Profitably complying with red ii: A q&a with shell biofuel technology specialists (ERTC)

Though it may be tempting to see the EU’s revised renewable energy directive (RED II) as simply another legislative burden, this conversation with Shell domain experts highlights that there is substantial business value to be won – or lost – according to how and when refiners respond.

Amit Kelkar and Bart Suijkerbuijk
Shell Catalysts & Technologies

Viewed : 492

Article Summary

Though it may be tempting to see the EU’s revised renewable energy directive (RED II) as simply another legislative burden, this conversation with Shell domain experts highlights that there is substantial business value to be won – or lost – according to how and when refiners respond.

Amit and Bart, right now, refiners will recognise the need to comply with RED II, but may be reluctant to invest significant capital. What is the easiest compliance option?

Amit: For most, the easiest will be co-processing. They can add up to 10% renewable feedstock to an existing hydroprocessing unit, often without any capex. There are some risks to manage, but this is a well-established technique; EU refiners have been doing it for a few years.

Bart: Yes, and in today’s new reality, with many refineries running below the severity that they were designed for, it should be quite straightforward to use this spare capacity to process renewable feeds. We are seeing a lot of interest in this.

And is 10% the maximum amount of renewable feedstock that they could co-process?

Amit: Well, the exact percentage depends on the capability of the specific unit, but generally we find that up to 10% co-processing is possible without significant capex. Beyond 10% will likely involve investment to, for example, debottleneck the fresh gas compressor.

You mentioned that there are risks to manage. What are they?

Amit: A renewable feed can affect unit operation in several ways. Hydrogen consumption and heat release will increase, for example, and there are the risks of increased corrosion and fouling. Also, there may be greater difficulty with blending in the diesel pool because of degradation of the cold flow properties. It is vital to identify all the risks for a specific unit, but mitigation measures are well established.

What about as the RED II targets become more onerous in the future (Figure 1)?

Amit: Indeed, at some point, refiners will likely need to build a dedicated unit capable of processing 100% biofeeds.

Bart: It is worth emphasising that, although many companies will be inclined to delay major investments for as long as possible, there may be a significant upside for the early adopters that invest in new units, as biofuels have a much higher market value than conventional diesel. So, expect some refiners to not only produce the minimum to secure compliance, but also to produce an excess to trade.

There is also the matter of feed supply. Growing demand for renewable feeds is likely to cause price increases and, therefore, to skew the economics, but the early adopters may be able to secure long-term deals.

RED II sets different targets according to the type of feedstock. Annex IX Part B feeds such as used cooking oil are currently more common, but RED II intends to constrain those and drive up the use of Annex IX Part A feeds, including inedible crops and forestry products. What does that mean for refiners’ road maps?

Amit: That is right, and it may require a different technology to process each type, so it is really important that refiners plan carefully to avoid regret investment.

At Shell Catalysts & Technologies, we are busy commercialising multiple biofuel technologies, the most appropriate of which for European refiners right now is probably the Shell Renewable Refining Process. This is a hydroprocessing technology that can process a wide range of biofeeds and produce renewable diesel and jet fuels.

Bart: Yes, it can currently process Annex IX Part B feeds and we are undertaking substantial R&D to enable it to process Annex IX Part A feeds in the future.

As an owner–operator, Shell has a vested interest in making it happen, as we want our units to remain full in the future. Moreover, operating the technology at our own sites will provide valuable real-world insights that will help those R&D programmes.

It means that refiners could deploy the Shell Renewable Refining Process to capture the economic benefits of the Annex IX Part B feeds immediately and then, when RED II mandates that refiners must process Annex IX Part A feeds, its operating window may have been further enhanced to handle these too.

Furthermore, there is another option for the Annex IX Part A feeds: IH², which is another of our technologies. It is still in development, but it will be able to process non-food organic waste such as forestry and agricultural residues. Crucially, though, this would not require a double investment, as there are significant equipment overlaps between the two technologies.

In these capital-constrained times, won’t a dedicated unit be out of reach for some refiners?

Amit: Perhaps, which is why co-processing is a good place to start. The cash it generates can fund the dedicated unit required in the future. There is also the option of equity sharing and offtake deals to explore: sharing the business risk with other downstream companies that are keen to reduce carbon dioxide emissions.

Bart: It is a good point. Broadly speaking, refiners have three decarbonisation pathways: improve the energy efficiency of their facilities, carbon capture and storage, or make lower carbon energy products such as biofuels.

In fact, they are probably going to need all three, but the last option gives the biggest bang for your buck: some 85% of the greenhouse gas emissions associated with an energy product come from the product’s end use – consumers driving their cars, for example. So, a biofuels investment may be particularly attractive to businesses keen to reduce their overall carbon footprint.
Many thanks Amit and Bart. Is there anything you would like to emphasise as a takeaway?

Amit: Thank you. I would like to emphasise how important co-processing could be for a refiner’s biofuels road map. It is a low-capex option and can potentially help to ‘bridge the gap’: to comply with RED II in the short term before building dedicated units for 100% renewable feeds in the future.

Bart: Clearly, European refiners are operating in a particularly challenging business environment. It was difficult before the Covid-19 pandemic, with long-term demand for gasoline and diesel forecast to decline, IMO 2020, and so on. But the need to protect your competitive position by investing in margin-improvement projects remains high.

So I would like to stress that those refiners that invest soon in biofuel production capacity could reap the rewards. The sooner you invest, the sooner you could be generating revenues from these higher value products. You could also secure long-term access to renewable feeds and benefit from feed price advantages.

This short article originally appeared in the 2020 ERTC Newspaper, produced by PTQ / DigitalRefining.

You can view the digital issue here - https://online.flippingbook.com/view/1029582


Add your rating:

Current Rating: 1

Your rate:

  • Responsive image Be future forward
  • Responsive image FluegasExact 2700 effective combustion analysis
  • Responsive image FCC catalysts & additives
  • Responsive image Distillation Experts Conclave
  • Responsive image Processing heavy canadian crude
  • Responsive image Process burners
  • Responsive image Axens on Youtube
  • Responsive image SSX™ Technology
  • Responsive image Oil and gas water treatment applications
  • Responsive image Ball valves for pipelines and refineries
  • Responsive image Jet mixers for tank mixing and blending