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

=== 11.3.6 CCS, CCU, Carbon Sources, Feedstocks, and Fuels ===

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Carbon is an important and highly flexible building block for a wide range of fuels, organic chemicals and materials including methanol, ethanol, olefins, plastics, textiles, and wood and paper products. In this chapter we define CCS as requiring return of CO 2 from combustion or process gases or ambient air to the geosphere for geological time periods (i.e., thousands of years) ( [[#IPCC--2005|IPCC 2005]] ; [[#IEA--2009|IEA 2009]] ; [[#Bruhn--2016|Bruhn et al. 2016]] ; [[#IEA--2019g|IEA 2019g]] ). CCU is defined as being where carbon (as CO or CO 2 ) is captured from one process and reused for another, reducing emissions from the initial process, but is then potentially but not necessarily released to the atmosphere in following processes ( [[#Bruhn--2016|Bruhn et al. 2016]] ; [[#Detz--2019|Detz and van der Zwaan 2019]] ; [[#Tanzer--2019|Tanzer and Ramírez 2019]] ). In both cases the net effect on atmospheric emissions depends on the initial source of the carbon, be it from a fossil fuel, from biomass, or from direct air capture ( [[#Cuéllar-Franca--2015|Cuéllar-Franca and Azapagic 2015]] ; [[#Hepburn--2019|Hepburn et al. 2019]] ) and the duration of storage or use, which can vary from days to millennia.

While CCS and CCU share common capture technologies, what happens to the CO 2 and therefore the strategies that will employ them can be very different. CCS can help maintain near-CO 2 neutrality for fossil CO 2 that passes through the process, with highly varying partially negative emissions if the source is biogenic ( [[#Hepburn--2019|Hepburn et al. 2019]] ), and fully negative emissions if the source is air capture, all not considering the energy used to drive the above processes. CCS has been covered in other IPCC publications at length, for example, [[#IPCC--2005|IPCC (2005)]] , and in most mitigation-oriented assessments since, for example, the IEA’s Energy Technology Perspectives (ETP) 2020 and Net Zero scenario reports ( [[#IEA--2021a|IEA 2021a]] , 2020a). The potentials and costs for CCS in industry vary considerably due to the diversity of industrial processes ( [[#Leeson--2017|Leeson et al. 2017]] ), as well as the volume and purity of different flows of CO 2 ( [[#Naims--2016|Naims 2016]] ); [[#Kearns--2021|Kearns et al. (2021)]] provide a recent review. As a general rule it is not possible to capture all the CO 2 emissions from an industrial plant. To achieve zero or negative emissions, CCS would need to be combined with some use of sustainably sourced biofuel or feedstock, or the remaining emissions would need to be offset by carbon dioxide removal (CDR) elsewhere.

For concentrated CO 2 sources (e.g., cleaning of wellhead formation gas to make it suitable for the pipeline network, hydrogen production using steam methane reforming, ethanol fermentation, or from combustion of fossil fuels with oxygen in a nitrogen-free environment, i.e., ‘oxycombustion’) CCS is already amenable to commercial oil and gas reinjection techniques used to eliminate hydrogen sulphide gas and brines at prices of USD10–40 tCO 2 -eq –1 sequestered ( [[#Wilson--2003|Wilson et al. 2003]] ; [[#Leeson--2017|Leeson et al. 2017]] ). Most currently operating CCS facilities take advantage of concentrated CO 2 flows, for example, from formation gas cleaning on the Snoevit and Sleipner platforms in Norway, from syngas production for the Al Reyadah DRI steel plant in Abu Dhabi, and from SMR hydrogen production on the Quest upgrader in Alberta. Since concentrated process CO 2 emissions are often exempted from existing cap and trade systems, these opportunities for CCS have largely gone unexploited. Many existing projects partially owe their existence to the utilisation of the captured CO 2 for enhanced oil recovery, which in many cases counts as both CCS and CCU because of the permanent nature of the CO 2 disposal upon injection if sealed properly ( [[#Mac%20Dowell--2017|Mac Dowell et al. 2017]] ). There are several industrial CCS strategies and pilot projects working to take advantage of the relative ease of concentrated CO 2 disposal (e.g., LEILAC for limestone calcination process emissions from cement production, HISARNA direct oxycombustion smelting for steel) ( [[#Bataille--2020a|Bataille 2020a]] ). An emerging option for storing carbon is methane pyrolysis by which methane is split into hydrogen and solid carbon that may subsequently be stored ( [[#Schneider--2020|Schneider et al. 2020]] ).

There are several post-combustion CCS projects underway globally ( [[#IEA--2019g|IEA 2019g]] ), generally focused on energy production and processing rather than industry. Their costs are higher but evolving downward – [[#Giannaris--2020|Giannaris et al. (2020)]] suggest USD47 tCO 2 –1 for a follow-up 90% capture power generation plant based on learnings from the Saskpower Boundary Dam pilot – but crucially these costs are higher than implicit and explicit carbon prices almost everywhere, resulting in limited investment and learning in these technologies. A key challenge with all CCS strategies, however, is building a gathering and transport network for CO 2 , especially from dispersed existing sites; hence most pilot projects are built near EOR/geological storage sites, and the movement towards industrial clustering in the EU and UK ( [[#UKCCC--2019b|UKCCC 2019b]] ), and as suggested in [[#IEA--2019f|IEA (2019f)]] .

In the case of CCU, CO and CO 2 are captured and subsequently converted into valuable products (e.g., building materials, chemicals and synthetic fuels) ( [[#Styring--2011|Styring et al. 2011]] ; [[#Bruhn--2016|Bruhn et al. 2016]] ; [[#Artz--2018|Artz et al. 2018]] ; [[#Brynolf--2018|Brynolf et al. 2018]] ; [[#Daggash--2018|Daggash et al. 2018]] ; [[#Breyer--2019|Breyer et al. 2019]] ; [[#Kätelhön--2019|Kätelhön et al. 2019]] ; [[#Vreys--2019|Vreys et al. 2019]] ). CCU has been envisioned as part of the ‘circular economy’ but conflicting expectations on CCU and its association or not with CCS leads to different and contested framings ( [[#Palm--2021|Palm and Nikoleris 2021]] ). The duration of the CO 2 storage in these products varies from days to millennia according to the application, potentially but not necessarily replacing new fossil, biomass or direct air capture feedstocks, before meeting one of several possible fates: permanent burial, decomposition, recycling or combustion, all with differing GHG implications. While the environmental assessment of CCS projects is relatively straightforward, however, this is not the case for CCU technologies. The net-GHG mitigation impact of CCU depends on several factors (e.g., the capture rate, the energy requirements, the lifetime of utilisation products, the production route that is substituted, and associated room for improvement along the traditional route) and has to be determined by lifecycle CO 2 or GHG analysis (e.g., [[#Nocito--2020|Nocito and Dibenedetto 2020]] ; and [[#Bruhn--2016|Bruhn et al. 2016]] ). For example, steel-mill gases containing carbon monoxide and carbon dioxide can be used as feedstock together with hydrogen for producing chemicals. In this way, the carbon originally contained in the coke used in the blast furnace is used again, or cascaded, and emissions are reduced but not brought to zero. If fossil-sourced CO 2 is only reused once and then emitted, the maximum reduction is 50% ( [[#Tanzer--2019|Tanzer and Ramírez 2019]] ). The logic of using steel-mill CO and CO 2 could equally be applied to gasified biomass, however, with a far lower net-GHG footprint, likely negative, which CCU fed by fossil fuels cannot be if end-use combustion is involved.

Partly because of the complexity of the lifecycle analysis accounting, the literature on CCU is not always consistent in terms of the net-GHG impacts of strategies. For example, [[#Artz--2018|Artz et al. (2018)]] , focused not just on GHG mitigation but multi-attribute improvements to chemical processes from reutilisation of CO 2 , suggests the largest reduction in the absolute amount of GHGs from CO 2 reutilisation could be achieved by the coupling of highly concentrated CO 2 sources with carbon-free hydrogen or electrons from low GHG power in so called ‘power-to-fuel’ scenarios. From the point of view of maximising GHG mitigation using surplus ‘curtailed’ renewable power, however, [[#Daggash--2018|Daggash et al. (2018)]] instead indicates the best use would be for direct air capture and CCS. These results depend on what system is being measured, and what the objective is.

There are several potential crucial transitional roles for synthetic hydrocarbons and alcohols (e.g., methane, methanol, ethanol, ethylene, diesel and jet fuel) constructed using fossil, biomass or direct carbon capture (DAC) and CCU ( [[#Breyer--2015|Breyer et al. 2015]] ; [[#Dimitriou--2015|Dimitriou et al. 2015]] ; [[#Sternberg--2015|Sternberg and Bardow 2015]] ; [[#Fasihi--2017|Fasihi et al. 2017]] ; [[#Bataille--2018a|Bataille et al. 2018a]] ; [[#Bataille--2020a|Bataille 2020a]] ). They can allow reductions in the GHG intensity of high-value legacy transport, industry and real estate that currently runs on fossil fuels but cannot be easily or readily retrofitted. They can be used by existing long-lived energy and feedstock infrastructure, transport and storage, which can compensate for seasonal supply fluctuations and contribute to enhancing energy security ( [[#Ampelli--2015|Ampelli et al. 2015]] ). Finally, they can reduce the GHG intensity of end uses that are very difficult to run on electricity, hydrogen or ammonia (e.g., long-haul aviation). However, their equivalent mitigation cost today would be very high (USD960–1440 tCO 2 -eq –1 ), with the potential to fall to USD24–324 tCO 2 -eq –1 ) with commercial economies of scale, with very high uncertainty ( [[#Hepburn--2019|Hepburn et al. 2019]] ; [[#IEA--2020a|IEA 2020a]] ; [[#Ueckerdt--2021|Ueckerdt et al. 2021]] ).

A very large and important uncertainty is the long-term demand for hydrocarbon and alcohol fuels (whether fossil-, biomass- or DAC-based), chemical feedstocks (e.g., methanol and ethylene) and materials, and competition for biomass feedstock with other priorities, including agriculture, biodiversity and other proximate land-use needs, as well as need for negative emissions through BECCS. The current global plastics production of around 350 Mt yr –1 is almost entirely based on petroleum feedstock and recycling rates are very low. If this or future demand were to be 100% biomass-based it would require tens of exajoules of biomass feedstock ( [[#Meys--2021|Meys et al. 2021]] ). If demand can be lowered and recycling increased (mechanical as well as chemical) the demand for biomass feedstock can be much lower ( [[#Material%20Economics--2019|Material Economics 2019]] ). Promising routes in the short-term would be to utilise CO 2 from anaerobic digestion for biogas and fermentation for ethanol in the production of methane or methanol ( [[#Ericsson--2017|Ericsson 2017]] ); methanol can be converted into ethylene and propylene in a methanol-to-olefins process and used in the production of plastics (Box 11.2). New process configurations where hydrogen is integrated into biomass conversion routes to increase yields and utilise all carbon in the feedstock are relatively unexplored ( [[#Ericsson--2017|Ericsson 2017]] ; [[#De%20Luna--2019|De Luna et al. 2019]] ).

There are widely varying estimates of the capacity of CCU to reduce GHG emissions and meet the net zero objective. According to [[#Hepburn--2019|Hepburn et al. (2019)]] , the estimated potential for the scale of CO 2 utilisation in fuels varies widely, from 1 to 4.2 GtCO 2 yr –1 , reflecting uncertainties in potential market penetration, requiring carbon prices of around USD40 to 80 tCO 2 –1 , increasing over time. The high end represents a future in which synthetic fuels have sizeable market shares, due to cost reductions and policy drivers. The low end – which is itself considerable – represents very modest penetration into the methane and fuels markets, but it could also be an overestimate if CO 2 -derived products do not become cost competitive with alternative clean energy vectors such as hydrogen or ammonia, or with direct sequestration. [[#Brynolf--2018|Brynolf et al. (2018)]] indicates that a key cost variable will be the cost of electrolysers for producing hydrogen. [[#Kätelhön--2019|Kätelhön et al. (2019)]] estimate that up to 3.5 GtC yr –1 could be displaced from chemical production by 2030 using CCU, but this would require clean electricity equivalent to 55% of estimated global power production, at the same time other sectors’ demand would also be rising. [[#Mac%20Dowell--2017|Mac Dowell et al. (2017)]] suggest that while CCU, and specifically CO 2 -based enhanced oil recovery, may be an important economic incentive for early CCS projects (up to 4–8% of required mitigation by 2050), it is unlikely the chemical conversion of CO 2 for CCU will account for more than 1% of overall mitigation.

Finally, there is another class of CCU activities associated with carbonation of alkaline industrial wastes (including iron and steel slags, coal fly ash, mining and mineral processing wastes, incinerator residues, cement and concrete wastes, and pulp and paper mill wastes) using waste or atmospheric CO 2 . Given the large volume of alkaline wastes produced by industry, capture estimates are as high as 4 GtCO 2 yr −1 ( [[#Cuéllar-Franca--2015|Cuéllar-Franca and Azapagic 2015]] ; [[#Ebrahimi--2017|Ebrahimi et al. 2017]] ; [[#Kaliyavaradhan--2017|Kaliyavaradhan and Ling 2017]] ; [[#Pasquier--2018|Pasquier et al. 2018]] ; [[#Huang--2019c|Huang et al. 2019c]] ; [[#Pan--2020|Pan et al. 2020]] ; [[#Zhang--2020|Zhang et al. 2020]] ) However, as some alkaline wastes are already used directly as supplementary cementitious materials to reduce clinker-to-cement ratios, and their abundant availability in the future is questionable (e.g., steel blast furnace slag and coal fly ash), there will be a strong competition between mitigation uses ( [[#11.4.2|Section 11.4.2]] ), and the potential for direct removal by carbonation is estimated at about 1 GtCO 2 yr −1 ( [[#Renforth--2019|Renforth 2019]] ).

The above CCU literature has identified that there may be a highly unpredictable competition between fossil, biogenic and direct air capture carbon to provide highly uncertain chemical feedstock, material and fuel needs. Fossil waste carbon will likely initially be plentiful but will add to net atmospheric CO 2 when released. Biogenic carbon is variably, partially net-negative, but the available stock will be finite and compete with biodiversity and agriculture needs for land. Direct air capture carbon will require significant amounts of low-GHG electricity or methane with high-capture rate CCS ( [[#Keith--2018|Keith et al. 2018]] ). There are clearly strong interactive effects between low-carbon electrification, switching to biomass, hydrogen, ammonia, synthetic hydrocarbons via CCU, and CCS.

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