Maximizing the Mitigation Potential of Curtailed Wind: A Comparison Between Carbon Capture and Utilization, and Direct Air Capture Processes for the UK

Carbon capture and storage (CCS) with fossil fuel or biomass plants (BECCS) is considered a critical technology to meet mitigation targets set by the Paris Agreement1. However, several drawbacks including high upfront investment costs, significant energy penalty and long-term permanent storage challenges have limited the uptake of CCS on the required scale. Carbon capture and utilisation (CCU) provides an alternative route to recycle CO2 into chemical feedstock and/or synthetic transport fuels (e.g. methanol, DME) that can displace fossil-derived fuels. As the carbon is only transformed, CCU must be integrated with capture/storage to actually offset subsequent emissions from the vehicles consuming them. The mitigation of decentralised emissions poses significant challenges and necessitates the use of carbon dioxide removal technologies (CDR), one of which is direct capture of CO2 from the atmosphere (DAC). The last decade has seen increasing penetration of wind power in the UK electricity system to meet mitigation targets. Because of this, periods of surplus wind generation and low demand or limited/full storage capacity arise. Constraint payments then have to be made to wind farms to curtail generation. This work investigates two possible options to achieve mitigation with this curtailed electricity. In Process A, curtailed electricity is used to produce electrolytic hydrogen and operate methanol synthesis plants. It is then integrated with a direct air capture (DAC) plant to recapture and recycle emissions from the vehicles. Process B assumes curtailed electricity is used to run a DAC plant directly in order to capture decentralised carbon emissions and provide CO2 feedstock for CCU processes. The UK was used as a case study and the methanol synthesis process described by Rihko-Struckmann et al.2 was used as the reference. A range of energy requirements for DAC are cited in literature; the lower and upper bounds of 6.7 GJ/tCO2 and 12.6 GJ/tCO23, respectively, were used. This work has taken a base case curtailment level of 2.5% of the UK total electricity demand, which is equivalent to 390 GWh/y4. Both processes have been compared on the basis of mitigation potential, defined by the proportion of CO2 emissions from gasoline vehicles that are avoided, and mitigation costs per tonne of CO2 captured. Process A resulted in avoiding 0.12% of gasoline emissions (~0.05 MtCO2/y). Surplus energy (~64% of the curtailed electricity) was required to run the DAC plant and an associated air separation unit. The mitigation of potential of Process B was 0.10% or 0.18%, depending on energy requirement used. Therefore, the process that maximises mitigation potential depends on the DAC process considered; using the lower-bound energy requirement, surplus electricity for DAC only is preferable. Neither process is economically viable. CCU costs ($905/tCO2) were found to be double the DAC-only costs ($449/tCO2), mainly due to high H2 costs. It will remain financially-unattractive unless the methanol production becomes profitable. This is unlikely as it requires methanol price to almost double, a carbon price of $313/t to be in effect, or H2 price to reduce to a third of today’s price to$1800/t. References 1. IPCC. Climate Change 2014: Mitigation of Climate Change. Working Group III Contribution to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (2014). doi:10.1017/CBO9781107415416 2. Rihko-Struckmann, L. K., Peschel, A., Hanke-Rauschenbach, R. & Sundmacher, K. Assessment of methanol synthesis utilizing exhaust CO2 for chemical storage of electrical energy. Ind. Eng. Chem. Res. 49, 11073–11078 (2010). 3. Socolow, R. et al. Direct Air Capture of CO 2 with Chemicals Panel on Public Affairs. Am. Phys. Soc. - Panel Public Aff. 100 (2011). 4. Messiou, A. Centre for Environmental Policy Investigating the role of power storage in accommodating the future wind. (2012)

Sector coupling via hydrogen to lower the cost of energy system decarbonization

There is growing interest in hydrogen (H$_2$) use for long-duration energy storage in a future electric grid dominated by variable renewable energy (VRE) resources. Modelling the role of H$_2$ as grid-scale energy storage, often referred as "power-to-gas-to-power (P2G2P)" overlooks the cost-sharing and emission benefits from using the deployed H$_2$ production and storage assets to also supply H$_2$ for decarbonizing other end-use sectors where direct electrification may be challenged. Here, we develop a generalized modelling framework for co-optimizing energy infrastructure investment and operation across power and transportation sectors and the supply chains of electricity and H$_2$, while accounting for spatio-temporal variations in energy demand and supply. Applying this sector-coupling framework to the U.S. Northeast under a range of technology cost and carbon price scenarios, we find a greater value of power-to-H$_2$ (P2G) versus P2G2P routes. P2G provides flexible demand response, while the extra cost and efficiency penalties of P2G2P routes make the solution less attractive for grid balancing. The effects of sector-coupling are significant, boosting VRE generation by 12-55% with both increased capacities and reduced curtailments and reducing the total system cost (or levelized costs of energy) by 6-14% under 96% decarbonization scenarios. Both the cost savings and emission reductions from sector coupling increase with H$_2$ demand for other end-uses, more than doubling for a 96% decarbonization scenario as H$_2$ demand quadraples. Moreover, we found that the deployment of carbon capture and storage is more cost-effective in the H$_2$ sector because of the lower cost and higher utilization rate. These findings highlight the importance of using an integrated multi-sector energy system framework with multiple energy vectors in planning energy system decarbonization pathways.Comment: 19 pages, 7 figure

The role and uses of antibodies in COVID-19 infections: a living review

Coronavirus disease 2019 has generated a rapidly evolving field of research, with the global scientific community striving for solutions to the current pandemic. Characterizing humoral responses towards SARS-CoV-2, as well as closely related strains, will help determine whether antibodies are central to infection control, and aid the design of therapeutics and vaccine candidates. This review outlines the major aspects of SARS-CoV-2-specific antibody research to date, with a focus on the various prophylactic and therapeutic uses of antibodies to alleviate disease in addition to the potential of cross-reactive therapies and the implications of long-term immunity

T cell phenotypes in COVID-19 - a living review

COVID-19 is characterized by profound lymphopenia in the peripheral blood, and the remaining T cells display altered phenotypes, characterized by a spectrum of activation and exhaustion. However, antigen-specific T cell responses are emerging as a crucial mechanism for both clearance of the virus and as the most likely route to long-lasting immune memory that would protect against re-infection. Therefore, T cell responses are also of considerable interest in vaccine development. Furthermore, persistent alterations in T cell subset composition and function post-infection have important implications for patients’ long-term immune function. In this review, we examine T cell phenotypes, including those of innate T cells, in both peripheral blood and lungs, and consider how key markers of activation and exhaustion correlate with, and may be able to predict, disease severity. We focus on SARS-CoV-2-specific T cells to elucidate markers that may indicate formation of antigen-specific T cell memory. We also examine peripheral T cell phenotypes in recovery and the likelihood of long-lasting immune disruption. Finally, we discuss T cell phenotypes in the lung as important drivers of both virus clearance and tissue damage. As our knowledge of the adaptive immune response to COVID-19 rapidly evolves, it has become clear that while some areas of the T cell response have been investigated in some detail, others, such as the T cell response in children remain largely unexplored. Therefore, this review will also highlight areas where T cell phenotypes require urgent characterisation

Air separation with cryogenic energy storage : Optimal scheduling considering electric energy and reserve markets

The concept of cryogenic energy storage (CES) is to store energy in the form of liquid gas and vaporize it when needed to drive a turbine. Although CES on an industrial scale is a relatively new approach, the technology is well-known and essentially part of any air separation unit (ASU) that utilizes cryogenic separation. In this work, we assess the operational benefits of adding CES to an existing air separation plant. We investigate three new potential opportunities: (1) increasing the plant’s flexibility for load shifting, (2) storing purchased energy and selling it back to the market during higher-price periods, (3) creating additional revenue by providing operating reserve capacity. We develop a mixed-integer linear programming (MILP) scheduling model and apply a robust optimization approach to model the uncertainty in reserve demand. The proposed model is applied to an industrial case study, which shows significant potential economic benefits

Sector coupling via hydrogen to lower the cost of energy system decarbonization

There is growing interest in using hydrogen (H2) as a long-duration energy storage resource in a future electric grid dominated by variable renewable energy (VRE) generation. Modeling H2 use exclusively for grid-scale energy storage, often referred to as “power-to-gas-to-power (P2G2P)”, overlooks the cost-sharing and CO2 emission benefits from using the deployed H2 assets to decarbonize other end-use sectors where direct electrification is challenging. Here, we develop a generalized framework for co-optimizing infrastructure investments across the electricity and H2 supply chains, accounting for the spatio-temporal variations in energy demand and supply. We apply this sector-coupling framework to the U.S. Northeast under a range of technology cost and carbon price scenarios and find greater value of power-to-H2 (P2G) vs. P2G2P routes. Specifically, P2G provides grid flexibility to support VRE integration without the round-trip efficiency penalty and additional cost incurred by P2G2P routes. This form of sector coupling leads to: (a) VRE generation increase by 13–56%, and (b) total system cost (and levelized costs of energy) reduction by 7–16% under deep decarbonization scenarios. Both effects increase as H2 demand for other end-uses increases, more than doubling for a 97% decarbonization scenario as H2 demand quadruples. We also find that the grid flexibility enabled by sector coupling makes deployment of carbon capture and storage (CCS) for power generation less cost-effective than its use for low-carbon H2 production. These findings highlight the importance of using an integrated energy system framework with multiple energy vectors in planning cost-effective energy system decarbonization