On Thursday 17^th March at 12.30CET our latest Energy Post panel, “Unlocking the potential of bioenergy” boasts representatives from two of the most challenging areas for decarbonisation: the cement and aviation industries. Taking part are  Winston Beck, Head of Government Affairs at HeidelbergCement and Laurent Donceel, Senior Policy Director at Airlines for Europe. They will be joined by Thomas Meth, Chief Commercial Officer at Enviva (event sponsor) and IRENA, whose World Energy Transition Outlook is due out later this month. IRENA will be represented by Dr. Ricardo Gorini, a Transition scenario expert who will present a sneak peek at the as-yet-unpublished chapter on bioenergy. You can register for the event here. And in the Biomass for Industrial Heat report published by IEA Bioenergy in December, bioenergy expert Olle Olsson, team-lead at the Swedish Environment Institute and his co-authors focused on three groups of technologies: CCS (carbon capture and sequestration), electrification and hydrogen, that need to be understood before coming specifically to the role of biomass. Here is the report’s overview…

Introduction

Most industrial process heat is currently provided by fossil energy, especially for higher temperatures above 500°C where fossil fuels dominate completely. As economies and demand grows it becomes more and more of a potential barrier to achieving net-zero emissions by 2050. Recent years have seen a diverse range of studies emerging on the different options – whether available or in development – that could enable shifts to fossil-free industrial heat processes. So when looking at the role that biomass could play, the discussion should be set in context by acknowledging and reviewing the bigger picture revealing all the alternatives.

Biomass-based process heat in industrial sectors

As is the case for electricity-based process heat, biomass-based process heat can come in many forms. Not only is there great heterogeneity when it comes to the different forms of biomass feedstock, depending on the pre-processing, the biomass can be turned into several different fuels that can be solid, liquid or gaseous. These can vary substantially in energy density, combustion properties and logistic characteristics. For example, wood chips can either be burned directly or after having gone through torrefaction. Alternatively, the wood chips could perhaps have been gasified to produce hydrogen, processed further into bio-methane or used to produce pyrolysis oil (Friedmann et al. 2019; Rehfeldt et al. 2020).

This means that biomass-based options can in principle fulfil the process heat needs of most industrial use cases (Malico et al. 2019), but the specific nature of the process and the industry in question will determine what kind of biomass-based process is applicable. For example, glass and ceramic sectors require temperatures above 500°C and a gaseous fuel to have clean combustion, which means that for this particular case, raw wood chips would not be feasible, but bio-methane produced from the same wood chips is a promising option at least from a technological perspective (Lenz et al. 2020). In addition to the wide range of process applications wherein biomass can be useful, an additional advantage compared to other forms of renewable process heat include the possibility to store fuels for long periods of time, although it should be mentioned that storage can be quite demanding in terms of space depending on the fuel. Another advantage of biomass is that when combined with CCS to bio-CCS or BECCS, it enables the generation of carbon dioxide removal (CDR) from the atmosphere, also referred to as negative emissions (Olsson et al. 2020).

Despite its potentially broad usability across different sectors and temperatures though, biomass is currently predominantly used for provision of process heat at temperatures around or below 200°C (see Figure 3 above). The largest volumes are concentrated in a few select sectors, especially forest industries in the form of sawmills and pulp and paper mills. As can be seen in Figure 4, almost 90% of the biomass used for industrial process heat in the EU-28 in 2017 was consumed in forest industries.

The reason why the use of biomass for process heat is so prevalent in forest industry sectors is that large amounts of biomass become available on-site as part of the key industrial processes themselves. Bark and sawdust are produced in large amounts as residues at sawmills and can be burned to produce heat used for drying of lumber. Similarly, at pulp and paper mills, residues in the form of bark and waste liquors (in Kraft mills) are burned to produce process steam as well as to generate electricity (ARENA 2019; Malico et al. 2019; Philibert 2017). By using biomass process residues, the use of fossil fuels can often be avoided. If the available residues in these sectors would not be used, an additional waste disposal problem would arise.

The “non-metallic minerals” sector referred to in Figure 4 is predominantly made up by the cement sector, which for decades has used different forms of solid waste materials, a portion of which are of biogenic origin, to replace fossil fuels in the form of e.g., coal and petroleum coke (Lenz et al. 2020).

The use of biomass in cement production is a practical example of an exception to the otherwise dominating pattern that biomass is used for relatively low temperatures and in forest industry sectors. Some argue that there is somewhat of a lost opportunity here, in that instead of being used to produce heat at temperatures where electricity-based options such as heat pumps could work, biomass should be used for purposes where other options are scarce (Lenz et al. 2020; Material Economics 2021). Leaving aside if/how this ambition should be supported, a key question that remains is whether and how biomass process heat can be made use of in other sectors. One challenge is that it is difficult to make general statements as biomass prices can vary widely between different locations. Material Economics (2021) note that in places where biomass can be made available at costs of 2-4 €/GJ, it can be quite competitive. However, actual costs for larger volumes can often be more in the order of 6-8 €/GJ, which makes for a quite substantial barrier to competitiveness. In addition, Malico et al (2019) identify high investment costs, feedstock availability and security of supply as key obstacles to uptake of biomass-based process heat in non-forest industry sectors.

Carbon Capture and Sequestration

As mentioned, the role of biomass needs to be considered alongside all available emissions mitigation technologies. One of the seemingly most straightforward ways of enabling deep emissions cuts is to maintain existing industrial processes and fuels but capture the CO2 emissions and sequester these in geological formations. CO2 capture and injection in geological formations are not new phenomena as such, as they have been implemented commercially for decades in e.g., the oil & gas sector, but the particularities of deployment vary quite substantially from sector to sector. This pertains both to the technological aspects of CO2 capture, transport and storage, and to the market and policy context in question.

For the actual CO2 capture, a few factors are especially important when it comes to determining the feasibility and techno-economic viability. A key issue is the composition of the CO2-containing gas stream, where the CO2 concentration is the central parameter – a higher CO2 concentration typically means less energy is needed to separate out the CO2 which can translate into lower costs of capture. A second key issue is whether the CO2 emissions at the site are concentrated in one large point source or distributed across many smaller point sources.

In this case the former is preferable and makes for lower costs, especially when it comes to achieving a high percentage of CO2 capture. Thirdly, a key factor is whether there is onsite excess energy that can be used in the capture process. Here, it should be noted that different CO2 capture processes have different requirements both in terms of the volumes needed and whether the energy demand comes in the form of electricity or heat (Olsson et al. 2020).

Depending on the geographical context, the transport and storage stages of the CCS supply chain can be set up in different ways, with pipelines and ship transport being the key options for long-distance CO2 transport. Pipelines tend to be more cost-efficient up to distances of 700-1200 km, but ship transport allows for more flexibility in that it enables many different capture sites to make use of one large storage site (Kjärstad et al. 2016), but also that ship transport makes possible more of an actual market for CO2 storage services as it might entail less of a lock-in compared to when the capture site is physically connected to the storage site via pipeline.

A drawback of CCS is that it adds substantial costs but does not always add corresponding revenue – that is, unless a specific system is in place that places value on the function of the capturing and sequestration of CO2. In other words, the commercial viability of an industry fitted with CCS rests upon the existence of an explicit or implicit price on CO2, without which a facility with CCS makes no economic sense compared to a facility without CCS. An alternative approach that is increasingly discussed is carbon capture and utilisation (CCU), which means that the captured CO2 is made use of for productive purposes. The advantage of this is that this would allow for other ways of generating revenue than through a carbon price. The drawback though is that in many CCU applications currently under discussion – including the production of fuels or chemicals from captured CO2 – carbon is locked in the product for only a relatively short time before being released into the atmosphere.

Electrification of industrial process heat

Up until around a decade ago, a common narrative in discussions on future global energy systems was that clean electricity would be expensive for the foreseeable future. Consequently, not only would deep decarbonisation be impossible without a high price on carbon – electricity would also have to be treated as a precious resource only to be used where other options were not available. However, the subsequent reductions in costs of solar and wind power have led to somewhat of a paradigm shift in narratives around the role of clean electricity in the global energy system. The last couple of years have seen the rise of a stream of thinking that can be summarised as “electrify everything” (Olsson and Bailis 2019; Roberts 2017).

There are several different ways electricity can be used to produce process heat, including resistive heating, heat pumps, microwave heating and plasma technologies (hydrogen could be seen as a form of indirect electrification if the hydrogen is produced from electrolysis, but we will nevertheless address hydrogen separately later in this article. Regardless, in addition to the possibility to benefit from decreasing costs of wind and solar power, the use of electricity as a means to produce industrial process heat comes with other potential advantages that are related to rather fundamental technological characteristics. Compared to combustion-based heating, electricity-based heating tends to be easier to control, has no local air pollution and has lower maintenance costs (Bartlett and Krupnick 2020; Rehfeldt et al. 2020).

In terms of commercial availability, electricity-based process heating is currently deployed across most temperatures and scales, with electric arc furnaces used in metals processing (e.g., steel) working at temperatures approaching 2,000°C and around 100 MW or more. However, there are in other sectors still technological aspects that limit the application of electricity-based process heating. These challenges relate especially to larger scales and very high temperatures (Rightor et al. 2020). Wiese & Baldini (2018) find that whereas it is possible to implement electric process heat in most applications below 250°C, this only applies to about 25% of demand above 250° (see also Rehfeldt et al. 2020). There are solutions for higher temperatures that could eventually become broadly applicable, e.g., plasma generation, but these are thus far limited to scales of around 5-10 MW (Burman and Engvall 2019).

When it comes to lower temperatures, one particularly valuable technology is heat pumps. These can leverage one unit of electricity into multiple units of usable heat, as measured by the so-called coefficient of performance (COP – a COP of 3 means that for every unit of electricity fed into the heat pump, 3 units of usable heat is produced) which allows more efficient use of electricity. There are industrial heat pumps available that can provide industrial process heat at temperatures up to around 90°C with some manufacturers also offering solutions that can reach temperatures around 150°C, with 200°C potentially being within reach. However, it is important to note that the performance of a heat pump is highly reliant on the heat source and the heat sink, where efficiencies decrease with larger differences between the heat source and the heat sink. This means that heat pumps are particularly useful as a means to produce process heat by raising temperature of on-site waste heat streams (Marina et al. 2021).

In terms of challenges to electrification of process heat more broadly, operational cost remains one, as the cost reductions in wind and solar power generation are not directly reflected in actual grid power prices paid by industries. In many locations, industrial electricity rates are on a per-kWh basis substantially higher than corresponding prices of natural gas, meaning that – unless a heat pump solution is possible – policy support will be needed to cover the difference in operational expenses. This then is in addition to the capital expenses needed for transition – electricity-based heating systems tend to require substantial conversion investments. For this reason, they might be more promising in greenfield rather than in brownfield settings (Bartlett and Krupnick 2020; McKinsey & Co 2018).

Industrial process heat from hydrogen

Hydrogen can be produced via several different pathways, including gasification of hydrocarbons or biomass, steam methane reforming (SMR) of natural gas, or electrolysis, where the latter entails the use of electricity to split water into hydrogen and oxygen. The vast majority of global hydrogen volumes used today are produced from fossil fuels, primarily through SMR. However, recent years’ substantial increase in the interest of how hydrogen can enable global emission reductions are largely based on anticipations of lower future costs of so-called “green hydrogen”, i.e., hydrogen produced via electrolysis powered by renewable electricity (Material Economics 2020). In addition to providing process heat, hydrogen can play several other roles in the field of industrial decarbonisation as well. This includes as a chemical component in synthetic hydrocarbon fuels and materials (e.g., Palm et al. 2016; Ueckerdt et al. 2021) and as a reducing agent in primary (primary steel is iron ore-based as opposed to secondary steel which is based on recycled steel scrap) steel production (Vogl et al. 2018).

When it comes to the use of hydrogen as a means of providing process heat, it can offer opportunities for relatively smooth integration into, or replacement of, process heat systems based on fossil gases such as natural gas or LPG (liquid petroleum gas). Hydrogen is also a gas and can provide very high temperatures. However, retrofitting existing gas-based heating systems to work with hydrogen does come with several caveats. Not only is hydrogen transport and storage more difficult and expensive, its combustion properties also differ somewhat from natural gas; for example, it burns more rapidly with a flame that is nearly invisible (Friedmann et al. 2019). Furthermore, heat transfer materials might also have to be retrofitted (Bartlett and Krupnick 2020).

Cost-wise, production of process heat using hydrogen is still quite challenging, especially in locations with readily available natural gas. For example, according to IRENA (2020), costs of green hydrogen are currently between 3-6 USD/kg (largely depending on electricity costs). Even if costs are reduced to around 1 USD/kg, a 60 USD/tonne CO2 price would be required in the US for it to be competitive as a source of process heat in cement production, although this to a large extent is a consequence of the low costs of natural gas in North America (Bartlett and Krupnick 2020).

***

Full report: Role of Biomass for Industrial Heat

Register for webinar here