tight oils and oil sands represent significant amounts of opportunity crudes. LTO, also commonly referred to as shale oil, is oil produced from low permeability (for example, tight) rock formations. Canadian oil sand, also called tar sand, is a mixture of sand, water, clay and bitumen. Bitumen in its natural state is too viscous to transport via pipeline and is usually diluted to make diluted bitumen (or dilbit), and heavily upgraded before it enters a refinery. The amount of upgrading will determine the final crude properties.

Due to the drastically different nature of these crudes, the properties are usually at opposite ends of the spectrum. Tight oil crudes typically have high naphtha and middle distillate cuts, whereas oil sands have low naphtha and middle distillate fractions. Tight oils contain almost no vacuum resid, where oil sands contain high amounts of resid. The vacuum gas oil (VGO) properties of several crudes are compared in Table 1.2 The table compares two tight oils, Texas Shale and Bakken, with two oil sands, Wabasca and Cold Lake, to two conventional crudes, West Texas Intermediate (WTI) (light and sweet) and Maya (heavy and sour). The light API gravity and paraffinic nature of tight oil VGO cuts is similar to WTI and means it is easily converted to gasoline and lighter products. The tight oils contain low amounts of the typical contaminant metals nickel (Ni) and vanadium (V), but can contain higher amounts of calcium (Ca), sodium (Na) and iron (Fe) compared with WTI. The lower sulphur content of these feeds gives lower gasoline sulphur and SOx emissions. For oil sands, the degree of upgrading before the refinery will affect the quality of the feed. Oil sands that are not upgraded are highly aromatic with low API gravity. These feeds are difficult to convert to gasoline and lighter products. They contain high amounts of contaminants including Ni, V and Fe. The high amounts of concarbon and contaminants make these feeds high delta coke producing feeds. They also contain high sulphur, which makes it more difficult to meet environmental regulations.
Operating with tight oils
When operating with tight oil feeds, refiners will have to deal with new challenges.3 The challenges facing FCC units processing these crudes are different depending on the specific unit operation. Some units need to manage high amounts of liquefied petroleum gas (LPG), maintaining a stable heat balance, higher alkali metals, increased Fe loadings, and reduced feed rates. In other units, the low VGO content of tight oil leads to a shortage of feed to the FCC unit. To keep the FCC unit fully utilised, refiners need to purchase VGO feedstock or introduce residue feedstock into the unit.

Tight oil quality varies between oil fields, and has been shown to be highly variable even from the same field. Batch shipping of these crudes by trucks and by rail increases this variability. The higher naphtha and distillate yields of tight oil can flood the crude column, limiting crude rates. Lower sulphur will alleviate sulphur constraints across the refinery. The high yield of naphtha, which is also more paraffinic, can cause the refinery to be octane constrained and is addressed by maximising alkylate production, increasing reforming severity, and placing higher emphasis on FCC gasoline octane. With the low resid content of the crude, refiners may consider shutting down the resid processing unit and feeding the resid directly to the FCC unit.

Maintaining heat balance is normally the main challenge for refineries processing LTO. Low coke producing feeds cause low regenerator temperatures and result in catalyst circulation constraints. With lower coke yield, verify that the air blower is rated for the lower air requirement and the pressure drop across the air grid is maintained. The minimum regenerator temperature is set by maintaining efficient coke burn, typically 1250-1260°F. Operating moves to increase bed temperature include using a CO promoter to reduce afterburn, reducing partial burn or going into full burn, increasing feed preheat, and using oxygen injection. Increasing delta coke through increasing heavy cycle oil/slurry recycle (nozzle erosion may be a concern), lowering the FCC feed hydrotreater severity (if an option), and feeding more resid to the unit will lead to increased bed temperatures.

Catalyst solutions to increase delta coke include higher equilibrium catalyst (E-cat) activity through higher additions, higher rare earth content or changing to a less coke selective catalyst. If the unit cannot maintain heat balance, some less desirable options to investigate are turning on the air preheater, adding torch oil and reducing dispersion or stripping steam. The air heater and air grid designs need to be reviewed to avoid damage when operating outside of start-up. Adding torch oil and reducing dispersion or stripping steam cause the negative impacts of higher catalyst deactivation rates and burning higher valued products over coke. Another concern with low regenerator bed temperature is the unit may become circulation limited due to slide valve pressure drop. To reduce the catalyst circulation, increase feed preheat, which has the added benefit of increasing the liquid yield due to less coke production. If the unit has a fuel gas-fired heater, operating at higher preheat temperatures also has the economic benefit of burning lower cost natural gas over burning coke with current economics. Changes in catalyst bed heights may provide small benefits. A long-term option is to change out the slide valve port size to remove the slide valve pressure drop constraint.

Due to the paraffinic nature of tight oils, they produce low octane straight-run naphtha and low octane naphtha from the FCC unit. Catalyst changes to increase octane include reformulating to a lower rare earth catalyst, which increases the gasoline octane but offsets the heat balance. Also consider using a ZSM-5 additive to increase the gasoline octane up to the wet gas compressor limit.    

Operations with oil sands
Operations with oil sands crude depend highly on how much upgrading was done prior to the FCC unit. Some locations hydrotreat these materials, making them far easier to process. For units that do not hydrotreat, the issues are around the types of hydrocarbon molecules charged to the riser 
and the contaminant materials contained in the oils. The hydrocarbon molecules will boil at a higher temperature than standard FCC unit feedstocks, and may be more aromatic. The FCC unit is a vapour phase process, requiring vaporisation of as many of the molecules coming into the riser as possible. Ensure proper feed vaporisation by adjusting steam injection or other diluents to drop the partial pressure of the hydrocarbon to get vaporisation. Another consideration is adjusting the mix zone temperature at the bottom of the riser to ensure maximum feed vaporisation. The feed that does not vaporise will ultimately go to the regenerator and be combusted, resulting in inefficient and uneconomical operation.
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