2.2.1 Increasing plant and stack size plus increased efficiency of hydrogen production and CO2 capturing processes

Almost all hydrogen in Europe is currently produced by grey hydrogen production routes. Green and blue hydrogen production routes are only in an early commercial stage (<1% of EU hydrogen production).

In the EU, around 339 TWhLHV (10.2 Mt H2, 33 bcm natural gas equivalent) of hydrogen was produced in 2019,46 constituting around 13% of the global production. Compared to grey hydrogen, the share of green and blue hydrogen produced is still small at less than 1% of production in the EU (Figure 2.18).47

Renewable and low-carbon hydrogen can be produced through multiple technology and feedstock routes (Figure 2.19).

The fossil-based production route without applying carbon capture (grey hydrogen) is an emissions-intensive process, leading to life cycle emissions ranging from 104 to 237 gCO2-eq./MJ (12.5-28.4 tCO2-eq./t H2) depending on the production technology and feedstock.48 Renewable and low-carbon production can be achieved through water electrolysis using renewable electricity or thermochemical conversion of biomass (green hydrogen) or through capturing CO2 emissions from hydrogen produced from fossil feedstocks (blue hydrogen) or biomass feedstocks (climate-positive green hydrogen).

When using renewable electricity, electrolysis can achieve significant emission reductions compared tounabatedfossilroutes.Electrolysis-basedroutes can even achieve an emissions intensity that is one- third that of fossil routes that use carbon capture and storage (CCS) and a slightly lower greenhouse gas (GHG) intensity compared to hydrogen derived from biomass.48 However, capturing and storing CO2 emissions from the bio-conversion route could result in negative CO2 emissions, meaning more emissions are permanently sequestered than emitted (i.e. climate-positive hydrogen).

The basic process for grey or blue hydrogen production involves stripping fossil hydrocarbon molecules of their hydrogen atoms. Mature processes that deconstruct these molecules into smaller parts includereforming,partialoxidation,andgasification processes. These processes can, in principle, be performed on any fossil source such as natural gas, coal, and oil. The benefit of blue hydrogen is that the existing fleet of EU hydrogen plants can be retrofitted with CCS, rapidly scaling up the availability of low- carbon hydrogen to existing uses.

Alkaline Electrolysis (ALK), Proton Exchange Membrane (PEM) and Solid Oxide Electrolysis Cells (SOEC) technologies are considered the most mature technologies to produce electrolysis-based hydrogen. PEM energy efficiency has increased by 4% since 2017, whereas ALK and SOEC increased by 2%. The efficiency gap is slowly closing, although ALK will likely remain ahead for the foreseeable future.

Multiple types of electrolysers are being developed. Four water electrolysis technologies are considered in the advanced stages of maturity: ALK, PEM, SOEC, and AEM. Table 2.3 summarises their key technical parameters.

Table 2.3.
Overview of the key parameters of water electrolysis technologies (based on current values)49

Technology System efficiency (LHV) (%) Efficiency degradation (%/1,000hrs) Ramp up from standby mode Footprint (m2/MW) Current density (A/cm2) Use of critical raw materials in catalyst (mg/W) Maturity level
ALK 67% 0.12 60 seconds 100 0.6 0.6 Multiple commercial applications

(multi MW)

PEM 61% 0.19 2 seconds 60 2.2 2.7 Commercial scale up (multi MW)
SOEC 83%[24] 1.9 10 minutes 150 0.6 n/a Commercial scale up, small scale (MW)
AEM 61% >1.0 30 seconds 90 0.8 1.7 Commercial scale up, small scale (kW)

ALK are the most mature and least costly (€/kW) technology today, predominantly used for brine electrolysis.49 Some ALK system setups have limited ability to respond to load changes, which is essential for off-grid integration and the flexibility requirements of a power system with high penetration of renewables.51 R&D efforts in the industry have improved the response time significantly. thyssenKrupp, Nel, and McPhy are among the main ALK technology suppliers. thyssenKrupp recently announced it will significantly increase its production capacity for ALK electrolysers to 1 GW annually.52 Nel is planning to commence production in 2020 with an annual capacity of 360 MW in its new manufacturing plant, with for the possibility to further expand to 1 GW per annum.53 McPhy has raised capital to expand its manufacturing capacity and will target large-scale projects exceeding 100 MW scale.54

PEM electrolysers have a simple and compact design. They are more expensive than ALK electrolysers and have a lower system energy efficiency. However, they are flexible, with ramp-up or ramp-down times of econds.PEMelectrolysersoperateathigheroutput pressures (30 bar) compared to the majority of ALK systems.ThefocusforPEMremainsinthesearch for new materials in the stack and the recycling of the precious metals used. Technology companies like ITM Power, Nel, Siemens, Giner ELX, and Hydrogenics are among the main PEM technology providers. The largest PEM electrolyser currently in operation is the 6 MW PEM system at EnergiePark Mainz.49 The largest announcement to date in Europe is in Rhineland, Germany, where Shell and ITM Power are constructing a 10 MW electrolyser.55 In terms of manufacturing, ITM Power announced the construction of a new manufacturing facility that will enable an upgrade in production capacity to around 1 GW/year.56

SOECs are used for high temperature electrolysis and can also be used in co-electrolysis with CO2 to produce syngas for e-fuels or other chemical processes. SOEC technology is in an earlier stage of development49, yet it is promising as substantially higher efficiencies can be reached where waste steam is available. The main challenge is to resolve the degradation of materials.57 Sunfire and Haldor Topsoe are the main market players in the development of SOEC technology. Sunfire delivered the largest SOEC electrolyser of 720 kW of capacity to Salzgitter Flachstahl in Germany.58 A consortium of Sunfire, Climeworks, and EDF, under the name of Nordic Blue Crude, are developing a 20 MW power- to-liquids facility based on an SOEC system. The consortium’s aim is to scale this capacity 10-fold between 2022 and 2025.59

Another promising electrolyser technology is AEM electrolysis. AEM is a new technology in an early stage of development and is an upgrade of PEM electrolysers.60 Enapter announced the start of a 260 MW/year electrolyser production facility in Germany this year.61 From the announced green hydrogen projects in the EU and UK that have detailed their technology, 27% of the projects use ALK electrolysers, constituting 76% of the planned capacity.47 PEM technology is the technology of choice in 69% of announced projects, but that only reflects 21% of the announced capacity. This confirms that PEM projects are currently smaller in size compared to ALK projects. PEM technology has improved its system efficiency by 4% since 2017, reaching an average of 61% (LHV) in 2020. Expectations of PEM efficiency improvement were higher compared to what was achieved over the past years. System efficiencies for ALK and SOEC technologies were already higher and increased by 2% since 2017, reaching 67% and 83% in 2020, respectively.49 The efficiency gap between PEM, and ALK and SOEC technologies is slowly closing, although ALK efficiency will likely remain ahead for the foreseeable future.62 Efficiency is just one of the metrics to assess performance next to e.g. system flexibility,plantsize,andstackdegradation.

Maturing the electrolyser sector requires projects on the 100 MW to GW scale, which is a scale jump of 1-2 orders of magnitude from current levels. Currently announced EU projects suggest that this scale will be reached well before 2030.

Many hydrogen R&D projects have been developed over the past decade (Figure 2.21). This growth helped to increase the scale of electrolysers and increase the knowledge surrounding the integration of renewable power generation with electrolyser operation and hydrogen use in specific demand sectors, such as road transport. The number of R&D projects in the EU increased linearly to 227 in 2018. These R&D developments attracted about €844 million in EU R&D subsidies from the FP7 and H2020 programmes between 2008 and 2018, complemented by €886 million from other sources, including private company funding.63

The average sizes of operational and announced electrolyser projects suggest that project sizes are rapidly growing, from an average size of around 2 MWel in 2019 to 110 MWel in 2025 (Figure 2.22). Announced projects after 2025 have even larger capacities, with some projects exceeding 2.5 GWel in 2030.64

Steam methane reforming (SMR) and autothermal reforming (ATR) technologies are mature technologies for grey hydrogen production today; SMR is responsible for a majority of hydrogen production. However, newly announced blue hydrogen projects mostly rely on ATR technology as deploying this in combination with CCS at large scales has various economic and operational benefits.

Two mature hydrogen production technologies coupled with carbon, capture and storage (CCS) are the most discussed: SMR and ATR. Methane pyrolysis is another technology that can be used for the large- scale production of hydrogen, which is in an early stage of development.65 Methane pyrolysis is also a well-known process to produce e.g. carbon black.2, 65

SMR66 is a well-established and mature technology responsible for most grey hydrogen production.67 In the SMR process, natural gas and steam are fed to a reformer, through which synthesis gas is produced; this is mainly a mixture of hydrogen, water, carbon monoxide (CO), and CO2. SMR is among the cheapest methods to produce hydrogen, but it produces significant CO2 emissions. Emissions can come down with increased efficiency, high CO2 capture rates, and a change to bio-based feedstock (e.g. biomethane). Capturing and storing the CO2 enables the abatement of direct emissions in hydrogen plants (both SMR and ATR) by 60%-95%, depending on the CO2 capture technology and the use of natural gas or hydrogen as fuel for the furnace. Using hydrogen in the furnace eliminates one point-source of CO2, leaving only the CO2 from the shifted syngas. However, this increases CAPEX and OPEX.68 System efficiencies for SMR range between 69% and 85% without CCS, largely depending on scale and operating temperature.69, 70 Large-scale units generally have a better energy efficiency.71 Adding a CO2 capture unit usually leads to a drop in efficiency of about 2%, depending on the process and share captured.72 NTNU, for example, reports an efficiency of 82% including CCS.47

SMR plants, ranging from small- to large-scale, can be retrofitted with CO2 capture technology.6 Upstream emissions from natural gas production and distribution are still present, leading to a higher GHG intensity compared to green hydrogen production even when all direct plant emissions are abated. When aiming to maximise the abatement of site emissions, ATR is often preferred over SMR for greenfield blue hydrogen plants.

ATR is used to obtain syngas; it combines the SMR process with partial oxidation (POX) reaction which provides the process heat. Depending on the grid emission factor, unabated ATR can be more emissions-intensive compared to SMR due to the need for oxygen, which is produced in an air separation unit. However, ATRs have only one point- source of CO2 onsite, which facilitates CO2 capture and thereby the abatement of the site emissions. Various process designs quote an abatement of 95% of site emissions when CO2 capture is applied.73 Capture technologies that separate CO2 and hydrogen from the process gas in one process step with a vacuum pressure swing adsorption (VPSA) technology are under investigation. These technologies enable capture rates of up to 99% and increased system cost savings.74 Using low-cost by-product oxygen originated from the electrolysis process could further reduce indirect emissions from power generation at ATR plants.

The final choice for SMR or ATR depends on the project goals. An important difference is that ATR yields a lower H2 to CO ratio. Without CCS, ATR is generally preferred when the CO product is desired, e.g. for methanol production.75 Recently announced blue hydrogen projects note high reliability of ATR plants, with recorded utilisation as high as 99,7% in the methanol industry. ATR plants have a broad operating range with almost unlimited scalability compared to SMR and high flexibility.76 Capturing close to 100% of site emissions is also less costly for ATR. ATR is a therefore logical choice when the aim is to maximise CO2 capture at the lowest cost.

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