Going for green
Heide Refinery has ambitious plans for green hydrogen, starting with replacing grey hydrogen in the production of its fuels and in the local chemicals industry
CEO Juergen Wollschlaeger sees a big role for Heide Refinery in Germany’s transition towards a hydrogen economy. The historic oil refinery, which can trace its routes back to 1856, is set to become a leading player in utilising renewable power to create green hydrogen.
Nestled amid Germany’s renewables industry and surrounded by potential offtakers in the chemicals industry in the northern part of the country above Hamburg, it is perfectly placed geographically to nurture the fledgling industry.
But this may be just the beginning. Industry association the Hydrogen Council predicts that the global hydrogen market could increase tenfold by 2050.
Wollschlaeger has been in the downstream oil and gas industry for nearly 20 years. Before taking the lead role at Heide Refinery at the beginning of 2013, he worked for OMV and, earlier, BP.
How is Heide Refinery approaching the energy transition?
Wollschlaeger: We started really looking into it three or four years ago, understanding how it could renew our business strategy. Being an oil refinery, we considered how our future would look and how we needed to change.
We have been working with hydrogen for decades in the production of fuels, to upgrade products and ensure specifications for diesel and gasoline. We operate a hydrogen pipeline connecting us with Brunsbuttel—where a number of consumers form a sizeable part of the chemical industry—and own a couple of salt caverns on-site that are suitable to store hydrogen.
We are located in a nice spot, in the heart of the German renewables industry, surrounded by substantial capacity for renewable wind turbine energy. These factors are very suitable for producing green hydrogen.
How are you seeking to develop green hydrogen?
Wollschlaeger: We have embarked on two projects. The first is an R&D project called Kerosyn 100, involving advanced technology to transform green hydrogen and CO₂ into synthetic kerosene.
We are looking into a new synthesis process based on methanol that provides a substantial yield of kerosene. The challenge is bringing the yield, currently 40-50pc of kerosene, up to 80-90 pc. We plan to build a small pilot plant at the refinery.
Our second project is much larger, called Westkuste 100. At the heart of the project is a 30MW electrolysis unit, three times the size of the biggest current one in Cologne.
Electrolysis obviously turns electricity into hydrogen, oxygen and heat. We are looking to already-installed wind turbine capacity for the electricity. Approximately 40pc of the electricity produced in the region is curtailed—attracting compensation payments of €320-350mn/yr ($353-386mn/yr)—and we want to tap into this.
In the first phase, we would replace grey hydrogen used in our refinery with green hydrogen. Later on—and this is where the projects come together—we would combine this hydrogen with CO₂ to create synthetic kerosene. The heat [from the electrolysis] would go into a local network.
700MW — Planned electrolysis capacity for Westkuste 100
The oxygen would go to a nearby cement factory, which [Swiss building materials company] Holcim operates halfway between us and Hamburg. It is very interested in pure oxygen for its furnace—it means the furnace could be much smaller and more efficient. The plant’s exhaust stack would then contain, pure CO₂, which we would offtake and form with the hydrogen to create synthetic fuel in Kerosyn 100.
Our vision for the entire project, in something like 10 years, is to scale it up to 700MW. We would then be able to fully decarbonise the Holcim cement factory, reducing CO₂ emissions by 1mn t/yr.
Could local demand for hydrogen be expanded to create a wider ecosystem?
Wollschlaeger: The idea that hydrogen is like a Swiss Army knife very nicely describes it, capturing its versatility and how it can apply to many different sectors. We are working on side projects, including taking hydrogen into the city of Heide to replace natural gas for heating. A small hydrogen pipeline would be built along with a filling station. Such complementary projects ultimately aim to build up a hydrogen ecosystem that taps into as many sectors as possible. At this stage, it is very difficult to say which sectors are the most promising.
To what extent do the economics of the projects rely on government support? Once scaled up, could they compete in an open market?
Wollschlaeger: Clearly, our project only flies with state support. However, it is designed so it only requires help at the beginning, during the investment phase. Once up and running, we aim to break even.
Westkuste 100 is based on a subsidy scheme called Reallabor. The German government wants to support technology that is missing only the last step before it can take off and be implemented on a large scale, referred to as ‘technology readiness level eight or nine’. We submitted a proposal to the Federal Ministry for Economic Affairs and Energy last year—from more than 100 ours was among 20 shortlisted. We submitted a more detailed plan in April and are expecting feedback by August.
At the beginning, there was a debate with electrolysis unit manufacturers about who would take the technological risk. I did not want to buy it because, at the moment of buying, it is already outdated. They were also asking for the full market price but wanted access to the unit and its data. I asked if there could be a middle way, but we could not cut this Gordian knot. With government involvement, there is now a third party willing to carry the technology risk, so we could proceed.
The overall project depends on many component parts. Where are problems most likely to emerge?
Wollschlaeger: The problem is more of economics, in two areas. The first is that—despite high curtailment rates—we would have to pay the market price for electricity. Regulatory change is needed to ensure that we can tap into this excess electricity.
The second problem is that there is no mechanism to account for its green attribute—no premium is available. One mechanism could use Renewable Energy Directive II (RED II), which has passed at the EU level but needs to be translated into German legislation. This would create an obligation for refineries to consider alternative fuels—such as hydrogen or biofuels for the production of [synthetic] fossil fuels—and we could get a green credit.
Is Germany’s National Hydrogen Plan now settled?
Wollschlaeger: There are still two opinions. The initial draft was more technologically open-minded, trying to set a level playing field for hydrogen. The current draft seems to have a problem with turning electricity into hydrogen and favours utilising electricity directly. I believe ideas need to compete and the best should win. A hydrogen solution will be best in some cases and an electric one in others—at the moment, it is very difficult to determine.
Is a consensus forming around green hydrogen? Or do others argue for blue hydrogen, based on natural gas and carbon capture and storage (CCS)?
Wollschlaeger: We have blue, grey, green and recently even turquoise. It sounds ridiculous, and all these colours do not do anyone any favours. There is a good logic behind green hydrogen. From a decarbonisation perspective, it is very defendable. If we put in a lot of effort, green hydrogen would quickly become cost-competitive.
Does the oil price crash affect the economics of hydrogen—in terms of the relative cost of feedstocks and electricity, as well as competition for hydrogen against other fuels?
Wollschlaeger: It depends on how long this period lasts. The hydrogen price is very much a function of the natural gas price, as it is the main feedstock [for blue and grey hydrogen]. Lower gas prices would mean that green hydrogen has to become even more cost-competitive.
We need to account for the environmental impact, which is where a green premium should play a role. I compare it to the German wind industry. At the beginning, you could argue about its commercial attractiveness, but now wind farms easily work without subsidies or support.
Does it make more sense to create hydrogen near sources of demand or near to plentiful renewable energy?
Wollschlaeger: Renewable energy technology is readily and cheaply available, and there is huge potential for offshore wind in the North Sea and solar in the Sahara. There are many sparsely populated areas suitable for large-scale renewable energy around the world, to provide electricity for hydrogen.
Germany is self-sufficient in terms of electricity but not for all our energy—most of the energy we need to import is oil. I envisage large solar farms and electrolysis units in North Africa turning excess electricity into hydrogen and transporting it to Europe.
“Hydrogen is like a Swiss Army knife… it can apply to many different sectors”
Whether we would transport it as pure hydrogen or in a form such as ammonia or methanol, time will tell. Ammonia is transported across the globe, so tankers are available, and we can cool and liquefy hydrogen so we could transportit in LNG tankers. We can easily transport it and can tap into existing infrastructure, such as ships and offloading points.
Does it make sense, from an environmental perspective, to divert electricity in Germany to create hydrogen, when some electricity is still generated from coal?
Wollschlaeger: For our project, there is no conflict. We are in a region with a substantial excess of green electricity. The problem I see occurring is people asking how to ensure electricity is green—a certification system may need to be developed.
Our projects can help to bridge the mismatch between wind turbine generation and electricity demand, stabilising the fluctuations that are a challenge for grids. And, in molecule form, it is much easier to store vast quantities of energy over a long period of time, for example in underground caverns.
There is plenty more offshore acreage around Germany that has not been developed—but to be energy self-sufficient we would need to double electricity production [largely to replace oil demand]. In my layman’s opinion, that looks like quite a challenge.
Without the need for transportation, is hydrogen as efficient as batteries for energy storage?
Wollschlaeger: I would say so. And I would even say that batteries and storing electricity in a liquid form do not necessarily compete. A battery can easily store a low amount of electricity over a short period—so if we need to buffer out fluctuations in the grid, batteries are the best choice. When storing a huge amount of energy for a long period you would go for molecules, in hydrogen.
LNG experiences big fluctuations in price when there is mismatch between supply and demand, falling when large supply projects come onstream. Can this volatile path be avoided for hydrogen?
Wollschlaeger: Once we have replaced grey hydrogen with green hydrogen, it starts to get interesting. By that time, would we have created enough additional demand? Have there been enough projects to make it cost competitive?
But first and foremost, the existing market is huge. Around 3pc of worldwide CO₂ emissions are related to hydrogen production. Hydrogen consumers just in our part of Germany—the chemical industry in Brunsbuttel is just 30km away—could absorb 1GW of installed electrolysis capacity.
How do the implementation timescales compare for green hydrogen and blue hydrogen projects?
Wollschlaeger: All things being equal, green should be faster as it is a lot simpler. You can order electrolysis units off-the-shelf. What takes most of the time is the design of the supporting systems, such as the grid connections, compressors and so forth, and we are on a learning curve. Blue hydrogen is more complex because you need to design and install CCS.
We are trying to be broad rather than big in our projects—tapping into many different sectors in order to understand what works and what does not. It is a new field and everyone is learning, so we cannot really predict which particular business models will provide the most attractive returns.