Editing IPCC:AR6/WGIII/Chapter-6 (section)

==== 6.4.2.5 Carbon Dioxide Capture, Utilisation and Storage ====

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Since AR5, there have been increased efforts to develop novel platforms that reduce the energy penalty associated with CO 2 capture, develop CO 2 utilisation pathways as a substitute to geologic storage, and establish global policies to support CCS ( ''high confidence'' ). CCS can be used within electricity and other sectors. While it increases the cost of electricity, CCS has the potential to contribute significantly to low-carbon energy system transitions ( [[#IPCC--2018|IPCC 2018]] ).

The theoretical global geologic storage potential is about 10,000 GtCO 2 , with more than 80% of this capacity existing in saline aquifers ( ''medium confidence'' ). Not all the storage capacity is usable because geologic and engineering factors limit the actual storage capacity to an order of magnitude below the theoretical potential, which is still more than the CO 2 storage requirement through 2100 to limit temperature change to 1.5°C ( [[#Martin-Roberts--2021|Martin-Roberts et al. 2021]] ) ( ''high confidence'' ). One of the key limiting factors associated with geologic CO 2 storage is the global distribution of storage capacity (Table 6.2). Most of the available storage capacity exists in saline aquifers. Capacity in oil and gas reservoirs and coalbed methane fields is limited. Storage potential in the USA alone is &gt;1000 GtCO 2 , which is more than 10% of the world total ( [[#NETL--2015|NETL 2015]] ). The Middle East has more than 50% of global enhanced oil recovery potential ( [[#Selosse--2017|Selosse and Ricci 2017]] ). It is likely that oil and gas reservoirs will be developed as geologic sinks before saline aquifers because of existing infrastructure and extensive subsurface data ( [[#Alcalde--2019|Alcalde et al. 2019]] ; [[#Hastings--2020|Hastings and Smith 2020]] ). Notably, not all geologic storage is utilisable. In places with limited geologic storage, international CCS chains are being considered, where sources and sinks of CO 2 are located in two or more countries ( [[#Sharma--2021|Sharma and Xu 2021]] ). For economic long-term storage, the desirable conditions are a depth of 800–3000 m, thickness of greater than 50 m and permeability greater than 500 mD ( [[#Chadwick--2008|Chadwick et al. 2008]] ; [[#Singh--2021|Singh et al. 2021]] ). Even in reservoirs with large storage potential, the rate of injection might be limited by the subsurface pressure of the reservoir ( [[#Baik--2018|Baik et al. 2018]] ). It is estimated that geologic sequestration is reliable with overall leakage rates at &lt;0.001% yr –1 ( [[#Alcalde--2018|Alcalde et al. 2018]] ). In many cases, geological storage resources are not located close to CO 2 sources, increasing costs and reducing viability ( [[#Garg--2017a|Garg et al. 2017a]] ).

'''Table 6.2 | Geologic storage potential across underground formations globally.''' '''These represent order-of-magnitude estimates.''' Data: Selosseand Ricci (2017).

{| class="wikitable"
|-
| '''Reservoir typ''' e

| '''Africa'''

| '''Australia'''

| '''Canada'''

| '''China'''

| '''CSA'''

| '''EEU'''

| '''FSU'''

| '''India'''

| '''MEA'''

| '''Mexico'''

| '''ODA'''

| '''USA'''

| '''WEU'''

|-
| Enhanced oil recovery

| 3

| 0

| 3

| 1

| 8

| 2

| 15

| 0

| 38

| 0

| 1

| 8

| 0

|-
| Depleted oil and gas fields

| 20

| 8

| 19

| 1

| 33

| 2

| 191

| 0

| 252

| 22

| 47

| 32

| 37

|-
| Enhanced coalbed methane recovery

| 8

| 30

| 16

| 16

| 0

| 2

| 26

| 8

| 0

| 0

| 24

| 90

| 12

|-
| Deep saline aquifers

| 1000

| 500

| 667

| 500

| 1000

| 250

| 1000

| 500

| 500

| 250

| 1015

| 1000

| 250

|}

CSA: Central and South America, EEU: Eastern Europe, FSU: Former Soviet Union, MEA: Middle East, ODA: Other Asia (except China and India), WEU: Western Europe.

CO 2 utilisation (CCU) – instead of geologic storage – could present an alternative method of decarbonisation ( ''high confidence'' ). The global CO 2 utilisation potential, however, is currently limited to 1–2 GtCO 2 yr –1 for use of CO 2 as a feedstock ( [[#Hepburn--2019|Hepburn et al. 2019]] ; [[#Kätelhön--2019|Kätelhön et al. 2019]] ) but could increase to 20 GtCO 2 by the mid-century ( ''medium confidence'' ). CCU involves using CO 2 as a feedstock to synthesise products of economic value and as substitute to fossil feedstock. However, several CO 2 utilisation avenues might be limited by energy availability. Depending on the utilisation pathway, the CO 2 may be considered sequestered for centuries (e.g., cement curing, aggregates), decades (plastics), or only a few days or months (e.g., fuels) ( [[#Hepburn--2019|Hepburn et al. 2019]] ). Moreover, when carbon-rich fuel end-products are combusted, CO 2 is emitted back into the atmosphere. Because of the presence of several industrial clusters (regions with high density of industrial infrastructure) globally, a number of regions demonstrate locations where CO 2 utilisation potential could be matched with large point sources of CO 2 ( [[#Wei--2020|Wei et al. 2020]] ).

The technological development for several CO 2 utilisation pathways is still in the laboratory, prototype, and pilot phases, while others have been fully commercialised (such as urea manufacturing). Technology development in some end uses is limited by purity requirements for CO 2 as a feedstock. The efficacy of CCU processes depends on additional technological constraints such as CO 2 purity and pressure requirements. For instance, urea production requires CO 2 pressurised to 122 bar and purified to 99.9%. While most utilisation pathways require purity levels of 95–99%, algae production may be carried out with atmospheric CO 2 ( [[#Voldsund--2016|Voldsund et al. 2016]] ; [[#Ho--2019|Ho et al. 2019]] ).

Existing post-combustion approaches relying on absorption are technologically ready for full-scale deployment ( ''high confidence'' ). More novel approaches using membranes and chemical looping that might reduce the energy penalty associated with absorption are in different stages of development – ranging from laboratory phase to prototype phase ( [[#Abanades--2015|Abanades et al. 2015]] ) ( ''high confidence'' ). There has been significant progress in post-combustion capture technologies that used absorption in solvents such as monoethanolamine (MEA). There are commercial-scale application of solvent-based absorption at two electricity generating facilities – Boundary Dam since 2015 and Petra Nova (temporarily suspended) since 2017, with capacities of 1 and 1.6 MtCO 2 yr –1 respectively ( [[#Mantripragada--2019|Mantripragada et al. 2019]] ; [[#Giannaris--2020|Giannaris et al. 2020]] a). Several second- and third-generation capture technologies are being developed with the aim of not just lowering costs but also enhancing other performance characteristics such as improved ramp-up and lower water consumption. These include processes such as chemical looping, which also has the advantage of being capable of co-firing with biomass with a better efficiency ( [[#Bhave--2017|Bhave et al. 2017]] ; [[#Yang--2019|Yang et al. 2019]] ). Another important technological development is the Allam cycle, which utilises CO 2 as a working fluid and operates based on oxy-combustion capture. Applications using the Allam Cycle can deliver net energy efficiency greater than 50% and nearly 100% CO 2 capture, but they are quite sensitive to oxygen and CO 2 purity needs ( [[#Scaccabarozzi--2016|Scaccabarozzi et al. 2016]] ; [[#Ferrari--2017|Ferrari et al. 2017]] ).

CO 2 capture costs present a key challenge, remaining higher than USD50 tCO 2 –1 for most technologies and regions; novel technologies could help reduce some costs ( ''high confidence'' ). The capital cost of a coal or gas electricity generation facility with CCS is almost double that of one without CCS ( [[#Rubin--2015|Rubin et al. 2015]] ; [[#Zhai--2016|Zhai and Rubin 2016]] ; [[#Bui--2018|Bui et al. 2018]] ). Additionally, the energy penalty increases the fuel requirement for electricity generation by 13–44%, leading to further cost increases (Table 6.3).

'''Table 6.3| Costs and efficiency parameters of CCS in electric power plants.''' Data: [[#Muratori--2017a|Muratori et al. (2017a)]] '''.'''

{| class="wikitable"
|-
|
| Capital cost [USD kW –1 ]

| Efficiency [%]

| CO 2 capture cost [USD tCO 2 –1 ]

| CO 2 avoided cost [USD tCO 2 –1 ]

|-
| Coal (steam plant) + CCS

| 5800

| 28%

| 63

| 88

|-
| Coal (IGCC) + CCS

| 6600

| 32%

| 61

| 106

|-
| Natural gas (CC) + CCS

| 2100

| 42%

| 91

| 33

|-
| Oil (CC) + CCS

| 2600

| 39%

| 105

| 95

|-
| Biomass (steam plant) + CCS

| 7700

| 18%

| 72

| 244

|-
| Biomass (IGCC) + CCS

| 8850

| 25%

| 66

| 242

|}

In addition to reductions in capture costs, other approaches to reduce CCS costs rely on utilising the revenues from co-products such as oil, gas, or methanol, and on clustering of large-point sources to reduce infrastructure costs. The potential for such reductions is limited in several regions due to low sink availability, but it could jump-start initial investments ( ''medium confidence'' ). Injecting CO 2 into hydrocarbon formations for enhanced oil or gas recovery can produce revenues and lower costs ( [[#Edwards--2018|Edwards and Celia 2018]] ). While enhanced oil recovery potential is &lt;5% of the actual CCS needs, they can enable early pilot and demonstration projects ( [[#Núñez-López--2019|Núñez-López and Moskal 2019]] ; [[#Núñez-López--2019|Núñez-López et al. 2019]] ). Substantial portions of CO 2 are effectively stored during enhanced oil recovery ( [[#Menefee--2020|Menefee and Ellis 2020]] ; [[#Sminchak--2020|Sminchak et al. 2020]] ). By clustering together of several CO 2 sources, overall costs may be reduced by USD10 tCO 2 –1 ( [[#Abotalib--2016|Abotalib et al. 2016]] ; [[#Garg--2017a|Garg et al. 2017a]] ), but geographical circumstances determine the prospects of these cost reductions via economies of scale. The major pathways for CO 2 utilisation via methanol, methane, liquid fuel production, and cement curing have costs greater than USD500 tCO 2 –1 ( [[#Hepburn--2019|Hepburn et al. 2019]] ). The success of these pathways therefore depends on the value of such fuels and on the values of other alternatives.

The public is largely unfamiliar with carbon capture, use and storage technologies ( [[#L’Orange%20Seigo--2014|L’Orange Seigo et al. 2014]] ; [[#Tcvetkov--2019|Tcvetkov et al. 2019]] ) ( ''high confidence'' ), and many people may not have formed stable attitudes and risk perceptions regarding these technologies ( [[#Daamen--2006|Daamen et al. 2006]] ; [[#Jones--2015|Jones et al. 2015]] ; [[#Van%20Heek--2017|Van Heek et al. 2017]] ) ( ''medium confidence'' ). In general, low support has been reported for CCS technologies ( [[#Allen--2013|Allen and Chatterton 2013]] ; [[#Demski--2017|Demski et al. 2017]] ). When presented with neutral information on CCS, people favour other mitigation options such as renewable energy and energy efficiency (de Best-Waldhober et al. 2009; [[#Scheer--2013|Scheer et al. 2013]] ; [[#Karlstrøm--2014|Karlstrøm and Ryghaug 2014]] ). Although few totally reject CCS, specific CCS projects have faced strong local resistance, which has contributed to the cancellation of CCS projects ( [[#Terwel--2012|Terwel et al. 2012]] ; [[#L’Orange%20Seigo--2014|L’Orange Seigo et al. 2014]] ). Communities may also consider CCU to be lower-risk and view it more favourably than CCS ( [[#Arning--2019|Arning et al. 2019]] ).

CCS requires considerable increases in some resources and chemicals, most notably water. Power plants with CCS could shut down periodically due to water scarcity. In several cases, water withdrawals for CCS are 25–200% higher than plants without CCS ( [[#Rosa--2020b|Rosa et al. 2020b]] ; [[#Yang--2020|Yang et al. 2020]] ) due to energy penalty and cooling duty. The increase is slightly lower for non-absorption technologies. In regions prone to water scarcity such as the Southwestern USA or Southeast Asia, this may limit deployment and result in power plant shutdowns during the summer months ( [[#Liu--2019b|Liu et al. 2019b]] ; [[#Wang--2019c|Wang et al. 2019c]] ). The water use could be managed by changing heat integration strategies and implementing reuse of wastewater ( [[#Magneschi--2017|Magneschi et al. 2017]] ; [[#Giannaris--2020|Giannaris et al. 2020]] b).

Because CCS always adds cost, policy instruments are required for it to be widely deployed ( ''high confidence'' ). Relevant policy instruments include financial instruments such as emission certification and trading, legally enforced emission restraints, and carbon pricing ( [[#Haszeldine--2016|Haszeldine 2016]] ; [[#Kang--2020|Kang et al. 2020]] ). There are some recent examples of policy instruments specifically focused on promoting CCS. The recent 45Q tax credits in the USA offer nationwide tax credits for CO 2 capture projects above USD35–50 tCO 2 –1 which offset CO 2 capture costs at some efficient plants ( [[#Esposito--2019|Esposito et al. 2019]] ). Similarly, California’s low-carbon fuel standard offers benefits for CO 2 capture at some industrial facilities such as biorefineries and refineries ( [[#Von%20Wald--2020|Von Wald et al. 2020]] ).

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