Editing IPCC:AR6/WGIII/Chapter-11 (section)

=== 11.3.5 Electrification and Fuel Switching ===

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The principle of electrification and fuel switching as a GHG mitigation strategy is that industries, to the extent possible, switch their end uses of energy from a high GHG intensity energy carrier to a lower or zero intensity one, including both its direct and indirect production and end-use GHG emissions. In general, and non-exclusively, this implies a transition from coal (about 0.09 tCO 2 GJ –1 on combustion), refined petroleum products (about 0.07 tCO 2 GJ –1 ), and natural gas (about 0.05 tCO 2 GJ –1 ) to biofuels, direct solar heating, electricity, hydrogen, ammonia, or net zero synthetic hydrocarbon fuels. Switching to these energy carriers is not necessarily lower emitting, however; how they are made matters.

Fuel switching has already been observed to reduce direct combustion CO 2 emissions in many jurisdictions. There are significant debates about the net effect of upstream fossil fuel production and fugitive emissions, but observers have noted that in the case of US power generation it would take a leakage rate of about 2.7% from natural gas production to undo the direct fuel switching from coal mitigation effect, and the value is likely higher in most cases ( [[#Alvarez--2012|Alvarez et al. 2012]] ; [[#Hausfather--2015|Hausfather 2015]] ). Coal mine methane emissions are also estimated to be substantially higher than previously assessed ( [[#Kholod--2020|Kholod et al. 2020]] ). [[#Alvarez--2018|Alvarez et al. (2018)]] estimated US fugitive emissions (not including the Permian) at 2.3% of supply, 60% more than previously estimated, while recent Canadian papers indicate fugitive emissions are at least 50% more than reported ( [[#Chan--2020|Chan et al. 2020]] ; [[#MacKay--2021|MacKay et al. 2021]] ). However, given the potential for energy supply infrastructure lock-in effects ( [[#Tong--2019|Tong et al. 2019]] ), purely fossil fuel to fossil fuel switching is a limited and potentially dangerous strategy unless it is used very carefully and in a limited way.

Biofuels come in many forms, including ones that are nearly identical to fossil fuels but sourced from biogenic sources. Solid biomass, either direct from wood chips, lignin or processed pellets, is the most commonly used renewable fuel in industry today and is occasionally used in cement kilns and boilers. Biomethane, biomethanol, and bioethanol are all commercially made today using fermentation and anaerobic digestion techniques and are mostly ‘drop-in’ compatible with fossil fuel equivalents. In principle they cycle carbon in and out of the atmosphere, but their lifecycle GHG intensities are typically not GHG neutral due to land-use changes, soil carbon depletion, fertiliser use, and other dynamics ( [[#Hepburn--2019|Hepburn et al. 2019]] ), and are highly case specific. Most commercial biofuel feedstocks come from agricultural (e.g., corn) and food waste sources, and the feedstock is limited; to meet higher levels of biomass use a transition to using higher cellulose feedstocks like straw, switchgrass and wood waste, available in much larger quantities, must be fully commercialised and deployed. Significant efforts have been made to make ethanol from cellulosic biomass, which promises much higher quantities, lower costs, and lower intensities, but commercialisation efforts, with a few exceptions, have largely not succeeded ( [[#Padella--2019|Padella et al. 2019]] ). The IEA estimates, however, that up to 20% of today’s fossil methane use, including by industry, could be met with biomethane ( [[#IEA--2020g|IEA 2020g]] ) by 2040, using a mixture of feedstocks and production techniques. Biofuel use may also be critical for producing negative emissions when combined with carbon capture and storage (i.e., bioenergy with carbon capture and storage – BECCS). Most production routes for biofuels, biochemicals and biogas generate large side streams of concentrated CO 2 which is easily captured, and which could become a source of negative emissions ( [[#Sanchez--2018|Sanchez et al. 2018]] ) (Section ). Finally, it should be noted that biofuel combustion can, if inadequately controlled, have substantial negative local air quality effects, with implications for SDGs 3, 7 and 11.

There is a large identified potential for direct solar heating in industry, especially in regions with strong solar insolation and sectors with lower heat needs (&lt;180°C), for example, food and beverage processing, textiles, and pulp and paper ( [[#Schoeneberger--2020|Schoeneberger et al. 2020]] ). The key challenges to adoption are site and use specificity, capital intensity, and a lack of standardised mass manufacturing for equipment and a supply chain to provide them.

Switching to electricity for end uses, or ‘direct electrification’, is a highly discussed strategy for net zero industrial decarbonisation ( [[#Lechtenböhmer--2016|Lechtenböhmer et al. 2016]] ; [[#Palm--2016|Palm et al. 2016]] ; [[#Åhman--2017|Åhman et al. 2017]] ; [[#Axelson--2018|Axelson et al. 2018]] ; [[#Bataille--2018a|Bataille et al. 2018a]] ; [[#Davis--2018|Davis et al. 2018]] ; [[#UKCCC--2019b|UKCCC 2019b]] ; [[#Material%20Economics--2019|Material Economics 2019]] ). Electricity is a flexible energy carrier that can be made from many forms of primary energy, with high potential process improvements in terms of end-use efficiency ( [[#Eyre--2021|Eyre 2021]] ), quality and process controllability, digitisability, and no direct local air pollutants ( [[#McMillan--2016|McMillan et al. 2016]] ; [[#Jadun--2017|Jadun et al. 2017]] ; [[#Deason--2018|Deason et al. 2018]] ; [[#Mai--2018|Mai et al. 2018]] ). The net-GHG effect of electrification is contingent on how the electricity is made, and because total output increases can be expected, for full effect it should be made with a very low GHG intensity primary source (i.e., &lt;50 g CO 2 kWh –1 : e.g., hydroelectricity, nuclear energy, wind, solar photovoltaics, or fossil fuels with 95+% carbon capture and storage ( [[#IPCC--2014|IPCC 2014]] )). This has strong implications for the electricity sector and its generation mix when the goal is a net-zero-emissions electricity system. Despite their falling costs, progressively higher mixes of variable wind and solar on a given grid will require support from grid flexibility sources, including demand response, more transmission, storage on multiple time scales, or firm low-to-negative emissions generation sources (e.g., nuclear energy, hydrogen fuel cells or turbines, biofuels, fossil or biofuels with CCS, and geothermal) to moderate costs ( [[#Jenkins--2018|Jenkins et al. 2018]] ; [[#Sepulveda--2018|Sepulveda et al. 2018]] ; [[#Williams--2021|Williams et al. 2021]] ). Regions that may be slower to reduce the GHG intensity of their electricity production will likely need to consider more aggressive use of other measures, like energy and material efficiency or bioenergy.

The long-term potential for full-process electrification is a very sector-by-sector and process-by-process phenomenon, with differing energy and capacity needs, load profiles, stock turnover, capacity for demand response, and characteristics of decision-makers. Industrial electrification is most viable in the near term in cases with: minimal retrofitting and rebuild in processes; with relatively low local electricity costs; where the degree of process complexity and process integration is more limited and extensive process re-engineering would not be required; where combined heat and power is not used; where induction heating technologies are viable; and where process heating temperatures are lower ( [[#Deason--2018|Deason et al. 2018]] ).

For these reasons, lighter, manufacturing-orientated industries are more readily electrifiable than heavier industry like steel, cement, chemicals and other sectors with high heat and feedstock needs. Steam boilers, curing, drying and small-scale process heating, with typically lower maximum heat temperature needs (&lt;200°C–250°C) are readily electrifiable with appropriate fossil-fuel-to-electricity price ratios (accounting for capital costs and efficiencies), and direct induction and infrared heating are available for higher temperature needs. These practices are uncommon outside regions with ample hydroelectric power due to the currently relatively low cost of coal, natural gas and heating oil, and especially when there is no carbon combustion cost. [[#Madeddu--2020|Madeddu et al. (2020)]] argue up to 78% of Europe’s industrial energy requirements are electrifiable through existing commercial technologies. In contrast, [[#Mai--2018|Mai et al. (2018)]] saw only a moderate industrial heat supply electrification in their high-electrification scenario for the US. Electrification has also been explored in: raw and recycled steel ( [[#Fischedick--2014|Fischedick et al. 2014]] b; [[#Vogl--2018|Vogl et al. 2018]] ); ammonia ( [[#Bazzanella--2017|Bazzanella and Ausfelder 2017]] ; [[#Philibert--2017a|Philibert 2017a]] ); and chemicals ( [[#Palm--2016|Palm et al. 2016]] ; [[#Bazzanella--2017|Bazzanella and Ausfelder 2017]] ). While most chemical production of feedstock chemicals (e.g., H 2 , NH 3 , CO, CH 3 OH, C 2 H 4, C 2 H 6 and C 2 H 5 OH ) is done thermo-catalytically today, it is feasible to use direct electrocatalytic production, by itself or in combination with utilisation of previously captured carbon sources if a fossil fuel feedstock is used, or well-known bio-catalytic (e.g., fermentation) and thermo-catalytic processes ( [[#Bazzanella--2017|Bazzanella and Ausfelder 2017]] ; [[#De%20Luna--2019|De Luna et al. 2019]] ; [[#Kätelhön--2019|Kätelhön et al. 2019]] ). It may even be commercially possible to electrify cement sintering and calcination through plasma or microwave options ( [[#Material%20Economics--2019|Material Economics 2019]] ).

Increased electrification of industry will result in increased overall demand for electricity. For example, 75 TWh of electricity was used by steel in the EU in 2015 (out of the 1000 TWh total used by industry), [[#Material%20Economics--2019|Material Economics (2019)]] , varying between their new process, circularity and CCUS scenarios, projects increased demand to 355 (+373%), 214 (+185%) and 238 (+217%) TWh. These values are consistent with [[#Vogl--2018|Vogl et al. (2018)]] , which projects a tripling of electricity demand in the German or Swedish steel industries if hydrogen-direct reduced iron and electric arc furnace steel-making (DRI EAFs) replaces BF-BOFs. [[#Material%20Economics--2019|Material Economics (2019)]] was conservative with its use of electricity in chemical production, making preferential use of biofeedstocks and some CCUS, and electricity demand still rose from 118 TWh to 510, 395 and 413 TWh in their three scenarios. [[#Bazzanella--2017|Bazzanella and Ausfelder (2017)]] , exploring deeper reductions from the chemical sector using more electrochemistry, projected scenarios with higher electricity demands of 960–4900 TWh (140% of the projected available clean electricity at the time) with maximum electricity use. In counterpoint, however, with revised wind capabilities and costs, the [[#IEA--2019e|IEA (2019e)]] Offshore Wind Outlook indicates that ten times the current EU electricity use could be produced if necessary. Greater use of electro-catalytic versus thermo-catalytic chemistry, as projected by [[#De%20Luna--2019|De Luna et al. (2019)]] , could greatly reduce these electricity needs, but the technology readiness levels are currently low. Finally, the [[#UKCCC--2019b|UKCCC (2019b)]] , which focused primarily on CCS for industry in its ‘Further Ambition’ scenario (the UK currently consumes about 300 TWh), in its supplementary ‘Further Electrification’ scenario projects an additional 300 TWh for general electrolysis needs and another 200 TWh for synthetic fuel production.

While it has been demonstrated that almost any heating end use can be directly electrified, this would imply very high instantaneous thermal loads for blast furnace-basic oxygen furnace (BF-BOF) steel production, limestone calcination for cement and lime production, and other end uses where flame-front (1000°C–1700°C) temperatures are currently needed. This indicates a possible need for another energy carrier to minimise instantaneous generation and transmission needs. These needs can be met at varying current and potential future costs using: bioliquids or gases hydrogen, ammonia, or net zero synthetic hydrocarbons or alcohols.

Broadly speaking, '''hydrogen''' can contribute to a cleaner energy system in two ways: (i) existing applications of hydrogen (e.g., nitrogen fertiliser production, refinery upgrading) can use hydrogen produced using alternative, cleaner production methods; (ii) new applications can use low-GHG hydrogen as an alternative to current fuels and inputs, or as a complement to the greater use of electricity in these applications. In these cases – for example, in transport, heating, industry (e.g., hydrogen-direct reduced iron and steel production) and electricity – hydrogen can be used in its pure form, or be converted to hydrogen-based fuels, including ammonia, or synthetic net zero hydrocarbons and alcohols such as methane or methanol ( [[#IEA--2019f|IEA 2019f]] ). The IEA states that hydrogen could be used to help integrate more renewables, including by enhancing storage options and ‘exporting sunshine and wind’ from places with abundant resources; decarbonise steel, chemicals, trucks, ships and planes; and boost energy security by diversifying the fuel mix and providing flexibility to balance grids ( [[#IEA--2019f|IEA 2019f]] ).

Around 70 Mt yr –1 of pure hydrogen is produced today: 76% from natural gas and 23% from coal, resulting in emissions of roughly 830 MtCO 2 yr –1 in 2016/17 ( [[#IEA--2019f|IEA 2019f]] ), or 4.7% of global industrial direct and indirect emissions (waste excluded; [[#_idTextAnchor023|Table 11.1]] ). Fuels refining (about 410 MtCO 2 yr –1 ) and production of ammonia (420 MtCO 2 yr –1 ) largely dominate its uses. Another 45 Mt hydrogen is being produced along with other gases, on purpose or as by-products, and used as fuel, to make methanol or as a chemical reactant ( [[#IEA--2019f|IEA 2019f]] ). Very low and potentially zero GHG (depending on the energy source) hydrogen can be made via: electrolysis separation of water into hydrogen and oxygen ( [[#Glenk--2019|Glenk and Reichelstein 2019]] ), also known as ‘green H 2 ’; electrothermal separation of water, as done in some nuclear plants ( [[#Bicer--2017|Bicer and Dincer 2017]] ); partial oxidation of coal or naphtha or steam/auto methane reforming (SMR/ATR) combined with CCS ( [[#Leeson--2017|Leeson et al. 2017]] ), or ‘blue H 2 ’; methane pyrolysis, where the hydrogen and carbon are separated thermally and the carbon is left as a solid (Abbas and Wan Daud 2010; [[#Ashik--2015|Ashik et al. 2015]] ), or via biomass gasification ( [[#Ericsson--2017|Ericsson 2017]] ), which could be negative emissions if the CO 2 from the gasification process is sequestered. All these processes would in turn need to be run using very low or zero GHG energy carriers for the resulting hydrogen to also be low in GHG emissions.

'''Ammonia production''' , made from hydrogen and nitrogen using the Haber-Bosch process, is the most voluminous chemical produced from fossil fuels, being used as feedstock for nitrogen fertilisers and explosives, as well as a cleanser, a refrigerant, and for other uses. Most ammonia is made today using methane as the hydrogen feedstock and heat source but has been made using electrolysis-based hydrogen in the past, and there are several announced investments to resume doing so. If ammonia is used as a combustion fuel, care must be taken to avoid N 2 O as a GHG and NO x in general as a local air pollutant.

Hydrogen can also be combined with low-to-zero net GHG carbon (Section ) and oxygen and made into '''methane''' , '''methanol''' and other potential net zero '''synthetic hydrocarbons''' '''and alcohol''' energy carriers using methanation, steam reforming and Fischer-Tropsch processes, all of which can provide higher degrees of storable and shippable high-temperature energy using known industrial processes in novel combinations ( [[#Bataille--2018a|Bataille et al. 2018a]] ; [[#Davis--2018|Davis et al. 2018]] ). If the hydrogen and oxygen is accessed via electrolysis, the terms ‘power-to-fuel’ or ‘e-fuels’ are often used ( [[#Ueckerdt--2021|Ueckerdt et al. 2021]] ). Given their carbon content, if used as fuels, their carbon will eventually be oxidised and emitted as CO 2 to the atmosphere. This makes their net-GHG intensity dependent on the carbon source ( [[#Hepburn--2019|Hepburn et al. 2019]] ), with recycled fossil fuels, biocarbon and direct air capture carbon all having very different net-CO 2 impacts – see section 11.3.6 on CCS and CCU for elaboration.

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