As green hydrogen experiences growing pains, blue hydrogen is benefitting from a boost.
Made from fossil fuels with the addition of carbon capture and storage (CCS), blue hydrogen is seen as one option to help clean up existing production of hydrogen from unabated fossil fuels.
In an attempt to encourage its scale-up, pushes to loosen production rules have taken place from the United States to the European Union. Most recently, Germany vowed to scrap the EU’s definition of green hydrogen for use in support schemes, treating both green and blue hydrogen equally.
Yet examining the technical and economic realities of CCS reveals multiple challenges plague blue hydrogen production, as they do green hydrogen.
In short? Producing blue hydrogen with low greenhouse gas emissions is technically possible, but commercially challenging. Without ambitious emission standards, there is no justification for costly blue hydrogen production.
Below, we lay out six evidence-based takeaways to cut through the noise surrounding blue hydrogen, examining what makes it a higher-risk energy transition option than green hydrogen.
Blue hydrogen is not a low-cost alternative to green hydrogen
Right now, blue hydrogen is the cheapest method of producing potentially clean hydrogen – but this does not mean that it is low-cost.
Blue hydrogen costs significantly more than the natural gas it is made from, due to the extra energy and additional equipment required to produce it. Its cost depends on two main elements: the hydrogen production process, and CCS.
The cost of blue hydrogen production increases in line with what fraction of the carbon is to be captured and stored. This means that producing acceptably clean blue hydrogen comes at a higher cost.
Truly low-carbon blue hydrogen that delivers on its climate promises is not yet in production. Cost estimates come with significant uncertainties, including CCS performance risks and gas price volatility.
A significant cost gap will remain between blue hydrogen and conventional grey hydrogen, made from fossil fuels without CCS, for the foreseeable future. This makes it a commercially unattractive option for hydrogen offtakers, similarly to green hydrogen, without policy intervention from governments.
Carbon capture is always partial, and most projects capture less than half of CO2 produced
Carbon capture is not a new technology. The oil and gas industry has been using it for decades, for example, to remove carbon dioxide (CO2) from natural gas to meet gas sales specifications. However, while partial carbon capture and storage on hydrogen projects has been trialed at scale, truly low-emissions blue hydrogen has yet to be produced.
Carbon capture is always partial: high capture rates are technically possible, but economically challenging. Achieving high carbon capture rates around 90% is possible but very expensive, requiring new, bespoke equipment.
Because of this, the level of CO2 capture on a real-world blue hydrogen plant will almost certainly be much lower than 90%.
While CO2 capture is a routine industrial process, no CCS project has ever reached its target CO2 capture rate. An IEEFA review of 16 projects found that despite claims a 95% capture rate is achievable, no existing project has consistently captured more than 80% of CO2. Most capture less than 50%.
True to this, one of the world’s only operating blue hydrogen production plants, the Shell Quest project in Canada, is capturing less than half (45%) of the total CO2 it is producing. Once the emissions of methane, and of CO2 from energy production to operate the CCS equipment are considered, the net capture rate drops to as low as 21%.
Underground CO2 storage has a record of complexity and underperformance
Most operational CCS projects today do not permanently store the CO2 they capture, but instead inject it into oil reservoirs to help sweep more oil from reservoir rock in a process known as “enhanced oil recovery”. This is not permanent storage, because much of the CO2 will be recovered again with the oil.
Only a small proportion of CCS projects to date have stored carbon in dedicated geological structures without using it for oil and gas production. Pilot projects carried out over the last 20 years are small in comparison to the storage aspirations in energy transition plans.
Large-scale CCS projects have proven most likely to fall short of expectations, with 78% of large-scale demonstration and pilot projects initiated between 1995 and 2018 cancelled or put on hold, according to a 2021 study. The risk of spiralling costs is also significant.
At present, permanent storage of captured CO2 underground is taking place at just 12 sites around the world, according to the Global Status of CCS 2024 report. This includes once again a single blue hydrogen project, the Shell Quest project in Canada.
Shell Quest has operated for over six years, storing roughly one million tonnes of captured CO2 underground per year. However, this still represents just a small percentage of the plant’s total greenhouse gas emissions, and a small fraction of global hydrogen production CO2 emissions, which are estimated to be about 2,000 million tonnes per year.
Similar to all CCS projects, future blue hydrogen projects will face the challenge of ensuring storage site monitoring continues after a storage contract period has lapsed, to guarantee CO2 storage is permanent. The additional cost of this monitoring, and the risk of far more significant costs if remedial action is required, will inevitably be carried by society many decades into the future.
CCS makes blue hydrogen production more gas-intensive
Blue hydrogen production requires more energy, most likely in the form of natural gas, than conventional hydrogen production from unabated fossil fuels. This makes it significantly more capital and fossil fuel-intensive.
Extra feed gas is required because producing blue hydrogen with a high CO2 capture rate involves both a less efficient production process, and additional energy to power CCS.
The most efficient process for producing hydrogen from natural gas is steam methane reforming (SMR). However, conventional SMR involves combustion, and the capture of CO2 emissions from combustion equipment is challenging and expensive. As a result, the less efficient autothermal reforming (ATR) process must be used for a CO2 capture rate greater than about 60%.*
The use of ATR, rather than SMR, reduces hydrogen production energy efficiency from about 70% to about 60% in the best case. This means that before considering the energy required for CCS, 66% more gas is required to make one joule of energy in the form of blue hydrogen, than by burning the gas itself. This additional gas will increase supply chain and production emissions, particularly methane.
CCS also requires extra energy input, both in the form of electricity to run equipment, and in the form of heat. While some heat recovery from the process may supply some of the required heat, the remainder must be produced either from renewable electricity, by burning the expensive blue hydrogen product, or by burning natural gas. The latter two options will further increase supply chain emissions, while burning natural gas will also increase production emissions unless more expensive post-combustion CCS is implemented.
An additional consideration is that CCS systems also increase hydrogen production’s water demand, meaning blue hydrogen uses a third more water per kilogram of hydrogen produced than even the most water-intensive green hydrogen. However, as with all hydrogen production processes, the real challenge is energy use, rather than water use.
Blue hydrogen’s supply chain emissions could outdo the benefits of CCS
CCS only tackles CO2 released directly during blue hydrogen production. It doesn’t reduce other greenhouse gas emissions along the blue hydrogen supply chain.
Beyond CO2, emissions from both methane and hydrogen itself are part of the blue hydrogen life cycle.
With leaking and deliberate venting along their supply chains, both of these gases have global warming potentials many times that of CO2. In the first 20 years after their release into the atmosphere, hydrogen emissions are 35 times more potent than CO2, while methane emissions are 84 times more potent.
Some methane leakage is unavoidable along the blue hydrogen supply chain, and just a few percent will undo the emission-reduction benefits of carbon capture.
Because of this, peer-reviewed studies have found that blue hydrogen has the potential to release a cocktail of emissions with climate impacts worse than simply burning fossil fuels outright.
Blue hydrogen isn’t a short-term solution or shortcut to cleaner hydrogen
Existing hydrogen production cannot be fully decarbonised by adding a CCS component. Rather than decarbonising existing facilities, producing blue hydrogen with high CO2 capture rates requires brand new plants.
This is because existing production largely relies on the process of steam methane reforming (SMR), which is incompatible with CO2 capture rates above 60%. As a result, most blue hydrogen production plans favour the autothermal reforming (ATR) process, which creates a single source of high-pressure CO2 that makes it possible to achieve capture rates of 90-95%.
Plants used to manufacture blue hydrogen typically have an operational life of at least 30 years, in order to recover their high capital cost. Similarly, the commercial viability of underground CO2 storage depends on supply commitments spanning decades.
As a result, any blue hydrogen plant and its CO2 storage scheme built in the next decade will probably still be operating into the 2060s, unless governments pay to shut it down.
Blue hydrogen projects are thus long-term investments with commercial life spans of several decades. They cannot be considered a temporary bridge, stopgap or short-term measure to fast-track a clean hydrogen economy.
Conclusion: Blue hydrogen’s credibility depends on ambitious low-emissions hydrogen standards, to justify its expensive production and mitigate its risks compared to green hydrogen.
Expensive, gas-intensive, and dependent on CCS technology with a problematic track record, blue hydrogen is a risky option for producing clean hydrogen. Should it fail to deliver the climate benefits that it promises, there is no justification for its implementation.
Blue hydrogen’s risks must be mitigated by robust standards to reliably ensure that it meets the same emissions levels as green hydrogen, the only near-zero emission form made from renewable energy. You can read more about the HSC’s definition of clean hydrogen here.
Important hydrogen standards are being finalised by both the European Union and International Organization for Standardization (ISO) this year, as countries around the world continue work to define what qualifies as ‘clean’, ‘low-emissions’ or ‘low-carbon’ hydrogen.
The ambition of these standards will be critical to ensuring blue hydrogen achieves the high carbon capture rates and permanent CO2 storage necessary to help, rather than harm, the energy transition and industrial resilience.
This will limit CCS performance risks and ensure a level playing field with green hydrogen, which offers more reliable emissions reductions, eliminates fossil fuel dependency, and has a more favourable long-term economic outlook.
Notes
*In theory, electrically-heated SMR could also be used, but this has not been done beyond pilot scale as it is very expensive and challenging.
How does CCS work in blue hydrogen production?
Blue hydrogen produced via the most popular autothermal reforming (ATR) process involves three inputs: natural gas, water/steam, and oxygen.
Steam, pure oxygen (made by the liquefaction of air) and natural gas are combined and fed to a special burner inside the ATR unit, where the natural gas is partially combusted to produce heat, carbon monoxide, CO2 and more water vapour. The hot gas stream then passes over a catalyst where the remaining methane and water are reacted with one another (reformed) to produce a mixture of carbon monoxide, CO2, hydrogen, and left-over water vapour. The extremely hot stream is cooled in a boiler, which makes steam to supply the process. The gas mixture is then passed through several stages of water-gas shift reactors, where carbon monoxide is reacted with water to make hydrogen and more CO2. The hydrogen/CO2 stream is then cooled to condense and remove water.
A chemical is then used to remove the CO2 from the hydrogen. The most common chemical type for the task is an amine, which has an end that readily reacts with CO2 and not hydrogen. Hydrogen that has passed through the amine unit is then further purified to remove trace amounts of CO2, carbon monoxide and methane. These separation steps usually produce a waste stream of mostly hydrogen, containing traces of carbon monoxide, CO2 and methane, which must be disposed of in some way. If this stream is combusted, which is the normal process used in steam methane reformer (SMR) units, uncaptured CO2 emissions occur. In blue hydrogen ATR plants, this waste gas stream will likely be compressed and fed back to the reformer, requiring extra equipment and electricity.
The CO2 that has reacted with the amine is then removed, which is done by heating the amine. The separated CO2 contains water, which has to be removed to avoid equipment and pipe corrosion using another chemical (glycol). The dry CO2 is then compressed to a pressure high enough to transport it to the site where it will be stored.
