Carbon Intensity of Blue Hydrogen Revised
Carbon Intensity of Blue Hydrogen Revised
Carbon Intensity of Blue Hydrogen Revised
Carbon intensity of
blue hydrogen production
Accounting for technology and upstream emissions
Jan Gorski, Tahra Jutt, Karen Tam Wu | August 2021 (revised)
photo: Roberta Franchuk, Pembina Institute
Carbon intensity of blue hydrogen production
Accounting for technology and upstream emissions
by Jan Gorski, Tahra Jutt, Karen Tam Wu | August 2021 (revised)
Introduction
As Canada considers pathways to net-zero emissions by 2050, blue hydrogen — hydrogen gas
derived from natural gas with carbon capture, utilization and storage (CCUS) — is receiving
significant interest as an energy carrier. There are many competing claims about the climate
benefits of blue hydrogen. This is partly because differences in production methods, technology
choices, gas supply, energy requirements, and carbon capture rates lead to different estimates
of emissions. As well, because blue hydrogen is created from fossil fuels, the emissions
associated with the production and transportation of the fossil fuel source must also be
included in its emissions profile.
In this paper we examine the emissions associated with blue hydrogen over the full life cycle,
and the potential contribution and limits of CCUS technologies to decrease production
emissions.
Steam methane reforming (SMR) uses steam to separate the hydrogen from natural
gas.1 Most SMR facilities in current operation produce hydrogen for use as a feedstock to
other processes such as oil refining, fertilizer, or chemical production.
1
Global Syngas Technologies Council, “Steam-Methane Reforming.” https://globalsyngas.org/syngas-
technology/syngas-production/steam-methane-reforming/
Auto-thermal reforming (ATR) is a commercial technology commonly used in the
production of ammonia and methanol.2 ATR is now being proposed as a preferred
technology to produce pure hydrogen from natural gas because it allows capture of
carbon at higher rates than conventional SMR, at lower cost.3 Compared to SMR, ATR has
a simpler production stream, with a high concentration of carbon dioxide. This makes it
easier to capture a higher percentage of carbon emissions in the conversion process.4
With blue hydrogen, the amount of carbon captured and stored from the production process is
a key factor in the carbon intensity of the hydrogen produced. CCUS is discussed in greater
detail below.
2
Global Syngas Technologies Council, “Auto-Thermal Reforming.” https://globalsyngas.org/syngas-
technology/syngas-production/auto-thermal-reforming/
3
Hydrogen Council, Path to hydrogen competitiveness: A cost perspective (2020), 21. https://hydrogencouncil.com/wp-
content/uploads/2020/01/Path-to-Hydrogen-Competitiveness_Full-Study-1.pdf
4
S. Assabumrungrat and N. Laosiripojana, “Fuels — Hydrogen Production: Autothermal Reforming,” Encyclopedia of
Electrochemical Power Sources (Elsevier Science, 2009).
https://www.sciencedirect.com/topics/engineering/autothermal-reforming
Upstream emissions
Emissions associated with producing, processing, and transporting natural gas — known as
upstream emissions — are also a significant contributor to the carbon intensity of blue
hydrogen production. The source of these emissions is methane vented or leaked during
production, processing, and transport, and fuel burned to power engines, compressors, boilers,
and heaters. These emissions vary based on the composition of gas found in different natural
gas reservoirs, the amount of gas processing required, the ratio of natural gas to electric power
used in the process and transport of gas, and the carbon intensity of the electricity that is used.
They can also vary significantly depending on the amount of methane leaked and vented in the
process and the stringency of regulations at a regional level that prevent methane emissions.
Carbon capture rates of 90% have been demonstrated but have not yet been applied to the
production of hydrogen by SMR.6 This is because existing blue hydrogen production is
integrated into refineries and ammonia plants — facilities where the end product is not
hydrogen. As a result, the design of the plant is specific to the application. These existing
integrated hydrogen plants were retrofitted to capture carbon and are not representative of
what can be achieved at new hydrogen production plants designed to produce hydrogen as a
commercial fuel. The Polaris project proposed by Shell aims to capture more than 90% of the
CO2 emissions related to hydrogen production in the Scotford refinery hydrogen plants.7
5
Path to hydrogen competitiveness, 21.
6
90% was demonstrated at the Petra Nova coal powered electricity plant demonstration project in Texas. NRG
Energy, “Petra Nova: Carbon capture and the future of coal power.” https://www.nrg.com/case-studies/petra-
nova.html
7
Shell, “Shell proposes large-scale CCS facility in Alberta,” news release, July 13, 2021.
https://www.shell.ca/en_ca/media/news-and-media-releases/news-releases-2021/shell-proposes-large-scale-ccs-
facility-in-alberta.html
If an SMR facility with CCUS captures 80% of its carbon process stream — but only about 60% of
carbon is emitted in the process stream — it captures only 48% of the total carbon produced
(see Figure 2).
Auto-thermal
reforming CO2
(ATR) with CCS
CO2 captured
Process gas
Auto- thermal Carbon Hydrogen
reformer capture purification H2
CO2
Natural gas
(feed)
8
Path to hydrogen competitiveness, 21.
CCUS at a glance
Carbon capture, utilization and storage (CCUS) is a process by which carbon dioxide emissions
produced from the combustion of fossil fuels (combustion emissions), or from the industrial
processes themselves (process emissions) are separated from other gases and stored
underground. The three main types of carbon capture technology are pre-combustion, post-
combustion and oxyfuel combustion. Capture technologies are generally categorized by the
method used to separate CO2 from the gas stream. The five broad categories are liquid solvent,
solid absorbent, membrane, solid looping, and inherent CO2 capture. In total there are 25
separate technologies encompassing the five categories.9
Carbon capture, utilization and storage is a tool to lower the carbon emissions from hydrogen
production. CCUS is a process by which CO2 emissions produced from the combustion of fossil
fuels (combustion emissions) or from the industrial processes themselves (process emissions)
are separated from other gases. The CO2 is then compressed, transported via pipelines, and
injected deep underground for permanent storage. The separated and purified carbon can also
be utilized in the manufacture of other products.10
To date, CCUS has mainly been used to reduce emissions from power generation (using
coal/natural gas), natural gas processing, refining and upgrading, and chemical and fertilizer
production. Around the world, there are 26 CCUS plants in operation, of which three are
associated with hydrogen production.11
The carbon capture rate is one of the key determinants of the carbon intensity of blue
hydrogen. To make hydrogen that can be part of a climate solution, production processes
require carbon capture systems that deliver high capture rates. Capture rates of 95% are
technically possible and have been proposed at new facilities.12 However, no plants in current
commercial operation demonstrate these maximum capture rates.
9
Global CCS Institute, Technology Readiness and Costs of CCS (2021). https://www.globalccsinstitute.com/wp-
content/uploads/2021/04/CCS-Tech-and-Costs.pdf
10
Canada is home to 27 of the world’s 181 carbon utilization projects and well placed to be a leader in this field. See:
The Carbontech Innovation System in Canada (Pembina Institute, 2020). https://www.pembina.org/pub/carbontech-
innovation-system-canada
11
Global CCS Institute, Global Status of CCS 2020, 19. https://www.globalccsinstitute.com/wp-
content/uploads/2020/12/Global-Status-of-CCS-Report-2020_FINAL_December11.pdf
12
International Energy Agency, Towards zero emissions CCS in power plants using higher capture rates or biomass
(2019). https://ieaghg.org/publications/technical-reports/reports-list/9-technical-reports/951-2019-02-towards-
zero-emissions
Grey H2
ATR, average
ATR, best
Blue H2
SMR, existing (Quest)
SMR, best
Wind
Green H2 Hydro
Solar
0 10 20 30 40 50 60 70 80 90 100
GHG intensity (kg CO2e/GJ H2)
Plant construction Plant operation Electricity Natural gas production and transport
As Figure 3 demonstrates, there are a wide range of carbon intensities for blue hydrogen,
depending on the choice of technology (SMR or ATR), carbon capture rate, emissions
associated with imported electricity, and the emissions from natural gas production (which
vary by production basin). Existing production at the Shell Quest facility has a higher carbon
intensity primarily driven by a lower carbon capture rate. New SMR and ATR facilities can
achieve much better performance if they capture over 90% of plant emissions, if emissions from
natural gas production are reduced, and if the electricity for the process is produced from non-
emitting sources. Emissions from construction of SMR and ATR plants with CCS are negligible
over the volume of hydrogen produced.
Grey hydrogen is produced from natural gas (via SMR or ATR), but without carbon capture, so
its emissions intensity is highest.
Appendix 2 shows the sources of emissions in the life cycle of green and grey hydrogen
production.
13
Capture rates are estimated based on reported quantity of CO2 captured at each facility and GHG emissions from
the facility reported in national inventories.
14
Equinor, “H2H Saltend.” https://www.equinor.com/en/what-we-do/h2hsaltend.html
In order to be consistent with carbon neutral by 2050, new hydrogen production will need to
have a carbon capture rate over 95% and low upstream emissions. Ultimately, hydrogen
production will need to have net-zero life cycle emissions by reducing facility and upstream
emissions as much as possible and offsetting the remainder.
Energy conservation and renewable energy play a large role in meeting our future energy
demands; the IEA’s scenario shows low carbon and renewable hydrogen could play a large role
in the future with hydrogen demand rising more than six-fold in 2050.18 In this scenario, more
than 60% of hydrogen production is green (i.e. using water electrolysis).19
The IEA suggests, however, that broad use of hydrogen across sectors will require significant
investment and planning, and points to the difficulty and costs of transporting hydrogen long-
distances: “Developing the infrastructure for hydrogen at the pace required in [the net-zero
scenario] would involve considerable investment risks along the value chain of production,
15
Air Product, “Air Products Announces Multi-Billion Dollar Net-Zero Hydrogen Energy Complex in Edmonton,
Alberta, Canada,” news release, June 9, 2021. https://www.airproducts.com/news-center/2021/06/0609-air-products-
net-zero-hydrogen-energy-complex-in-edmonton-alberta-canada
16
BP, “BP plans UK’s largest hydrogen project,” news release, March 18, 2021.
https://www.bp.com/en/global/corporate/news-and-insights/press-releases/bp-plans-uks-largest-hydrogen-
project.html
17
International Energy Agency, Net Zero by 2050: A Roadmap for the Global Energy Sector (2021)
https://www.iea.org/reports/net-zero-by-2050
18
Net Zero by 2050, 129.
19
Net Zero by 2050, 76.
A large share of emissions reductions from fossil fuels outlined in the IEA’s net-zero pathway is
due to the elimination of all technically avoidable methane emissions by 2030. Methane
emissions — which have significantly higher global warming impact than CO2 does —
amounted to 98 megatonnes in 2019, or 13% of Canada’s total greenhouse gas emissions. These
came mostly in the form of vented and leaked gas from oil and natural gas systems, with further
emissions from agriculture and landfills. As discussed above, methane is a source of emissions
in the life cycle of blue hydrogen; the long term viability of blue hydrogen as a low-carbon
energy carrier depends on addressing these upstream emissions.
Conclusion
Any investment in blue hydrogen will have to consider the full life cycle impacts of hydrogen
production and distribution. If blue hydrogen is to be able to compete as a contributing
pathway to a net-zero future, significant emissions must be addressed, including emissions
from plant operation and upstream natural gas extraction. Upstream emissions from natural
gas extraction will have to be virtually eliminated and a rate of carbon capture above 95% will
need to be employed.
Currently, production of hydrogen as an energy carrier is still in its early stages. Most blue
hydrogen facilities in operation today are integrated into refineries and fertilizer plants and
were built before carbon pricing and meaningful climate targets called for high rates of capture.
New facilities built to produce hydrogen as a mass market fuel will need to adopt the best
available technology and achieve carbon capture rates over 95% to provide return on
investment with a net climate benefit by significantly lowering the carbon intensity for blue
hydrogen.
By 2050 all fuels used, including hydrogen, will need to be close to carbon neutral.
Governments and proponents will need to provide rigorous, consistent information on life
cycle emissions intensity of proposals.
20
International Energy Agency, Techno-Economic Evaluation of SMR Based Standalone (Merchant) Hydrogen Plant with
CCS (2017). https://ieaghg.org/exco_docs/2017-02.pdf
21
One tonne of hydrogen can fuel 2000 light duty vehicles per day, assuming a hydrogen consumption rate of 0.5
kg/vehicle/day.
The baseline gas leak rate was calculated to be 1.0% in Alberta and 0.26% in British Columbia,
excluding oilsands methane emissions, based on 2018 data.24 In the analysis presented here,
leak rates in Alberta and B.C. of 0.6% and 0.16%. were used, accounting for a 40% reduction in
methane emissions from 2012 levels which is in line with the current federal target. Leak rates
are calculated based on the amount of gas that vented and leaked from the natural gas supply
chain divided by total gross natural gas production.
22
Government of Canada, 2021 National Inventory Report (NIR) (2021).
https://open.canada.ca/data/en/dataset/779c7bcf-4982-47eb-af1b-a33618a05e5b
23
Statistics Canada, “Supply and disposition of natural gas, monthly (data in thousands) (x 1,000)” Table 25-10-
0055-01 (August 2021).
https://www150.statcan.gc.ca/t1/tbl1/en/tv.action?pid=2510005501&pickMembers%5B0%5D=1.1&pickMembers%5
B1%5D=3.2&cubeTimeFrame.startMonth=01&cubeTimeFrame.startYear=2016&cubeTimeFrame.endMonth=05&cu
beTimeFrame.endYear=2021&referencePeriods=20160101%2C20210504
24
This is comparable to a leak rate of 1.4% based on the U.S. Environmental Protection Agency national inventory.
Ramón A. Alvarez et al., “Assessment of methane emissions from the U.S. oil and gas supply chain,” Science 361, no.
6398, (2018). https://science.sciencemag.org/content/361/6398/186
25
“Assessment of methane emissions from the U.S. oil and gas supply chain,”
26
Elton Chan et al., “Eight-Year Estimates of Methane Emissions from Oil and Gas Operations in Western Canada
Are Nearly Twice Those Reported in Inventories,” Environmental Science and Technology 54, 23, (2020).
https://pubs.acs.org/doi/10.1021/acs.est.0c04117
27
Matthew R. Johnson et al., “Comparisons of Airborne Measurements and Inventory Estimates of Methane
Emissions in the Alberta Upstream Oil and Gas Sector,” Environmental Science and Technology 51, no. 21 (2017).
https://pubs.acs.org/doi/10.1021/acs.est.7b03525
28
Matthew R. Johnson and David R. Tyner, “A case study in competing methane regulations: Will Canada’s and
Alberta’s contrasting regulations achieve equivalent reductions?” Elementa: Science of the Anthropocene 8, no. 7
(2020). https://online.ucpress.edu/elementa/article/doi/10.1525/elementa.403/112749/A-case-study-in-competing-
methane-regulations-Will
29
Jan Gorski, The case for raising ambition in curbing methane pollution (Pembina Institute, 2021).
https://www.pembina.org/pub/case-raising-ambition-curbing-methane-pollution
Blue H2
ATR, average 95% 11.1 3.5 8.7 23.4 Alberta gas Alberta electricity grid negligible
performance average GHG intensity
GHG intensity = 8.4
from 2023 to 2042,
kg CO2e/GJ natural
based on CER 2020
gas (0.6% leak rate)
evolving scenario
SMR, 48% 11.1 36.6 6.1 53.8 Alberta electricity grid negligible
existing GHG intensity in 2019
(Quest) from NIR 2021 report
ATR, high 95% 6.7 3.5 0.4 10.6 B.C. gas BC electricity grid negligible
performance average GHG intensity
GHG intensity = 5.1
from 2023 to 2042,
kg CO2e/GJ natural
SMR, high 90% 6.7 7.0 0.2 14.0 based on CER 2020 negligible
gas (0.16% leak
performance evolving scenario
rate)
30
Pamela L. Spath and Margaret K. Mann, Life Cycle Assessment of Hydrogen Production via Natural Gas Steam Reforming (National Renewable Energy Laboratory, 2001).
https://www.nrel.gov/docs/fy01osti/27637.pdf
Green H2
31, 32
Wind -- -- -- -- 3.3 3.3
The higher heating value of hydrogen and natural gas was used to convert the GHG intensity from a mass to energy basis.
31
Electricity consumption for green hydrogen from: Zen and the Art of Clean Energy Solutions, British Columbia Hydrogen Study (2019).
https://www2.gov.bc.ca/assets/gov/government/ministries-organizations/zen-bcbn-hydrogen-study-final-v6.pdf
32
Life cycle GHG emissions of electricity generation from: IPCC, “Annex III: Technology-specific cost and performance parameters.” In: Climate Change 2014:
Mitigation of Climate Change. Contribution of Working Group III to the Fifth Assessment Report (2014).
https://www.ipcc.ch/site/assets/uploads/2018/02/ipcc_wg3_ar5_annex-iii.pdf
ATR, average
ATR, best
Blue H2
SMR, existing (Quest)
SMR, best
Wind
Green H2 Hydro
Solar
0 10 20 30 40 50 60 70 80 90 100
GHG intensity (kg CO2e/GJ H2)
Plant construction Plant operation Electricity Natural gas production and transport
CO2
CH4 CO2 H2
NATURAL GAS
HYDROGEN HYDROGEN
EXTRACTION AND
PRODUCTION TRANSPORT
TRANSPORT
(SMR or ATR)
CO2
ELECTRICITY
PRODUCTION
FACILITY
CONSTRUCTION
H2
HYDROGEN HYDROGEN
PRODUCTION TRANSPORT
from water