Mild hydrocracking of FCC feeds yields more fuels, boosts margins

June 10, 2002
Mild hydrocracking (MHC) provides a profitable minimum-investment route to achieve incremental vacuum gas oil (VGO) conversion while producing high quality, low-sulfur fuels from FCC units.

Mild hydrocracking (MHC) provides a profitable minimum-investment route to achieve incremental vacuum gas oil (VGO) conversion while producing high quality, low-sulfur fuels from FCC units.

Refiners with VGO hydrotreating units can retrofit their units for MHC operations with little investment to maximize refinery margins. Refiners without any FCC feed pretreatment should consider investing in an MHC unit instead of hydrocracker.

Investments for retrofitting existing VGO hydrotreaters or building new MHC units readily pay out, given increased conversion to valuable fuels and superior product quality.

FCC product quality

Refiners blend FCC naphtha and cycle oils with other refinery streams to produce gasoline and diesel fuels. FCC units contribute about 30-40% of the total gasoline pool.

The FCC gasoline fraction, however, contributes 90-99% of the total gasoline pool sulfur content.1 FCC gasoline typically contains 2,000-2,500 ppm sulfur when processing a VGO with a sulfur content of around 2.0 wt %.

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FCC gasoline sulfur increases proportionately with feed sulfur content. As a rule of thumb, sulfur in FCC gasoline is about 10% of that in the FCC feed.

Cycle oils produced from an FCC unit can contribute up to 25% of the refinery diesel pool. Cycle oils with high sulfur and aromatics content pose serious limitations for blending with the diesel pool.

About 30% of feed sulfur concentrates in FCC cycle oils. For example, if the feed contains 20,000 ppm of sulfur, about 6,000 ppm will go to cycle oil fraction, which constitutes about 30,000 ppm in cycle oils, assuming a 20% yield.

Treatment options

Treating the feedstock or product streams from an FCC can lower a fuel's sulfur content. With pretreatment, a typical vacuum distillate hydrodesulfurizer reduces sulfur, nitrogen, and aromatics in the FCC feed.

FCC feed pretreatment is more cost effective for reducing sulfur in naphtha and diesel products. Adding hydrogen to the FCC feed can increase conversion and light distillate yield due to increased saturates content. Feed pretreatment can also reduce coke yield by saturating the polyaromatic hydrocarbons to decrease the coke precursors.

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About 90-95% of the feed sulfur is removed; resulting products from FCC unit are low in sulfur. Another benefit of increased conversion due to pretreatment is lower light cycle oil (LCO) production. LCO degrades diesel pool quality.2

Hydrotreating the FCC feed can also decrease clarified oil yield due to added hydrogen. A significant benefit with additional hydrogen in the feed is a shift in yield pattern, which gives higher production of transportation fuel and decreased production of fuel oil and coke.

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Several post-treatment technologies are based on hydrodesulfurization (HDS), fractionation, catalytic distillation, and adsorption. Besides these, posttreatment requires multiple process options-naphtha treating, LCO treating, and flue gas treating-to control SOx emissions.

Product treatment, however, offers no yield benefits. Olefin saturation and the resultant octane loss is critical when a refiner hydrodesulfurizes FCC naphtha.

Hydroprocessing FCC feed

Many available hydrogen-addition options will improve FCC feed quality. A low-investment option is the conventional HDS process that uses a cobalt-molybdenum or nickel-molybdenum catalyst and operates under moderate process conditions. This is the most widely used FCC pretreatment option.

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Although this option improves FCC feed quality to a great extent, it does not produce any additional fuels. Severe operating conditions are needed to produce quality FCC products due to changing product specifications. High-severity conditions result in shorter run lengths, require frequent catalyst changeouts, and make the option uneconomical.

Unconverted oils from hydrocrackers are an excellent feedstock for FCC units because they have low sulfur, nitrogen, aromatics, metals and carbon residues. This option improves FCC feed quality and also produces required additional fuels.

Conventional hydrocracking processes are designed and operated for pressures around 150-170 bar. This leads to high investment costs due to high-pressure equipment. Operating costs are also higher due to high hydrogen production and compression costs and utility requirements.

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Refiners with hydrocracker facilities can readily use this option. Installing a dedicated hydrocracker unit to feed an FCC unit is cost intensive and economically unattractive.

Refiners have tried to convert existing VGO hydrotreating units into MHC units because high-conversion hydrocracking units are expensive. MHC units use moderate operating conditions compared to conventional hydrocrackers. Operating at lower pressures significantly reduces capital investment and operating costs.

The MHC unit operates at 50-100 bar pressure, 340-425° C. reactor temperature, and 350-1,000 volumetric H2-oil ratios. Existing VGO hydrotreating units operate in this range and can easily convert to MHC operations.

Specially designed acidic MHC catalysts combined with changes in operating strategy will allow the conversion of a hydrotreater to MHC. Production of low-boiling hydrocarbons in an MHC produces additional fuels and improves the FCC feed quality.

Figs. 1 and 2 show flow diagrams for hydroprocessing and MHC.

MHC vs. hydrotreating

Table 1 shows the properties of MHC pilot plant feedstocks. VGO sulfur content varies widely and generally depends on crude source. MHC pilot plant testing resulted in 14.2 wt % and 19.2 wt % conversion to 370° C. products at an operating pressure of 60 bar and 100 bar, respectively.

Table 2 shows MHC conversions and properties of unconverted VGO. Unconverted VGO had a sulfur content of 110 ppm at an operating pressure of 100 bar indicating 96.2 wt % HDS for low-sulfur VGO case. Other VGO feeds gave similar HDS levels.

Lower density and aromatic levels in unconverted VGO indicate significant hydrogen addition during the MHC step. Naphtha produced from an MHC pilot plant had a sulfur content of less than 100 ppm for the high-sulfur VGO feed. The middle distillate fraction (140-370° C.) had a sulfur content of 500 ppm. With low sulfur levels, these MHC fractions can easily blend with other refinery streams to produce high-quality fuels.

Table 3 presents data on micro-activity test conversions and yields from cracking VGO over FCC equilibrium catalyst for different options.

We compared FCC performance with hydrotreated VGO and MHC VGO vs. untreated VGO. Cracking hydrotreated VGO resulted in 52 wt % conversion to 216°- C. products compared to 51 wt % for the untreated case.

Table 3 also presents data on the conversion of 370°+ C. fraction, separated from MHC unconverted oil derived at an operating pressure of 60 bar and 100 bar.

We obtained 53 wt % and 55 wt % conversions to 216°- C. products for MHC cases. Unconverted oil from the MHC resulted in higher FCC conversions due to more hydrogen in the feed.

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Removing nitrogen (especially basic) from the feed also contributed to higher FCC conversions. FCC products should have low sulfur levels because more than 95 wt % of the sulfur was removed during MHC step.

A low-sulfur FCC feed can also reduce SOx emissions from the FCC regenerator, which helps meet emission standards.

Table 3 shows that the FCC yield pattern shifts towards more fuels and less coke and residue during use of hydrotreated or MHC feed.

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Fig. 3 presents integrated product yields from HDT-FCC and MHC-FCC combinations. Overall yields based on fresh VGO feed also shift towards more gasoline and diesel compared to the untreated case.

Incremental yields,revenue benefits

Table 4 shows an economic analysis of the different options. We based our estimates on a refinery with a 22,000-b/sd FCC unit with 340 days on stream time. We assumed that additional VGO is available for upgrading to higher value fuels.

Calculations are based on tariff-adjusted import parity prices in India for April 2002. We also assumed that the VGO, if not upgraded, is used for fuel oil blending.

VGO hydrotreating generates additional annual revenues of $5.5 million compared to untreated case. MHC of VGO at 100 bar and feeding 370°+ C. to the FCC unit results in additional annual revenues of $10.9 million compared to untreated case.

These benefits arise because up to 20% more VGO can be upgraded to valuable fuels through MHC route. For a refinery with a larger FCC unit, the potential benefits will be much higher.

References

  1. Debuisschert, Q., and Nocca, J.-L., "Benzene and sulfur reduction strategies for the gasoline pool," XI Refinery Technology Meeting, Feb. 9-11, 2000, Hyderabad, India.
  2. Shorey, S.W., Lomas, D.A., and Keesom, W.H., "Use FCC feed pretreating methods to remove sulfur," Hydrocarbon Processing, November 1999, pp. 43-51.

The authors

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M. Bhaskar is a manager at the research and development center of Chennai Petroleum Corp. Ltd., Chennai, India. Bhaskar holds a B.Tech. in chemical engineering from Andhra University College of Engineering, Vizag, India, and an M.Tech. in petroleum refining and petrochemicals from Anna University, Chennai.

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G. Valavarasu is a senior engineer at the research and development center of Chennai Petroleum. He holds a B.Tech. in chemical engineering from Coimbatore Institute of Technology, Coimbatore, India, and an M.Tech. in petroleum refining and petrochemicals from Anna University, Chennai.

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K.S. Balaraman is general manager at the research and development center of Chennai Petroleum. Balaraman holds a MS from the Indian Institute of Technology, Madras, and a PhD from the Indian Institute of Technology, Bombay. He is a life member of Indian Institute of Chemical Engineers, India.

Fuel-quality trends

Refiners are facing dual challenges of more stringent environmental regulations and changing product demand patterns. Countries are enacting new regulations to improve automotive fuel quality.

Changing diesel fuel specifications will demand lower sulfur and higher cetane numbers. The most common worldwide diesel sulfur specification is 500 ppm. Many countries, however, are revising this sulfur specification to comply with the newer environmental regulations.

The US Environmental Protection Agency (EPA) has proposed a diesel sulfur target of 15 ppm by 2006. The European Union (EU) similarly indicated a specification of 50 ppm by 2005. Other countries are also contemplating sulfur specifications in-line with US and EU.

Countries are also upgrading gasoline quality with respect to sulfur, aromatics, benzene, etc. Similar to EPA regulations, the maximum gasoline sulfur content will be restricted to a maximum of 80 ppm in 2005.

Automotive fuel demand will maintain steady growth. Demand projections for refined products indicate that middle distillates grow at the highest rate. Worldwide diesel fuel demand will experience annual growth of 2.3%.1 In contrast, the demand for fuel oil will decline.

Refiners are evaluating different process options and optimizing resources to maximize fuels that meet revised specifications and reduce the bottom of the barrel.

The FCC unit allows refiners to maximize yield of fuels and convert bottoms. In view of the changing scenario, refiners must carefully consider FCC products as part of their sulfur management strategies.

Reference

  1. Chen, Q., van den Oosterkamp, P., and Barendregt, S., "Upgrading gasoils by mild hydrocracking," Petroleum Technology Quarterly, June 1999.