What is the cost of zero-carbon hydrogen with CCS?
Mr Daniel Mullen, School of Engineering, University of Edinburgh
Prof Mathieu Lucquiaud, Department of Mechanical Engineering, University of Sheffield & School of Engineering, University of Edinburgh
To achieve the balance of sources and sinks of greenhouse gases required by the Paris Climate Change Agreement, industrial carbon dioxide (CO2) emissions must be reduced as closely as possible to zero, and any residual greenhouse gas emissions must be offset by removing excess CO2 from the atmosphere.
The role of hydrogen as a zero-carbon energy vector could be essential in decarbonising key sectors of the economy, both for industrial and domestic use.
However, hydrogen produced from natural gas with CCS can only be truly carbon neutral, and therefore compatible with net-zero commitments, if the following two conditions are met:
- CO2 emissions occurring at the point of hydrogen production from natural gas must tend to zero.
- Emissions of natural gas in the supply chain, i.e. occurring upstream from hydrogen production, and all emissions associated with the construction of the hydrogen plant and the CCS infrastructure are offset with some form of negative emission technology.
For the latter, the choice of the offset matters greatly, with only permanent geological CO2 storage ensuring that the offset is compatible with long-term climate targets1. Rolling out current best practices to reduce supply chain emissions must also clearly take place.
In our recent work, we examine the cost of truly zero-carbon hydrogen production from natural gas, with 100% of the fossil carbon entering the hydrogen plant being captured, and the offsetting of supply chain and construction emissions with direct air capture (DAC) and permanent geological CO2 storage.
Capturing 100% of the fossil carbon entering a hydrogen plant, i.e. achieving zero direct emissions of fossil CO2, is possible with a moderate oversizing of the post-combustion CO2 capture process. This achieves an overall CO2 capture level of 99.8% of all the carbon entering the hydrogen plant, with the remaining 0.2% of uncaptured CO2, comprising atmospheric CO2, brought in with the combustion air and passing through the hydrogen plant. These ultra-high capture levels in excess of 99% are possible with existing post-combustion CO2 capture technology and were recently demonstrated at industrial scale at Technology Centre Mongstad with open art solvents2.
Our techno-economic model shows that operating at zero direct emissions can be achieved cost-effectively at a levelised cost of hydrogen (LCOH) of 53£/MWhth HHV or 2.1£/kg. This is based on a Steam Methane Reformer (SMR) plant with a capacity of 1 GW, 2020 UK capital costs of 804M£ and a mid-range natural gas and electricity prices of 22.5£/MWh and 46 £/MWh respectively.
This compares to current estimates for the levelised cost of hydrogen produced from electrolysis with dedicated renewable electricity of 97-116£/MWh (3.8 - 4.6£/kg)3.
From zero direct emissions to net-zero hydrogen
To achieve net-zero hydrogen production across the supply chain, we examine the cost implications of using direct air capture with safe, permanent, geological CO2 storage as a long-term carbon offset. Although the technologies are relatively new, early commercial projects of moderate scale are in operation4, and a commercial project in the USA with a capacity of 1 million tonnes of CO2 per year is at the Front End Engineering Design (FEED) study stage5.
Although advancing from a FEED study to a final investment decision has been a tortuous path for most UK CCS projects, these early projects give confidence that DAC can be deployed at the million tonne scale.
Our analysis reflects the uncertainty of the long-term cost of DAC by using an extended range of 100-500£/tCO2 for the levelised cost of air capture. As DAC is predicted to be more costly than other forms of negative emissions6, the upper end of this range represents a worst-case scenario for CO2 emissions offset.
For new hydrogen plants with CCS, DAC can offset the estimated 1.1 million tonnes of CO2 associated with the construction of the SMR, as well as the construction and operation of the CCS infrastructure at an additional cost to production of 0.5-2.6£/MWhth (0.02-0.10£/kg).
Crucially, it can also offset natural gas supply chain emissions at an additional cost to production of 0.5-32.0£/MWhth (0.02-1.26£/kg), depending on emissions and the cost of DAC. Emission rates as low as 0.1% are reported in regions implementing best practices, such as Norway and Qatar, while rates of over 6% are reported in areas such as Libya and Iraq. A mid-range value of 1.5% for life cycle assessments (LCA) is recommended in a recent, comprehensive paper by Bauer et al.5.
Figure 1 shows the premium to offset supply chain emissions and deliver natural gas to the point of conversion to hydrogen, using the metric from the latest IPCC report[†] to represent the global warming potential of methane7.
Figure 1: The additional cost to natural gas price to offset supply chain emissions, for a range of supply chain emissions and costs of direct air capture. For comparison, the gas price in our study is 22.5£/MWh. This translates into a levelised cost of hydrogen of 64£/MWhth (2.5£/kg) for a mid-range representative case of 1.5% natural gas supply chain emissions and a DAC price of 300£/tCO2.
Should best practices in managing supply chain emissions of natural gas rates be rolled out to reduce emissions globally to 0.2%, the cost of net-zero hydrogen could be as low as 54-57£/MWhth (2.1-2.3£/kg), as shown in Figure 2.
Figure 2: Levelised cost of net-zero CO2 hydrogen with CCS, for a range of costs of direct air capture and supply chain emissions. The green line represents a possible future if best practice were implemented globally.
Zero-carbon hydrogen from natural gas is possible at an acceptable price to consumers, should long-term gas prices return to their early 2020s levels. The first step is to achieve zero direct emissions, by nudging the industry in the right direction. The second step requires much more. Recent pledges at COP26 to reduce global methane emissions by 30% by 2030 are a welcome step to make hydrogen more climate compatible, yet there can be no future for hydrogen from natural gas without deploying cost–effective, large-scale negative emission technologies.
[†] While natural gas is a more potent greenhouse gas than CO2, it is shorter-lived in the atmosphere (11.8 ± 1.8 years)7 and does not accumulate in the same way as CO2. Recent research at Oxford University8, 9 recommends the use of a new metric GWP* which traces global temperature response to methane emissions to a much higher degree of accuracy. The primary value of GWP* used in our analysis is 19.5 tCH4/tCO2. This represents the highest value of GWP* occurring during the intermediate emissions pathway RCP4.5 (7) which results in a long term increase in global surface temperature of 2.1–3.5oC, and should therefore, hopefully, be considered a worst-case scenario.
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2. Ismail Shah M, Silva E, Gjernes E, Åsen Ingvar K. Cost Reduction Study for MEA based CCGT Post-Combustion CO 2 Capture at Technology Center Mongstad. 15th Greenhouse Gas Control Technologies Conference; 15-18 March 2021; Abu dhabi: SSRN; 2021.
5. IEA. DAC1: IEA; 2021 [Available from: https://www.iea.org/reports/ccus-around-the-world/dac-1.
6. Fuss S, F Lamb W, Callaghan MW, Hilaire J, Creutzig F, Amann T, et al. Negative emissions - Part 2: Costs, potentials and side effects. Environmental research letters. 2018;13(6).
7. Masson-Delmotte V, Pirani A, Chen Y, Matthews JBR, Yelekçi O, Lonnoy E, et al. Climate Change 2021: The Physical Science Basis. Cambridge University Press: IPCC; 2021.
8. Cain M, Lynch J, R. Allen M, S. Fuglestvedt J, J. Frame D, H Macey A. Improved calculation of warming-equivalent emissions for short-lived climate pollutants. Climate and Atmospheric Science. 2019;2.
9. Smith MA, Cain M, Allen MR. Further improvement of warming-equivalent emissions calculation. Climate and Atmospheric Science. 2021;4.