Figure 1: Marine sulphur regulations. The allowable sulphur level in marine fuel oil in emission control areas (ECA) was reduced to 0.1% in 2015; the global cap will be cut to 0.5% in 2020.
Figure 1: Marine sulphur regulations. The allowable sulphur level in marine fuel oil in emission control areas (ECA) was reduced to 0.1% in 2015; the global cap will be cut to 0.5% in 2020.

The impending shift from 3.5 to 0.5% maximum sulphur specifications for marine bunker fuels means that refiners must conduct a thorough evaluation of their conversion and desulphurisation capacity. Many will need to add costly new units to their configurations. What are the technology options and how do they compare?

One of the most profound investment issues facing refiners is the so-called bunker fuels challenge, which will tighten the global cap on the maximum sulphur content of marine fuel oil from 3.5 to 0.5% (Figure 1). The International Maritime Organization recently clarified the timeline for this shift: having considered delaying the new specification until 2025, the organisation decided in October 2016 to impose it at the earliest opportunity: January 2020.

With the introduction of the 0.5% sulphur limit, it will only be possible for ships to continue using marine fuel oil with 3.5% sulphur if they are fitted with on-board scrubbers. It is not clear how many ships will invest in this technology but there could be a large reduction in demand for 3.5%-sulphur marine fuel oil, with a corresponding increase in demand for 0.5%-sulphur marine fuel oil.

In addition, there appears to be limited likelihood of other sectors, such as onshore power generation, taking up the slack for 3.5%-sulphur marine fuel oil.

Adapting to changes in product specifications, market demand and emissions regulations is nothing new for refiners, but this is an unprecedented shift and most refiners will struggle to produce sufficient niche low-sulphur blend  stock to make 0.5%-sulphur marine fuel oil. Although some refiners are already tooling up by planning or implementing residue conversion projects  that will reduce their exposure to the fuel oil market and increase their competitiveness, few have taken the decision to invest in structurally moving away from  making high-sulphur marine bunker fuel.

There is a wide range of residue conversion technologies for refiners to consider and they should base their decision on their specific circumstances, so, in this article, we review some of the leading technology choices.

Delayed Coking

Delayed coking has long been considered the industry-standard approach for residue conversion, usually in combination with hydrocracking. It is one of the lower capital cost options.

This technology produces significant amounts of coke: about 1.3 times the Conradson carbon residue (CCR) content of the feed. If petroleum coke (petcoke) production is targeted, delayed coking offers high crude flexibility. However, petcoke has a low, coal-related value. Higher-value, anode-grade coke can also be produced, although that restricts crude flexibility.

Figure 2: A comparison between historical LH differential versus crude price and break-even economics for a delayed coker.
Figure 2: A comparison between historical LH differential versus crude price and break-even economics for a delayed coker.

As an investment, delayed coking is highly dependent on the crude price: as this increases, the required light–heavy (LH) differential1 for breaking even increases. Historically, the LH differential has been above the break-even point for coker operation, but not necessarily high enough to support some companies’ required investment criteria (Figure 2).
1Defined as 50% gasoline/50% diesel – HSFO price.

Refiners considering the introduction of a coker should always pay special attention to the interfaces with the rest of the refinery. For example, the coker must integrate with the hydrocracker (or other downstream conversion unit) and the hydrotreaters, where capacity can sometimes be a constraint.


Flexicoking enables the in-situ coke to be turned into power. It generally requires major rework of the site’s utilities requirements and fuel and utilities consumption, which can affect the total capital investment requirements.

The process enables petcoke to be valued at natural gas equivalent, which is attractive in some locations, although it can significantly conflict with some companies’ carbon footprint aspirations.

Solvent Deasphalting (SDA) And Deasphalted Oil (DAO) Hydrocracking

The combination of SDA and DAO hydrocracking offers one of the lowest capital cost options for residue conversion, especially compared with slurry bed hydrocracking. The allowable extraction depth is crude dependent.

Although this combination is considered a relatively new option, it has been applied at several sites over the last decade. Traditionally, DAO had to be processed in a fluidised catalytic cracking unit because of its high metals and CCR content, but can now be processed in a hydrocracker with a modern, well-designed catalyst system with a demetallisation catalyst followed by pretreat and cracking catalysts.

Meanwhile, some refiners are converting their existing residue desulphurisation units to mild hydrocrackers and combining mild hydrocracking with SDA. Depending on the site’s existing assets and the markets it serves, this can be a highly attractive option. For more on this, see Converting a reside desulphurisation unit to a DAO hydrocracker.


Gasification can process highly viscous residues, including residues that cannot be blended back to stable fuel oil (such as severely thermally cracked vacuum residue) if they are fed hot from the upstream process units. Although gasification has a high capital-cost intensity, it can be used to produce synthesis gas for producing chemicals, hydrogen and power, and the economics depend on the alternative pricing of these products.

For example, hydrogen could alternatively be produced using a steam methane reformer. However, this can be expensive if the natural gas price is high, as it requires 3.5 t of natural gas to produce 1 t of hydrogen. The capital cost of the steam methane reformer can also be discounted. In addition, the economic case is also enhanced because heavier, lower-value crude oils can be used; these yield a lot more residual oil but the gasification plant can handle that.

Responding to the bunker fuels challenge – key technologies at a glance

n/a Affordability High crude flexibility Conversion to transport fuels Commercial track record Exposure to fuel oil or niche market
Delayed coking Good Good Good Good No, petcoke market is liquid
Flexicoking Neutral Good Good Neutral No, power
SDA + DAO hydrocracking Excellent Neutral Good Good Yes, asphalt to fuel oil/bitumen

Ebullated-bed residue hydrocracking

Neutral Neutral Good Good Yes, unconverted material to fuel oil
Ebullated-bed residue hydrocracking + SDA Disadvantaged Good Excellent Disadvantaged Yes, bleed
Gasification Disadvantaged Good Disadvantaged Good No
Slurry-phase residue hydrocracking Disadvantaged Good Excellent Disadvantaged Yes, bleed

Slurry-Phase Residue Hydrocracking

Slurry-phase residue hydrocracking could be considered the technology of choice if maximising the yield of liquid automotive fuels while avoiding low-value products such as petroleum coke is the prime objective. Although slurry-phase residue hydrocracking is still an emerging option, its commercialisation is taking off: several licensors have developed pilot plants, one has built and operated a world-scale unit, and a handful of licences for world-scale units have been sold in the last few years.

Slurry-phase residue hydrocracking offers the promise of feed flexibility for a wide range of residue qualities and the highest achievable conversion to liquid transport fuels compared with other options.

The capital cost can be comparatively high, but in higher oil price scenarios where the preservation of liquid yield is important, the economics can be highly favourable, although slurry-phase residue hydrocracking will only produce intermediates unless it is integrated with downstream hydrotreating or hydrocracking.

Moreover, refiners need to be aware that disposing of the bleed stream can be challenging. These non-catalytic units typically use additives to prevent coke formation in the reactor. These concentrate in the unconverted material, thus restricting possible outlets for the bleed stream.

Ebullated-Bed Residue Hydrocracking

Ebullated-bed residue hydrocracking is a well-proven technology. The achievable conversion depends on the crude type, so it is less flexible than delayed coking, although some refiners are using a combination of operational and process experience with the latest-generation sediment-control catalyst technology to diversify the crude mix.

To close some of the conversion gap with slurry bed hydrocracking, licensors have licensed schemes in which an ebullated-bed residue hydrocracking unit is integrated with an SDA unit.

Key Takeaways

  • The sulphur content of marine bunker fuels will be cut from 3.5 to 0.5%, which is an unprecedented shift.
  • In response, many refiners will need to add conversion and desulphurisation capacity.
  • There are many technology options and the optimum solution for one refiner will be suboptimal for another.
  • The International Maritime Organization recently confirmed the new specifications will come into force in 2020; refiners would be well advised to begin planning their response immediately

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